Edgar Filing: GULFMARK OFFSHORE INC

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2011

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

Commission file number 001-33607

GulfMark Offshore, Inc.

(Exact name of Registrant as specified in its charter)


Delaware		76-0526032
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

10111 Richmond Avenue, Suite 340 Houston, Texas		77042
(Address of principal executive offices)		(Zip Code)

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

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


Class A Common Stock, $0.01 Par Value		New York Stock Exchange
(Title of each class)		(Name of each exchange on which registered)

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

None

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

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

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 ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation in S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ 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, 2011, the last business day of the registrant’s most recently completed second fiscal quarter was $1,037,584,831, calculated by reference to the closing price of $44.19 for the registrant’s common stock on the New York Stock Exchange on that date.

Number of shares of Class A common stock outstanding as of February 22, 2012: 26,619,163

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 73

TABLE OF CONTENTS


		Page
PART I
Items 1 and 2.	Business and Properties		3
	General Business		3
	Worldwide Fleet		4
	Operating Segments		9
	Other		12
Item 1A.	Risk Factors		15
Item 1B.	Unresolved Staff Comments		22
Item 3.	Legal Proceedings		22
Item 4.	Mine Safety Disclosures		22

PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		22
Item 6.	Selected Consolidated Financial Data		24
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		26
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		39
Item 8.	Financial Statements and Supplementary Data		41
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		70
Item 9A.	Controls and Procedures		70
Item 9B.	Other Information		72

PART III
Item 10.	Directors, Executive Officers and Corporate Governance		72
Item 11.	Executive Compensation		72
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		72
Item 13.	Certain Relationships and Related Transactions, and Director Independence		72
Item 14.	Principal Accounting Fees and Services		72

PART IV
Item 15.	Exhibits, Financial Statement Schedules		73

PART I

ITEMS 1. and 2. Business and Properties

GENERAL BUSINESS

The Company

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, with New GulfMark as the surviving corporation (such transaction, the “Reorganization”). The Reorganization was adopted by the stockholders and New GulfMark changed its name from “New GulfMark Offshore, Inc.” to “GulfMark Offshore, Inc”. The business, operations, assets and liabilities of New GulfMark after the Reorganization are the same as business, operations, assets and liabilities of Old GulfMark immediately prior to the Reorganization. The Reorganization was effected primarily to better position us to benefit from and adhere to U.S. maritime laws and regulations.

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 currently operate a fleet of 91 offshore supply vessels (“OSVs”) in the following regions: 41 vessels in the North Sea, 15 vessels offshore Southeast Asia, and 35 vessels offshore the Americas. Our fleet is one of the world’s youngest, largest and most geographically balanced, high specification OSV fleets. Our owned vessels have an average age of approximately eight years.

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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Segment Results” included in Part II, Item 7, and Note 13 to our Consolidated Financial Statements included in Part II, Item 8.

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

Our principal executive offices are located at 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 Securities and Exchange Commission (“SEC”). This annual report on Form 10-K for the year ended December 31, 2011 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 SEC’s 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 SEC’s 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.

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 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 a combination of multi-national and regional competitors.

Our business is directly impacted by the level of activity in worldwide offshore oil and natural gas exploration, development and production, which in turn is influenced by trends in oil and natural gas prices. In addition, oil and natural gas prices are affected by a host of geopolitical and economic forces, including the fundamental principles of supply and demand. The characteristics and current

marketing environment in each region are discussed later in greater detail. Each of the major geographic offshore oil and natural gas production regions has unique characteristics that influence the economics of exploration and production and, consequently, the market demand for vessels in support of these activities. While there is some vessel interchangeability between geographic regions, barriers such as mobilization costs, vessel suitability and cabotage restrict migration of some vessels between regions. This is most 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.

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, 2010:


	Owned Vessels	Managed Vessels	Total Fleet
December 31, 2010	74	14	88

New-Build Program	—	—	—
Vessel Additions	—	4	4
Vessel Dispositions	(1)	(1)	(2)

December 31, 2011	73	17	90

New-Build Program	—	—	—
Vessel Additions	1	1	2
Vessel Dispositions	(1)	—	(1)

February 23, 2012	73	18	91

Vessel Classifications

Offshore supply 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 Supply Vessels (PSVs) serve drilling and production facilities and support offshore construction and maintenance work. They are differentiated from other offshore supply 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 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		—		18		2		—		—		1		24
Southeast Asia		8		3		2		1		—		—		—		14
Americas		3		—		3		21		4		3		1		35

		14		3		23		24		4		3		2		73

Vessel Construction and Acquisitions

We did not take delivery of any new-build vessels in 2011. Subsequent to December 31, 2011, we purchased a vessel for operation in the Americas region for a total price of $22.3 million.

