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Table of Contents
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2010
OR
o 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 |
(I.R.S. Employer Identification No.) | |
incorporation or organization) |
||
10111 Richmond Avenue, Suite 340 |
||
Houston, Texas |
77042 | |
(Address of principal executive offices) |
(Zip Code) |
Registrants 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 þ No o
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 o No þ
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 þ No
o
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
þ No o
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 registrants 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. o
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 þ Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company) Smaller Reporting Company o
Non-accelerated filer o (Do not check if a smaller reporting company) Smaller Reporting Company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Act). Yes o No þ
The aggregate market value of the voting and non-voting common equity held by
non-affiliates of the registrant as of June 30, 2010, the last business day of the registrants
most recently completed second fiscal quarter was $603,266,667, calculated by reference to the
closing price of $26.20 for the registrants common stock on the New York Stock Exchange on that
date.
Number of shares of Class A common stock outstanding as
of February 23, 2011: 26,031,962
DOCUMENTS INCORPORATED BY REFERENCE
The information called for by Part III, Items 10, 11, 12, 13 and 14, 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.
Exhibit Index Located on Page 78
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.
Exhibit Index Located on Page 78
TABLE OF CONTENTS
2
Table of Contents
PART I
ITEMS 1. and 2. Business and Properties
REORGANIZATION
GulfMark Offshore, Inc., a Delaware corporation, was incorporated in 1996. On February 24,
2010, GulfMark Offshore, Inc., (Old GulfMark) merged with and into its wholly owned subsidiary,
New GulfMark Offshore, Inc., a Delaware corporation (New GulfMark), pursuant to an agreement and
plan of reorganization, dated as of October 14, 2009 (the Reorganization Agreement), with New
GulfMark as the surviving corporation (such transaction, the Reorganization). The Reorganization
was adopted by the requisite vote of stockholders at a special meeting of the stockholders of Old
GulfMark on February 23, 2010. Under the U.S. maritime and vessel documentation laws, commonly
referred to as the Jones Act, only those vessels that are owned and managed by U.S. citizens (as
determined by those laws) and are built in and registered under the laws of the United States are
allowed to transport merchandise and passengers for hire in U.S. territorial waters, otherwise
known as Coastwise Trade. The Reorganization was designed to prevent certain situations from
occurring that could jeopardize the Companys eligibility as a U.S. citizen under the Jones Act
and, therefore, its ability to engage in Coastwise Trade. At the effective time of the
Reorganization, New GulfMark changed its name from New GulfMark Offshore, Inc. to GulfMark
Offshore, Inc. The business, operations, assets and liabilities of New GulfMark immediately after
the Reorganization were the same as business, operations, assets and liabilities of Old GulfMark
immediately prior to the Reorganization.
At the effective time of the Reorganization and pursuant to the Reorganization Agreement, each
outstanding and treasury share of the common stock of Old GulfMark automatically converted into one
share of Class A common stock of New GulfMark, which are subject to certain transfer and ownership
restrictions designed to protect our eligibility to engage in Coastwise Trade (the Maritime
Restrictions). References to our common stock mean, with respect to Old GulfMark prior to the
Reorganization, common stock and, with respect to New GulfMark after the Reorganization, Class A
common stock. The issuance of the shares of Class A common stock was registered under the
Securities Act of 1933, as amended, pursuant to New GulfMarks registration statement on Form S-4
(File No. 333-162612), which was declared effective by the U.S. Securities and Exchange Commission
(the SEC) on January 22, 2010. Shares of Class A common stock of New GulfMark trade on the same
exchange, the New York Stock Exchange (the NYSE), and under the same symbol, GLF, that the
shares of Old GulfMark common stock traded on and under prior to the Reorganization.
Unless otherwise indicated, references to we, us, our and the Company refer to New
GulfMark, its subsidiaries and its predecessor, Old GulfMark, except that all such references prior
to the effective time of the Reorganization on February 24, 2010 are references to Old GulfMark and
its subsidiaries.
GENERAL BUSINESS
We provide offshore marine 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, as well as move and position drilling structures. The majority of
our operations are conducted in the North Sea, offshore Southeast Asia and offshore in the
Americas. We also contract vessels into other regions to meet our customers requirements.
We have the following operating segments: the North Sea (N. Sea), Southeast Asia (SEA) 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. 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 Financial Accounting Standards Board (FASB) Accounting Standards
Codification (ASC) 280, Segment Reporting. For financial information about our operating
segments and geographic areas, see Managements Discussion and Analysis of Financial Condition and
Results of Operations Segment Results included in Part II, Item 7, and Note 14 to our
Consolidated Financial Statements included in Part II, Item 8.
Our principal executive offices are located at 10111 Richmond Avenue, Suite 340, Houston,
Texas 77042, 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 SEC. This annual report on
Form 10-K for the year ended December 31, 2010 includes as exhibits all required Sarbanes-Oxley Act
Section 302 certifications by our CEO and CFO regarding the quality of our public disclosure. In
addition, our CEO certifies annually to the New York Stock Exchange (NYSE) that he is not aware
of any violation by the Company of the NYSE corporation governance listing standards. 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 SECs website at http://www.sec.gov. Filings are available on
our website as soon as reasonably practicable after we electronically file or furnish them to the
SEC. You may also read and copy any document we file at the SECs Public Reference Room at the
following location: 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.
3
Table of Contents
THE COMPANY
Offshore Marine Services Industry Overview
Our customers employ our vessels to provide services 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. This
industry employs various types of vessels, referred to broadly as offshore support vessels, or
OSVs, that are used to transport materials, supplies and personnel, and to move and position
drilling structures. Offshore marine service providers are employed by oil and natural gas
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 North Sea, offshore Southeast Asia, offshore West Africa, offshore Middle
East, offshore Brazil and the U.S. Gulf of Mexico are each major markets that employ a large number
of vessels. Vessel usage is also significant in other international markets, including offshore
India, offshore Australia and offshore Trinidad, the Persian Gulf and the Mediterranean Sea. The
industry is relatively fragmented, with more than 20 major participants and numerous smaller
regional competitors. We currently operate a fleet of 88 OSVs in the following regions: 37 vessels
in the North Sea, 15 vessels offshore Southeast Asia, and 36 vessels offshore the Americas. Our
fleet is one of the worlds youngest, largest and most geographically balanced, high specification
OSV fleets and our owned vessels have an average age of approximately eight years.
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. The
characteristics and current marketing environment in each region are discussed later in greater
detail. Our strongest markets in recent years have been in the Southeast Asia region and in the
Americas components of Brazil, Mexico and Trinidad. The North Sea region has
experienced weak spot but strengthened long-term market conditions. Currently, our most challenging market is in the U.S.
Gulf of Mexico, a component of the Americas segment, where several factors have decreased
profitability and have made the area highly competitive. In the later half of 2009 and continuing
in early 2010, natural gas commodity prices suffered declines compared to the previous couple of
years. The lower prices had already affected drilling activity in the U.S. Gulf of Mexico when, in
April 2010, a catastrophic fire and explosion sank a deepwater drilling rig and precipitated a
major oil spill (the Macondo Incident). The Macondo Incident effectively shut down drilling in
the U.S. Gulf of Mexico due both to oil spill cleanup efforts and a drilling moratorium. Although
the cleanup was largely completed in August 2010 and the moratorium was lifted in October 2010, drilling
activity has not recovered in the area and new government regulations continue to limit the
possibility of a recovery in the near future. We continue to evaluate the market conditions in
each region, and the potential impact these conditions may have on our business.
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 notably
the case in the North Sea, where vessel design requirements dictated by the harsh operating
environment restrict relocation of vessels into that market. 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.
4
Table of Contents
WORLDWIDE FLEET
In addition to the vessels we own, we manage a number of 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. The following table summarizes the
overall owned, managed and total fleet changes since December 31, 2009:
Owned | Managed | Total | ||||||||||
Vessels | Vessels | Fleet | ||||||||||
December 31, 2009 |
73 | 19 | 92 | |||||||||
New Build Program |
3 | - | 3 | |||||||||
Vessel Reductions |
- | (5 | ) | (5 | ) | |||||||
Vessel Dispositions |
(2 | ) | - | (2 | ) | |||||||
December 31, 2010 |
74 | 14 | 88 | |||||||||
New Build Program |
- | - | - | |||||||||
Vessel Reductions |
- | - | - | |||||||||
Vessel Dispositions |
- | - | - | |||||||||
February 24, 2011 |
74 | 14 | 88 | |||||||||
Vessel Classifications
Offshore support vessels generally fall into seven functional classifications derived from
their primary or predominant operating characteristics or capabilities. However, these
classifications are not rigid, 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 (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 (SmAHTSs) while AHTSs in excess of
10,000 BHP are referred to as large AHTSs (LgAHTSs). The most powerful North Sea class
AHTSs have upwards of 25,000 BHP. All of our AHTSs can also function as PSVs. |
||
| Platform Support Vessels (PSVs) serve drilling and production facilities and support
offshore construction and maintenance work. They are differentiated from other offshore
support vessels 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 range in size from 150
to 200 feet. Large PSVs (LgPSVs) typically range up 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 (FSVs/Crewboat) transport personnel and cargo to and from
production platforms and rigs. Older crewboats (early 1980s build) 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 support
vessels (FSVs). They are used primarily to transport cargo on a time-sensitive basis. |
||
| Specialty Vessels (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 (FPSOs); diving operations; remotely
operated vehicles (ROVs); 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. |
||
| Standby Rescue Vessels (Stby) perform a safety patrol function for an 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 |
5
Table of Contents
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:
Owned Vessels by Classification | ||||||||||||||||
AHTS | PSV | FSV/Crewboat | ||||||||||||||
Region | AHTS | SmAHTS | LgPSV | PSV | FSV | Crew | SpV | Total | ||||||||
North Sea |
3 | - | 19 | 2 | - | - | 1 | 25 | ||||||||
Southeast Asia |
8 | 3 | 2 | 1 | - | - | - | 14 | ||||||||
Americas |
3 | - | 3 | 20 | 4 | 4 | 1 | 35 | ||||||||
14 | 3 | 24 | 23 | 4 | 4 | 2 | 74 | |||||||||
New Vessel Construction, Acquisition and Divestiture Program, and Drydocking Obligations
Vessel Construction and Acquisitions
In 2007, we committed with Aker Yards ASA to build two new PSVs with double hull and various
environmental enhancements. The first vessel was delivered in November 2009 and the second vessel
was delivered in February 2010.
Also in 2007, we entered into agreements with two shipyards to construct five vessels. Bender
Shipbuilding & Repair Co., Inc. (Bender), a Mobile, Alabama based company, was contracted to
build three PSVs and Gdansk Shiprepair Yard Remontowa SA, a Polish company, was contracted to
build two AHTS vessels. In March 2009, we notified Bender that it was in default under our contract
as a result of non-performance. We determined that we had a material impairment and recognized a
charge of $46.2 million in the first quarter of 2009 relating to the construction in progress
recorded under this contract. See Note 2 to the Consolidated Financial Statements included in Part
II, Item 8 for more information. The first Remontowa vessel was completed and delivered in the
second quarter of 2010, and the second vessel was completed and delivered in the third quarter of
2010. Both vessels were deployed to our Southeast Asia region.
During 2010, we took delivery of three vessels that were under construction at December 31,
2009. We have no vessels currently under construction.
Vessel Additions Since December 31, 2009 | ||||||||||||||
Year | Length | Month | ||||||||||||
Vessel | Region | Type | Built | (feet) | BHP | DWT | Delivered | |||||||
North Purpose |
N. Sea | PSV | 2010 | 284 | 10,738 | 4,850 | Feb-10 | |||||||
Sea Valiant |
SEA | AHTS | 2010 | 230 | 10,188 | 2,301 | Jun-10 | |||||||
Sea Victor |
SEA | AHTS | 2010 | 230 | 10,188 | 2,301 | Jul-10 |
Foreign Currency Contracts Related to Construction Contracts
When applicable, we enter into forward currency contracts to minimize our foreign currency
exchange risk related to the construction of new vessels. During 2007, we entered into a series of
forward currency contracts relative to future milestone payments for the construction of Keppel
vessels, all of which were delivered prior to December 31, 2009, and the two Aker Yards vessels
6
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described above. These contracts were closed in early 2010 when the last Aker Yards vessel was
delivered under the construction contract. As of December 31, 2010, we had no open foreign
currency contracts.
Vessel Divestitures/ Vessels Held For Sale (Laid Up)
In the second quarter of 2010, we sold one of our Americas vessels and recorded a $0.1 million
loss. At the end of the third quarter of 2010, we sold one of our North Sea vessels and recorded a
$5.2 million gain. As of February 24, 2011, we have one vessel that is held for sale and is not
included in our fleet numbers.
Vessels Sold Since December 31, 2009 | ||||||||||||||
Year | Length | Month | ||||||||||||
Vessel | Region | Type | Built | (feet) | BHP | DWT | Sold | |||||||
North Traveller |
N. Sea | LgPSV | 1998 | 221 | 5,450 | 3,115 | Sep-10 | |||||||
Seapower |
Americas | SpV | 1974 | 222 | 7,040 | 1,205 | Apr-10 |
Vessels Held for Sale (Laid Up) | ||||||||||||||||||||||||
Year | Length | |||||||||||||||||||||||
Vessel | Region | Type | Built | (feet) | BHP | DWT | ||||||||||||||||||
Clwyd Supporter |
N. Sea | SpV | 1984 | 266 | 10,700 | 1,350 |
Maintenance of Our Vessels and Drydocking Obligations
In addition to repairs, we are required to make expenditures for the certification and
maintenance of our vessels, and those expenditures typically increase with age. The demands of the
market, the expiration of existing contracts, the start of new contracts, and customer preferences
influence the timing of drydocks. Our drydocking expenditures for 2010 were $22.2 million. We
anticipate approximately $16.7 million in drydocking expenditures in 2011.
Vessel Listing
Currently, we operate a fleet of 88 vessels. Of these vessels, 74 are owned by us (see table
below, which excludes laid up vessels and the 14 vessels we manage for other owners).
7
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Owned Vessel Fleet | ||||||||||||||
Year | Length | |||||||||||||
Vessel | Region | Type (a) | Built | (feet) | BHP (b) | DWT (c) | Flag | |||||||
Highland Bugler |
N. Sea | LgPSV | 2002 | 221 | 5,450 | 3,115 | UK | |||||||
Highland Champion |
N. Sea | LgPSV | 1979 | 265 | 4,800 | 3,910 | UK | |||||||
Highland Citadel |
N. Sea | LgPSV | 2003 | 236 | 5,450 | 3,200 | UK | |||||||
Highland Eagle |
N. Sea | LgPSV | 2003 | 236 | 5,450 | 3,200 | UK | |||||||
Highland Fortress |
N. Sea | LgPSV | 2001 | 236 | 5,450 | 3,200 | UK | |||||||
Highland Monarch |
N. Sea | LgPSV | 2003 | 221 | 5,450 | 3,115 | UK | |||||||
Highland Navigator |
N. Sea | LgPSV | 2002 | 275 | 9,600 | 4,250 | Panama | |||||||
Highland Pioneer |
N. Sea | LgPSV | 1983 | 224 | 5,400 | 2,500 | UK | |||||||
Highland Prestige |
N. Sea | LgPSV | 2007 | 284 | 10,767 | 4,993 | UK | |||||||
Highland Pride |
N. Sea | LgPSV | 1992 | 265 | 6,600 | 3,080 | UK | |||||||
Highland Rover(d) |
N. Sea | LgPSV | 1998 | 236 | 5,450 | 3,200 | Panama/UK | |||||||
Highland Star |
N. Sea | LgPSV | 1991 | 265 | 6,600 | 3,075 | UK | |||||||
North Challenger |
N. Sea | LgPSV | 1997 | 221 | 5,450 | 3,115 | Norway | |||||||
North Mariner |
N. Sea | LgPSV | 2002 | 275 | 9,600 | 4,400 | Norway | |||||||
North Promise |
N. Sea | LgPSV | 2007 | 284 | 10,767 | 4,993 | Norway | |||||||
North Stream |
N. Sea | LgPSV | 1998 | 276 | 9,600 | 4,585 | Norway | |||||||
North Truck |
N. Sea | LgPSV | 1983 | 265 | 6,120 | 3,370 | Norway | |||||||
North Vanguard |
N. Sea | LgPSV | 1990 | 265 | 6,600 | 4,000 | Norway | |||||||
North Purpose |
N. Sea | PSV | 2010 | 284 | 10,738 | 4,850 | Norway | |||||||
Highland Trader |
N. Sea | LgPSV | 1996 | 221 | 5,450 | 3,115 | UK | |||||||
Highland Courage |
N. Sea | AHTS | 2002 | 260 | 16,320 | 2,750 | UK | |||||||
Highland Valour |
N. Sea | AHTS | 2003 | 260 | 16,320 | 2,750 | UK | |||||||
Highland Endurance |
N. Sea | AHTS | 2003 | 260 | 16,320 | 2,750 | UK | |||||||
Highland Prince |
N. Sea | PSV | 2009 | 284 | 10,738 | 4,850 | UK | |||||||
Highland Spirit |
N. Sea | SpV | 1998 | 202 | 6,000 | 1,800 | UK | |||||||
Highland Guide |
SEA | LgPSV | 1999 | 218 | 4,640 | 2,800 | Panama | |||||||
Highland Legend |
SEA | PSV | 1986 | 194 | 3,600 | 1,442 | Panama | |||||||
Highland Drummer |
SEA | LgPSV | 1997 | 221 | 5,450 | 3,115 | Panama | |||||||
Sea Apache |
SEA | AHTS | 2008 | 250 | 10,700 | 2,700 | Panama | |||||||
Sea Cheyenne |
SEA | AHTS | 2007 | 250 | 10,700 | 2,700 | Panama | |||||||
Sea Guardian |
SEA | SmAHTS | 2006 | 191 | 5,150 | 1,500 | Panama | |||||||
Sea Intrepid |
SEA | SmAHTS | 2005 | 191 | 5,150 | 1,500 | Panama | |||||||
Sea Sovereign |
SEA | SmAHTS | 2006 | 230 | 5,500 | 1,800 | Panama | |||||||
Sea Supporter |
SEA | AHTS | 2007 | 225 | 7,954 | 2,360 | Panama | |||||||
Sea Choctaw |
SEA | AHTS | 2008 | 250 | 10,700 | 2,700 | Panama | |||||||
Sea Cherokee |
SEA | AHTS | 2009 | 250 | 10,700 | 2,700 | Panama | |||||||
Sea Comanche |
SEA | AHTS | 2009 | 250 | 10,700 | 2,700 | Panama | |||||||
Sea Valiant |
SEA | AHTS | 2010 | 213 | 10,188 | 2,301 | Panama | |||||||
Sea Victor |
SEA | AHTS | 2010 | 213 | 10,188 | 2,301 | Panama | |||||||
Austral Abrolhos(e) |
Americas | SpV | 2004 | 215 | 7,100 | 2,000 | Brazil | |||||||
Highland Scout |
Americas | LgPSV | 1999 | 218 | 4,640 | 2,800 | Panama | |||||||
Highland Piper |
Americas | LgPSV | 1996 | 221 | 5,450 | 3,115 | Panama | |||||||
Highland Warrior |
Americas | LgPSV | 1981 | 265 | 5,300 | 4,049 | Panama | |||||||
Sea Kiowa |
Americas | AHTS | 2008 | 250 | 10,700 | 2,700 | Panama | |||||||
Coloso |
Americas | AHTS | 2005 | 199 | 5,916 | 1,674 | Mexico | |||||||
Titan |
Americas | AHTS | 2005 | 199 | 5,916 | 1,674 | Mexico |
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Owned Vessel Fleet | ||||||||||||||
Year | Length | |||||||||||||
Vessel | Region | Type (a) | Built | (feet) | BHP (b) | DWT (c) | Flag | |||||||
Orleans |
Americas | PSV | 2004 | 210 | 6,342 | 2,586 | USA | |||||||
Bourbon |
Americas | PSV | 2004 | 210 | 6,342 | 2,586 | USA | |||||||
Royal |
Americas | PSV | 2004 | 210 | 6,342 | 2,586 | USA | |||||||
Chartres |
Americas | PSV | 2004 | 210 | 6,342 | 2,586 | USA | |||||||
Iberville |
Americas | PSV | 2004 | 210 | 6,342 | 2,586 | USA | |||||||
Bienville |
Americas | PSV | 2005 | 210 | 6,342 | 2,586 | USA | |||||||
Conti |
Americas | PSV | 2005 | 210 | 6,342 | 2,586 | USA | |||||||
St. Louis |
Americas | PSV | 2005 | 210 | 6,342 | 2,586 | USA | |||||||
Toulouse |
Americas | PSV | 2005 | 210 | 6,342 | 2,586 | USA | |||||||
Esplanade |
Americas | PSV | 2005 | 210 | 6,342 | 2,586 | USA | |||||||
First and Ten |
Americas | PSV | 2007 | 190 | 3,894 | 1,860 | USA | |||||||
Double Eagle |
Americas | PSV | 2007 | 190 | 3,894 | 1,860 | USA | |||||||
Triple Play |
Americas | PSV | 2007 | 190 | 3,894 | 1,860 | USA | |||||||
Grand Slam |
Americas | PSV | 2007 | 190 | 3,894 | 1,860 | USA | |||||||
Sailfish |
Americas | Crew | 2007 | 176 | 7,200 | 307 | USA | |||||||
Slam Dunk |
Americas | PSV | 2008 | 190 | 3,894 | 1,860 | USA | |||||||
Touchdown |
Americas | PSV | 2008 | 190 | 3,894 | 1,860 | USA | |||||||
Hat Trick |
Americas | PSV | 2008 | 190 | 3,894 | 1,860 | USA | |||||||
Slap Shot |
Americas | PSV | 2008 | 190 | 3,894 | 1,860 | USA | |||||||
Homerun |
Americas | PSV | 2008 | 190 | 3,894 | 1,860 | USA | |||||||
Knockout |
Americas | PSV | 2008 | 190 | 3,894 | 1,860 | USA | |||||||
Hammerhead |
Americas | FSV | 2008 | 181 | 7,200 | 543 | USA | |||||||
Bluefin |
Americas | Crew | 2008 | 165 | 7,200 | 337 | USA | |||||||
Albacore |
Americas | Crew | 2008 | 165 | 7,200 | 337 | USA | |||||||
Mako |
Americas | FSV | 2008 | 181 | 7,200 | 543 | USA | |||||||
Swordfish |
Americas | Crew | 2009 | 176 | 7,200 | 307 | USA | |||||||
Blacktip |
Americas | FSV | 2009 | 181 | 7,200 | 543 | USA | |||||||
Tiger |
Americas | FSV | 2009 | 181 | 7,200 | 543 | USA |
The table above does not include the managed vessels or those vessels being held for sale.
(a) | Legend: LgPSV Large platform supply vessel |
PSV Platform supply vessel
AHTS 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
Crew Crewboats
AHTS 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
Crew Crewboats
(b) | Brake horsepower. |
|
(c) | Deadweight tons. |
|
(d) | 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 each;
October 1, 2012; April 1, 2015; and October 1, 2016 provided 120 days notice has been given by
the charterer. |
|
(e) | The Austral Abrolhos is subject to an annual right of its charterer to purchase the vessel
during the term of the charter, which commenced May 2, 2003 and, subject to the charterers
right to extend, terminates April 29, 2016, at a purchase price in the first year of
approximately $26.8 million declining to an adjusted purchase price of approximately $12.9
million in the thirteenth year. |
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OPERATING SEGMENTS
The North Sea Operating Segment
Owned | Managed | Total | ||||||||||
Vessels | Vessels | Fleet | ||||||||||
December 31, 2009 |
25 | 17 | 42 | |||||||||
New Build Program |
1 | - | 1 | |||||||||
Vessel Reductions |
- | (5 | ) | (5 | ) | |||||||
Vessel Dispositions |
(1 | ) | - | (1 | ) | |||||||
December 31, 2010 |
25 | 12 | 37 | |||||||||
New Build Program |
- | - | - | |||||||||
Vessel Reductions |
- | - | - | |||||||||
Vessel Dispositions |
- | - | - | |||||||||
February 24, 2011 |
25 | 12 | 37 | |||||||||
Market and Segment Overview
We define the North Sea market as offshore Norway, Denmark, the Netherlands, Germany, Great
Britain, Ireland, the Faeroes Islands and Greenland. 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 (such as major and state-owned oil and natural
gas companies) in large part because of the significant financial commitment required. However, in
recent years, a number of independent operators have established operating bases in the region,
thus diversifying the customer base. Projects in the North Sea tend to be fewer in number but
larger in scope, with longer planning horizons than projects in regions with less demanding
environments. Due to these factors, vessel demand in the North Sea has historically been more
stable and less susceptible to abrupt swings than vessel demand 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 as much by the volatility in demand for the
AHTSs. Our North Sea-based fleet is oriented toward support vessels that work in the more stable
segments of the market: production platform support and field development and construction.