In the third quarter of 2011, our Board of Directors approved the initiation of a new-build construction program. We began the program in the North Sea region where we contracted with three shipyards to build a total of six new platform supply vessels. Remontowa Shipbuilding SA (“Remontowa”), a Polish company, will build three vessels, Rosetti Marino S.p.A. (“Rosetti Marino”), an Italian company, will build two vessels and Simek A/S (“Simek”), a Norwegian company, will build one vessel. The estimated total cost of these initial six vessels is $245.0 million. In addition, in late 2011, we exercised an option under the Simek contract to build an additional vessel with essentially the same specifications as the vessel currently under construction. The cost of the additional vessel is estimated at $60.9 million. Our agreements also include additional options that expire in the first quarter 2012, to build four more vessels. The Remontowa and Rosetti Marino contracts are denominated in Euros and the Simek contract is denominated in Norwegian Kroner. The first of these vessels is scheduled to be delivered in the second quarter of 2013 and the last is scheduled to be delivered in the first quarter of 2014. All seven vessels currently under construction are capable of international operations and will be managed from our North Sea region.

The following table details our new-build program as of December 31, 2011:


Construction Yard	Region	Type⁽¹⁾	Expected Delivery	Length (feet)	BHP⁽²⁾	DWT⁽³⁾	Expected Cost
							(in millions)
Remontowa	North Sea	LgPSV	Q2 2013	291	9120	5100	$41.0
Remontowa	North Sea	LgPSV	Q3 2013	291	9120	5100	$41.1
Remontowa	North Sea	LgPSV	Q3 2013	260	9120	4000	$37.7
Rosetti Marino	North Sea	LgPSV	Q4 2013	246	7483	3000	$32.1
Rosetti Marino	North Sea	LgPSV	Q2 2014	246	7483	3000	$32.1
Simek	North Sea	LgPSV	Q2 2013	304	11265	4700	$60.9
Simek	North Sea	LgPSV	Q3 2013	304	11265	4700	$60.9

⁽¹⁾

LgPSV—Large Platform Supply Vessel

⁽²⁾

BHP—Breakhorse Power

⁽³⁾

DWT—Deadweight Tons

Vessel Divestitures / Vessels Held For Sale (Laid Up)

We sold one of our North Sea vessels in the fourth quarter of 2011 and one of our Americas vessels subsequent to December 31, 2011. As of February 23, 2012, we have one vessel that is held for sale and is not included in our active fleet numbers.

Vessels Sold Since December 31, 2010

Vessel

Region

Type

Year

Built

Length

(feet)

BHP

DWT

Month

Sold

Highland Pioneer

N. Sea

LgPSV

1983

224

5,400

2,500

Oct-11

Bluefin

Americas

Crew

2008

165

7,200

337

Jan-12

Vessels Held for Sale (Laid Up)

Vessel

Region

Type

Year

Built

Length

(feet)

BHP

DWT

Clywd 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 2011 totaled $15.9 million. We anticipate approximately $29.0 million in drydocking expenditures in 2012. We had 24 drydocks in 2011 and anticipate 35 drydocks in 2012. A substantial number of the vessels acquired in our acquisition of Rigdon Marine Corporation and Rigdon Marine Holdings, LLC in July 2008 (the “Rigdon Acquisition”) are due for drydocks this year. In addition, a large number of North Sea vessels, each with drydock cost estimates in excess of $1.0 million are due for drydock as well.

Vessel Listing

Currently, we operate a fleet of 91 vessels. Of these vessels, 73 are owned by us (see table below, which excludes laid up vessels and the 18 vessels we manage for other owners).


Owned Vessel Fleet
Vessel	Region	Type (a)	Year Built	Length (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	Malta
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	Malta
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	2,700	Panama
Highland Warrior	Americas	LgPSV	1981	265	5,300	2,450	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


		Owned Vessel Fleet
Vessel	Region	Type (a)	Year Built	Length (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
Jermaine Gibson	Americas	PSV	2008	190	3,894	1,860	USA
Homerun	Americas	PSV	2008	225	3,894	2,371	USA
Knockout	Americas	PSV	2008	225	3,894	2,371	USA
Hammerhead	Americas	FSV	2008	181	7,200	543	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
Thomas Wainwright (f)	Americas	PSV	2010	242	4,200	2,700	USA

The table above does not include the managed vessels or 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

(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 charterer’s 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.

(f)	Purchased on January 19, 2012.

OPERATING SEGMENTS

The North Sea Operating Segment


	Owned Vessels			Managed Vessels		Total Fleet
December 31, 2010		25			12		37

New-Build Program		—			—		—
Vessel Additions		—			4		4
Vessel Dispositions		(1	)		—		(1	)

December 31, 2011		24			16		40

New-Build Program		—			—		—
Vessel Additions		—			1		1
Vessel Dispositions		—			—		—

February 23, 2012		24			17		41

Market and Segment Overview

We define the North Sea market as offshore Norway, Great Britain, the Netherlands, Denmark, Germany, 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 operations 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 supply 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

Vessel demand in the North Sea 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.

Exploration and development spending in the North Sea region increased in 2011 and is expected to continue to rise in 2012, increasing offshore drilling and subsea construction activity and demand for vessel services in this region.

The Southeast Asia Operating Segment


	Owned Vessels		Managed Vessels		Total Fleet
December 31, 2010		14		1		15

New-Build Program		—		—		—
Vessel Additions / (Reductions)		—		—		—
Vessel Dispositions		—		—		—

December 31, 2011		14		1		15

New-Build Program		—		—		—
Vessel Additions / (Reductions)		—		—		—
Vessel Dispositions		—		—		—

February 23, 2012		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, Malaysia and Thailand.

Southeast Asia’s 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.

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. During the last five years, we have sold 11 of our older vessels serving Southeast Asia and have taken delivery of 12 new-builds significantly decreasing the age of our fleet and increasing our capabilities.

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. Overall, Southeast Asia is a dynamic market and from time to time certain types of vessels may be subject to more intense competition.

The Americas Operating Segment


	Owned Vessels			Managed Vessels			Total Fleet
December 31, 2010		35			1			36

New-Build Program		—			—			—
Vessel Additions		—			(1	)		(1	)
Vessel Dispositions		—			—			—

December 31, 2011		35			0			35

New-Build Program		—			—			—
Vessel Additions		1			—			1
Vessel Dispositions		(1	)		—			(1	)

February 23, 2012		35			0			35

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. 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 substantially recovered in the area and the government regulations that have been implemented since the moratorium continue to limit a recovery in the near future. We continue to evaluate the market conditions in each area, and the potential impact these conditions may have on our business. 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 and early 2011, primarily as a result of the substantially reduced drilling activity in the U.S. Gulf of Mexico as a result of the Macondo Incident we transferred nine vessels, in total, to Brazil, Mexico and Trinidad to work on long term contracts. All vessels based in the Americas are supported from our onshore bases in Louisiana; Trinidad; Brazil; and 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 dynamically positioned vessels (“DP-2”) 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. United States law requires that all vessels engaged in Coastwise Trade in the U.S. (which includes vessels servicing rigs and platforms in U.S. waters within the Exclusive Economic Zone), must be owned and managed by U.S. citizens, and be built in and registered under the laws of the United States. “Coastwise Trade”, as defined under the U.S. maritime and vessel documentation laws commonly referred to as the Jones Act, allows only those vessels that are owned and managed by U.S. citizens (as determined by those laws) and built in and registered under the laws of the United States to transport merchandise and passengers for hire between ports in U.S. territorial waters.

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 supply 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 supply vessel opportunities as they develop.

As of December 31, 2011, we operated nine vessels in Brazil, including a Brazilian built and flagged vessel. We had 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 for work outside of our industry. In the first quarter of 2012, one of the AHTSs came off contract and is now in transit to our SEA region.