Unless deployed to one of our 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
Future visibility with regard to vessel demand is directly related to drilling and development
activities in the region, construction work required in support of these activities, as well as
demands outside of the region that draw vessels to other international markets. Geopolitical
events, the demand for oil and natural gas in both mature and emerging countries and a host of
other factors will influence the expenditures of both independent and major oil and gas companies.
There was a transformation in the customer base in the region that began in 2003 as the major
oil and natural gas companies disposed of prospects and mature producing properties in the North
Sea to independent oil and natural gas companies. The independent companies typically had smaller
capital expenditure budgets and shorter horizons that resulted in a decline in the number of
long-term contracts and a corresponding increase in the number of vessels working in the spot
market.
Starting in late 2004 and continuing through early 2008, there was an increase in the number
of large projects and long-term charters resulting from new reserve discoveries, an opening of
portions of the Barents Sea to exploration activities by the Norwegian government, and a
significant improvement in industry fundamentals. These actions triggered the building of a number
of new vessels. In mid-2008, the outlook for the global economy became negative and worldwide
energy demand forecasts declined. These factors
resulted in a noticeable decrease in activity during 2009 and in the early part of 2010.
However, exploration and development
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spending in the North Sea region is expected to increase
throughout 2011 and 2012, increasing offshore drilling and subsea construction activity and demand
for vessel services in this region.
The Southeast Asia Operating Segment
Owned | Managed | Total | ||||||||||
Vessels | Vessels | Fleet | ||||||||||
December 31, 2009 |
12 | 1 | 13 | |||||||||
New Build Program |
2 | - | 2 | |||||||||
Vessel Reductions |
- | - | - | |||||||||
Vessel Dispositions |
- | - | - | |||||||||
December 31, 2010 |
14 | 1 | 15 | |||||||||
New Build Program |
- | - | - | |||||||||
Vessel Reductions |
- | - | - | |||||||||
Vessel Dispositions |
- | - | - | |||||||||
February 24, 2011 |
14 | 1 | 15 | |||||||||
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, Cambodia, Indonesia, Malaysia, Myanmar, the
Philippines, Singapore, Thailand, Australia, New Zealand 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 onshore bases in Singapore and Malaysia.
Southeast Asias competitive environment is broadly characterized by a large number of small
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 since the mid-1970s and we currently maintain long-standing business relationships with
a number of local companies.
During 2010, we took delivery of two vessels that were built in Poland. See further
discussion under Vessel Construction and Acquisitions on page 6.
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 have historically made up the
bulk of the vessels in the Southeast Asia market. Demand for larger, newer and higher
specification vessels has developed in the region where deepwater projects occur or where oil and
natural gas companies employ larger fleets of vessels. This development led us to mobilize several
vessels from the North Sea into this region from 2002 to 2007, to meet the changing market. North
Sea vessels are larger than the typical vessels of the region. During the last five years, we have
sold 11 of our older vessels serving Southeast Asia and have taken delivery of 12 new vessels.
Changes in supply and demand dynamics have led, at times, to an excess number of vessels in
other geographic markets. It is possible that vessels currently located in the Arabian/Persian
Gulf area, 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. As with many other regions, Southeast Asia is suffering from the economic downturn, with
many vessels lying idle awaiting work.
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The Americas Operating Segment
Owned | Managed | Total | ||||||||||
Vessels | Vessels | Fleet | ||||||||||
December 31, 2009 |
36 | 1 | 37 | |||||||||
New Build Program |
- | - | - | |||||||||
Vessel Reductions |
- | - | - | |||||||||
Vessel Dispositions |
(1 | ) | - | (1 | ) | |||||||
December 31, 2010 |
35 | 1 | 36 | |||||||||
New Build Program |
- | - | - | |||||||||
Vessel Reductions |
- | - | - | |||||||||
Vessel Dispositions |
- | - | - | |||||||||
February 24, 2011 |
35 | 1 | 36 | |||||||||
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. Most of our vessels operate in the
deepwater areas of the U.S. Gulf of Mexico where we have a significant position. However, during
2010, primarily as a result of the substantially reduced drilling activity in the U.S. Gulf of
Mexico as a result of the Macondo Incident and subsequent tightening of U.S. government
regulations, we transferred seven vessels to Brazil, Mexico and Trinidad to work on long term
contracts. We moved two additional vessels from the U.S. Gulf of Mexico to Trinidad in the first
quarter of 2011. All vessels based in the Americas are supported from our onshore bases in St.
Rose and Youngsville, Louisiana; Trinidad; Macae, Brazil; and Paraiso, Mexico.
U.S. Gulf of Mexico
Drilling in the U.S. Gulf of Mexico can be divided into two sectors: the shallow waters of the
continental shelf and the deepwater areas. Deepwater drilling is generally considered to be in
water depths in excess of 1,000 feet. 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 resurgence of deepwater
drilling 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 make it less susceptible to short-term
fluctuations in the price of crude oil and natural gas. Although the activity level of deepwater
drilling had been increasing, the Macondo Incident resulted in a drilling moratorium. This
moratorium was specifically centered around deepwater drilling, but effectively stopped all
developmental drilling. The moratorium was lifted in October 2010, but more restrictive U.S.
government regulations have continued to affect drilling operations. As a result, we made the
decision to move a number of vessels out of the U.S. Gulf of Mexico to other markets in the
Americas region in an effort to increase our vessel utilization. We expect activity in the U.S.
Gulf of Mexico to resume and we remain positive about its future potential. As a result, a number
of our modern DP-2 vessels remain in the U.S. Gulf of Mexico, some under long term contracts, and
others in the spot market.
In general, the U.S. Gulf of Mexico remains a protected market. The Jones Act 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. For more information
see Reorganization and OtherGovernment and Environmental Regulation Maritime Regulations in
our Business and Properties included in this Part I, Items 1 and 2.
Brazil
The Brazilian government presently permits private investment in the petroleum business and
the early bid rounds for certain offshore concessions resulted in extensive commitments by major
international oil companies and consortia of independents, many of whom have explored and are
likely to continue to explore the offshore blocks awarded in the lease sales. This has created a
demand for deepwater AHTSs and PSVs in support of the drilling and exploration activities that has
been met primarily from mobilization of vessels from other regions. Petrobras, the Brazilian
national oil company, as well as several international independents, continue to expand operations
and announce discoveries. This expansion has created additional demand for offshore support vessels
in the area and in 2010, we transferred four vessels from the U.S. Gulf of Mexico to work in Brazil
under long term contracts. Looking forward, we expect continued growth in the area and we will
continue to be active in bidding offshore support vessel opportunities as they develop.
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Currently, we operate nine vessels in Brazil, including a Brazilian built and flagged vessel.
We have four PSVs, three LgPSVs and two AHTSs operating in the area under contracts of varying
lengths, the earliest of which began in 1990 and the most recent of which began in the fourth
quarter of 2010 under a multi-year contract. In May 2010, we sold one of the oldest vessels in our
fleet, the SPV SeaPower for work outside our industry.
Mexico
Since 2005, we have operated two AHTSs offshore Mexico on five-year primary-term contracts
with Pemex, Mexicos national oil company, that originally expired in February 2010. We recently entered into new long-term contracts with Pemex for these AHTSs. In addition, during 2010, we moved a crew boat into
the area from the U.S. Gulf of Mexico on a long term contract with Pemex, bringing our vessel count
in Mexico to three. Mexico could be a potentially large market for expanded deepwater activity,
provided the government can develop a methodology for operations with non-Mexican international oil
companies that works within its constitutional constraints. We will continue to actively bid into
the area when opportunities arise.
Trinidad
In Trinidad, we are supporting a significant drilling campaign for an international operator
with five PSVs and three FSVs. During 2010, we moved two vessels into the area from the U.S. Gulf
of Mexico, and two additional vessels moved during the first quarter of 2011. These vessels are
all working on term charters with international clients. Given recent licensing and exploration
activity in nearby locations, including Suriname and Guyana, we expect to see vessel support
requirements operating from a Trinidad base for the foreseeable future.
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 affecting the movement of drilling rigs and delivery 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 because
fewer drilling rigs meet the enhanced regulatory requirements for operating in the U.S. Gulf of
Mexico that are in effect during the period. 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 drilling
and development activities.
Fleet Availability
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 as of February 23, 2010 and
February 24, 2011:
As of February 24, 2011 | As of February 23, 2010 | |||||||||||||||
2011 | 2012 | 2010 | 2011 | |||||||||||||
Vessel Days | Vessel Days | Vessel Days | Vessel Days | |||||||||||||
North Sea |
75.5% | 55.4% | 72.5% | 37.2% | ||||||||||||
Southeast Asia |
49.8% | 22.7% | 71.1% | 30.6% | ||||||||||||
Americas |
56.0% | 29.4% | 43.8% | 14.0% | ||||||||||||
Overall Fleet |
61.3% | 36.7% | 58.4% | 24.5% |
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.
Other Markets
From time to time, we have contracted our vessels outside of our operating segment regions
principally on short-term charters in offshore Africa and 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 will 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.
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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-cancelable provisions except for unsatisfactory
performance by the vessel. No single customer accounted for 10 percent or more of our total
consolidated revenue for the past three years.
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 less than two
years in length. Recently, however, consistent with the change in the demand in the region,
Southeast Asia contract periods are extending out further in time. 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 with cancellation provisions. We also
have other contracts containing non-cancelable provisions except for unsatisfactory vessel
performance. 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 a particular
customer.
Bareboat charters are contracts for vessels, generally for a term in excess of one year,
whereby the owner transfers all market exposure for the vessel to the charterer in exchange for an
arranged fee. The charterer has the right to market the vessel without direction from the owner.
Currently, we have no third party bareboat chartered vessels in our fleet.
Managed vessels add to the market presence of the manager but provide limited direct financial
contribution. Management fees are typically based on a per diem rate and are not subject to
fluctuations in the charter hire rates. The manager is typically responsible for disbursement of
funds for operating the vessel on behalf of the owner. Currently, we have 14 vessels under
management.
Substantially all of our charters are fixed in British Pounds, or GBP; Norwegian Kroner, or
NOK; Euros; U.S. Dollars, or US$; or Brazilian Reais. We attempt to reduce currency risk by
matching each vessels contract revenue to the currency in which its operating expenses are
incurred.
We compete with approximately a dozen competitors in the North Sea market and numerous small
and large competitors in the Southeast Asia and Americas markets, some of which have significantly
greater financial resources than we do. 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 Customs Service,
and their foreign equivalents, and to regulation by private industry organizations such as the
American Bureau of Shipping. 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 Customs Service is authorized to inspect vessels at will. We believe that we
are in material compliance 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
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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.
Environmental Regulations
Our operations are subject to a variety of federal, state, local and international laws and
regulations regarding the 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.
Failure to comply with applicable 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.
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.
The Clean Water Act imposes strict controls on the discharge of pollutants into the navigable
waters of the United States. The Clean Water Act 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 Clean Water Act 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-base facilities.
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 and thus 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.
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The Resource Conservation and Recovery Act 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 Resource
Conservation and Recovery Act and analogous state statutes.
Insurance
In mid-2010, we reviewed our insurance coverage, specifically in light of the Macondo Incident. In
particular, we assessed our coverage levels and limits for possible marine liabilities, including
pollution, personal injury or death, and property damage. Our 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 1,700 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 840 contract
crew members who are members of two North Sea 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.
Properties
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 and Kemaman, Terengganu, Malaysia. 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; 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 1A. Risk Factors
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; |
||
| 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; |
||
| technological advances; and |
||
| ability of oil and natural gas companies to obtain leases, permits, or obtain funds for
capital. |
The level of offshore exploration, development and production activity has historically been
characterized by volatility. Prior to mid-2008, there was a period of high prices for oil and
natural gas, and oil and gas companies increased their exploration and development activities. A
decline in the worldwide demand for oil and natural gas or prolonged low oil or natural gas prices
in the future, such as occurred in late 2008, however, typically results in reduced
exploration and development of offshore areas and a
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decline in the demand for our offshore marine services. 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.
An increase in the supply of offshore support vessels would likely have a negative effect on
charter rates for our vessels, which could reduce our earnings.
Charter rates for marine support vessels depend in part on the supply of the vessels. We could
experience a reduction in demand as a result of an increased supply of vessels. Excess vessel
capacity in the industry may result from:
| constructing new vessels; |
||
| moving vessels from one offshore market area to another; |
||
| converting vessels formerly dedicated to services other than offshore marine services;
or |
||
| declining offshore oil and gas drilling production activities. |
In the last ten years, construction of vessels of the types we operate has
increased. The addition of new capacity of various types to the worldwide offshore marine fleet or
declining offshore oil and gas drilling and production activities are likely to increase
competition in those markets where we presently operate which, in turn, could reduce day rates,
utilization rates and operating margins, which would adversely affect our financial condition and
results of operations.
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 Jones Act, as well as with environmental, health, 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 the future costs or
other future impact of these laws on our operations and our customers. 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.
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; and |
||
| war, sabotage, piracy and terrorism risks. |
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 have significant claims against us for damages due to personal injury, death,
property damage, pollution and loss of business.
We maintain insurance coverage against substantially all 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 2011-2012, and have negotiated terms for renewal of our 2012-2013
primary marine coverages. We can provide no assurance, however, that our insurance coverage will be
available beyond the renewal periods, and will be adequate to cover future claims that may arise.
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A substantial portion of our revenue is derived from our international operations and those
operations 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 government 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; |
||
| 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. Also, 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.
Our tax expense and effective tax rate on our worldwide earnings could be higher should there
be changes in tax legislation in countries where we operate, should we lose our tonnage tax
qualifications or tax exemptions and/or should we increase our operations in high tax
jurisdictions where we operate.
Our worldwide operations are conducted through our various subsidiaries. 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 a qualified vessels, resulting in significantly lower taxes
than those that would apply if we were not a qualified shipping company in those jurisdictions.
Norway enacted a new tonnage tax system in January 2007, subjecting us to ordinary corporate tax on
accumulated untaxed shipping profits as of December 31, 2006. In February 2010, Norways Supreme
Court ruled that the 2007 legislation to tax prior years profits was retroactive taxation and
unconstitutional and, accordingly, in June 2010 Norways Minister of Finance published revised
rules for the taxation of pre-2007 tonnage tax profits. The revised Norwegian rules provide a
qualified tonnage tax company to choose one of two systems, or methods, to determine and pay tax on
its untaxed shipping profits as of December 31, 2006. We have decided to elect the simplified tax
system, which beginning in 2011 requires three equal annual installment payments of the tax that is
calculated as ten percent (10%) of two-thirds of the untaxed tonnage tax profits. 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 guarantee that
extensions will be granted.
Our operations in the United States increased with the Rigdon Acquisition in July 2008, and
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. Additionally, 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
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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 potentially adversely affect our operating revenue or construction costs when translated into
U.S. Dollars.
Vessel construction and repair 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 and repair 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 and repair
projects would 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.
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. The cost of adding a new vessel to our fleet ranges from
under $10.0 million to $100.0 million and potentially higher. 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.
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, 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 Managements Discussion and Analysis of Financial Condition and Results of
Operations (MD&A) included in Part II, Item 7.
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. |
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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 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 is generally 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, although following a hurricane, activity may increase as there
may be a greater demand for vessel services as repair and remediation activities take place.
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 increased drilling and development activities.
We are subject to war, sabotage, piracy and terrorism risk.
War, sabotage, pirate and terrorist attacks or any similar risk may 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, could be direct targets of, or indirect casualties of, an act of piracy
or terror. War or risk of war 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 continually evaluate the need to maintain this coverage as it
applies to our fleet. Instability in the financial markets as a result of war, sabotage, piracy or
terrorism could also affect our ability to raise capital and could also adversely affect the oil,
natural gas and power industries and restrict their future growth.
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 imposed as a result of the Reorganization may have an adverse effect
on us and our stockholders.
As a result of the Reorganization, our Class A common stock is now 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 (collectively, 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 shareholders 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 (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 the Company, even if doing
so would benefit our stockholders. |
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Our business could be adversely effected 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
becoming ineligible 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. Currently, we believe we meet the requirements to engage in Coastwise
Trade, and the Maritime Restrictions imposed as part of the Reorganization were designed to assist
us in complying with these requirements, but there can be no assurance that we will always be in
compliance with the Jones Act.
Circumvention or repeal of the Jones Act may have an adverse impact on us.
The Jones Acts 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.
The recent volatility in oil and gas prices and disruptions in the credit markets and general
economy may adversely impact our business.
As a result of volatility in oil and natural gas prices and ongoing uncertainty of the global
economic environment, we are unable to determine whether customers will reduce spending on
exploration and development drilling or whether customers and/or vendors and suppliers will be able
to access financing necessary to sustain their current level of operations, fulfill their
commitments and/or fund future operations and obligations. The current global economic environment
may impact industry fundamentals and impact our customers abilities to pay for the services of our
vessels. The potential resulting 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.
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 (GHG) 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. Physical risks from climate change include
an increase in sea level and changes in weather conditions. Given the maritime nature of our
business, we do not believe that physical climate change is likely to have a material adverse
effect on us.
Financial risks relating to climate change are likely to arise from increasing legislation and
regulation, as compliance with any new rules could be difficult and costly. U.S. federal
legislation has been proposed in Congress to reduce GHG emissions. In addition, in the absence of
federal GHG legislation, the EPA has taken several recent steps to regulate GHG emissions, which
regulations have been challenged. Depending on the outcome of such Congressional legislation or EPA
regulations, increased energy, environmental and other costs and capital expenditures could be
necessary to comply with the limitations. Our vessels also operate in foreign jurisdictions that
are addressing climate changes by legislation or regulation. Unless and until Congressional
legislation or EPA regulations are
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enacted and its terms are finalized, we cannot reasonably or reliably estimate its impact on
our financial condition, operating performance or ability to compete.
Adverse impacts upon the oil and gas industry relating to climate change may also effect us as
demand for our services depends on the level of activity in offshore oil and natural gas
exploration, development and production. Although we do not expect that demand for oil and gas will
lessen dramatically over the short term, in the long term global warming may reduce the demand for
oil and gas or increased regulation of GHG may create greater incentives for use of alternative
energy sources. Any long term material adverse effect on the oil and gas industry may have a
material adverse effect on our financial condition and operating results, but we cannot reasonably
or reliably estimate that it will occur, when it will occur or that it will impact us.
Recent Events in the U.S. Gulf of Mexico Have Adversely Impacted and Are Likely to Continue to
Adversely Impact Our Operations and Financial Condition.
The Macondo Incident resulted in 11 deaths, multiple personal injuries, significant property
damage and the release of hydrocarbons that resulted in significant pollution and contamination. In
May 2010, the U.S. Department of Interior issued a memorandum imposing a temporary moratorium on
deepwater drilling on the outer continental shelf. This moratorium was lifted on October 12, 2010,
subject, however, to new standards, requirements and regulations that must be complied with before
drilling can commence. The catastrophe and moratorium have significantly and adversely disrupted
oil and gas exploration and development activities in the U.S. Gulf of Mexico.
On January 11, 2011, a federal commission appointed by the President released its report
regarding the causes of the catastrophe and made recommendations as to what legislative or
regulatory measures should be taken in order to minimize the possibility of a recurrence of a
disastrous oil spill. It is currently unclear how any of these recommendations will be implemented
and what impact they would have on oil and gas exploration and development activities in the U.S.
Gulf of Mexico. It remains uncertain what impact the incident itself and the commission report may
have on the regulation of offshore oil and gas exploration and development activity, the cost or
availability of insurance coverage to cover the risks of such operations, or what actions may be
taken by our customers, governmental agencies, or other industry participants in response to the
incident. In addition, we cannot predict whether any possible changes in regulations would affect
only deepwater drilling or all operations in the U.S. Gulf of Mexico or would also affect drilling
and operations in other regions around the world in which we operate. At this time, various bills
are being considered by Congress which, if enacted, could either significantly increase the costs
of conducting oil and gas drilling and exploration activities in the U.S. Gulf of Mexico, or
potentially eliminate a substantial portion of drilling and operation activity from the U.S. Gulf
of Mexico. There is uncertainty as to whether Congress will repeal the $75.0 million limitation for
non-reclamation liability under the Oil Pollution Act of 1990 and revise penalties for pollution
liabilities, broaden liability under the Jones Act and Death on the High Seas Act, and restrict
certain rights to limit liability of a vessel owner under the Limitations of Liability Act of 1851.
Significant changes in these laws could have a material adverse effect on our business, financial
condition and results of operation.
The disruption in oil and gas exploration activities from the moratorium had a material
adverse impact on our U.S. Gulf of Mexico drilling support operations in the second and third
quarters of 2010, and, even with the lifting of the moratorium, continued through the fourth
quarter of 2010. Announced and anticipated changes in laws and regulations regarding offshore oil
and gas exploration and development activities, the cost or availability of insurance, and
decisions by customers, governmental agencies, or other industry participants could further reduce
demand for our services or increase our costs of operations. This could further increase the
adverse impact on our financial condition and operating results, but we cannot reasonably or
reliably estimate to what extent such changes will occur, when they will occur, or how severely
they will impact us.
After cleanup efforts ceased, the portion of our U.S. fleet involved in the effort were
released in a more restricted and more competitive market in the U.S. Gulf of Mexico. We have since
relocated vessels to Brazil, Mexico and Trinidad where more profitable opportunities existed.
However, as a result of the Macondo Incident and the subsequent issues regarding drilling in the
region, our competitors could redeploy their vessels into other regions in which we operate, which
would increase the competition in that area, potentially resulting in lowered profit margins. In
addition, our customers may seek to renegotiate the terms of their contracts or avoid their
obligations under the contracts, both of which could adversely affect our business, financial
condition and results of operations.
Although we have no knowledge of any litigation or claims against us relating to the recent
events in the U.S. Gulf of Mexico, no assurance can be given that we will not be involved in
litigation or claims in the future or that they will not have a material adverse effect on our
financial condition or results of operation.
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ITEM 1B. Unresolved Staff Comments
NONE
ITEM 3. Legal Proceedings
General
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. (Removed and Reserved)
PART II
ITEM 5. Market for Registrants 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
for the periods indicated:
2010 | 2009 | |||||||||||||||
High | Low | High | Low | |||||||||||||
Quarter ended March 31, |
$29.77 | $23.79 | $28.36 | $16.00 | ||||||||||||
Quarter ended June 30, |
$34.47 | $24.56 | $34.63 | $25.12 | ||||||||||||
Quarter ended September 30, |
$30.95 | $25.69 | $33.49 | $24.73 | ||||||||||||
Quarter ended December 31, |
$33.53 | $29.25 | $34.88 | $25.84 |
For the period from January 1, 2011 through February 23, 2011, the range of low and high sales
prices of our common stock was $30.30 to $43.10, respectively. On February 23, 2011, the closing
sale price of our Class A common stock as reported by the NYSE was $41.25 per
share and there were
607 stockholders of record.
We have not declared or paid cash dividends during the past five years. Pursuant to the terms
of the indenture under which the senior notes, as further described in Part II, Item 7,
Managements Discussion and Analysis of Financial Condition and Results of Operations Long-Term
Debt and Note 6 of the Notes to the Consolidated Financial Statements in Part II, Item 8 are
issued, we may be restricted from declaring or paying dividends; however, we currently anticipate
that, for the foreseeable future, any earnings will be retained for the growth and development of
our business. The declaration of dividends is at the discretion of our Board of Directors. Our
dividend policy will be reviewed by the Board of Directors at such time as may be appropriate in
light of future operating conditions, dividend restrictions of subsidiaries and investors,
financial requirements, general business conditions and other factors.
Equity incentive plan information required by this item may be found in Note 9 of the Notes
to the Consolidated Financial Statements in Part II, Item 8 herein.
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Performance Graph
The following performance graph and table compare the cumulative return on our 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) the value
of the investment of our common stock and each index to have been $100 at December 31, 2005.
Comparison of Cumulative Total Return
2005 | 2006 | 2007 | 2008 | 2009 | 2010 | |||||||
GulfMark Offshore, Inc. |
100 | 119 | 152 | 78 | 91 | 96 | ||||||
Dow Jones Total Market Index |
100 | 116 | 123 | 77 | 96 | 110 | ||||||
Dow Jones Oilfield Equipment and Services Index |
100 | 113 | 164 | 67 | 102 | 126 |
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ITEM 6. Selected Consolidated 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 and Managements Discussion and Analysis of
Financial Condition and Results of Operations, included in Part II, Item 7.