Mexico

Since 2005, we have operated two AHTSs offshore Mexico on long-term contracts with Pemex, Mexico’s national oil company. 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. We sold the crew boat in January 2012. 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 international operators with five PSVs and three FSVs on term charters in the area as of December 31, 2011. During 2010 and early 2011, we moved several vessels into the area from the U.S. Gulf of Mexico. In the first quarter of 2012, two of the vessels came off contract and are now back in the U.S. Gulf of Mexico. Given recent licensing and exploration activity in nearby locations, including Suriname and Guyana, we expect to see supply vessels 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 deliveries to offshore platforms. Vessels operating offshore Southeast Asia are generally at their lowest utilization rates during the monsoon season, which moves across the Asian continent between September and early March. The monsoon season for a specific Southeast Asian location is generally about two months. Activity in the U.S. Gulf of Mexico is often lower during the North Atlantic hurricane season of June through November 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 22, 2012 and February 24, 2011:


	As of February 22, 2012						As of February 24, 2011
	2012 Vessel Days			2013 Vessel Days			2011 Vessel Days			2012 Vessel Days
North Sea		68.0	%		53.1	%		75.5	%		55.4	%
Southeast Asia		41.3	%		14.7	%		49.8	%		22.7	%
Americas		32.3	%		15.0	%		56.0	%		29.4	%

Overall Fleet		44.0	%		24.7	%		61.3	%		36.7	%

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.

Customers, Contract Terms and Competition

Our principal customers are major integrated oil and natural gas companies, large independent oil and natural gas exploration and production companies working in international markets, and foreign government-owned or controlled oil and natural gas companies. Additionally, our customers also include companies that provide logistic, construction and other services to such oil and natural gas companies and foreign government organizations. Generally, our contracts are industry standard time charters for periods ranging from a few days or months up to ten years. Contract terms vary and often are similar within geographic regions with certain contracts containing cancellation provisions and others containing non-cancellable provisions except for unsatisfactory performance by the vessel. For the year ended December 31, 2011, our revenue with Petrobras, one of our customers, exceeded 10% of our total consolidated revenue. No single customer accounted for 10 percent or more of our total consolidated revenue for 2010 or 2009.

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 18 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$; Brazilian Reais, or BRL; or Singapore Dollars, or SGD. We attempt to reduce currency risk by matching each vessel’s 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 Custom and Border Protection (CBP), and their foreign equivalents, and to regulation by private industry organizations such as the American Bureau of Shipping and Det Norske Veritas. The Coast Guard and the National Transportation Safety Board set safety standards and are authorized to investigate vessel accidents and recommend improved safety standards, while the CBP is authorized to inspect vessels at will. We believe that we are in substantial 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 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.

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

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

Litigation

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

Employees

We have approximately 1,700 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 780 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; Thailand; and Kemaman and 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; Trinidad; and St. Rose and Youngsville, Louisiana. Our operations generally do not require highly specialized facilities, and suitable facilities are generally available on a lease basis as required.

ITEM 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. A decline in exploration and development of offshore areas may result in a 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 supply vessels would likely have a negative effect on charter rates for our vessels, which could reduce our earnings.

Charter rates for marine supply 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 or a particular offshore market 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 with certainty the future costs or other future impact of these laws on our operations and our customers. We could also incur substantial costs, including cleanup costs, fines, civil or criminal sanctions and third party claims for property damage or personal injury as a result of violations of, or liabilities under, environmental laws and regulations. In addition, there can be no assurance that we can avoid significant costs, liabilities and penalties imposed on us as a result of government regulation in the future.

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

Our international operations require us to comply with a number of U.S. and international laws and regulations, including those involving anti-bribery and anti-corruption. In order to effectively operate in certain foreign jurisdictions, circumstances may require that we establish joint ventures with local operators or find strategic partners. As a U.S. corporation, we are subject to the regulations imposed by the Foreign Corrupt Practices Act (FCPA), which generally prohibits U.S. companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or keeping business or obtaining an improper business benefit. We have an ongoing program of proactive procedures to promote compliance with the FCPA and other similar anti-bribery and anti-corruption laws, but we may be held liable for actions taken by our strategic or local partners or agents even though these partners or agents may not themselves be subjected to the FCPA or other similar laws. Any determination that we have violated the FCPA or other similar laws could have a material adverse effect on our business, results of operations, and cash flows.

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

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

•

catastrophic marine disaster;

•

adverse sea and weather conditions;

•

mechanical failure;

•

navigation errors;

•

collision;

•

oil and hazardous substance spills, containment and clean up;

•

labor shortages and strikes;

•

damage to and loss of drilling rigs and production facilities; 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 2012-2013. We can provide no assurance, however, that our insurance coverage will be available beyond the renewal periods, or that it will be adequate to cover future claims that may arise.