Year Ended December 31, | ||||||||||||||||||||
2010 | 2009 | 2008 | 2007 | 2006 | ||||||||||||||||
(Amounts in thousands, except per share amounts) | ||||||||||||||||||||
Operating Data: |
||||||||||||||||||||
Revenue |
$ | 359,766 | $ | 388,871 | $ | 411,740 | $ | 306,026 | $ | 250,921 | ||||||||||
Direct operating expenses |
170,638 | 166,183 | 143,925 | 108,386 | 91,874 | |||||||||||||||
Drydock expense |
22,182 | 15,696 | 11,319 | 12,606 | 9,049 | |||||||||||||||
General and administrative expenses |
44,029 | 43,700 | 40,244 | 32,311 | 24,504 | |||||||||||||||
Depreciation and amortization |
56,959 | 53,044 | 44,300 | 30,623 | 28,470 | |||||||||||||||
Impairment charge |
97,665 | 46,247 | - | - | - | |||||||||||||||
Gain on sale of assets |
(5,095 | ) | (5,552 | ) | (34,811 | ) | (12,169 | ) | (10,237 | ) | ||||||||||
Operating income (loss) |
(26,612 | ) | 69,553 | 206,763 | 134,269 | 107,261 | ||||||||||||||
Interest expense |
(21,693 | ) | (20,281 | ) | (14,291 | ) | (7,923 | ) | (15,648 | ) | ||||||||||
Interest income |
985 | 377 | 1,446 | 3,147 | 1,263 | |||||||||||||||
Other income (expense), net |
(126 | ) | (1,153 | ) | 1,609 | (298 | ) | (95 | ) | |||||||||||
Income tax (provision) benefit (a) |
12,701 | 2,087 | (11,743 | ) | (30,220 | ) | (3,052 | ) | ||||||||||||
Net income (loss) |
$ | (34,745 | ) | $ | 50,583 | $ | 183,784 | $ | 98,975 | $ | 89,729 | |||||||||
Amounts per common share (basic) (b): |
||||||||||||||||||||
Net income (loss) |
$ | (1.36 | ) | $ | 2.01 | $ | 7.74 | $ | 4.41 | $ | 4.40 | |||||||||
Weighted average common shares (basic) |
25,519 | 25,151 | 23,737 | 22,435 | 20,377 | |||||||||||||||
Amounts per common share (diluted) (b): |
||||||||||||||||||||
Net income (loss) |
$ | (1.36 | ) | $ | 1.99 | $ | 7.56 | $ | 4.29 | $ | 4.28 | |||||||||
Weighted average common shares (diluted) |
25,519 | 25,446 | 24,319 | 23,059 | 20,975 | |||||||||||||||
Statement of Cash Flows Data: |
||||||||||||||||||||
Cash provided by operating activities |
$ | 91,574 | $ | 171,045 | $ | 205,201 | $ | 128,577 | $ | 104,869 | ||||||||||
Cash used in investing activities |
(53,857 | ) | (68,199 | ) | (186,787 | ) | (175,383 | ) | (28,300 | ) | ||||||||||
Cash provided by (used in) financing activities |
(32,837 | ) | (120,250 | ) | 56,754 | 373 | (20,679 | ) | ||||||||||||
Effect of exchange rate changes on cash |
236 | 8,722 | (14,526 | ) | 3,793 | 2,679 | ||||||||||||||
Other Data: |
||||||||||||||||||||
Adjusted EBITDA (c) |
$ | 127,760 | $ | 168,844 | $ | 251,063 | $ | 164,892 | $ | 135,731 | ||||||||||
Cash dividends per share |
- | - | - | - | - | |||||||||||||||
Total vessels in fleet as of year end (d) |
88 | 92 | 94 | 61 | 60 | |||||||||||||||
Average number of owned or chartered vessels (e) |
73.4 | 71.3 | 59.5 | 46.8 | 48.5 | |||||||||||||||
As of December 31, | ||||||||||||||||||||
2010 | 2009 | 2008 | 2007 | 2006 | ||||||||||||||||
(In thousands) | ||||||||||||||||||||
Balance Sheet Data: |
||||||||||||||||||||
Cash and cash equivalents |
$ | 97,195 | $ | 92,079 | $ | 100,761 | $ | 40,119 | $ | 82,759 | ||||||||||
Vessels, equipment and other fixed assets,
including construction in
progress, net |
1,194,200 | 1,204,416 | 1,169,513 | 754,000 | 571,989 | |||||||||||||||
Total assets |
1,464,450 | 1,565,659 | 1,556,967 | 934,012 | 750,829 | |||||||||||||||
Long-term debt (f) |
293,095 | 326,361 | 462,941 | 159,558 | 159,490 | |||||||||||||||
Total stockholders equity |
945,957 | 987,468 | 854,843 | 676,091 | 541,428 |
(a) | See Note 7 to our Consolidated Financial Statements Income Taxes, 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 |
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or non-operational, consisting of: (i) 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. |
||
EBITDA and Adjusted EBITDA are presented because they are widely used by security 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 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 calculation provides 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, financingrelated charges and deferred income taxes that may be required as normal
business operations. Management compensates for these limitations by using our GAAP results to
supplement the EBITDA and Adjusted EBITDA calculations. |
The following table summarizes the calculation of EBITDA and Adjusted EBITDA for the periods
indicated.
Year Ended December 31, | ||||||||||||||||||||
2010 | 2009 | 2008 | 2007 | 2006 | ||||||||||||||||
(In thousands) | ||||||||||||||||||||
Net income (loss) |
$ | (34,745 | ) | $ | 50,583 | $ | 183,784 | $ | 98,975 | $ | 89,729 | |||||||||
Interest expense |
21,693 | 20,281 | 14,291 | 7,923 | 15,648 | |||||||||||||||
Interest income |
(985 | ) | (377 | ) | (1,446 | ) | (3,147 | ) | (1,263 | ) | ||||||||||
Income tax provision (benefit) |
(12,701 | ) | (2,087 | ) | 11,743 | 30,220 | 3,052 | |||||||||||||
Depreciation, amortization and impairment |
154,624 | 99,291 | 44,300 | 30,623 | 28,470 | |||||||||||||||
EBITDA |
127,886 | 167,691 | 252,672 | 164,594 | 135,636 | |||||||||||||||
Adjustments: |
||||||||||||||||||||
Cumulative effect of change in accounting principle |
- | - | - | - | - | |||||||||||||||
Debt refinancing costs |
- | - | - | - | - | |||||||||||||||
Other * |
(126 | ) | 1,153 | (1,609 | ) | 298 | 95 | |||||||||||||
Adjusted EBITDA |
$ | 127,760 | $ | 168,844 | $ | 251,063 | $ | 164,892 | $ | 135,731 | ||||||||||
* | Includes foreign currency transaction adjustments. |
|
(d) | Includes managed vessels in addition to those that are owned and chartered at the end of
the applicable period (excludes vessels held for sale). See Our Fleet in Part I, Items 1 and
2 Business and Properties for further information concerning our fleet. |
|
(e) | 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. Includes
owned and bareboat chartered vessels only, and is adjusted for additions and dispositions
occurring during each period. |
|
(f) | Excludes current portion of long-term debt. |
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ITEM 7. Managements 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 Consolidated Financial Statements and
Supplementary Data. See also Part II, Item 6 Selected Consolidated Financial Data.
Our Business Strategy
Our goal is to enhance our position as a premier provider of offshore marine services by
achieving higher vessel utilization rates, relatively stable growth rates and returns on
investments that are superior to those of our competitors. Key elements in implementing our
strategy include:
Developing and maintaining a large, modern, diversified and technologically advanced fleet: Our
fleet size, location and profile allow us to provide a full range of services to our customers from
platform supply work to specialized floating, production, storage and offloading, or FPSO support,
including anchor handling and remotely operated vehicle, or ROV, operations. We regularly upgrade
our fleet to improve capability, reliability and customer satisfaction. We also seek to take
advantage of attractive opportunities to acquire or build new vessels to expand our fleet. Since
2001, we have increased our owned fleet by more than 50 vessels through either new build programs
or acquisitions. In addition, we have sold certain older vessels that no longer meet our objective
of maintaining a modern, diversified and technologically advanced fleet. We believe our relatively
young fleet, which requires less maintenance and refurbishment work during required drydockings
than older fleets, allows for less downtime, resulting in more dependable operations for us and for
our customers.
Enhancing fleet utilization through development of specialty applications for our vessels: We
operate some of the most technologically advanced vessels available. Our highly efficient,
multiple-use vessels provide our customers flexibility and are constructed with design elements
such as dynamic positioning, firefighting, moon pools, ROV handling and oil spill response
capabilities. In addition, we design and equip new build vessels specifically to meet our customer
needs.
Focusing on attractive markets: We conduct our operations mainly in the North Sea, offshore
Southeast Asia and offshore Americas markets. Our focus on these regions is driven by what we
perceive to be higher barriers to entry, lower volatility of day rates (except in the Americas) and
greater potential for increasing day rates in these markets than in other markets. Our operating
experience in these markets has enabled us to anticipate and profitably respond to trends, such as
the increasing demand for multi-function vessels, which we believe will be met through the
additions we have made in the past few years to our North Sea and Southeast Asia fleets. In
addition, we have the capacity under appropriate market conditions to alter the geographic focus of
our operations to a limited degree by shifting vessels between our existing markets and by entering
new markets as they develop economically and become more profitable.
Managing our risk profile through chartering arrangements: We utilize various contractual
arrangements in our fleet operations, including long-term charters, short-term charters, sharing
arrangements and vessel alliances. Sharing arrangements provide us and our customers the
opportunity to benefit from rising charter rates by subchartering the contracted vessels to third
parties at prevailing market rates during any downtime in the customers operations. We also
operate and participate in arrangements where vessels of similar specifications enter into
alliances which include technical cooperation. We believe these contractual arrangements help us
reduce volatility in both day rates and vessel utilization and are beneficial to our customers.
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, as well as move and position drilling structures. A
substantial portion of our operations are international. Our fleet has grown in both size and
capability, from an original 11 vessels in 1990 to our present number of 88 active vessels, through
strategic acquisitions and the new construction of technologically advanced vessels, partially
offset by dispositions of certain older, less profitable vessels. At February 24, 2011, our active
fleet includes 74 owned vessels and 14 managed vessels.
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 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.
From time to time, we bareboat charter vessels with revenue and operating expenses reported in
the same income and expense categories as our owned vessels. The chartered vessels, however, incur
bareboat charter fees instead of depreciation expense. Bareboat
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charter fees are generally higher than the depreciation expense on owned vessels of similar
age and specification. The operating income realized from these vessels is therefore adversely
affected by the higher costs associated with the bareboat charter fees. These vessels are included
in calculating fleet day rates and utilization in the applicable periods.
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.
Our operating costs are primarily a function of fleet configuration. The most significant
direct operating cost is wages paid to vessel crews, followed by maintenance and repairs and
insurance. 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 the depreciation of
our fleet and costs for routine drydock inspections and modifications designed to ensure compliance
with applicable regulations and maintaining certifications for our vessels with various
international classification societies. The number of drydockings and other repairs undertaken in a
given period generally determines maintenance and repair expenses. The demands of the market, the
expiration of existing contracts, the start of new contracts, and customer preferences influence
the timing of drydocks.
Critical Accounting Policies and Estimates
The Consolidated Financial Statements, including notes thereto, contained in Part II, Item 8
contain information that is pertinent to managements discussion and analysis. 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.
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 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
corporate policy. This formalized policy ensures there is 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 appreciably all of our accounts receivable balances. At
December 31, 2010 and 2009, respectively, we provided an allowance for doubtful accounts of $0.3
million for both years. 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 deteriorating
economic 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.
Drydocking, Mobilization and Financing Costs
The periodic requirements of the various classification societies requires 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.
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 deferred amount would be immediately expensed. In contrast, costs of relocating vessels
from one region to another without a contract are expensed as incurred.
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Deferred financing costs are capitalized as incurred and are 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.
Long-Lived Assets, Goodwill and Intangibles
Our long-lived tangible assets consist primarily of vessels and construction-in-progress. Our
goodwill primarily relates to the 2001 acquisition of Sea Truck Holding AS and the 1998 acquisition
of Brovig Supply AS. Our identifiable intangible assets relate to the value assigned to customer
relationships as a result of the Rigdon Acquisition. 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 on tangible long-lived assets is performed
on an asset-by-asset basis and impairment testing on goodwill is performed on a reporting-unit
basis for the reporting units where the goodwill is recorded.
In assessing potential impairment related to our long-lived assets, the assets carrying
values 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. We assess whether impairment exists
by comparing the fair value of each operating segment to its carrying value, including goodwill. We
use a combination of two valuation methods, a market approach and an income approach, to estimate
the fair value of our operating segments. Fair value computed by these two methods is arrived at
using a number of factors, including projected future operating results, economic projections,
anticipated future cash flows, comparable marketplace data and the cost of capital. There are
inherent uncertainties related to these factors and to our judgment in applying them to this
analysis. However, we believe that these two methods provide a reasonable approach to estimating
the fair value of our operating segments.
The market approach estimates fair value by measuring the aggregate market value of
publicly-traded companies with similar characteristics of our business as a multiple of their
reported cash flows. We then apply that multiple to our operating segments cash flows to estimate
their fair value. We believe that this approach is appropriate because it provides a fair value
estimate using valuation inputs from entities with operations and economic characteristics
comparable to our operating segments.
The income approach is based on the long-term projected future cash flows of our operating
segments. We discount the estimated cash flows to present value using a weighted-average cost of
capital that considers factors such as the timing of the cash flows and the risks inherent in those
cash flows. We believe that this approach is appropriate because it provides a fair value estimate
based upon our operating segments expected long-term performance considering the economic and
market conditions that generally affect our business.
In the second quarter of 2010, we assessed our Americas region goodwill for impairment. In
our assessment, we evaluated the impact on the segments fair value due to the Macondo Incident,
the resulting oil spill and the drilling moratorium. Based on the factors discussed above, which
were incorporated into our evaluations and testing as prescribed under U.S. GAAP, we determined
that an impairment of our Americas region goodwill existed, and accordingly we recorded a $97.7
million impairment charge as of June 30, 2010, reflecting all of our Americas region goodwill. The
non-cash charge does not impact our liquidity or debt covenant compliance. See Note 2 to the
Consolidated Financial Statements contained in Part II, Item 8.
In the third quarter of 2007, Bender Shipbuilding and Repair Co., Inc. (Bender), a Mobile,
Alabama based company, was contracted to build three PSVs. In March 2009, we notified Bender that
it was in default under our contract as a result of non-performance. We determined that we had a
material impairment and recognized a charge of $46.2 million in the first quarter of 2009 relating
to the construction in progress recorded under this contract. See Note 2 to the Consolidated
Financial Statements contained in Part II, Item 8.
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 having a ten year term and are renewable. 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. The tonnage tax regimes provide for a tax based on the net tonnage weight of a
qualified vessel. These foreign tax beneficial structures 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.
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In late 2007, Norway enacted legislation that created a new tonnage tax system from January
2007 forward and repealed the previous tonnage tax regime effective December 31, 2006 resulting in
mandatory exit from Norways tonnage tax system or payment of tax at 28% of accumulated untaxed
pre-2007 profits. Accordingly, we recorded approximately $15.0 million Norwegian tax liability in
2007. Our liability for pre-2007 taxes was to be paid equally over ten years beginning in 2008. In
February 2010 the Norway Supreme Court ruled the 2007 tax legislation to be unconstitutional
retroactive taxation and we reversed our remaining tonnage tax liability and received a refund of
the pre-2007 tonnage taxes that had been paid in 2008 and 2009, which resulted in our recording an
approximately $15.0 million tax benefit in our 2010 tax provision. In June 2010, Norways Minister
of Finance published revised rules for the taxation of pre-2007 tonnage tax profits permitting a
qualified tonnage tax company to elect one of two systems, or methods, to determine and pay tax on
its untaxed shipping profits as of December 31, 2006. We decided to elect the simplified tax
system, which beginning in 2011 requires three equal annual installment payments of the tax that is
calculated as ten percent (10%) of two-thirds of the untaxed tonnage tax profits. Under this
system we recorded an approximately $4.9 million tax provision. The net result of the 2010
Norwegian tonnage tax law changes was a $10.1 million tax benefit recorded in our 2010 tax
provision. Our liability to settle under the simplified tax system is included in our December 31,
2010 balance sheet as approximately $1.6 million current income tax payable and approximately $3.3
million as other long term payable. Annually the subsequent years cash installment is classified
on our consolidated balance sheet as current income taxes payable, and the remainder is classified
on our consolidated balance sheet as other income taxes payable.
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 or that are otherwise tax exempt. 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. 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 $7.2 million of such
foreign tax credit carryforwards that begin to expire in 2011. We also have certain foreign net
operating loss carryforwards that result in net deferred tax assets of approximately $2.3 million
for which we have established a valuation allowance. We have considered estimated future taxable
income in the relevant tax jurisdictions to utilize these tax credit and loss carryforwards 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.
Effective January 1, 2008, Mexico legislated a new revenue based tax, which in effect is an
alternative minimum tax payable to the extent that the new revenue based tax exceeds the current
income tax liability. These revenue based tax rates were 16.5% for 2008, 17% for 2009 and are
17.5% for 2010 and beyond. Effective January 1, 2010, Mexico enacted changes to corporate income
tax rates as follows: 2010 through 2012 30%; 2013 29%; and 2014 and beyond - 28%.
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 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,
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
consolidated balance sheet presentations for accrued income tax assets and liabilities, including
any amounts for uncertain tax positions.
See also Note 1 and Note 7 to our Consolidated Financial Statements included in Part II, Item
8.
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
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nature of the exposure. Such exposures change from period to period based upon updated
relevant facts and circumstances, which can cause the estimate 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 current and former U.K. subsidiaries are participating in a multi employer retirement
fund known as the Merchant Navy Officers Pension Fund (MNOPF). At December 31, 2010, we had $5.1
million accrued related to this liability, which reflects all obligations assessed by the funds
trustee on the Company. 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. In addition, we have been advised by the trustee that as of March 31, 2009, the MNOPF
was underfunded and as a result there is the potential that in the future participating employers
will be assessed additional obligations to correct the underfunding. The amount and timing of
additional potential future obligations depends on a number of factors, but principally on future
fund performance and the underlying actuarial assumptions. Our share of the funds deficit is
dependent on a number of factors including future actuarial valuations, the number of participating
employers, and the final method used in allocating the required contribution among participating
employers.
Split-Dollar Life Insurance Plans
Our President and Chief Executive Officer and our Executive Vice President Operations each
have split-dollar life insurance policies for which we pay the premiums, with a right to repayment
of such premiums paid. We have also entered into a supplemental income plan, as amended in December
2010, with each covered individual to provide him with a cash amount equal to the premiums paid.
Off-Balance Sheet Arrangements
We have evaluated our off-balance sheet arrangement, and have concluded that we do not have
any material relationships with unconsolidated entities or financial partnerships that have been
established for the purpose of facilitating off-balance sheet arrangements (as that term is defined
in Item 303(a)(4)(ii) of Regulations S-K). Based on this evaluation we believe that no disclosures
relating to off-balance sheet arrangements are required.
Consolidated Results of Operations
Comparison of the Fiscal Years Ended December 31, 2010 and December 31, 2009
Our consolidated revenue decreased from $388.9 million to $359.8 million, or $29.1 million,
mainly due to lower day rates in all regions, partially offset by the increased capacity resulting
from a full year for vessels added in 2009 and the three new vessels added in 2010. For the year
ended December 31, 2010, we had a net loss of $34.7 million or $1.36 per diluted share, compared to
net income of $50.6 million or $1.99 per diluted share for the year ended December 31, 2009.
Day rates decreased 14.3% in 2010, from $18,388 in 2009 to $15,758 in 2010, contributing $48.2
million to the decrease in revenue. This decrease was offset by an increase in utilization from
81.4% in 2009 to 85.5% in 2010, increasing revenue by $3.0 million. In addition, the weakening of
the U.S. Dollar contributed $3.0 million to the revenue increase. Capacity resulting from the
overall net additions increased revenue by $13.1 million.
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Year Ended December 31, | ||||||||||||
Increase | ||||||||||||
2010 | 2009 | (Decrease) | ||||||||||
(Dollars in thousands) | ||||||||||||
Average Rates Per Day Worked (a) (b): |
||||||||||||
North Sea (c) |
$ | 16,985 | $ | 19,930 | $ | (2,945) | ||||||
Southeast Asia |
16,943 | 20,780 | (3,837) | |||||||||
Americas |
14,281 | 16,098 | (1,817) | |||||||||
Overall Utilization (a) (b): |
||||||||||||
North Sea (c) |
93.5% | 88.8% | 4.7% | |||||||||
Southeast Asia |
84.7% | 90.0% | (5.3%) | |||||||||
Americas |
80.1% | 73.3% | 6.8% | |||||||||
Average Owned or Chartered Vessels (a) (d): |
||||||||||||
North Sea |
25.1 | 24.8 | 0.3 | |||||||||
Southeast Asia |
13.0 | 11.5 | 1.5 | |||||||||
Americas |
35.3 | 35.0 | 0.3 | |||||||||
Total |
73.4 | 71.3 | 2.1 | |||||||||
(a) | Includes all owned or bareboat chartered vessels. Managed vessels and vessels held for sale
are not included. |
|
(b) | Average rates per day worked is defined as total charter revenue 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) | Revenue 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 (US Dollar/GBP, US Dollar/NOK
and US Dollar/Euro) for the periods indicated below. The North Sea based fleet also includes
vessels working offshore India, offshore Africa and the Mediterranean. |
Year Ended December 31, | |||||||||
2010 | 2009 | ||||||||
$1 US=GBP
|
0.647 | 0.638 | |||||||
$1 US=NOK
|
6.036 | 6.244 | |||||||
$1 US=Euro
|
0.754 | 0.716 |
(d) | Adjusted for vessel additions and dispositions occurring during each period. |
Direct operating expenses increased by $4.5 million during 2010 mainly as a result in the net
increase in fleet size compared to 2009. We recorded a $97.7 million dollar impairment of our
goodwill during the second quarter of 2010 as a result of the deteriorating market conditions in
the U.S. Gulf of Mexico. Drydock expense increased by $6.5 million from 2009 to 2010 due to a
higher number of drydock days. General and administrative expenses increased by $0.3 million from
2009 and depreciation expense increased by $3.9 million year over year as a result of the increase
in the size of our fleet in 2010. The gain on sale of assets relates to the sale of two of our
vessels during 2010.
Interest expense increased $1.4 million year over year due mainly to the decrease in
capitalized interest resulting from the completion of all vessels in our new build program.
Interest income increased $0.6 million due to moderately higher market interest rates, and other
expense decreased by $1.0 million as a result of foreign currency movements throughout 2010.
The income tax benefit for 2010 was $12.7 million, compared to a benefit of $2.1 million from
2009. The 2010 effective tax rate was 26.8% and the 2009 effective tax rate was (4.3%). The 2010
tax benefit was mostly the result of our $10.1 million Norwegian net tax benefit coupled with the
net effect of tax benefits from operating losses in our high tax jurisdictions exceeding tax
expense from our lower taxed operations.
Comparison of the Fiscal Years Ended December 31, 2009 and December 31, 2008
Our revenue decreased from $411.7 million in 2008 to $388.9 million in 2009, resulting mainly
from the decreased utilization related to the overall market downturn and the currency effect of
the stronger U.S. Dollar. Overall day rates decreased for the same time period which also
negatively impacted revenue. In 2009, we sold two vessels and deemed one vessel a constructive
total loss after the vessel was damaged in a fire. In addition, we experienced the full year effect
of the five vessel sales that occurred in mid to
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late 2008. The reduction in vessels is offset by
the full year effect of the vessels acquired as part of the Rigdon Acquisition on July 1,
2008 and the addition of six new builds throughout the year. For the year ended December 31,
2009, net income was $50.6 million or $1.99 per diluted share, compared to $183.8 million, or $7.56
per diluted share for the year ended December 31, 2008.
Overall utilization decreased from 94.3% in 2008 to 81.4% in 2009, contributing $39.9 million
to the decrease in revenue. The strengthening of the U.S. Dollar in all regions decreased revenue
by $29.1 million. Overall day rates decreased from $19,697 in 2008 to $18,388 in 2009, contributing
$12.4 million to the decrease in revenue. Offsetting the decreases to revenue was the capacity
increase related to the full year effect of the vessels acquired in the Rigdon Acquisition and the
net additions throughout the year. This increased revenue by $58.6 million.
Year Ended December 31, | ||||||||||||
Increase | ||||||||||||
2009 | 2008 | (Decrease) | ||||||||||
(Dollars in thousands) | ||||||||||||
Average Rates Per Day Worked (a) (b): |
||||||||||||
North Sea (c) |
$ | 19,930 | $ | 22,837 | $ | (2,907 | ) | |||||
Southeast Asia |
20,780 | 17,723 | 3,057 | |||||||||
Americas |
16,098 | 16,567 | (469 | ) | ||||||||
Overall Utilization (a) (b): |
||||||||||||
North Sea (c) |
88.8% | 94.6% | (5.8%) | |||||||||
Southeast Asia |
90.0% | 94.5% | (4.5%) | |||||||||
Americas |
73.3% | 93.4% | (20.1%) | |||||||||
Average Owned or Chartered Vessels (a) (d): |
||||||||||||
North Sea |
24.8 | 27.2 | (2.4 | ) | ||||||||
Southeast Asia |
11.5 | 13.0 | (1.5 | ) | ||||||||
Americas |
35.0 | 19.3 | 15.7 | |||||||||
Total |
71.3 | 59.5 | 11.8 | |||||||||
(a) | Includes all owned or bareboat chartered vessels. Managed vessels are not included. |
|
(b) | Average rates per day worked is defined as total charter revenue 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) | Revenue 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 (US Dollar/GBP, US Dollar/NOK
and US Dollar/Euro) for the periods indicated below. The North Sea based fleet also includes
vessels working offshore India, offshore Africa and the Mediterranean. |
Year Ended December 31, | |||||||||
2009 | 2008 | ||||||||
$1 US=GBP
|
0.638 | 0.541 | |||||||
$1 US=NOK
|
6.244 | 5.580 | |||||||
$1 US=Euro
|
0.716 | 0.681 |
(d) | Adjusted for vessel additions and dispositions occurring during each period. |
Direct operating expenses increased $22.3 million in 2009 when compared to 2008. This increase
was mainly due to the full year effect of the increase in vessels as a result of the Rigdon
Acquisition, and the delivery of new vessels throughout the year. We reported an impairment charge
of $46.2 million in the first quarter of 2009 as a result of a default of the construction contract
by the builder of three of our vessels. Drydock expense increased by $4.4 million from 2008 to
2009. General and administrative expenses increased $3.5 million from 2008, and depreciation
expense increased $8.7 million year over year. The increase in general and administrative and
depreciation expense was mainly a result of the Rigdon Acquisition coupled with higher salary,
bonus and employee benefits. The gain on sale of assets of approximately $5.5 million relates to
the sale of three vessels.
Interest expense increased $6.0 million from 2008 due mainly to the increase in debt incurred
and assumed as part of the Rigdon Acquisition and the decrease in capitalized interest resulting
from the decrease in new build construction. The decrease in interest income of $1.1 million is due
to lower interest rates in the year. Other expense of $1.2 million was mainly related to foreign
currency movements throughout 2009.
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The income tax benefit for 2009 was $2.1 million, compared to an $11.7 million income tax
expense in 2008. The 2008 effective tax rate was 6.0%, which included the effect of six months of
earnings from operations attributable to the Rigdon Acquisition along with a provision for
uncertain tax liabilities in a foreign jurisdiction. The 2009 effective tax rate was (4.3%) with
the decrease from the
2008 rate mostly attributable to operating losses in our high tax jurisdictions plus the
reversal of certain valuation allowances no longer required, which were somewhat offset by the net
tax expense from repatriations to the U.S.
Segment Results
As discussed in General Business included in Part I, Items 1 and 2, 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. In 2010, we had $104.5 million in revenue and $462.9 million in
long-lived assets 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 remeasurements associated with these items are excluded from operating income.
Management considers segment operating income to be a good indicator of each segments 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 segments
operating income (loss) is summarized in the following table, and further detailed in the following
paragraphs.
Operating Income (Loss) by Operating Segment
Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
North Sea |
$ | 38,209 | $ | 54,014 | $ | 126,486 | ||||||
Southeast Asia |
39,761 | 58,105 | 62,447 | |||||||||
Americas |
(81,223 | ) | (19,155 | ) | 38,344 | |||||||
Total reportable segment operating income (loss) |
(3,253 | ) | 92,964 | 227,277 | ||||||||
Other |
(23,359 | ) | (23,411 | ) | (20,514 | ) | ||||||
Total reportable segment and other operating income (loss) |
$ | (26,612 | ) | $ | 69,553 | $ | 206,763 | |||||
North Sea Region:
Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
Revenue |
$ | 148,740 | $ | 165,415 | $ | 226,124 | ||||||
Direct operating expenses |
78,253 | 80,854 | 86,445 | |||||||||
Drydock expense |
7,598 | 6,818 | 8,237 | |||||||||
General and administrative expense |
11,277 | 10,598 | 11,414 | |||||||||
Depreciation and amortization expense |
18,649 | 17,186 | 22,623 | |||||||||
Gain on sale of assets |
(5,246 | ) | (4,055 | ) | (29,081 | ) | ||||||
Operating income |
$ | 38,209 | $ | 54,014 | $ | 126,486 | ||||||
Comparison of Fiscal Year Ended December 31, 2010 and December 31, 2009
Revenue for the North Sea of $148.7 million decreased $16.7 million, or 10% compared to 2009.
The decrease in day rates from $19,930 in 2009 to $16,985 in the current year contributed $24.7
million to the decrease in revenue. This decrease was offset by increased utilization and capacity
during 2010. Utilization increased in the current year to 93.5% from 88.8% in 2009, resulting in
an increase to revenue of $2.4 million. Increased capacity from the addition of one new build
vessel in late 2009 and one new build vessel in early 2010 contributed $5.6 million to revenue
compared to the prior year. Operating income of $38.2 million in 2010 was $15.8 million lower than
2009 due mainly to the decrease in revenues. Direct operating expenses were lower by $2.6 million
in 2010
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partly due to the strengthening of the U.S. Dollar, in addition to lower crew salaries and
lower supplies expense. Drydock expense increased $0.8 million from 2009 due to a higher drydock
cost per day average. Depreciation expense increased year over year by $1.5 million due to the
previously mentioned delivery of two new build vessels. General and administrative expense
increased by $0.7 million due primarily to increased employee benefits.
Comparison of Fiscal Year Ended December 31, 2009 and December 31, 2008
Revenue for the North Sea of $165.4 million in 2009 decreased $60.7 million, or 26.8%,
compared to 2008. The decrease is attributable to the strengthening of the U.S. Dollar against the
GBP and NOK, which reduced revenue by $26.9 million. In addition, due to the weakening of the
market, utilization decreased from 94.6% in 2008 to 88.8% in 2009, which reduced revenue by $16.4
million, and day rates also decreased from $22,839 in 2008 to $19,930 in 2009 negatively impacting
revenue by $5.4 million. In 2009, the region experienced the full year effect of the sale of two
vessels and the mobilization of a vessel to the Southeast Asia region in 2008, which is partially
offset by the addition of a new delivery in late 2009 and the overall effect of an increase in
capacity of $12.0 million. Operating income decreased by $72.5 million, primarily as a result of
the decrease in revenue and the decrease on the gain on sale of assets. Direct operating expenses
year over year were lower by $5.6 million due in part by the strengthening of the U.S. Dollar
coupled with lower crew salaries and benefits. Drydock expense was also lower by $1.4 million
resulting mainly from a lower number of drydock days. Depreciation expense decreased by $5.4
million resulting mainly from the sale of two vessels. General and administrative expense decreased
by $0.8 million due to lower salaries and benefits.
Southeast Asia Region:
Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
Revenue |
$ | 66,533 | $ | 76,544 | $ | 77,851 | ||||||
Direct operating expenses |
10,395 | 8,865 | 12,509 | |||||||||
Drydock expense |
4,796 | 2,095 | 250 | |||||||||
General and administration expense |
2,659 | 1,841 | 2,193 | |||||||||
Depreciation and amortization expense |
8,922 | 7,131 | 6,170 | |||||||||
Gain on sale of assets |
- | (1,493 | ) | (5,718 | ) | |||||||
Operating income |
$ | 39,761 | $ | 58,105 | $ | 62,447 | ||||||
Comparison of Fiscal Year Ended December 31, 2010 and December 31, 2009
Revenues for the Southeast Asia based fleet decreased by $10.0 million to $66.5 million in
2010. Day rates decreased from $20,780 in 2009 to $16,943 in the current year, which decreased
revenue by $14.2 million. Overall utilization decreased from 90% in 2009 to 84.7% in 2010,
contributing $3.7 million to the decrease in revenue. Capacity had a positive impact to revenue of
$7.9 million compared to 2009 as a result of the full year effect of two new build vessels added in
2009 and one new build vessel added in 2010. Although two new build vessels were added in 2010,
only one was utilized in the year. Operating income was lower during 2010 by $18.3 million year
over year, due mainly by the lower revenue and the decrease in gain on sale of assets, coupled with
increases to direct operating expense and depreciation expense resulting primarily from the
increased fleet. Drydock expense increased by $2.7 million as a result of more drydock days in
2010. General and administrative expense increased by $0.8 million as a result of higher office
salaries, benefits and higher bad debt expense.
Comparison of Fiscal Year Ended December 31, 2009 and December 31, 2008
Southeast Asia region revenue decreased by $1.3 million to $76.5 million in 2009, compared to
$77.9 million in 2008. The slight decrease in revenue is due mainly to the decrease in utilization
which decreased from 94.5% in 2008 to 90% in 2009 contributing $4.5 million to the decrease in
revenue. Average day rates increased from $17,723 in 2008 to $20,780 in 2009 due mainly to the
additions of four new vessels, however, the mix of days worked on low day rate vessels negatively
impacted revenue by $4.9 million. Capacity positively impacted revenue by $8.1 million due to the
full year effect of the two new deliveries in 2008 and the two new deliveries in 2009, which was
offset by the full year effect of the sale of three older vessels in 2008 and the loss of a vessel
as a result of the damage incurred in a fire in 2009. Operating income decreased $4.3 million year
over year, primarily as a result of the decrease in revenue and the decrease of the gain on sale of
assets. General and administrative cost decreased by $0.4 million as a result of lower salaries and
benefits and a decrease in bad debt expense.
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Americas Region:
Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
Revenue |
$ | 144,493 | $ | 146,912 | $ | 107,765 | ||||||
Direct operating expenses |
81,990 | 76,464 | 44,972 | |||||||||
Drydock expense |
9,788 | 6,783 | 2,832 | |||||||||
General and administrative expense |
7,798 | 8,685 | 6,769 | |||||||||
Depreciation and amortization expense |
28,321 | 27,892 | 14,860 | |||||||||
(Gain) loss on sale of assets |
154 | (4 | ) | (12 | ) | |||||||
Impairment charge |
97,665 | 46,247 | - | |||||||||
Operating income (loss) |
$ | (81,223 | ) | $ | (19,155 | ) | $ | 38,344 | ||||
Comparison of Fiscal Year Ended December 31, 2010 and December 31, 2009
Our Americas region revenue decreased $2.4 million, from $146.9 in 2009 to $144.5 in 2010. Day
rates decreased from $16,098 in 2009 to $14,281 in 2010, which negatively impacted revenue by $6.3
million. Capacity had an overall negative impact to revenue by $0.3 million as a result of the sale
of one of our older vessels during the second quarter of the current year, offset by the full year
effect of three new build vessels added during 2009. Utilization increased from 73.3% in 2009 to
80.1% in 2010, resulting in $4.2 million of higher revenue. Despite the Macondo Incident and its
subsequent effects, we were able to maintain a higher utilization in 2010 due to our involvement in
the cleanup effort. In addition, we moved vessels to other areas in the Americas region and kept
them fully utilized. Excluding impairment charges in both years, operating income decreased $10.7
million from 2009 resulting from lower revenues and higher direct operating expenses resulting due
to increases in fleet costs and higher crew wages and benefits. Drydock expense was also higher in
2010 as we incurred 41 more drydock days during the current year than during 2009. General and
administrative expense decreased by $0.9 million due to a combination of lower operating taxes and
lower bad debt expense.
Comparison of Fiscal Year Ended December 31, 2009 and December 31, 2008
Revenue for the Americas region increased year over year by $39.1 million, or 36.3%, from
$107.8 million in 2008 to $146.9 million in 2009, primarily as a result of the full year effect of
the Rigdon Acquisition that occurred July 1, 2008, the full year effect of the mobilization of two
vessels into the region in 2008 and the addition of three new deliveries in 2009 which in total
contributed $62.4 million to the increase in revenue. As a result of the market down turn mainly in
the U.S. Gulf of Mexico, utilization decreased from 93.4% in 2008 to 73.3% in 2009, decreasing
revenue by $18.9 million. Average day rates also decreased from $16,567 in 2008 to $16,098 in 2009,
reducing revenue by $4.4 million. Operating income, excluding the impairment charge of $46.2
million decreased by $11.3 million, which resulted from the $31.5 million increase in direct
operating expense and the increase in dry dock expense of $4.0 million, both resulting from the
increase in the number of vessels. Depreciation expense also increased by $13.0 million due to the
increase in fleet. General and administrative expense increased by $1.9 million from the prior
year due to increased salaries and benefits, mainly attributable to the Rigdon Acquisition.
Liquidity and Capital Resources
Our ongoing liquidity requirements are generally associated with our need to service debt,
fund working capital, maintain our fleet, finance the construction of new vessels and to acquire or
improve equipment or vessels. We plan to continue to be active in the acquisition of additional
vessels through both the resale market and new construction. Bank financing, equity capital 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 by the supply and demand
for the offshore drilling for crude oil and natural gas.
We completed our last vessel construction program in 2010 and have no new vessel construction
commitments for 2011. Interest expense at current rates under our existing debt arrangements,
assuming no additional borrowings, will be approximately $22.9 million for 2011. Minimum repayments
under our existing debt arrangements will be approximately $33.3 million for 2011. These amounts
are anticipated to be paid from a combination of cash on hand and cash from operations.
In addition, we are required to make expenditures for the certification and maintenance of our
vessels. We expect our drydocking expenditures to be approximately $16.7 million in 2011.
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At December 31, 2010, we had approximately $97.2 million of cash on hand, no amounts drawn
under our $175.0 million Revolving Loan Facility, $166.7 million borrowed under our Facility
Agreement, and $160.0 million outstanding under our Senior Notes.
We anticipate that cash on hand and future cash flow from operations for 2011 will be adequate
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 operating and working capital
requirements. This expectation, however, is dependent upon the success of our operations.
Long-Term Debt
Revolving Loan Facility
We currently have a $175.0 million Secured Reducing Revolving Loan Facility (the Revolving
Loan Facility) with a syndicate of financial institutions led by Den Norske Bank, or DNB, as
agent. The multi-currency facility is structured as follows: $25.0 million allocated to GulfMark
Offshore, Inc.; $60.0 million allocated to Gulf Offshore N.S. Limited, a wholly owned U.K.
subsidiary; $30.0 million allocated to GulfMark Rederi AS, a wholly owned Norwegian subsidiary; and
$60.0 million allocated to Gulf Marine Far East Pte Ltd., a wholly owned Singapore subsidiary. The
facility matures in June 2013 and the maximum availability begins to reduce in increments of $15.0
million every six months beginning in December 2011. Security for the facility is provided by first
priority mortgages on certain vessels. The interest rate ranges from LIBOR plus a margin of 0.7% to
0.9% depending on our EBITDA coverage ratio. At December 31, 2010, we were in compliance with all
covenants and had no amounts drawn under this facility.
Senior Notes
In 2004, we issued $160.0 million aggregate principal amount of 7.75% senior notes due July
2014. The 7.75% senior notes pay interest semi-annually on January 15 and July 15. The 7.75% senior
notes are currently callable at a redemption price of 102.583%. Beginning on July 15, 2011 the
redemption price reduces to 101.292% and after July 15, 2012 the 7.75% senior notes are callable at
par, respectively, plus accrued interest.
The 7.75% senior notes are general unsecured obligations and rank equally in right of payment
with all existing and future unsecured senior indebtedness and are senior to all existing and
future subordinated indebtedness. The 7.75% senior notes are effectively subordinated to all future
secured obligations to the extent of the assets securing such obligations and all existing and
future indebtedness and other obligations of our subsidiaries and trade payables incurred in the
ordinary course of business. Under certain circumstances, our payment obligations under the 7.75%
senior notes may be jointly and severally guaranteed on a senior unsecured basis by one or more of
our subsidiaries.
The indenture under which the 7.75% senior notes are issued imposes operating and financial
restrictions on us. These restrictions can limit or prohibit, among other things, our ability to
incur additional indebtedness, make capital expenditures, create liens, sell assets and make cash
dividends or other payments. At December 31, 2010, we were in compliance with all indenture
covenants.
Facility Agreement
On December 17, 2009, our subsidiary GulfMark Americas, Inc. (the Borrower) entered into a
$200.0 million facility agreement (the Facility Agreement) with the Royal Bank of Scotland PLC
(RBS). The Facility Agreement bears interest at the rate of LIBOR plus 250 basis points and
principal is due in quarterly installments of $8.3 million. The Facility Agreement matures on
December 31, 2012. We have an interest rate swap agreement overlaying a portion of the Facility
Agreement that has the effect of fixing the interest rate at 4.145% on $100.0 million of this debt.
This interest rate swap is accounted for as a cash flow hedge.
The Facility Agreement is secured by a majority of our U.S. flagged vessels. We have
unconditionally guaranteed all existing and future indebtedness and liabilities of the Borrower
arising under the Facility Agreement and other loan documents. Such guarantee also covers
obligations of the Borrower arising under any interest rate swap contract and other security
documentation related to the Facility Agreement. The collateral that secures the loans under the
Facility Agreement will secure all of the Borrowers obligations under any hedging agreements
between the Borrower and RBS.
The Facility Agreement requires compliance with financial covenants and customary covenants
and events of default. The Facility Agreement also contains customary representations, warranties
and affirmative and negative covenants. As set forth in the Facility Agreement, there are several
occurrences that constitute an event of default, including without limitation, defaults on payments
of amounts borrowed under the Facility Agreement, defaults on payments of other material
indebtedness, bankruptcy or insolvency, a change of control of GulfMark or the Borrower, material
unsatisfied judgments, the occurrence of a material adverse change, and other customary events of
default. Upon the occurrence of an event of default, RBS may terminate the Facility Agreement,
declare
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that all obligations under the Facility Agreement are due and payable and exercise its rights
with respect to the collateral under the Facility Agreement.
The Facility Agreement contains customary financial covenants, representations, and
warranties. We have been and continue to be in compliance with the requirements of the Facility
Agreement and we anticipate that we will be in compliance with these covenants throughout the term
of the agreement.
Current Year Cash Flow
At December 31, 2010, we had cash on hand of $97.2 million. Cash provided by operating
activities for the year ended December 31, 2010, was $91.6 million compared to $171.0 million in
the previous year. The decrease was primarily attributable to lower operating income resulting from
the downturn in the global market conditions.
Cash used in investing activities for the years ended December 31, 2010 and 2009 was $53.9
million and $68.2 million, respectively. In 2010, we spent approximately $73.4 million on asset
purchases, primarily new construction. In 2009, we spent approximately $77.4 million. In 2010 and
2009, we sold assets for approximately $19.6 million and $9.2 million, respectively. The proceeds
from these asset sales decreased the reported cash used in investing activities.
In 2010, we used $32.8 million in financing activities, compared to providing $120.3 million
in 2009. In 2010, we incurred $51.0 million in new long-term debt and repaid $84.3 million of
debt. During 2009, we incurred $200.0 million of new long-term debt and repaid $322.3 million in
debt.
Debt and Other Contractual Obligations
The following table summarizes our contractual obligations at December 31, 2010, and the
effect these obligations are expected to have on liquidity and cash flows in future periods (in
millions):
2011 | 2012 | 2013 | 2014 | 2015 | Thereafter | |||||||||||||||||||
Repayment of Long-Term Debt, Excluding
Debt Discount of $0.3 million |
$ | 33.3 | $ | 133.3 | $ | - | $ | 160.0 | $ | - | $ | - | ||||||||||||
Interest Payments |
$ | 21.5 | $ | 19.8 | $ | 12.4 | $ | 12.4 | $ | - | $ | - | ||||||||||||
Purchase Obligations for New Build Program |
- | - | - | - | - | - | ||||||||||||||||||
Non-Cancelable Operating Leases |
1.7 | 1.3 | 0.9 | 0.8 | 0.5 | 0.7 | ||||||||||||||||||
Long Term Income Taxes Payable |
1.8 | 1.8 | 1.8 | - | - | 5.4 | ||||||||||||||||||
Other |
0.8 | 0.8 | 1.0 | 0.8 | 0.7 | 3.4 | ||||||||||||||||||
Total |
$ | 59.1 | $ | 157.0 | $ | 16.1 | $ | 174.0 | $ | 1.2 | $ | 9.5 | ||||||||||||
Due to the uncertainty with respect to the timing of future cash payments, if any,
associated with our unrecognized tax benefits at December 31, 2010, we are unable to make
reasonably reliable estimates of the period of cash settlements with the respective taxing
authority. Therefore, $15.7 million of unrecognized tax benefits have been excluded from the
contractual obligations table above.
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. The aggregate notional value of
these instruments was $4.6 million and $0.2 million at December 31, 2010 and 2009, respectively. 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 paid 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 41% of our total consolidated revenue for the year ended December 31, 2010. In 2010, the
exchange rates of GBP, NOK and Euros against the U.S. Dollar ranged as follows:
38
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Year | As of | ||||||||||||||||
High | Low | Average | February 23, 2011 | ||||||||||||||
$1 US=GBP
|
0.701 | 0.611 | 0.647 | 0.616 | |||||||||||||
$1 US=NOK
|
6.705 | 5.610 | 6.036 | 5.629 | |||||||||||||
$1 US=Euro
|
0.839 | 0.689 | 0.754 | 0.727 |
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, such as a fair value hedge associated with the construction of vessels.
In this regard, in 2007, we entered into forward currency contracts to specifically hedge the
foreign currency exposure related to firm contractual commitments in the form of future vessel
payments. As a result, by design, there is an exact offset between the gain or loss exposure in
the related underlying contractual commitment. These contracts expired in early 2010 and there are
no outstanding contracts at December 31, 2010. See Part I, Items 1 and 2 Business and Properties
New Vessel Construction, Acquisition and Divestiture Program, and Drydocking Obligations. We
do not use foreign currency forward contracts for trading or speculative purposes.
Reflected in the accompanying consolidated balance sheet at December 31, 2010, is $39.1
million in accumulated other comprehensive income primarily relating to the higher exchange rate at
December 31, 2010 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 $54.0 million at December 31, 2009. 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 current year 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 PoliciesNew
Accounting Pronouncements in our Notes to Consolidated Financial Statements included in Part II,
Item 8.
Forward-Looking Statements
This Form 10-K, particularly this Item 7 Managements Discussion and Analysis of Financial
Condition and Results of Operations and Part I, Items 1 and 2 Business and Properties contain
certain forward-looking statements and other statements that are not historical facts concerning,
among other things, market conditions, the demand for marine support and transportation services
and future capital expenditures. Such statements are subject to certain risks, uncertainties and
assumptions, including, without limitation, operational risk, catastrophic or adverse sea or
weather conditions, dependence on the oil and natural gas industry, volatility in oil and gas
prices, delay or cost overruns on construction projects or insolvency of the shipbuilders, lack of
shipyard or equipment availability, ongoing capital expenditure requirements, uncertainties
surrounding environmental and government regulation, risks relating to compliance with the Jones
Act, risks relating to leverage, risks of foreign operations, risk of war, sabotage, piracy or
terrorism, assumptions concerning competition, and risks of currency fluctuations and other
matters. 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. Such statements are subject
to risks and uncertainties, including the risk factors discussed above and in Part I, Item 1A Risk
Factors, general economic and business conditions, the business opportunities that may be
presented to and pursued by us, changes in law or regulations and other factors, many of which are
beyond our control. There can be no assurance that we have accurately identified and properly
weighed all
39
Table of Contents
of the factors which 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. Important
factors that could cause actual results to differ materially from our expectations are disclosed
within Part I, Item 1A Risk Factors, this Item 7, Managements Discussion and Analysis of
Financial Condition and Results of Operations, and Part I, Items 1 and 2 Business and Properties
and elsewhere in this Form 10-K.
ITEM 7A. Quantitative and Qualitative Disclosures about Market Risk
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, 2010, our derivative holdings consist of an interest rate swap agreement. Refer to
Note 1 Nature of Operations and Summary of Significant Accounting PoliciesFair Value of
Financial Instruments in our Notes to Consolidated Financial Statements included in Part II, Item
8 for additional information on financial instruments.
Foreign Currency Risk
The functional currency for the majority of our international operations is that operations
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 loses 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
currency. Other information required under this Item 7A has been provided in Part II, Item 7
Managements Discussion and Analysis of Financial Condition and Results of Operations Currency
Fluctuations and Inflation and Part I, Items 1 and 2 Business and Properties New Vessel
Construction, Acquisition and Divestiture Program, and Drydocking Obligations. 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 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.
We do hedge firmly committed, anticipated transactions in the normal course of business and
these contracts are designated and qualify as cash flow hedges. Changes in the fair value of
derivatives that are designated as cash flow 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,
2010, 2009 and 2008 were $0.1 million, $2.2 million, and $2.0 million, respectively.
Interest Rates
We are and will be 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, 2010 and 2009 that are sensitive to changes in interest rates. The floating portion
of our variable debt is based on LIBOR.
We utilize interest rate swap agreements to fix a portion of our exposure to floating interest
rates. These agreements are classified as cash flow hedges and we report changes in the fair value
of these cash flow hedges in accumulated other comprehensive income. At December 31, 2010, we had
a $100.0 million interest rate swap agreement that fixed the interest rate for a portion of our
Facility Agreement at 4.145% and which matures on December 31, 2012. The consolidated balance sheet
classifies cash flow hedges within other long-term liabilities and as of December 31, 2010, the
fair value of the interest rate swap was $6.8 million. We expect to reclassify $1.7 million of
deferred loss on the current interest rate swap to interest expense during the next 12 months.