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

We have a substantial amount of indebtedness which could:

•

increase our vulnerability to general adverse economic and industry conditions;

•

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

•

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

•

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

•

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

•

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

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

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, should we increase our operations in high tax jurisdictions where we operate, and/or should we elect to repatriate cash from our foreign operations in amounts higher than recent years.

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

For example, our North Sea operations based in the U.K. and Norway have special tax incentives for qualified shipping operations, commonly referred to as tonnage tax, which provides for a tax based on the net tonnage capacity of 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 June 2010 Norway’s 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 elected annual installment payments of one-third of the tax that is calculated as ten percent (10%) of two-thirds of the untaxed tonnage tax profits with the third payment in 2013. 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.

In addition, our reported tax expense reflects our intention to permanently reinvest a significant portion of the current earnings from our foreign operations and therefore those earnings are not subject to U.S. taxation. In the future, we may elect to decrease the portion of annual foreign earnings we intend to permanently reinvest, and, if so, this would increase our overall effective tax rate upwards towards the U.S. federal statutory rate, which is currently 35%. Although we have neither the need nor the inclination to change our current intention, if we should change our intention with regard to our prior years accumulated unremitted foreign earnings, we would recognize a charge to current earnings to reflect the effect of U.S. taxation on those prior years’ unremitted foreign earnings and that charge would be significant and material.

Our income tax expense, or benefit, and effective tax rate are impacted by inclusion of related U.S. earnings, or losses, taxed at the combined U.S. federal and state tax rates. 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 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. Also, customers may prefer modern vessels over older vessels, especially in weaker markets. The cost of adding a new vessel to our fleet ranges from under $10 million to $100 million and potentially higher.

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

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

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

•

price, service and reputation of vessel operations and crews;

•

national flag preference;

•

operating conditions;

•

suitability of vessel types;

•

vessel availability;

•

technical capabilities of equipment and personnel;

•

safety and efficiency;

•

complexity of maintaining logistical support; and

•

cost of moving equipment from one market to another.

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

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

Operations in the North Sea are generally at their highest levels during the months from April through August and at their lowest levels from December through February primarily due to lower construction activity and harsh weather conditions 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 established to comply with the Jones Act 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 stockholders to transfer or purchase shares of our Class A common stock;

•

provide for the automatic transfer of shares in excess of the maximum permitted percentage (“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.

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 be in compliance with the Jones Act in the future.

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

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

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

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

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

The 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. For example, 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 these or other regulatory matters, increased energy, environmental and other costs and capital expenditures could be necessary to comply with the relevant limitations. Our vessels also operate in foreign jurisdictions that are addressing climate changes by legislation or regulation. Unless and until legislation or regulations are enacted and 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 demand for our services which in part 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.

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 in April 2010 effectively caused the cessation of 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 and proposed government regulations could limit the possibility of a recovery in the near future.

It remains uncertain what impact the incident itself 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. Significant changes in legislation governing our business could have a material adverse effect on our business, financial condition and results of operation.

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.

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.

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.

Mine Safety Disclosures

NOT APPLICABLE

PART II

ITEM 5.

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

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


	2011				2010
	High		Low		High		Low
Quarter ended March 31,	$	47.00	$	30.30	$	29.77	$	23.79
Quarter ended June 30,	$	44.79	$	38.25	$	34.47	$	24.56
Quarter ended September 30,	$	49.20	$	32.97	$	30.95	$	25.69
Quarter ended December 31,	$	45.89	$	34.53	$	33.53	$	29.25

For the period from January 1, 2012 through February 22, 2012, the range of low and high closing prices of our common stock was $42.21 to $51.13, respectively. On February 22, 2012, the closing sale price of our Class A common stock as reported by the NYSE was $50.12 per share and there were 504 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, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Long-Term Debt” and Note 5 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 our 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 8 of the “Notes to the Consolidated Financial Statements” in Part II, Item 8 herein.

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, 2006.

Comparison of Cumulative Total Return

LOGO


	2006		2007		2008		2009		2010		2011
GulfMark Offshore, Inc.		100		127		65		76		80		109
Dow Jones Total Market Index		100		106		67		83		96		96
Dow Jones Oilfield Equipment and Services Index		100		145		59		90		111		97

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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, included in Part II, Item 7.