40
Table of Contents
2011 | 2012 | 2013 | 2014 | 2015 | Thereafter | |||||||||||||||||||
(Dollar amounts in thousands) | ||||||||||||||||||||||||
2010 Long-term Debt: |
||||||||||||||||||||||||
Fixed rate |
$ | - | $ | - | $ | - | $ | 160,000 | $ | - | $ | - | ||||||||||||
Average interest rate |
7.75% | 7.75% | 7.75% | 7.75% | - | - | ||||||||||||||||||
Variable rate |
$ | 33,333 | $ | 133,334 | $ | - | $ | - | $ | - | $ | - | ||||||||||||
Average interest rate |
2.49% | 2.60% | - | - | - | - | ||||||||||||||||||
2010 Notional Value: |
||||||||||||||||||||||||
Interest Rate Swap-Variable to Fixed |
$ | 100,000 | $ | 100,000 | $ | - | $ | - | $ | - | ||||||||||||||
Average pay rate |
4.15% | 4.15% | - | - | - | |||||||||||||||||||
Average receive rate |
2.49% | 2.60% | - | - | - | |||||||||||||||||||
2010 | 2011 | 2012 | 2013 | 2014 | Thereafter | |||||||||||||||||||
(Dollar amounts in thousands) | ||||||||||||||||||||||||
2009 Long-term Debt: |
||||||||||||||||||||||||
Fixed rate |
$ | - | $ | - | $ | - | $ | - | $ | 160,000 | $ | - | ||||||||||||
Average interest rate |
7.75% | 7.75% | 7.75% | 7.75% | 7.75% | - | ||||||||||||||||||
Variable rate |
$ | 33,333 | $ | 33,333 | $ | 133,334 | $ | - | $ | - | $ | - | ||||||||||||
Average interest rate |
0.97% | 2.49% | 2.60% | - | - | - | ||||||||||||||||||
2009 Notional Value: |
||||||||||||||||||||||||
Interest Rate Swap-Variable to Fixed |
$ | 100,000 | $ | 100,000 | $ | 100,000 | $ | - | $ | - | $ | - | ||||||||||||
Average pay rate |
4.15% | 4.15% | 4.15% | - | - | - | ||||||||||||||||||
Average receive rate |
0.97% | 2.49% | 2.60% | - | - | - |
Our fixed rate 7.75% Senior Notes outstanding at December 31, 2010, subjects us to risks
related to changes in the fair value of the debt and exposes us to potential gains or losses if we
were to repay or refinance such debt. A 1% change in market interest rates would increase or
decrease the fair value of our fixed rate debt by approximately $4.9 million.
The fair value of our 7.75% Senior Notes as compared to the carrying value at December 31,
2010 and 2009, was as follows:
December 31, | ||||||||||||||||
2010 | 2009 | |||||||||||||||
Carrying | Fair | Carrying | Fair | |||||||||||||
Value | Value | Value | Value | |||||||||||||
(In millions) | ||||||||||||||||
7.75% Senior Notes due 2014 |
$ | 159.8 | $ | 164.5 | $ | 159.6 | $ | 159.6 |
41
Table of Contents
ITEM 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of GulfMark Offshore, Inc. and its subsidiaries:
We have audited the accompanying consolidated balance sheets of GulfMark Offshore, Inc. and
its subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of
operations, stockholders equity, comprehensive income, and cash flows for each of the years in the
three-year period ended December 31, 2010. These consolidated financial statements are the
responsibility of the Companys 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 audits to
obtain reasonable assurance about whether the consolidated 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 consolidated financial position of GulfMark Offshore, Inc. and its
subsidiaries as of December 31, 2010 and 2009, and the consolidated results of their operations and
their cash flows for each of the years in the three-year period ended December 31, 2010, in
conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the effectiveness of GulfMark Offshore, Inc. and its subsidiaries
internal control over financial reporting as of December 31, 2010, 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 24, 2011 expressed an unqualified
opinion.
UHY LLP
Houston, Texas
February 24, 2011
Houston, Texas
February 24, 2011
42
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GULFMARK OFFSHORE, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, | ||||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 97,195 | $ | 92,079 | ||||
Trade accounts receivable, net of allowance for doubtful accounts of $283 and $334, respectively |
66,714 | 76,554 | ||||||
Other accounts receivable |
10,326 | 4,235 | ||||||
Prepaid expenses and other current assets |
16,645 | 12,206 | ||||||
Total current assets |
190,880 | 185,074 | ||||||
Vessels, equipment, and other fixed assets at cost, net of accumulated depreciation of $282,395 and $239,518, respectively |
1,191,280 | 1,164,067 | ||||||
Construction in progress |
2,920 | 40,349 | ||||||
Goodwill |
31,987 | 129,849 | ||||||
Fair value hedges |
- | 6,886 | ||||||
Intangibles, net of accumulated amortization of $7,208 and $4,325, respectively |
27,390 | 30,273 | ||||||
Deferred costs and other assets |
19,993 | 9,161 | ||||||
Total assets |
$ | 1,464,450 | $ | 1,565,659 | ||||
LIABILITIES AND STOCKHOLDERS EQUITY |
||||||||
Current liabilities: |
||||||||
Current portion of long-term debt |
$ | 33,333 | $ | 33,333 | ||||
Accounts payable |
15,130 | 19,519 | ||||||
Income and other taxes payable |
4,066 | 4,815 | ||||||
Accrued personnel costs |
23,417 | 26,312 | ||||||
Accrued interest expense |
5,757 | 5,966 | ||||||
Other accrued liabilities |
7,676 | 7,088 | ||||||
Total current liabilities |
89,379 | 97,033 | ||||||
Long-term debt |
293,095 | 326,361 | ||||||
Long-term income taxes: |
||||||||
Deferred tax liabilities |
102,509 | 112,960 | ||||||
Other income taxes payable |
19,400 | 24,029 | ||||||
Fair value hedges |
- | 6,886 | ||||||
Cash flow hedges |
6,807 | 6,422 | ||||||
Other liabilities |
7,303 | 4,500 | ||||||
Stockholders equity: |
||||||||
Preferred stock, no par value; 2,000 shares authorized; no shares issued |
- | - | ||||||
Class A Common stock, $0.01 par value; 60,000 shares authorized; 26,269 and 25,906 shares issued and 26,013 and 25,697
shares outstanding, respectively; Class B Common Stock $.01 par value; 60,000 shares authorized; no shares issued |
259 | 255 | ||||||
Additional paid-in capital |
370,218 | 362,022 | ||||||
Retained earnings |
536,468 | 571,213 | ||||||
Accumulated other comprehensive income |
39,137 | 54,005 | ||||||
Treasury stock, at cost |
(7,228 | ) | (5,865 | ) | ||||
Deferred compensation expense |
7,103 | 5,838 | ||||||
Total stockholders equity |
945,957 | 987,468 | ||||||
Total liabilities and stockholders equity |
$ | 1,464,450 | $ | 1,565,659 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
43
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GULFMARK OFFSHORE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(In thousands, except per share amounts) | ||||||||||||
Revenue |
$ | 359,766 | $ | 388,871 | $ | 411,740 | ||||||
Costs and expenses: |
||||||||||||
Direct operating expenses |
170,638 | 166,183 | 143,925 | |||||||||
Drydock expense |
22,182 | 15,696 | 11,319 | |||||||||
General and administrative expenses |
44,029 | 43,700 | 40,244 | |||||||||
Depreciation and amortization |
56,959 | 53,044 | 44,300 | |||||||||
Impairment charge |
97,665 | 46,247 | - | |||||||||
Gain on sale of assets |
(5,095 | ) | (5,552 | ) | (34,811 | ) | ||||||
Total costs and expenses |
386,378 | 319,318 | 204,977 | |||||||||
Operating income (loss) |
(26,612 | ) | 69,553 | 206,763 | ||||||||
Other income (expense): |
||||||||||||
Interest expense |
(21,693 | ) | (20,281 | ) | (14,291 | ) | ||||||
Interest income |
985 | 377 | 1,446 | |||||||||
Foreign currency gain (loss) and other |
(126 | ) | (1,153 | ) | 1,609 | |||||||
Total other expense |
(20,834 | ) | (21,057 | ) | (11,236 | ) | ||||||
Income (loss) before income taxes |
(47,446 | ) | 48,496 | 195,527 | ||||||||
Income tax (provision) benefit |
12,701 | 2,087 | (11,743 | ) | ||||||||
Net income (loss) |
$ | (34,745 | ) | $ | 50,583 | $ | 183,784 | |||||
Earnings (loss) per share: |
||||||||||||
Basic |
$ | (1.36 | ) | $ | 2.01 | $ | 7.74 | |||||
Diluted |
$ | (1.36 | ) | $ | 1.99 | $ | 7.56 | |||||
Weighted average shares outstanding: |
||||||||||||
Basic |
25,519 | 25,151 | 23,737 | |||||||||
Diluted |
25,519 | 25,446 | 24,319 | |||||||||
The accompanying notes are an integral part of these consolidated financial statements.
44
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GULFMARK OFFSHORE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
For the Years Ended December 31, 2010, 2009 and 2008
(In thousands)
For the Years Ended December 31, 2010, 2009 and 2008
(In thousands)
Common | Accumulated | Deferred | ||||||||||||||||||||||||||||||
Stock at | Additional | Other | Compen- | Total | ||||||||||||||||||||||||||||
$0.01 Par | Paid-in | Retained | Comprehensive | sation | Stockholders | |||||||||||||||||||||||||||
Value | Capital | Earnings | Income (loss) | Treasury Stock | Expense | Equity | ||||||||||||||||||||||||||
Share | ||||||||||||||||||||||||||||||||
Shares | Value | |||||||||||||||||||||||||||||||
Balance at December 31, 2007 |
$ | 227 | $ | 211,004 | $ | 336,846 | $ | 128,308 | (172 | ) | $ | (4,200 | ) | $ | 3,906 | $ | 676,091 | |||||||||||||||
Net income |
- | - | 183,784 | - | - | - | - | 183,784 | ||||||||||||||||||||||||
Issuance of common stock |
22 | 139,757 | - | - | - | - | - | 139,779 | ||||||||||||||||||||||||
Exercise of stock options |
1 | 2,082 | - | - | - | - | - | 2,083 | ||||||||||||||||||||||||
Deferred compensation plan |
- | - | - | - | (39 | ) | (2,652 | ) | 1,223 | (1,429 | ) | |||||||||||||||||||||
Loss on cash flow hedge, net of tax |
- | - | - | (6,062 | ) | - | - | - | (6,062 | ) | ||||||||||||||||||||||
Translation adjustment |
- | - | - | (139,403 | ) | - | - | - | (139,403 | ) | ||||||||||||||||||||||
Balance at December 31, 2008 |
250 | 352,843 | 520,630 | (17,157 | ) | (211 | ) | (6,852 | ) | 5,129 | 854,843 | |||||||||||||||||||||
Net income |
- | - | 50,583 | - | - | - | - | 50,583 | ||||||||||||||||||||||||
Issuance of common stock |
3 | 8,523 | - | - | - | - | - | 8,526 | ||||||||||||||||||||||||
Exercise of stock options |
2 | 1,743 | - | - | - | - | - | 1,745 | ||||||||||||||||||||||||
Deferred compensation plan |
- | (1,087 | ) | - | - | 2 | 987 | 709 | 609 | |||||||||||||||||||||||
Gain on cash flow hedge, net of tax |
- | - | - | 3,081 | - | - | - | 3,081 | ||||||||||||||||||||||||
Translation adjustment |
- | - | - | 68,081 | - | - | - | 68,081 | ||||||||||||||||||||||||
Balance at December 31, 2009 |
255 | 362,022 | 571,213 | 54,005 | (209 | ) | (5,865 | ) | 5,838 | 987,468 | ||||||||||||||||||||||
Net income |
- | - | (34,745 | ) | - | - | - | - | (34,745 | ) | ||||||||||||||||||||||
Issuance of common stock |
2 | 6,224 | - | - | - | - | - | 6,226 | ||||||||||||||||||||||||
Exercise of stock options |
2 | 1,836 | - | - | - | - | - | 1,838 | ||||||||||||||||||||||||
Deferred compensation plan |
- | 136 | - | - | (47 | ) | (1,363 | ) | 1,265 | 38 | ||||||||||||||||||||||
Loss on cash flow hedge, net of tax |
- | - | - | (722 | ) | - | - | - | (722 | ) | ||||||||||||||||||||||
Translation adjustment |
- | - | - | (14,146 | ) | - | - | - | (14,146 | ) | ||||||||||||||||||||||
Balance at December 31, 2010 |
$ | 259 | $ | 370,218 | $ | 536,468 | $ | 39,137 | (256 | ) | $ | (7,228 | ) | $ | 7,103 | $ | 945,957 | |||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
45
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GULFMARK OFFSHORE, INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2010, 2009 and 2008
For the Years Ended December 31, 2010, 2009 and 2008
Year Ended December 31, | ||||||||||||||
2010 | 2009 | 2008 | ||||||||||||
(In thousands) | ||||||||||||||
Net income (loss) |
$ | (34,745 | ) | $ | 50,583 | $ | 183,784 | |||||||
Comprehensive income: |
||||||||||||||
Gain (loss) on cash flow hedge, net of tax |
(722 | ) | 3,081 | (6,062 | ) | |||||||||
Foreign currency gain (loss) |
(14,146 | ) | 68,081 | (139,403 | ) | |||||||||
Total comprehensive
income (loss) |
$ | (49,613 | ) | $ | 121,745 | $ | 38,319 | |||||||
The accompanying notes are an integral part of these consolidated financial statements.
46
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GULFMARK OFFSHORE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
Cash flows from operating activities: |
||||||||||||
Net income |
$ | (34,745 | ) | $ | 50,583 | $ | 183,784 | |||||
Adjustments to reconcile net income from operations to net
cash provided by operations |
||||||||||||
Depreciation and amortization |
56,959 | 53,044 | 44,300 | |||||||||
Amortization of deferred financing costs |
1,598 | 780 | 711 | |||||||||
Amortization of stock-based compensation |
5,670 | 7,115 | 5,853 | |||||||||
Provision for doubtful accounts receivable, net of write offs |
(1 | ) | (73 | ) | 336 | |||||||
Deferred income tax provision (benefit) |
(8,371 | ) | (3,459 | ) | 7,225 | |||||||
Gain on sale of assets |
(5,095 | ) | (5,552 | ) | (34,811 | ) | ||||||
Impairment charge |
97,665 | 46,247 | - | |||||||||
Foreign currency transaction loss |
1,195 | 2,901 | 3,123 | |||||||||
Change in operating assets and liabilities |
||||||||||||
Accounts receivable |
3,287 | 29,054 | (6,631 | ) | ||||||||
Prepaids and other |
(1,775 | ) | (2,286 | ) | 1,095 | |||||||
Accounts payable |
(4,118 | ) | 2,781 | (8,259 | ) | |||||||
Other accrued liabilities and other |
(20,695 | ) | (10,090 | ) | 8,475 | |||||||
Net cash provided by operating activities |
91,574 | 171,045 | 205,201 | |||||||||
Cash flows from investing activities: |
||||||||||||
Purchases of vessels, equipment and other fixed assets |
(73,439 | ) | (77,438 | ) | (108,626 | ) | ||||||
Proceeds from disposition of equipment |
19,582 | 9,239 | 43,432 | |||||||||
Cash received with acquisition of business |
- | - | 31,028 | |||||||||
Consideration paid for acquired business |
- | - | (152,621 | ) | ||||||||
Net cash used in investing activities |
(53,857 | ) | (68,199 | ) | (186,787 | ) | ||||||
Cash flows from financing activities: |
||||||||||||
Proceeds from secured credit facilities |
- | 200,000 | - | |||||||||
Repayment of secured credit facilities |
(33,334 | ) | (238,035 | ) | (42,156 | ) | ||||||
Proceeds from revolving loan facility |
51,000 | - | 163,399 | |||||||||
Repayment of revolving loan facility |
(51,000 | ) | (84,250 | ) | (65,135 | ) | ||||||
Debt refinancing cost |
(2,000 | ) | (278 | ) | - | |||||||
Proceeds from exercise of stock options |
1,838 | 718 | 163 | |||||||||
Proceeds from issuance of stock |
659 | 1,595 | 483 | |||||||||
Net cash provided by (used in) financing activities |
(32,837 | ) | (120,250 | ) | 56,754 | |||||||
Effect of exchange rate changes on cash |
236 | 8,722 | (14,526 | ) | ||||||||
Net increase (decrease) in cash and cash equivalents |
5,116 | (8,682 | ) | 60,642 | ||||||||
Cash and cash equivalents at beginning of year |
92,079 | 100,761 | 40,119 | |||||||||
Cash and cash equivalents at end of year |
$ | 97,195 | $ | 92,079 | $ | 100,761 | ||||||
Supplemental cash flow information: |
||||||||||||
Interest paid, net of interest capitalized |
$ | 21,285 | $ | 20,010 | $ | 12,590 | ||||||
Income taxes paid, net |
$ | 4,712 | $ | 3,438 | $ | 3,294 | ||||||
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 support 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.
On February 23, 2010, we reorganized the Company. The Reorganization was designed to prevent
certain situations from occurring that could jeopardize our ability to engage in Coastwise Trade.
See Reorganization in Note 11.
Principles of Consolidation
Our consolidated financial statements include our accounts and those of our majority-owned
subsidiaries. All significant intercompany 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 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 then
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 assets estimated useful life. In 2010, 2009, and 2008,
interest of $1.4 million, $3.6 million, and $8.5 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 2010, 2009 and 2008, are $20.6 million, $20.1 million, and $16.7 million,
respectively, of costs for maintenance and repairs.
Goodwill and Intangibles
At December 31, 2009, our goodwill consisted of $97.7 million related to an acquisition in our
Americas region and $32.1 million related to acquisitions in the North Sea region. 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 the second quarter of 2010, we assessed our Americas region goodwill for impairment and, as
a result, recorded a $97.7 million impairment charge, reflecting all of our Americas region
goodwill. See Note 2 for a discussion of the goodwill impairment charge.
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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 assets
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 managements best
estimate based on currently available information and reasonable and supportable assumptions. Any
impairment recognized is permanent and may not be restored. We did not record any significant
impairment write-downs of our long-lived assets during 2010 or 2008. See Note 2 for discussion of
an impairment of assets under construction in the first quarter of 2009.
Fair Value of Financial Instruments
As of December 31, 2010, our financial instruments consist primarily of accounts receivable
and payable (which are stated at fair value), long-term debt and an interest rate swap for a
portion of the Facility Agreement.
As of December 31, 2009, we had forward currency exchange contracts that were designated as
fair value hedges and were highly effective, as the terms of the forward contracts were the same as
the purchase commitments under a new build contract. Any gains or losses resulting from changes in
fair value were recognized in income with an offsetting adjustment to income for changes in the
fair value of the hedged item such that there was no net impact on the statement of operations. As
of December 31, 2010, no contracts remained open under such agreements.
We also had interest rate swap agreements that hedged the interest rate associated with a
portion of our previous senior indebtedness. We reported changes in the fair value of these cash
flow hedges in accumulated other comprehensive income. On December 17, 2009 we entered into the
$200.0 million Facility Agreement (See Note 6) and terminated the existing senior indebtedness and
the swaps associated with that debt. Concurrently, we entered into an interest rate swap agreement
for approximately $100.0 million of the Facility Agreement indebtedness that has fixed the interest
rate at 4.145%. The interest rate swap is accounted for as cash flow hedge. We report changes in
the fair value of the cash flow hedges in accumulated other comprehensive income. The consolidated
balance sheet contains a cash flow hedge reflecting the fair value of the interest rate swap, which
was $6.8 million at December 31, 2010 based on expected cash inflows and outflows associated with
the contracts. We expect to reclassify $3.1 million of deferred loss related to the interest rate
swaps to interest expense during the next 12 months.
In addition, when we terminated the interest rate swaps discussed above, there was a $4.3
million balance remaining in other comprehensive income representing expected future interest
payments. Of this amount, $0.1 million was amortized to interest expense in 2009, $2.4 million was
amortized to interest expense in 2010 and the remaining $1.8 million will be amortized into
interest expense through December 31, 2012 based on forecasted payments as of the settlement date.
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 deferred tax assets and liabilities for the expected future tax consequences of
events that have been recognized in the financial statements or tax returns. 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 in the years in which the differences are expected to reverse. The likelihood and amount
of future taxable income and tax planning strategies
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are included in the criteria used to determine the timing and amount of tax benefits
recognized for net operating loss and tax credit carryforwards in the consolidated financial
statements.
In addition, we also account for uncertainty in income taxes by determining 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. 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.
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, 2010, 2009 and 2008, we reported net foreign
currency losses in the amount of $0.1 million, $2.2 million and $2.0 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
managements judgment as to the customers ability to pay are considered in determining whether an
allowance is necessary. Historically, write-offs for doubtful accounts have been insignificant. In
2010, 2009 and 2008, no single customer accounted for 10% or more of total consolidated revenue.
Stock-Based Compensation
We account for stock-based compensation using the modified prospective application method
where compensation cost will be recognized related to new awards and to awards modified,
repurchased, or cancelled after the required effective date. Additionally, compensation cost for
portions of awards for which the requisite service has not been rendered that are outstanding at
January 1, 2006 shall be recognized as if the requisite service is rendered on or after the
required effective date. At January 1, 2006, all of our stock option awards were fully vested.
Under the modified prospective method, vested equity awards outstanding at the effective date
create no additional compensation expense. Only new awards granted after January 1, 2006 would
continue to be measured and charged to expense over remaining requisite service. 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 common stock at 85% of the fair market value of
the common stock under a qualified plan as defined by Section 423 of the Internal Revenue Service.
The plan has a look-back option that establishes the purchase price as an amount based on the
lesser of the common stocks 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.
Pro forma information regarding net income and earnings per share, or EPS, and has been
determined as if we had accounted for our employee stock options under the fair-value method
described above. The last granted stock options were in October 2003. The fair value calculations
at the date of grant using the Black-Scholes option pricing model were calculated with the
following weighted average assumptions:
2003 | ||||
Risk-free interest rate |
2.2% | |||
Volatility factor of stock price |
0.28 | |||
Dividends |
- | |||
Option life |
4 years | |||
Calculated fair value per share |
$ | 3.58 |
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Earnings Per Share
Basic EPS is computed by dividing net income (loss) by the weighted average number of shares
of 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, 2010, 2009 and 2008 is as follows (in
thousands, except per share amounts):
Year ended December 31, 2010 | ||||||||||||
Net | Weighted | Per Share | ||||||||||
Loss | Average Shares | Amount | ||||||||||
Loss per share, basic |
$ | (34,745 | ) | 25,519 | $ | (1.36 | ) | |||||
Dilutive effect of common
stock options |
- | - | ||||||||||
Loss per share, diluted |
$ | (34,745 | ) | $ | 25,519 | $ | (1.36 | ) | ||||
Year ended December 31, 2009 | ||||||||||||
Net | Weighted | Per Share | ||||||||||
Income | Average Shares | Amount | ||||||||||
Income per share, basic |
$ | 50,583 | 25,151 | $ | 2.01 | |||||||
Dilutive effect of common
stock options |
- | 295 | ||||||||||
Income per share, diluted |
$ | 50,583 | $ | 25,446 | $ | 1.99 | ||||||
Year ended December 31, 2008 | ||||||||||||
Net | Weighted | Per Share | ||||||||||
Income | Average Shares | Amount | ||||||||||
Income per share, basic |
$ | 183,784 | 23,737 | $ | 7.74 | |||||||
Dilutive effect of common
stock options |
- | 582 | ||||||||||
Income per share, diluted |
$ | 183,784 | 24,319 | $ | 7.56 | |||||||
Reclassifications
Certain reclassifications of previously reported information have been made to conform to the
current year presentation.
New Accounting Pronouncements
In June 2009, the Financial Accounting Standards Board (FASB) amended its accounting
guidance on Accounting Standards Codification (ASC) Topic 810, Consolidations relating to the
consolidation of variable interest entities (VIE). Among other things, the new guidance requires
a qualitative rather than a quantitative assessment to determine the primary beneficiary of a VIE
based on whether the entity (1) has the power to direct matters that most significantly impact the
activities of the VIE and (2) has the obligation to absorb losses or the right to receive benefits
of the VIE that could potentially be significant to the VIE. In addition, the amended guidance
requires an ongoing reconsideration of the primary beneficiary. The provisions of this new guidance
were effective as of the beginning of our 2010 fiscal year, and the adoption did not have a
material impact on our consolidated financial statements.
In April 2010, the FASB issued additional guidance relating to the ASC Topic 718, Compensation
Stock Compensation to clarify classification of an employee stock-based payment award when the
exercise price is denominated in the currency of a market in which the underlying equity security
trades. This guidance becomes effective for us on January 1, 2011 and will not have a material
effect on our consolidated financial statements.
In January 2010, the FASB amended ASC Topic 820, Fair Value Measurement and Disclosure to
require additional disclosures on (1) transfers between levels, (2) Level 3 activity presented on a
gross basis, (3) valuation techniques, and (4) inputs into the valuation. The additional disclosure
has no impact on our consolidated financial statements.
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(2) IMPAIRMENT CHARGES
Goodwill
At December 31, 2009, our goodwill consisted of $97.7 million related to an acquisition in our
Americas region and $32.1 million related to acquisitions in the North Sea region. 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 the second quarter of 2010, we assessed our Americas region goodwill for impairment. In
our assessment, we evaluated the impact on the segments fair value due to the recent events in the
U.S. Gulf Of Mexico relating to the Macondo Incident, the resulting oil spill and the drilling
moratorium. The U.S. Gulf of Mexico market is generally divided into two distinct areas:
shallow-water and deepwater. The deepwater market has historically been less volatile and more
profitable. Our long-term strategy has been to become more focused on the deepwater business. The
ban on new drilling permits issued on April 30 and the deepwater drilling moratorium issued on May
30, 2010 negatively impacted our outlook for deepwater drilling. Based on these factors, which were
incorporated into our evaluations and testing as prescribed under U.S. GAAP, we determined that an
impairment of our Americas region goodwill existed. As a result, we recorded a $97.7 million
impairment charge as of June 30, 2010, reflecting all of our Americas region goodwill. The
non-cash charge does not impact our liquidity or debt covenant compliance.
Assets Under Construction
In March 2009, we notified a shipyard building three of the vessels in our new build program
that they were in default under the construction contract. The default arose as a result of
non-performance under the terms of the contract caused by financial difficulties of the shipyard.
Construction on these vessels has stopped and we are evaluating our remedies under the contract and
under applicable law. We determined that we had a material impairment and recognized a charge of
$46.2 million in the first quarter of 2009 pertaining to the construction in progress related to
this contract. That charge represented the full amount of our investment in these vessels. The
shipyard building the three vessels is in Chapter 11 bankruptcy proceedings.
(3) RIGDON ACQUISITION
On July 1, 2008, we acquired 100% of the membership interests of Rigdon Marine Holdings,
L.L.C. and 100% of the outstanding common stock of Rigdon Marine Corporation for consideration of
$554.7 million, consisting of $152.6 million in cash and approximately 2.1 million shares of
GulfMark Offshore, Inc. common stock valued at $133.2 million, plus the assumption of $268.9
million in debt (the Rigdon Acquisition).
The pro forma effect of the acquisition and the associated financing on the historical results
for the year ended December 31, 2008 is presented in the following table (in thousands, except
earnings per share):
Year Ended | ||||
December 31, | ||||
2008 | ||||
Revenue |
$ | 466,787 | ||
Operating income |
226,887 | |||
Net income |
188,939 | |||
Basic earnings per share |
$ | 7.96 |
(4) VESSEL ACQUISITIONS AND DISPOSITIONS
During 2010, we have taken delivery of three vessels that were under construction at December
31, 2009. As of February 24, 2011, we have one vessel that is being held for sale that is not
included in our fleet numbers and have no vessels under construction. In the second quarter of
2010, we sold one of our Americas vessels and recorded a $0.1 million loss. At the end of the
third quarter of 2010, we sold one of our North Sea vessels and recorded a $5.2 million gain.
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The following tables illustrate the details of the vessels added, disposed of and classified
as held for sale since December 31, 2009.
Vessel Additions Since December 31, 2009 | ||||||||||||||
Year | Length | Month | ||||||||||||
Vessel | Region | Type (1) | Built | (feet) | BHP (2) | DWT (3) | Delivered | |||||||
North Purpose |
N. Sea | PSV | 2010 | 284 | 10,738 | 4,850 | Feb-10 | |||||||
Sea Valiant |
SEA | AHTS | 2010 | 230 | 10,188 | 2,301 | Jun-10 | |||||||
Sea Victor |
SEA | AHTS | 2010 | 230 | 10,188 | 2,301 | Jul-10 |
1) | AHTS - Anchor handling, towing and supply vessel |
|
FSV - Fast supply vessel |
||
PSV - Platform supply vessel |
||
SpV - Specialty vessel, including towing and oil response |
||
SmAHTS - Small anchor handling, towing and supply vessel |
||
2) | BHP - Breakhorse power |
|
3) | DWT - Deadweight tons |
Vessels Disposed of Since December 31, 2009 | ||||||||||||||
Year | Length | Month | ||||||||||||
Vessel | Region | Type | Built | (feet) | BHP | DWT | Disposed | |||||||
Seapower |
Americas | SpV | 1974 | 222 | 7,040 | 1,205 | May-10 | |||||||
North Traveller |
N.Sea | LgPSV | 1998 | 221 | 5,450 | 3,115 | Sep-10 |
Vessels Held for Sale (Laid Up) | ||||||||||||
Year | Length | |||||||||||
Vessel | Region | Type | Built | (feet) | BHP | DWT | ||||||
Clwyd Supporter |
N. Sea | SpV | 1984 | 266 | 10,700 | 1,350 |
(5) GOODWILL AND INTANGIBLES
Changes to goodwill are as follows:
2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
Balance, January 1, |
$ | 129,849 | $ | 123,981 | $ | 34,264 | ||||||
Adjustment related to acquisition |
- | 463 | 97,202 | |||||||||
Impact on foreign currency
translation and adjusment |
(197 | ) | 5,405 | (7,485 | ) | |||||||
Impairment (see Note 2) |
(97,665 | ) | - | - | ||||||||
Balance, December 31, |
$ | 31,987 | $ | 129,849 | $ | 123,981 | ||||||
Intangible assets of $27.4 million, net of accumulated amortization of $7.2 million, as of
December 31, 2010 are recorded at cost and are amortized on a straight-line basis over the years
expected to be benefited, currently estimated to be 10 years. Amortization expense related to
intangible assets was $2.9 million for the years ended December 31, 2010 and 2009 and $1.4 million
for the year ended December 31, 2008. Annual amortization expense related to existing intangible
assets for years 2011 through 2015 is expected to be $2.9 million per year.
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(6) LONG-TERM DEBT
Our long-term debt at December 31, 2010 and 2009 consisted of the following:
2010 | 2009 | |||||||
(In thousands) | ||||||||
7.75% Senior Notes due 2014 |
$ | 160,000 | $ | 160,000 | ||||
Facility Agreement |
166,667 | 200,000 | ||||||
Secured Reducing Revolving Loan Facility |
- | - | ||||||
$ | 326,667 | $ | 360,000 | |||||
Less: Current maturities of long-term debt |
(33,333 | ) | (33,333 | ) | ||||
Debt discount, net |
(239 | ) | (306 | ) | ||||
Total |
$ | 293,095 | $ | 326,361 | ||||
The following is a summary of scheduled debt maturities by year:
Year | Debt Maturity | |||
(In thousands) | ||||
2011 |
33,333 | |||
2012 |
133,334 | |||
2013 |
- | |||
2014 |
160,000 | |||
2015 |
- | |||
Total |
$ | 326,667 | ||
Senior Notes
On July 21, 2004, we issued $160.0 million aggregate principal amount of 7.75% senior notes
due 2014. The 7.75% senior notes pay interest semi-annually on January 15 and July 15. The 7.75%
senior notes may be called beginning on July 15, 2011 at a redemption price of 101.292% and on July
15, 2012 and thereafter at 100% of the principal amount, plus accrued interest.
At December 31, 2010, the fair value of these notes, based on quoted market prices, was
approximately $164.5 million, compared to a carrying amount of $159.8 million.
Facility Agreement
On December 17, 2009, one of our wholly-owned subsidiaries (the Borrower) entered into a
$200.0 million facility agreement (the Facility Agreement) with The Royal Bank of Scotland plc
(RBS). The termination date under the Facility Agreement is December 31, 2012 and amounts
borrowed are repayable in quarterly installments of $8.3 million with a final installment of
$108.33 million. Loans under the Facility Agreement bear interest at the three month LIBOR rate,
plus a margin of 2.5% per annum. The Facility Agreement is secured by certain vessels and GulfMark
Management, Inc., the Borrowers parent, has pledged all of the shares of common stock in the
Borrower to the agent, on behalf of the lender, as security for the Facility Agreement.
The Facility Agreement is secured by certain vessels. We have unconditionally guaranteed all
existing and future indebtedness and liabilities of the Borrower arising under the Facility
Agreement and other loan documents. Such guarantee also covers obligations of the Borrower arising
under any interest rate swap contract and other security documentation related to the Facility
Agreement. The collateral that secures the loans under the Facility Agreement will secure all of
the Borrowers obligations under any hedging agreements between the Borrower and RBS.
The Facility Agreement requires compliance with financial covenants. The Facility Agreement
also contains customary representations, warranties and affirmative and negative covenants. As set
forth in the Facility Agreement, there are several occurrences that constitute an event of default,
including without limitation, defaults on payments of amounts borrowed under the Facility
Agreement, defaults on payments of other material indebtedness, bankruptcy or insolvency, a change
of control applicable to GulfMark or the Borrower, material unsatisfied judgments, the occurrence
of a material adverse change, and other customary events
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of default. Upon the occurrence of an event of default, RBS may terminate the Facility
Agreement, declare that all obligations under the Facility Agreement are due and payable and
exercise its rights with respect to the collateral under the Facility Agreement.
At December 31, 2010, we were in compliance with all covenants, and had $166.7 million
borrowed under the facility. At December 31, 2010, the fair value of borrowings under this facility
is considered to be book value as the interest is at market rates.
Revolving Loan Facility
We currently have a $175.0 million Secured Reducing Revolving Loan Facility with a syndicate
of financial institutions led by Den Norske Bank, as agent. The multi-currency facility is
structured as follows: $25.0 million allocated to GulfMark Offshore, Inc.; $60.0 million allocated
to Gulf Offshore N.S. Limited, a U.K. wholly owned subsidiary; $30.0 million allocated to GulfMark
Rederi AS, a Norwegian wholly owned subsidiary; and $60.0 million allocated to Gulf Marine Far East
Pte Ltd., a wholly owned Singapore subsidiary. The facility matures in 2013 and the maximum
availability begins to reduce in increments of $15.2 million every six months beginning in December
2011, with a final reduction of $129.5 million in June 2013. Security for the facility is provided
by first priority mortgages on certain vessels. The interest rate ranges from LIBOR plus a margin
of 0.7% to 0.9% depending on our EBITDA coverage ratio. The Secured Reducing Revolving Loan
Facility is subject to financial covenants. At December 31, 2010, we were in compliance with all
covenants and had no amounts drawn under this facility.
Other Debt
As part of the Rigdon Acquisition, we acquired the right to purchase a mortgaged vessel owned
by one of our joint ventures in the event of the joint ventures default on that mortgage
obligation. The purchase price of the vessel would be the outstanding balance on the mortgage,
which was $2.9 million at December 31, 2010.
(7) 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 ten year tonnage tax regimes and in late 2010 we renewed our U.K. tonnage tax
election through November 2020. Our qualified Singapore based vessels are exempt from Singapore
taxation through December 2017 with extensions available in certain circumstances beyond 2017. The
tonnage tax regimes provide for a tax based on the net tonnage weight of a qualified vessel. These
foreign tax beneficial structures 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.
In late 2007, Norway enacted legislation that created a new tonnage tax system from January
2007 forward and repealed the previous tonnage tax regime effective December 31, 2006 resulting in
a mandatory exit from Norways tonnage tax system or payment of tax at 28% of accumulated untaxed
pre-2007 profits. Accordingly, we recorded approximately $15.0 million Norwegian tax liability in
2007. Our liability for pre-2007 taxes was to be paid equally over ten years beginning in 2008. In
February 2010, the Norway Supreme Court ruled the 2007 tax legislation to be unconstitutional
retroactive taxation and we reversed our remaining tonnage tax liability and received a refund of
the pre-2007 tonnage taxes that had been paid in 2008 and 2009, which resulted in our recording an
approximately $15.0 million tax benefit in our 2010 tax provision. In June 2010, Norways Minister
of Finance published revised rules for the taxation of pre-2007 tonnage tax profits permitting a
qualified tonnage tax company to elect one of two systems, or methods, to determine and pay tax on
its untaxed shipping profits as of December 31, 2006. We decided to elect the simplified tax
system, which, beginning in 2011 requires three equal annual installment payments of the tax that
is calculated as ten percent (10%) of two-thirds of the untaxed tonnage tax profits. Under this
system, we recorded an approximately $4.9 million tax provision. The net result of the 2010
Norwegian tonnage tax law changes was a $10.1 million tax benefit recorded in our 2010 tax
provision. Our liability to settle under the simplified tax system is included in our December 31,
2010 balance sheet as approximately $1.6 million current income tax payable and approximately $3.3
million as other long term payable. Annually the subsequent years cash installment is classified
on our consolidated balance sheet as current income taxes payable, and the remainder is classified
on our consolidated balance sheet as other income taxes payable.
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 or that are otherwise tax exempt. 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 $7.2 million of such
foreign tax credit carryforwards that begin to expire in 2011. We also have certain foreign net
operating loss carryforwards that result in net deferred tax assets of approximately $2.3 million
for which we have established a valuation allowance. We have considered estimated future taxable
income
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in the relevant tax jurisdictions to utilize these tax credit and loss carryforwards 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.
Effective January 1, 2008, Mexico legislated a new revenue based tax, which in effect is an
alternative minimum tax payable to the extent that the new revenue based tax exceeds the current
income tax liability. These revenue based tax rates are16.5% for 2008, 17% for 2009 and 17.5% for
2010 and beyond. Effective January 1, 2010, Mexico enacted changes to corporate income tax rates as
follows: 2010 through 2012 30%; 2013 29%; and 2014 and beyond - 28%.
Income before income taxes attributable to domestic and foreign operations was (in thousands):
Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
U.S. |
$ | (121,938 | ) | $ | (66,854 | ) | $ | 7,109 | ||||
Foreign |
74,492 | 115,350 | 188,418 | |||||||||
$ | (47,446 | ) | $ | 48,496 | $ | 195,527 | ||||||
The components of our tax provision (benefit) attributable to income before income taxes are
as follows for the year ended December 31, (in thousands):
2010 | 2009 | 2008 | ||||||||||||||||||||||||||||||||||||||||||||||
Current | Deferred | Other (a) | Total | Current | Deferred | Other (a) | Total | Current | Deferred | Other (a) | Total | |||||||||||||||||||||||||||||||||||||
U.S. |
$ | 65 | $ | (7,519 | ) | $ | - | $ | (7,454 | ) | $ | 20 | $ | (2,988 | ) | $ | (254 | ) | $ | (3,222 | ) | $ | 432 | $ | 2,437 | $ | - | $ | 2,869 | |||||||||||||||||||
Foreign |
3,576 | (851 | ) | (7,972 | ) | $ | (5,247 | ) | 5,223 | (5,314 | ) | 1,226 | $ | 1,135 | 2,385 | 981 | 5,508 | 8,874 | ||||||||||||||||||||||||||||||
$ | 3,641 | $ | (8,370 | ) | $ | (7,972 | ) | $ | (12,701 | ) | $ | 5,243 | $ | (8,302 | ) | $ | 972 | $ | (2,087 | ) | $ | 2,817 | $ | 3,418 | $ | 5,508 | $ | 11,743 | ||||||||||||||||||||
(a) | Income tax effects determined under a more likely than not, or greater than 50%
probability, threshold. |
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:
2010 | 2009 | 2008 | ||||||||||
U.S. federal statutory income tax rate |
35.0% | 35.0% | 35.0% | |||||||||
Effect of foreign operations |
66.0 | (36.6 | ) | (29.3 | ) | |||||||
US state income taxes |
(0.7 | ) | 4.5 | - | ||||||||
Valuation allowance |
- | (9.2 | ) | 0.5 | ||||||||
Impairment |
(72.0 | ) | - | - | ||||||||
Other |
(1.5 | ) | 1.0 | (0.2 | ) | |||||||
Total |
26.8% | (4.3%) | 6.0% | |||||||||
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, 2010 and
2009 are as follows:
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December 31, | ||||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
Deferred tax assets |
||||||||
Accruals currently not deductible for tax
purposes |
$ | 26,083 | $ | 24,773 | ||||
Net operating loss carryforwards |
44,549 | 25,357 | ||||||
Foreign and other tax credit carryforwards |
10,686 | 11,793 | ||||||
81,318 | 61,923 | |||||||
Less valuation allowance |
(4,468 | ) | (5,192 | ) | ||||
Net deferred tax assets |
$ | 76,850 | $ | 56,731 | ||||
Deferred tax liabilities |
||||||||
Depreciation |
$ | (151,912 | ) | $ | (142,674 | ) | ||
Foreign income not currently recognizable |
- | - | ||||||
Other |
(27,447 | ) | (27,017 | ) | ||||
Total deferred tax liabilities |
$ | (179,359 | ) | $ | (169,691 | ) | ||
Net deferred tax liability |
$ | (102,509 | ) | $ | (112,960 | ) | ||
As of December 31, 2010 and 2009, the total net deferred tax liability of $102.5 million and
$113.0 million, respectively, is included in non-current liabilities in the consolidated balance
sheet. The net change in the total valuation allowance for the years ended December 31, 2010 and
2009 was a decrease of $0.7 million and a decrease of $4.6 million, respectively. As of December
31, 2010, we had net operating loss carryforwards, or NOLs, for income tax purposes totaling $115.1
million in the U.S., $10.6 million in Brazil, $5.9 million in Norway, and $4.6 million in Mexico
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 through 2029. The NOLs in
Mexico will begin to expire in 2016, however as a result of the Mexico legislation described above,
it is more likely than not that the Mexican NOLs will not be utilized and a $0.3 million valuation
allowance has been established for these NOLs. In addition, it is more likely than not that the
Norway NOLs will not be utilized and a full valuation allowance has been established for such NOLs.
Except for the amounts related to Brazilian temporary differences, it is also more likely than not
that the Brazilian NOLs will not be utilized and a $2.5 million valuation allowance has been
established for such NOLs. Based on future expected U.S. taxable income, in 2009 we reversed $4.5
million of valuation allowance previously recorded against U.S. foreign tax credits.
Currently, our intention is to permanently reinvest the unremitted earnings of our non-U.S.
subsidiaries. As a result, we have not provided for U.S. deferred taxes on the cumulative
unremitted earnings of $766.3 million at December 31, 2010. In addition, as of December 31, 2010,
we had $84.3 million of cash held by our foreign subsidiaries which is 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 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
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 $15.7 million at December 31, 2010 and $13.3 million at December 31, 2009.
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A reconciliation of the beginning and ending balances of the total amounts of gross
unrecognized tax benefits is as follows:
2010 | 2009 | |||||||
(in thousands) | ||||||||
Unrecognized tax benefits balance at January 1, |
$ | 10,786 | $ | 9,810 | ||||
Gross increases for tax positions taken in prior
years |
645 | 1,265 | ||||||
Gross decreases for tax positions taken in prior
years |
(795 | ) | (289 | ) | ||||
Decreases for settlements |
- | - | ||||||
Lapse of statute of limitations |
- | - | ||||||
Unrecognized tax benefits balance at December 31, |
$ | 10,636 | $ | 10,786 | ||||
We expect a foreign tax examination issue representing approximately $1.6 million of our
unrecognized tax benefits as of December 31, 2010 will be settled within twelve months. As of
December 31, 2010, we are under tax examination, or may be subject to examination in the U. S. for
years after 2001 and in seven major foreign tax jurisdictions with open years for one after 1999,
one after 2000, one after 2003, one after 2004, two after 2005 and one after the year 2006.
We accrue interest and penalties related to unrecognized tax benefits in our provision for
income taxes. At December 31, 2010, we had accrued interest and penalties related to unrecognized
tax benefits of $11.4 million. The amount of interest and penalties recognized in our tax provision
for the year ended December 31, 2010 was $1.6 million.
(8) COMMITMENTS AND CONTINGENCIES
At December 31, 2010, 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, 2010, 2009 and 2008 was $2.2 million, $2.0 million, and $1.8 million, respectively.
Future minimum rental commitments under these leases are as follows (in thousands):
Minimum Rental | ||||
Year | Commitments | |||
2011 |
1,664 | |||
2012 |
1,296 | |||
2013 |
938 | |||
2014 |
822 | |||
2015 |
461 | |||
Thereafter |
722 | |||
Total |
$ | 5,903 | ||
The Austral Abrolhos is subject to an annual right of its charterer to purchase the vessel
during the term of the charter, which commenced May 2, 2003 and, subject to the charterers right
to extend, terminates April 29,
2016, at a purchase price in the first year of $26.8 million declining
to an adjusted purchase price of $12.9 million in the thirteenth year.
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 each of October 1, 2012;
April 1, 2015; and 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 $4.6 million and $0.2 million at December 31, 2010 and 2009, respectively. 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. 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
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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 estimate 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.
(9) EQUITY INCENTIVE PLANS
Stock Options and Stock Option Plans
Under the terms of our Amended and Restated 1993 Non-Employee Director Stock Option Plan, or
1993 Director Plan, options to purchase 20,000 shares of our common stock were granted to each of
our five non-employee directors in 1993, 1996, 1999 and 2002, and to a newly appointed director in
2001 and 2003. The exercise price of options granted under the 1993 Director Plan is fixed at the
market price at the date of grant. A total of 800,000 shares were reserved for issuance under the
1993 Director Plan. The options have a term of ten years. On April 21, 2006, the 1993 Director
Plan was terminated and, therefore, no additional shares were reserved for granting of options
under this plan, though options remain outstanding under this plan.
In May 1998, the stockholders approved the GulfMark Offshore, Inc. 1997 Incentive Equity Plan
that replaced the 1987 Employee Plan. A total of 814,000 shares were reserved for issuance of
options or awards of restricted stock under this plan. Stock options generally become exercisable
in 1/3 increments over a three-year period and to the extent not exercised, expire on the tenth
anniversary of the date of grant. Under the terms of the 2010 Omnibus Equity Incentive Plan
(described below) which replaced the 1997 Incentive Equity Plan, no further shares have been
awarded.
In May 2005, the stockholders approved the GulfMark Offshore, Inc. 2005 Non-Employee Director
Plan, or Director Plan. The terms of our Director Plan provide that each non-employee director will
receive an annual grant of stock awards. The non-employee director may also be granted an annual
stock option to purchase up to 6,000 shares of common stock. The exercise price of options granted
under the Director Plan is fixed at the fair market value of the common stock on the date of grant.
The maximum number of shares authorized under the Director Plan is 150,000.
On June 8, 2010, the stockholders approved the GulfMark Offshore, Inc. 2010 Omnibus Equity
Incentive Plan that replaced the 1997 Incentive Equity 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.
The following table summarizes the activity of our stock option incentive plans during the
indicated periods.
2010 | 2009 | 2008 | ||||||||||||||||||||||
Weighted | Weighted | Weighted | ||||||||||||||||||||||
Average | Average | Average | ||||||||||||||||||||||
Exercise | Exercise | Exercise | ||||||||||||||||||||||
Shares | Price | Shares | Price | Shares | Price | |||||||||||||||||||
Outstanding at beginning of year |
457,650 | $ | 15.75 | 673,650 | $ | 13.94 | 789,650 | $ | 14.33 | |||||||||||||||
Granted |
- | - | - | - | - | - | ||||||||||||||||||
Forfeitures |
- | - | - | - | - | - | ||||||||||||||||||
Exercised |
158,000 | 11.63 | 216,000 | 10.09 | 116,000 | 16.56 | ||||||||||||||||||
Outstanding at end of year |
299,650 | $ | 17.92 | 457,650 | $ | 15.75 | 673,650 | $ | 13.94 | |||||||||||||||
Exercisable shares and weighted average exercise price |
299,650 | $ | 17.92 | 457,650 | $ | 15.75 | 673,650 | $ | 13.94 | |||||||||||||||
Shares available for future grants at December 31: |
||||||||||||||||||||||||
2005 Director Plan |
37,000 | 54,600 | 77,900 | |||||||||||||||||||||
2010 Omnibus Equity Incentive Plan |
985,294 | - | - |
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The following table summarizes information about stock options outstanding at December
31, 2010:
Outstanding | Exercisable | |||||||||||||||||||
Weighted | Weighted | Weighted | ||||||||||||||||||
Average | Average | Average | ||||||||||||||||||
Range of Exercise Prices | Shares | Exercise Price | Remaining Life | Shares | Exercise Price | |||||||||||||||
$13.10 to $17.44 |
216,000 | $ | 16.67 | 0.91 years | 216,000 | $ | 16.67 | |||||||||||||
$19.37 to $21.25 |
83,650 | $ | 21.17 | 1.35 years | 83,650 | $ | 21.17 | |||||||||||||
299,650 | $ | 17.92 | 299,650 | $ | 17.92 | |||||||||||||||
Historically, we have used stock options as a long-term incentive for our employees,
officers and directors under the above-mentioned stock option plans. The exercise price of options
granted is equal to or greater than the market price of the underlying stock on the date of the
grant. Accordingly, consistent with the provisions of U.S. GAAP no compensation expense has been
recognized in the accompanying financial statements for these options. See Note 1 Nature of
Operations and Summary of Significant Accounting Policies-Stock-Based Compensation.
ESPP
We have an employee stock purchase plan, or ESPP, that is available to all 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 common stock at 85% of the fair market value of the
common stock on the first or the last day of the Option Period, whichever is lower. Prior to 2006,
these plans were considered non-compensatory and as such, our financial statements did not reflect
any related expense through December 31, 2005. However, effective January 1, 2006, we adopted FASB
ASC 718, Stock Compensation, and expense these costs as compensation. We have authorized the
issuance of up to 400,000 shares of common stock through these plans. At December 31, 2010, there
were 277,265 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 Incentive Equity Plan.
Executive Deferred Compensation Plan
We maintain an executive deferred compensation plan, or EDC Plan. Under the EDC Plan, a
portion of the compensation for certain of our key employees, including officers and directors, can
be deferred for payment after retirement or termination of employment. Under the EDC Plan, deferred
compensation can be used to purchase our 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 common stock and
may be matched by us. At December 31, 2010, a total of $2.8 million had been deferred into the
Prime plus 2% portion of the plan.
We have established a Rabbi trust to hold the stock portion of benefits under the EDC Plan.
The funds provided to the trust are invested by a trustee independent of us in our 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 EDC Plan are included in the
accompanying consolidated balance sheets as treasury stock and deferred compensation expense.
(10) 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 $1.4 million, $1.3
million and $0.8 million for the years ended December 31, 2010, 2009 and 2008, respectively.
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Multi-employer Pension Obligation
Certain current and former U.K. subsidiaries are participating in a multi-employer retirement
fund known as the Merchant Navy Officers Pension Fund (MNOPF). At December 31, 2010, we had $5.1
million accrued related to this liability, which reflects all obligations assessed by the funds
trustee on the Company. We continue to have employees who participate in the MNOPF and will as a
result continue to have routine payments to the fund as those employees accrue additional benefits
over time. In addition, we have been advised by the trustee that as of March 31, 2009, the MNOPF
was underfunded and as a result there is the potential that in the future participating employers
will be assessed additional obligations to correct the underfunding. The amount and timing of
additional potential future obligations depends on a number of factors, but principally on future
fund performance and the underlying actuarial assumptions.
Norwegian Pension Plans
The Norwegian benefit pension plans include approximately seven of our office employees and
260 seamen and are defined benefit, multiple-employer plans, insured with Nordea Liv. We also have
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, 2010 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):
2010 | 2009 | |||||||
Change in Benefit Obligation |
||||||||
Benefit obligation at beginning of the year |
$ | 8,083 | $ | 5,615 | ||||
Benefit periodic cost |
933 | 698 | ||||||
Interest cost |
334 | 284 | ||||||
Benefits paid |
(337 | ) | (499 | ) | ||||
Actuarial gain (loss) |
(574 | ) | 842 | |||||
Translation adjustment |
(50 | ) | 1,143 | |||||
Benefit obligation at year end |
$ | 8,389 | $ | 8,083 | ||||
2010 | 2009 | |||||||
Change in Plan Assets |
||||||||
Fair value of plan assets at beginning of the year |
$ | 5,350 | $ | 3,741 | ||||
Actual return on plan assets |
311 | 276 | ||||||
Contributions |
518 | 1,116 | ||||||
Benefits paid |
(147 | ) | - | |||||
Administrative fee |
(50 | ) | (37 | ) | ||||
Actuarial gain (loss) |
45 | (570 | ) | |||||
Translation adjustment |
(8 | ) | 824 | |||||
Fair value of plan assets at end of year |
$ | 6,019 | $ | 5,350 | ||||
2010 | 2009 | |||||||
Funded status |
$ | 2,370 | $ | 2,733 | ||||
Social security |
401 | 385 | ||||||
Net obligation including social security |
$ | 2,771 | $ | 3,118 | ||||
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Amounts recognized in the balance sheet consist of (in thousands):
December 31, | ||||||||
2010 | 2009 | |||||||
Deferred costs and other assets |
$ | 406 | $ | 58 | ||||
Other liabilities |
2,078 | 190 | ||||||
Year Ended December 31, | ||||||||
2010 | 2009 | |||||||
Components of Net Period Benefit Cost |
||||||||
Service cost |
$ | 900 | $ | 647 | ||||
Interest cost |
323 | 263 | ||||||
Return on plan assets |
(311 | ) | (276 | ) | ||||
Administrative fee |
50 | 37 | ||||||
National insurance (social security) contribution |
136 | 117 | ||||||
Recognized net actuarial gain (loss) |
(618 | ) | 1,337 | |||||
Net periodic benefit cost |
$ | 480 | $ | 2,125 | ||||
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 | 2010 | 2009 | ||||||
Discount rate |
3.2 | % | 4.3 | % | ||||
Return on plan assets |
4.6 | % | 5.6 | % | ||||
Rate of compensation increase |
3.0 | % | 4.3 | % |
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:
2010 | 2009 | |||||||
Equity securities |
13 | % | 10 | % | ||||
Debt securities |
66 | % | 69 | % | ||||
Property |
19 | % | 20 | % | ||||
Other |
2 | % | 1 | % | ||||
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 $8.4 million and $6.0 million, respectively as of December 31, 2010, and
$8.1 million and $5.4 million, respectively as of December 31, 2009. We expect to contribute
approximately $0.6 million to the Norwegian pension plan in 2011. No plan assets are expected to
be returned to us in 2011.
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The following benefit payments, which reflect expected future service, as appropriate,
are expected to be paid (in thousands):
Year ended December 31, | Benefit Payments | |||
2011 |
$ | 337 | ||
2012 |
357 | |||
2013 |
368 | |||
2014 |
379 | |||
2015 |
390 | |||
Total |
$ | 1,831 | ||
(11) STOCKHOLDERS EQUITY
Common Stock Issuances
During 2010, 25,021 shares were issued through the ESPP, generating approximately $0.6 million
in proceeds. The provisions of the ESPP are described above in Note 9 in more detail.
As a result of the Rigdon Acquisition on July 1, 2008, we issued approximately 2.1 million
shares of our common stock valued at $133.2 million.
A total of 167,096 and 326,207 restricted shares of our stock were granted to certain officers
and key employees in 2010 and 2009, respectively, pursuant to our 1997 Incentive Equity Plan and
2010 Omnibus Equity Incentive Plan described above in Note 9, with an aggregate market value of
$4.7 million and $5.8 million, respectively, on the grant dates. The restrictions terminate at the
end of three years and the value of the restricted shares is being amortized to expense over that
period.
Preferred Stock
We are authorized by our Certificate of Incorporation, as amended, to issue up to 2,000,000
shares of no par value preferred stock. No shares have been issued.
Dividends
We have not declared or paid cash dividends during the past five years. Pursuant to the terms
of the indenture under which the senior notes are issued, we may be restricted from declaring or
paying cash dividends; however, we currently anticipate that, for the foreseeable future, any
earnings will be retained for the growth and development of our business. The declaration of
dividends is at the discretion of our Board of Directors. Our dividend policy will be reviewed by
the Board of Directors at such time as may be appropriate in light of future operating conditions,
dividend restrictions of subsidiaries and investors, financial requirements, general business
conditions and other factors.
Reorganization
On February 23, 2010, our stockholders approved a corporate reorganization (the
Reorganization) and as a result, we have a new Certificate of Incorporation.
The Certificate of Incorporation created two classes of common stock: Class A and Class B. All
existing shares were converted to Class A common stock in the Reorganization. These 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, 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 the Company or, if such sale is
ineffective, redemption by the Company. 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.
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The Certificate of Incorporation also authorized 60 million shares of each class of common
stock. Pursuant to the Reorganization, the Certificate of Incorporation and the Bylaws of the
Company now require that the Chairman of the Board and chief executive officer, by whatever title,
must each be U.S. citizens and not more than a minority of the minimum number of directors of the
Board of Directors necessary to constitute a quorum of the Board of Directors (or such other
portion as the Board of Directors may determine is necessary to comply with the Jones Act) may be
non-U.S. citizens so long as shares of New GulfMark Class A common stock remain outstanding.
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 (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.
The business, assets, liabilities, directors and executive officers of the Company did not
change as a result of the reorganization.
(12) DERIVATIVE FINANCIAL INSTRUMENTS
Derivative instruments are accounted for at fair value. The accounting for changes in the fair
value of a derivative depends on the intended use and designation of the derivative instrument. For
a derivative instrument designated as a fair value hedge, the gain or loss on the derivative is
recognized in earnings in the period of change in fair value together with the offsetting gain or
loss on the hedged item. For a derivative instrument designated as a cash flow hedge, the effective
portion of the derivatives gain or loss is initially reported as a component of Other
Comprehensive Income (OCI) and is subsequently recognized in earnings when the hedged exposure
affects earnings. The ineffective portion of the gain or loss is recognized in earnings. Gains and
losses from changes in fair values of derivatives that are not designated as hedges for accounting
purposes are recognized in earnings.
Using derivative instruments means assuming counterparty credit risk. Counterparty credit risk
relates to the loss we could incur if a counterparty were to default on a derivative contract. We
deal with investment grade counterparties and monitor the overall credit risk and exposure to
individual counterparties. We do not anticipate nonperformance by any counterparties. The amount of
counterparty credit exposure is the unrealized gains, if any, on such derivative contracts. We do
not require, nor do we post, collateral or security on such contracts.
Hedging Strategy
We are exposed to certain risks relating to our ongoing business operations. As a result, we
enter into derivative transactions to manage certain of these exposures that arise in the normal
course of business. The primary risks managed by using derivative instruments are foreign currency
exchange rate and interest rate risks. Fluctuations in these rates and prices can affect our
operating results and financial condition. We manage the exposure to these market risks through
operating and financing activities and through the use of derivative financial instruments. We do
not enter into derivative financial instruments for trading or speculative purposes.
We enter into forward foreign currency contracts which are designated as fair value hedges and
are highly effective, as the terms of the forward contracts are the same as the purchase
commitments under the related new build contract. Any gains or losses resulting from changes in
fair value were recognized in income with an offsetting adjustment to income for changes in the
fair value of the hedged item such that there was no net impact in the consolidated statements of
operations. As of December 31, 2010, we have no open foreign currency contracts.
We entered into an interest rate swap with the objective of reducing our exposure to interest
rate risk for $100.0 million of our $200.0 million Facility Agreement variable-rate debt. At
December 31, 2010, our interest rate derivative instruments have an outstanding notional amount of
$100.0 million and have been designated as cash flow hedges. The critical terms of these swaps,
including reset dates and floating rate indices match those of our underlying variable-rate debt
and no ineffectiveness has been recorded.
Early Hedge Settlement
During December 2009, we cash settled certain interest rate swap contracts prior to their
scheduled settlement dates. As a result of these transactions, we paid $6.4 million in cash, which
represented the fair value of these contracts at the date of settlement. Unrecognized losses of
$1.8 million are recorded as of December 31, 2010 in accumulated OCI related to these interest rate
swaps.
This balance will be amortized into interest expense through December 31, 2012 based on
forecasted payments as of the settlement date.
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The following table quantifies the fair values, on a gross basis, of all our derivative
contracts and identifies the consolidated balance sheet location as of December 31 (dollars in
thousands):
Asset Derivatives | Liability Derivatives | |||||||||||||||||||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||||||||||||||||||
Derivaties designated as | Balance Sheet | Balance Sheet | Balance Sheet | Balance Sheet | ||||||||||||||||||||||||||||
hedging instruments | Location | Fair Value | Location | Fair Value | Location | Fair Value | Location | Fair Value | ||||||||||||||||||||||||
Foreign exchange contracts |
Fair value hedges | $ | - | Fair value hedges | $ | 6,886 | Fair value hedges | $ | - | Fair value hedges | $ | 6,886 | ||||||||||||||||||||
Interest Rate Swaps |
- | - | Cash flow hedges | 6,807 | Cash flow hedges | 6,422 | ||||||||||||||||||||||||||
$ | - | $ | 6,886 | $ | 6,807 | $ | 13,308 | |||||||||||||||||||||||||
The following tables quantify the amount of gain or loss recognized during the year ended
December 31 and identify the consolidated statement of operations location:
Location of Gain or Loss | Amount of Gain or Loss | |||||||||||
Derivatives in fair value | Recognized in Income on | Recognized in Income on | ||||||||||
hedging relationships | Derivative | Derivative | ||||||||||
2010 | 2009 | |||||||||||
(in thousands) | ||||||||||||
Foreign exchange contracts |
See note. | $ | - | $ | - |
Location of Gain or (Loss) | Amount of Gain or (Loss) | |||||||||||||||||||
Amount of Gain or (Loss) | Reclassified from | Reclassified from | ||||||||||||||||||
Derivatives in cash flow | Recognized in OCI on | Accumulated OCI into | Accumulated OCI into | |||||||||||||||||
hedging relationships | Derivative | Income | Income | |||||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||||||
(in thousands) | (in thousands) | |||||||||||||||||||
Interest rate contracts |
$ | (4,351 | ) | $ | 1,448 | Interest expense | $ | (2,716 | ) | $ | (3,976 | ) |
(13) 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
As of December 31, 2009, we had open fair value hedges associated with firm contractual
commitments for future vessel payments denominated in a foreign currency. These forward contracts
were designated as fair value hedges and were highly effective, as the terms of the forward
contracts were the same as the purchase commitment under the new build contract. We recognized the
fair value of our derivative assets as Level 2
valuations. We determined the fair value of our financial instrument position based upon the
forward contract price and the foreign currency exchange rate as of December 31, 2009. At December
31, 2009, the fair value of our derivatives was approximately $6.9 million. There are no open fair
value hedges at December 31, 2010.
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We had interest rate swap agreements that hedged the interest rate associated with a portion
of our previous senior indebtedness. These cash flow hedges fixed the interest rate at 4.725% on
approximately $85.0 million of the senior debt facility. On December 17, 2009, we entered into the
$200.0 million Facility Agreement and terminated the existing senior indebtedness and the swaps
associated with that debt. As a result, we entered into an interest rate swap agreement for
approximately $100.0 million of the Facility Agreement indebtedness that has fixed the interest
rate at 4.145%. The interest rate swap is accounted for as cash flow hedge. We report changes in
the fair value of the cash flow hedges in accumulated other comprehensive income. The consolidated
balance sheet contains cash flow hedges within other long term liabilities, reflecting the fair
value of the interest rate swap which was $6.8 million at December 31, 2010. We report changes in
the fair value of these cash flow hedges in accumulated other comprehensive income. For the year
ended December 31, 2010, $2.7 million was reclassified from other comprehensive income to interest
expense. We expect to reclassify $3.1 million of deferred loss related to the interest rate swaps
to interest expense during the next 12 months. We recognize the fair value of our derivative swaps
as a Level 2 valuation. We determined the fair value of our interest rate swap based on the
contractual fixed rate in the swap agreement and the forward curve of three month LIBOR supplied by
the bank as of December 31, 2010.
The following table presents information about our assets (liabilities) measured at fair value
on a recurring basis as of December 31, 2010, and indicates the fair value hierarchy we utilized to
determine such fair value (in millions).
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
Cash Flow Hedges |
$ | - | $ | (6.8 | ) | $ | - | $ | (6.8 | ) | ||||||
The following table presents information about our assets (liabilities) measured at fair value
on a recurring basis as of December 31, 2009, and indicates the fair value hierarchy we utilized to
determine such fair value (in millions).
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
Fair Value Hedges |
$ | - | $6.9 | $ | - | $ | 6.9 | |||||||||
Purchase Commitments |
- | (6.9 | ) | - | (6.9 | ) | ||||||||||
Cash Flow Hedges |
- | (6.4 | ) | - | (6.4 | ) | ||||||||||
$ | - | $ | (6.4 | ) | $ | - | $ | (6.4 | ) | |||||||
The purchase commitments and cash flow hedges are included in other long term liabilities
on the consolidated balance sheet as of December 31, 2010 and 2009.
(14) OPERATING SEGMENT INFORMATION
Business Segments
We operate our business based on geographical locations and maintain the following 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 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 segments 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. Operating income and other information regularly provided to
our chief operating decision-maker is summarized in the following table (all amounts in thousands):
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North | Southeast | |||||||||||||||||||
Sea | Asia | Americas | Other | Total | ||||||||||||||||
Year Ended December 31, 2010 |
||||||||||||||||||||
Revenue |
$ | 148,740 | $ | 66,533 | $ | 144,493 | $ | - | $ | 359,766 | ||||||||||
Direct operating expenses |
78,253 | 10,395 | 81,990 | - | 170,638 | |||||||||||||||
Drydock expense |
7,598 | 4,796 | 9,788 | - | 22,182 | |||||||||||||||
General and administrative
expense |
11,277 | 2,659 | 7,798 | 22,295 | 44,029 | |||||||||||||||
Depreciation and amortization |
18,649 | 8,922 | 28,321 | 1,067 | 56,959 | |||||||||||||||
Impairment charge |
- | - | 97,665 | - | 97,665 | |||||||||||||||
(Gain) loss on sale of assets |
(5,246 | ) | - | 154 | (3 | ) | (5,095 | ) | ||||||||||||
Operating income (loss) |
$ | 38,209 | $ | 39,761 | $ | (81,223 | ) | $ | (23,359 | ) | $ | (26,612 | ) | |||||||
Cash and cash equivalents |
$ | 47,628 | $ | 16,532 | $ | 16,123 | $ | 16,912 | $ | 97,195 | ||||||||||
Long-lived assets(a)(b) |
$ | 408,798 | $ | 249,678 | $ | 590,436 | $ | 4,665 | $ | 1,253,577 | ||||||||||
Total assets |
$ | 505,062 | $ | 292,189 | $ | 635,582 | $ | 31,617 | $ | 1,464,450 | ||||||||||
Capital expenditures |
$ | 31,997 | $ | 34,959 | $ | 4,456 | $ | 2,027 | $ | 73,439 | ||||||||||
Year Ended December 31, 2009 |
||||||||||||||||||||
Revenue |
$ | 165,415 | $ | 76,544 | $ | 146,912 | $ | - | $ | 388,871 | ||||||||||
Direct operating expenses |
80,854 | 8,865 | 76,464 | - | 166,183 | |||||||||||||||
Drydock expense |
6,818 | 2,095 | 6,783 | - | 15,696 | |||||||||||||||
General and administrative
expense |
10,598 | 1,841 | 8,685 | 22,576 | 43,700 | |||||||||||||||
Depreciation and amortization |
17,186 | 7,131 | 27,892 | 835 | 53,044 | |||||||||||||||
Impairment charge |
- | - | 46,247 | - | 46,247 | |||||||||||||||
Gain on sale of assets |
(4,055 | ) | (1,493 | ) | (4 | ) | - | (5,552 | ) | |||||||||||
Operating income (loss) |
$ | 54,014 | $ | 58,105 | $ | (19,155 | ) | $ | (23,411 | ) | $ | 69,553 | ||||||||
Cash and cash equivalents |
$ | 29,207 | $ | 16,215 | $ | 25,680 | $ | 20,977 | $ | 92,079 | ||||||||||
Long-lived assets(a)(b) |
$ | 443,598 | $ | 202,461 | $ | 710,565 | $ | 8,115 | $ | 1,364,739 | ||||||||||
Total assets |
$ | 519,228 | $ | 245,160 | $ | 768,345 | $ | 32,926 | $ | 1,565,659 | ||||||||||
Capital expenditures |
$ | 44,901 | $ | 15,289 | $ | 16,820 | $ | 428 | $ | 77,438 | ||||||||||
Year Ended December 31, 2008 |
||||||||||||||||||||
Revenue |
$ | 226,124 | $ | 77,851 | $ | 107,765 | $ | - | $ | 411,740 | ||||||||||
Direct operating expenses |
86,445 | 12,509 | 44,972 | - | 143,926 | |||||||||||||||
Drydock expense |
8,237 | 250 | 2,832 | - | 11,319 | |||||||||||||||
General and administrative
expense |
11,414 | 2,193 | 6,769 | 19,867 | 40,243 | |||||||||||||||
Depreciation and amortization |
22,623 | 6,170 | 14,860 | 647 | 44,300 | |||||||||||||||
Gain on sale of assets |
(29,081 | ) | (5,718 | ) | (12 | ) | - | (34,811 | ) | |||||||||||
Operating income (loss) |
$ | 126,486 | $ | 62,447 | $ | 38,344 | $ | (20,514 | ) | $ | 206,763 | |||||||||
Cash and cash equivalents |
$ | 46,080 | $ | 19,707 | $ | 7,723 | $ | 27,251 | $ | 100,761 | ||||||||||
Long-lived assets(a)(b) |
$ | 341,553 | $ | 159,288 | $ | 684,601 | $ | 141,208 | $ | 1,326,650 | ||||||||||
Total assets |
$ | 436,758 | $ | 209,179 | $ | 738,181 | $ | 172,850 | $ | 1,556,968 | ||||||||||
Capital expenditures |
$ | 23,805 | $ | 45,089 | $ | 39,733 | $ | 1,072 | $ | 109,699 |
a. | Goodwill is included in the North Sea and Americas segments. The Americas segment
goodwill was charged to impairment expense in the second quarter of 2010. |
b. | Most 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 2010, we had $104.5 million in revenue
and $462.9 million in long-lived assets attributed to business in the United States, our
country of domicile. In 2009, we had $106.5 million in revenue and $603.9 million
in long-lived assets attributed to the United States. |
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(15) UNAUDITED QUARTERLY FINANCIAL DATA
Summarized quarterly financial data for the two years ended December 31, 2010 and 2009 are as
follows:
Quarter | ||||||||||||||||
First | Second | Third | Fourth | |||||||||||||
(In thousands, except per share amounts) | ||||||||||||||||
2010 |
||||||||||||||||
Revenues |
$ | 84,651 | $ | 92,782 | $ | 94,479 | $ | 87,854 | ||||||||
Operating income (loss) |
8,912 | (79,239 | ) | 25,981 | 17,734 | |||||||||||
Net income (loss) |
21,543 | (90,731 | ) | 19,207 | 15,236 | |||||||||||
Per share (basic) |
$0.85 | ($3.55 | ) | $0.75 | $0.59 | |||||||||||
Per share (diluted) |
$0.84 | ($3.55 | ) | $0.75 | $0.59 | |||||||||||
2009 |
||||||||||||||||
Revenue |
$ | 108,795 | $ | 104,656 | $ | 90,764 | $ | 84,656 | ||||||||
Operating income |
1,550 | 39,040 | 19,765 | 9,197 | ||||||||||||
Net income (loss) |
14,221 | 34,923 | 12,702 | (11,263 | ) | |||||||||||
Per share (basic) |
$0.57 | $1.39 | $0.50 | ($0.45 | ) | |||||||||||
Per share (diluted) |
$0.56 | $1.38 | $0.50 | ($0.45 | ) |
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ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
NONE
ITEM 9A. Controls and Procedures
(a) Disclosure Controls and Procedures. We maintain disclosure controls and procedures that are
designed to ensure 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 SECs
rules and forms, and that such information is accumulated and communicated to management, including
our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions
regarding required disclosure. Our management, with the participation of our Chief Executive
Officer and Chief Financial Officer, has evaluated the effectiveness of the Companys disclosure
controls and procedures as of the end of the fiscal year covered by this Annual Report on Form
10-K. Our Chief Executive Officer and Chief 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.
(b) Managements 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 Rules 13a-15(f).
Our management assessed the effectiveness of our internal control over financial reporting at
December 31, 2010, 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. Based on this assessment, management determined that our internal control over financial
reporting was effective as of December 31, 2010. UHY LLP has issued the following opinion on the
Companys internal control over financial reporting.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of GulfMark Offshore, Inc. and its Subsidiaries:
We have audited GulfMark Offshore, Inc. and its subsidiaries internal control over financial
reporting as of December 31, 2010, based on criteria established in Internal ControlIntegrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
GulfMark Offshore, Inc. and its 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 Managements Annual Report on
Internal Control over Financial Reporting. Our responsibility is to express an opinion on the
companys 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 of internal control over financial reporting
included obtaining an understanding of internal control over financial reporting, assessing the
risk that a material weakness exists, and testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk. Our audit also included performing
such other procedures as we considered necessary in the circumstances. We believe that our audit
provides a reasonable basis for our opinion.
A companys 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 companys 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 companys 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 its subsidiaries maintained, in all material
respects, effective internal control over financial reporting as of December 31, 2010, based on
criteria established in Internal ControlIntegrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO).
We have also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheets and the related consolidated
statements of income, stockholders equity, comprehensive income, and cash flows of GulfMark
Offshore, Inc. and its subsidiaries, and our report dated February 24, 2011 expressed an
unqualified opinion.
UHY LLP
Houston, Texas
February 24, 2011
Houston, Texas
February 24, 2011
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(c) Changes in Internal Control Over Financial Reporting. There were no changes in our internal
control over financial reporting during the quarter ended December 31, 2010, 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.
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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 Consolidated
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
Filed Herewith or | ||||
Incorporated by Reference | ||||
Exhibits | Description | 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 | ||
3.2
|
Bylaws, as amended | Exhibit 3.2 to our current report on Form 8-K filed on February 24, 2010 | ||
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 | ||
4.2
|
Form of U.S. Citizen Stock Certificates | Exhibit 4.2 to our current report on Form 8-K filed on February 24, 2010 | ||
4.3
|
Form of Non-U.S. Citizen Stock Certificates | Exhibit 4.3 to our current report on Form 8-K filed on February 24, 2010 | ||
4.4
|
Indenture, dated as of July 21, 2004, between GulfMark Offshore, Inc., as the Company, and U.S. Bank National Association, as Trustee, including a form of the Companys 7.75% Senior Notes due 2014 | Exhibit 4.4 to our quarterly report on Form 10-Q for the quarter ended September 30, 2004 | ||
4.5
|
First Supplemental Indenture, dated as of February 24, 2010, between GulfMark Offshore, Inc. (f/k/a New GulfMark Offshore, Inc.), as the Company and U.S. Bank Association, as Trustee, for the Companys 7.75% Senior Notes due 2014 | Exhibit 10.1 to our Form 8-K filed February 24, 2010 | ||
4.6
|
Registration Rights Agreement, dated July 1, 2008, among GulfMark Offshore, Inc. and certain of the Rigdon Shareholders | Exhibit 4.5 to our current report on Form 8-K filed on July 7, 2008 | ||
10.1
|
GulfMark International, Inc. Amended and Restated 1993 Non-Employee Director Stock Option Plan* | Exhibit 10.7 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997 | ||
10.2
|
Amendment No. 1 to the GulfMark International, Inc. Amended and Restated 1993 Non-Employee Director Stock Option Plan* | Exhibit 10.8 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997 | ||
10.3
|
GulfMark Offshore, Inc. Instrument of Assumption and Adjustment (Amended and Restated 1993 Non-Employee Director Stock Option Plan)* | Exhibit 10.9 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997 |
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10.4
|
Form of Stock Option Agreement (Amended and Restated 1993 Non-Employee Director Stock Option Plan)* | Exhibit 10.12 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997 | ||
10.5
|
Form of Amendment No. 1 to Stock Option Agreement (Amended and Restated 1993 Non-Employee Director Stock Option Plan)* | Exhibit 10.11 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997 | ||
10.6
|
GulfMark Offshore, Inc. 1997 Incentive Equity Plan* | Exhibit 10.16 to our annual report on Form 10-K for the year ended December 31, 1998 | ||
10.7
|
Amendment No. 1 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan* | Exhibit 4.4.2 to our Registration Statement on Form S-8, Registration No. 333-57294 filed on March 20, 2001 | ||
10.8
|
Amendment No. 2 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan* | Exhibit 4.8.3 to our Post-Effective Amendment No. 1 to our Registration Statement on Form S-8, Registration No. 333-57294 filed on May 25, 2007 | ||
10.9
|
Amendment No. 3 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan* | Exhibit 4.8.4 to our Post-Effective Amendment No. 1 to our Registration Statement on Form S-8, Registration No. 333-57294 filed on May 25, 2007 | ||
10.10
|
Amendment No. 4 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan * | Exhibit 10.1 to our current report on Form 8-K filed on March 26, 2008 | ||
10.11
|
Amendment No. 5 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan* | Exhibit 10.4 to our current report on Form 8-K filed on October 19, 2009 | ||
10.12
|
Form of Incentive Stock Option Agreement (1997 Incentive Equity Plan)* | Exhibit 10.17 to our annual report on Form 10-K for the year ended December 31, 1998 | ||
10.13
|
GulfMark Offshore, Inc. 2010 Omnibus Equity Incentive Plan* | Exhibit A to our Proxy Statement on Form DEF 14A filed on April 30, 2010 | ||
10.14
|
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 | ||
10.15
|
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 | ||
10.16
|
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 | ||
10.17
|
GulfMark Offshore, Inc. 2005 Non-Employee Director Share Incentive Plan* | Exhibit A to our Proxy Statement on Form DEF 14A, filed on April 11, 2005 | ||
10.18
|
Amendment No. 1 to the GulfMark Offshore, Inc. 2005 Non-Employee Director Share Incentive Plan* | Exhibit 4.8.2 to our Registration Statement on Form S-8, Registration No. 333-143258 filed on May 25, 2007 | ||
10.19
|
Amendment No. 2 to the GulfMark Offshore, Inc. 2005 Non-Employee Director Share Incentive Plan* | Exhibit 10.5 to our current report on Form 8-K filed on October 19, 2009 | ||
10.20
|
Amendment No. 3 to the GulfMark Offshore, Inc. 2005 Non-Employee Director Share Incentive Plan* | Exhibit 10.2 to our current report on Form 8-K filed on March 23, 2010 | ||
10.21
|
Form of Restricted Stock Award Agreement (2005 Non-Employee Director Share Incentive Plan)* | Exhibit 10.1 to our current report on Form 8-K filed on May 18, 2006 |
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10.22
|
Form of Stock Award Agreement (2005 Non-Employee Director Share Incentive Plan)* | Exhibit 10.3 to our Form 8-K filed on March 23, 2010 | ||
10.23
|
GulfMark Offshore, Inc. Employee Stock Purchase Plan* | Exhibit 4.4.3 to our Registration Statement on Form S-8, Registration No. 333-84110 filed on March 11, 2002 | ||
10.24
|
Amendment No. 1 to Employee Stock Purchase Plan* | Exhibit 10.1 to our current report on Form 8-K filed on March 23, 2010 | ||
10.25
|
Executive Nonqualified Excess Plan Document* | Exhibit 10.1 to our quarterly report on Form 10-Q for the quarter ended September 30, 2010 | ||
10.26
|
Executive Nonqualified Excess Plan Adoption Agreement, amended effective January 1, 2010* | Exhibit 10.2 to our quarterly report on Form 10-Q for the quarter ended September 30, 2010 | ||
10.27
|
Form of the Executive Nonqualified Excess Plan Participation Agreement* | Exhibit 10.3 to our quarterly report on Form 10-Q for the quarter ended September 30, 2010 | ||
10.28
|
Amended and Restated Employment Agreement dated October 14, 2009, made by and between GulfMark Americas, Inc. and Bruce A. Streeter* | Exhibit 10.1 to our current report on Form 8-K filed on October 19, 2009 | ||
10.29
|
Amended and Restated Employment Agreement dated October 14, 2009, made by and between GulfMark Americas, Inc. and John E. Leech* | Exhibit 10.2 to our current report on Form 8-K filed on October 19, 2009 | ||
10.30
|
Employment Agreement dated October 14, 2009, made by and between GulfMark Americas, Inc. and Quintin V. Kneen* | Exhibit 10.3 to our current report on Form 8-K filed on October 19, 2009 | ||
10.31
|
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 | ||
10.32
|
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 | ||
10.33
|
Form of Indemnification Agreements* | Exhibit 10.2 to our current report on Form 8-K filed on February 24, 2010 | ||
10.34
|
GM Offshore, Inc. Supplemental Income Plan effective as of January 1, 2000* | Filed herewith | ||
10.35
|
Split-Dollar Insurance Agreement (Collateral Assignment) dated January 1, 2000, between GM Offshore, Inc. and Bruce A. Streeter* | Filed herewith | ||
10.36
|
Participation Agreement Supplemental Income Plan of GulfMark Offshore Inc. dated January 1, 2000 by Bruce A. Streeter* | Filed herewith | ||
10.37
|
Amendment One to Participation Agreement Supplemental Income Plan of GulfMark Offshore, Inc. dated December 28, 2010, between GulfMark Offshore, Inc. and Bruce A. Streeter* | Filed herewith | ||
10.38
|
Split-Dollar Insurance Agreement (Collateral Assignment) dated January 1, 2000, between GM Offshore, Inc. and John E. Leech* | Filed herewith |
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10.39
|
Participation Agreement Supplemental Income Plan of GulfMark Offshore Inc. dated January 1, 2000 by John E. Leech* | Filed herewith | ||
10.40
|
Amendment One to Participation Agreement Supplemental Income Plan of GulfMark Offshore, Inc. dated December 29, 2010, between GulfMark Offshore, Inc. and John E. Leech* | Filed herewith | ||
10.41
|
U.S. $25.0 million Secured Reducing Revolving Loan Facility Agreement between GulfMark Offshore, Inc. and DnB NOR Bank ASA and others dated June 1, 2006, as Amended and Restated by a First Supplemental Agreement dated June 5, 2008 | Exhibits 10.24 and 10.25 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008 | ||
10.42
|
U.S. $60.0 million Secured Reducing Revolving Loan Facility Agreement between Gulf Offshore N.S. Limited and DnB NOR Bank ASA and others dated June 1, 2006 | Exhibit 10.29 to our current report on Form 8-K filed on June 9, 2006 | ||
10.43
|
U.S. $30.0 million Secured Reducing Revolving Loan Facility Agreement between GulfMark Rederi AS and DnB NOR Bank ASA and others dated June 1, 2006 | Exhibit 10.30 to our current report on Form 8-K filed on June 9, 2006 | ||
10.44
|
U.S. $60.0 million Secured Reducing Revolving Loan Facility Agreement between GulfMark Marine Far East Pte. Ltd. And DnB NOR Bank ASA and others dated June 5, 2008 | Exhibit 10.26 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008 | ||
10.45
|
Membership Interest and Stock Purchase Agreement among GulfMark Offshore, Inc., Rigdon Marine Corporation, Rigdon Marine Holdings, L.L.C., all the members of Rigdon Marine Holdings, L.L.C., Sherwood Investment, L.L.C., John J. Tennant III Irrevocable Trust, Brian M. Bowman Irrevocable Trust, and Bourbon Offshore, dated May 28, 2008 | Exhibit 10.6 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008 | ||
10.46
|
Assignment and Assumption Agreement between GulfMark Offshore, Inc. and GulfMark Management, Inc., dated June 30, 2008 | Exhibit 10.7 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008 | ||
10.47
|
Non-Competition and Non-Solicitation Agreement between GulfMark Offshore, Inc. and Larry T. Rigdon, dated July 1, 2008 | Exhibit 10.8 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008 | ||
10.48
|
Operating Agreement and By-laws of Jackson Offshore, LLC, by and between Rigdon Marine Corporation, Lee Jackson, and Bourbon Offshore Holdings SAS, dated August 16, 2006 | Exhibit 10.9 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008 | ||
10.49
|
Delphin Marine Logistics Limited Joint Venture Agreement, by and between Rigdon Marine Corporation, Mariners Haven Limited and Delphin Marine Logistics Limited, dated February 29, 2008 | Exhibit 10.10 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008 | ||
10.50
|
U.S. $200.0 million Facility Agreement among GulfMark Americas, Inc., as borrower, GulfMark Offshore, Inc., as guarantor, The Royal Bank of Scotland plc, as arranger, as agent of the Finance Parties and as security trustee for the Secured Parties, and the lenders that are parties thereto, dated December 17, 2009 | Exhibit 10.1 to our current report on Form 8-K filed on December 17, 2009 | ||
12.1
|
Computation of Ratio of Earnings to Fixed Charges | Filed herewith | ||
21.1
|
Subsidiaries of GulfMark Offshore, Inc. | Filed herewith |
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23.1
|
Consent of UHY LLP | Filed herewith | ||
31.1
|
Section 302 Certification for B.A. Streeter | Filed herewith | ||
31.2
|
Section 302 Certification for Q.V. Kneen | Filed herewith | ||
32.1
|
Section 906 Certification furnished for B.A. Streeter | Filed herewith | ||
32.2
|
Section 906 Certification furnished for Q.V. Kneen | Filed herewith | ||
101
|
The following materials from GulfMark Offshore, Inc.s Annual Report on Form 10-K for the year ended December 31, 2010, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Stockholders Equity, (iv) Consolidated Statements of Comprehensive Income (Loss), (v) Consolidated Statements of Cash Flows and (vi) Notes to Consolidated Financial Statements, tagged as blocks of text. | Filed herewith |
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934,
the Registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto
duly authorized.
GulfMark Offshore, Inc. (Registrant) | ||||
By: | /s/ Bruce A. Streeter | |||
Bruce A. Streeter | ||||
Chief Executive Officer, President and Director (Principal Executive Officer) | ||||
Date: February 24, 2011
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/ Bruce A. Streeter | Chief Executive Officer, President and Director | February 24, 2011 | ||
Bruce A. Streeter | (Principal Executive Officer) | |||
/s/ Quintin V. Kneen | Executive Vice President and Chief Financial Officer | February 24, 2011 | ||
Quintin V. Kneen | (Principal Financial Officer) | |||
/s/ Samuel R. Rubio | Vice President, Controller and Chief Accounting Officer | February 24, 2011 | ||
Samuel R. Rubio | (Principal Accounting Officer) | |||
/s/ David J. Butters | Director | February 24, 2011 | ||
David J. Butters | ||||
/s/ Peter I. Bijur | Director | February 24, 2011 | ||
Peter I. Bijur | ||||
/s/ Brian R. Ford | Director | February 24, 2011 | ||
Brian R. Ford | ||||
/s/ Louis S. Gimbel, 3rd | Director | February 24, 2011 | ||
Louis S. Gimbel 3rd | ||||
/s/ Sheldon S. Gordon | Director | February 24, 2011 | ||
Sheldon S. Gordon | ||||
/s/ Robert B. Millard | Director | February 24, 2011 | ||
Robert B. Millard | ||||
/s/ Robert T. OConnell | Director | February 24, 2011 | ||
Robert T. OConnell | ||||
/s/ Rex C. Ross | Director | February 24, 2011 | ||
Rex C. Ross |
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INDEX TO EXHIBITS
Filed Herewith or | ||||
Incorporated by Reference | ||||
Exhibits | Description | 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 | ||
3.2
|
Bylaws, as amended | Exhibit 3.2 to our current report on Form 8-K filed on February 24, 2010 | ||
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 | ||
4.2
|
Form of U.S. Citizen Stock Certificates | Exhibit 4.2 to our current report on Form 8-K filed on February 24, 2010 | ||
4.3
|
Form of Non-U.S. Citizen Stock Certificates | Exhibit 4.3 to our current report on Form 8-K filed on February 24, 2010 | ||
4.4
|
Indenture, dated as of July 21, 2004, between GulfMark Offshore, Inc., as the Company, and U.S. Bank National Association, as Trustee, including a form of the Companys 7.75% Senior Notes due 2014 | Exhibit 4.4 to our quarterly report on Form 10-Q for the quarter ended September 30, 2004 | ||
4.5
|
First Supplemental Indenture, dated as of February 24, 2010, between GulfMark Offshore, Inc. (f/k/a New GulfMark Offshore, Inc.), as the Company and U.S. Bank Association, as Trustee, for the Companys 7.75% Senior Notes due 2014 | Exhibit 10.1 to our Form 8-K filed February 24, 2010 | ||
4.6
|
Registration Rights Agreement, dated July 1, 2008, among GulfMark Offshore, Inc. and certain of the Rigdon Shareholders | Exhibit 4.5 to our current report on Form 8-K filed on July 7, 2008 | ||
10.1
|
GulfMark International, Inc. Amended and Restated 1993 Non-Employee Director Stock Option Plan* | Exhibit 10.7 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997 | ||
10.2
|
Amendment No. 1 to the GulfMark International, Inc. Amended and Restated 1993 Non-Employee Director Stock Option Plan* | Exhibit 10.8 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997 | ||
10.3
|
GulfMark Offshore, Inc. Instrument of Assumption and Adjustment (Amended and Restated 1993 Non-Employee Director Stock Option Plan)* | Exhibit 10.9 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997 | ||
10.4
|
Form of Stock Option Agreement (Amended and Restated 1993 Non-Employee Director Stock Option Plan)* | Exhibit 10.12 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997 | ||
10.5
|
Form of Amendment No. 1 to Stock Option Agreement (Amended and Restated 1993 Non-Employee Director Stock Option Plan)* | Exhibit 10.11 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997 | ||
10.6
|
GulfMark Offshore, Inc. 1997 Incentive Equity Plan* | Exhibit 10.16 to our annual report on Form 10-K for the year ended December 31, 1998 | ||
10.7
|
Amendment No. 1 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan* | Exhibit 4.4.2 to our Registration Statement on Form S-8, Registration No. 333-57294 filed on March 20, 2001 |
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Table of Contents
10.8
|
Amendment No. 2 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan* | Exhibit 4.8.3 to our Post-Effective Amendment No. 1 to our Registration Statement on Form S-8, Registration No. 333-57294 filed on May 25, 2007 | ||
10.9
|
Amendment No. 3 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan* | Exhibit 4.8.4 to our Post-Effective Amendment No. 1 to our Registration Statement on Form S-8, Registration No. 333-57294 filed on May 25, 2007 | ||
10.10
|
Amendment No. 4 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan * | Exhibit 10.1 to our current report on Form 8-K filed on March 26, 2008 | ||
10.11
|
Amendment No. 5 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan* | Exhibit 10.4 to our current report on Form 8-K filed on October 19, 2009 | ||
10.12
|
Form of Incentive Stock Option Agreement (1997 Incentive Equity Plan)* | Exhibit 10.17 to our annual report on Form 10-K for the year ended December 31, 1998 | ||
10.13
|
GulfMark Offshore, Inc. 2010 Omnibus Equity Incentive Plan* | Exhibit A to our Proxy Statement on Form DEF 14A filed on April 30, 2010 | ||
10.14
|
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 | ||
10.15
|
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 | ||
10.16
|
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 | ||
10.17
|
GulfMark Offshore, Inc. 2005 Non-Employee Director Share Incentive Plan* | Exhibit A to our Proxy Statement on Form DEF 14A, filed on April 11, 2005 | ||
10.18
|
Amendment No. 1 to the GulfMark Offshore, Inc. 2005 Non-Employee Director Share Incentive Plan* | Exhibit 4.8.2 to our Registration Statement on Form S-8, Registration No. 333-143258 filed on May 25, 2007 | ||
10.19
|
Amendment No. 2 to the GulfMark Offshore, Inc. 2005 Non-Employee Director Share Incentive Plan* | Exhibit 10.5 to our current report on Form 8-K filed on October 19, 2009 | ||
10.20
|
Amendment No. 3 to the GulfMark Offshore, Inc. 2005 Non-Employee Director Share Incentive Plan* | Exhibit 10.2 to our current report on Form 8-K filed on March 23, 2010 | ||
10.21
|
Form of Restricted Stock Award Agreement (2005 Non-Employee Director Share Incentive Plan)* | Exhibit 10.1 to our current report on Form 8-K filed on May 18, 2006 | ||
10.22
|
Form of Stock Award Agreement (2005 Non-Employee Director Share Incentive Plan)* | Exhibit 10.3 to our Form 8-K filed on March 23, 2010 | ||
10.23
|
GulfMark Offshore, Inc. Employee Stock Purchase Plan* | Exhibit 4.4.3 to our Registration Statement on Form S-8, Registration No. 333-84110 filed on March 11, 2002 | ||
10.24
|
Amendment No. 1 to Employee Stock Purchase Plan* | Exhibit 10.1 to our current report on Form 8-K filed on March 23, 2010 | ||
10.25
|
Executive Nonqualified Excess Plan Document* | Exhibit 10.1 to our quarterly report on Form 10-Q for the quarter ended September 30, 2010 | ||
10.26
|
Executive Nonqualified Excess Plan Adoption Agreement, amended effective January 1, 2010* | Exhibit 10.2 to our quarterly report on Form 10-Q for the quarter ended September 30, 2010 |
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Table of Contents
10.27
|
Form of the Executive Nonqualified Excess Plan Participation Agreement* | Exhibit 10.3 to our quarterly report on Form 10-Q for the quarter ended September 30, 2010 | ||
10.28
|
Amended and Restated Employment Agreement dated October 14, 2009, made by and between GulfMark Americas, Inc. and Bruce A. Streeter* | Exhibit 10.1 to our current report on Form 8-K filed on October 19, 2009 | ||
10.29
|
Amended and Restated Employment Agreement dated October 14, 2009, made by and between GulfMark Americas, Inc. and John E. Leech* | Exhibit 10.2 to our current report on Form 8-K filed on October 19, 2009 | ||
10.30
|
Employment Agreement dated October 14, 2009, made by and between GulfMark Americas, Inc. and Quintin V. Kneen* | Exhibit 10.3 to our current report on Form 8-K filed on October 19, 2009 | ||
10.31
|
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 | ||
10.32
|
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 | ||
10.33
|
Form of Indemnification Agreements* | Exhibit 10.2 to our current report on Form 8-K filed on February 24, 2010 | ||
10.34
|
GM Offshore, Inc. Supplemental Income Plan effective as of January 1, 2000* | Filed herewith | ||
10.35
|
Split-Dollar Insurance Agreement (Collateral Assignment) dated January 1, 2000, between GM Offshore, Inc. and Bruce A. Streeter* | Filed herewith | ||
10.36
|
Participation Agreement Supplemental Income Plan of GulfMark Offshore Inc. dated January 1, 2000 by Bruce A. Streeter* | Filed herewith | ||
10.37
|
Amendment One to Participation Agreement Supplemental Income Plan of GulfMark Offshore, Inc. dated December 28, 2010, between GulfMark Offshore, Inc. and Bruce A. Streeter* | Filed herewith | ||
10.38
|
Split-Dollar Insurance Agreement (Collateral Assignment) dated January 1, 2000, between GM Offshore, Inc. and John E. Leech* | Filed herewith | ||
10.39
|
Participation Agreement Supplemental Income Plan of GulfMark Offshore Inc. dated January 1, 2000 by John E. Leech* | Filed herewith | ||
10.40
|
Amendment One to Participation Agreement Supplemental Income Plan of GulfMark Offshore, Inc. dated December 29, 2010, between GulfMark Offshore, Inc. and John E. Leech* | Filed herewith | ||
10.41
|
U.S. $25.0 million Secured Reducing Revolving Loan Facility Agreement between GulfMark Offshore, Inc. and DnB NOR Bank ASA and others dated June 1, 2006, as Amended and Restated by a First Supplemental Agreement dated June 5, 2008 | Exhibits 10.24 and 10.25 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008 |
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Table of Contents
10.42
|
U.S. $60.0 million Secured Reducing Revolving Loan Facility Agreement between Gulf Offshore N.S. Limited and DnB NOR Bank ASA and others dated June 1, 2006 | Exhibit 10.29 to our current report on Form 8-K filed on June 9, 2006 | ||
10.43
|
U.S. $30.0 million Secured Reducing Revolving Loan Facility Agreement between GulfMark Rederi AS and DnB NOR Bank ASA and others dated June 1, 2006 | Exhibit 10.30 to our current report on Form 8-K filed on June 9, 2006 | ||
10.44
|
U.S. $60.0 million Secured Reducing Revolving Loan Facility Agreement between GulfMark Marine Far East Pte. Ltd. And DnB NOR Bank ASA and others dated June 5, 2008 | Exhibit 10.26 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008 | ||
10.45
|
Membership Interest and Stock Purchase Agreement among GulfMark Offshore, Inc., Rigdon Marine Corporation, Rigdon Marine Holdings, L.L.C., all the members of Rigdon Marine Holdings, L.L.C., Sherwood Investment, L.L.C., John J. Tennant III Irrevocable Trust, Brian M. Bowman Irrevocable Trust, and Bourbon Offshore, dated May 28, 2008 | Exhibit 10.6 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008 | ||
10.46
|
Assignment and Assumption Agreement between GulfMark Offshore, Inc. and GulfMark Management, Inc., dated June 30, 2008 | Exhibit 10.7 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008 | ||
10.47
|
Non-Competition and Non-Solicitation Agreement between GulfMark Offshore, Inc. and Larry T. Rigdon, dated July 1, 2008 | Exhibit 10.8 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008 | ||
10.48
|
Operating Agreement and By-laws of Jackson Offshore, LLC, by and between Rigdon Marine Corporation, Lee Jackson, and Bourbon Offshore Holdings SAS, dated August 16, 2006 | Exhibit 10.9 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008 | ||
10.49
|
Delphin Marine Logistics Limited Joint Venture Agreement, by and between Rigdon Marine Corporation, Mariners Haven Limited and Delphin Marine Logistics Limited, dated February 29, 2008 | Exhibit 10.10 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008 | ||
10.50
|
U.S. $200.0 million Facility Agreement among GulfMark Americas, Inc., as borrower, GulfMark Offshore, Inc., as guarantor, The Royal Bank of Scotland plc, as arranger, as agent of the Finance Parties and as security trustee for the Secured Parties, and the lenders that are parties thereto, dated December 17, 2009 | Exhibit 10.1 to our current report on Form 8-K filed on December 17, 2009 | ||
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 UHY LLP | Filed herewith | ||
31.1
|
Section 302 Certification for B.A. Streeter | Filed herewith | ||
31.2
|
Section 302 Certification for Q.V. Kneen | Filed herewith | ||
32.1
|
Section 906 Certification furnished for B.A. Streeter | Filed herewith | ||
32.2
|
Section 906 Certification furnished for Q.V. Kneen | Filed herewith | ||
101
|
The following materials from GulfMark Offshore, Inc.s Annual Report on Form 10-K for the year ended December 31, 2010, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Stockholders Equity, (iv) Consolidated Statements of Comprehensive Income (Loss), (v) Consolidated Statements of Cash Flows and (vi) Notes to Consolidated Financial Statements, tagged as blocks of text. | Filed herewith |
81