	Year Ended December 31,
	2011			2010			2009			2008			2007
	(Amounts in thousands, except per share amounts)
Operating Data:
Revenue	$	381,870		$	359,766		$	388,871		$	411,740		$	306,026
Direct operating expenses		182,585			170,638			166,183			143,925			108,386
Drydock expense		15,932			22,182			15,696			11,319			12,606
General and administrative expenses		45,495			44,029			43,700			40,244			32,311
Depreciation and amortization		59,586			56,959			53,044			44,300			30,623
Impairment charge		1,750			97,665			46,247			—			—
Gain on sale of assets		(2,018	)		(5,095	)		(5,552	)		(34,811	)		(12,169	)

Operating income (loss)		78,540			(26,612	)		69,553			206,763			134,269
Interest expense		(22,314	)		(21,693	)		(20,281	)		(14,291	)		(7,923	)
Interest income		748			985			377			1,446			3,147
Foreign currency gain (loss) and other		(2,346	)		(126	)		(1,153	)		1,609			(298	)
Income tax (provision) benefit (a)		(4,694	)		12,701			2,087			(11,743	)		(30,220	)


Net income (loss)	$	49,934		$	(34,745	)	$	50,583		$	183,784		$	98,975

Amounts per common share (basic) (b):
Net income (loss)	$	1.92		$	(1.36	)	$	1.98		$	7.65		$	4.36

Weighted average common shares (basic)		25,828			25,519			25,151			23,737			22,435

Amounts per common share (diluted) (b):
Net income (loss)	$	1.91		$	(1.36	)	$	1.96		$	7.47		$	4.24

Weighted average common shares (diluted)		25,962			25,519			25,447			24,319			23,059

Statement of Cash Flows Data:
Cash provided by operating activities	$	97,471		$	91,574		$	171,045		$	205,201		$	128,577
Cash used in investing activities		(49,408	)		(53,857	)		(68,199	)		(186,787	)		(175,383	)
Cash provided by (used in) financing activities		(16,231	)		(32,837	)		(120,250	)		56,754			373
Effect of exchange rate changes on cash		(210	)		236			8,722			(14,526	)		3,793
Other Data:
Adjusted EBITDA (c)	$	139,876		$	128,012		$	168,844		$	251,063		$	164,892
Cash dividends per share		—			—			—			—			—
Total vessels in fleet as of year end (d)		90			88			92			94			61
Average number of owned or chartered vessels (e)		73.8			73.4			71.3			59.5			46.8


	As of December 31,
	2011		2010		2009		2008		2007
	(In thousands)
Balance Sheet Data:
Cash and cash equivalents	$	128,817	$	97,195	$	92,079	$	100,761	$	40,119
Vessels, equipment and other fixed assets, including construction in progress, net		1,180,548		1,194,200		1,204,416		1,169,513		754,000
Total assets		1,499,799		1,468,649		1,565,659		1,556,967		934,012
Long-term debt (f)		305,830		293,095		326,361		462,941		159,558
Total stockholders’ equity		996,860		945,957		987,468		854,843		676,091

(a)	See Note 6 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 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, financing–related 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,
	2011			2010			2009			2008			2007
	(In thousands)
Net income (loss)	$	49,934		$	(34,745	)	$	50,583		$	183,784		$	98,975
Interest expense		22,314			21,693			20,281			14,291			7,923
Interest income		(748	)		(985	)		(377	)		(1,446	)		(3,147	)
Income tax provision (benefit)		4,694			(12,701	)		(2,087	)		11,743			30,220
Depreciation, amortization and impairment		61,336			154,624			99,291			44,300			30,623

EBITDA		137,530			127,886			167,691			252,672			164,594
Adjustments:
Other *		2,346			126			1,153			(1,609	)		298

Adjusted EBITDA	$	139,876		$	128,012		$	168,844		$	251,063		$	164,892

*	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 “Worldwide 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.

ITEM 7.

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

This information should be read in conjunction with our Consolidated Financial Statements, including the notes thereto, contained in Part II, Item 8 “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. In addition, we will sell 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 91 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 23, 2012, our active fleet includes 73 owned vessels and 18 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 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 management’s 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.

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.

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 Norway’s 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, Norway’s 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 a $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 remaining liability to settle under the simplified tax system is included in our December 31, 2011 balance sheet as $1.8 million current income tax payable and $1.8 million as other long term payable. Annually the subsequent year’s 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.

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 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 6 to our Consolidated Financial Statements included in Part II, Item 8.

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. In assessing goodwill for impairment, we analyze certain qualitative factors that affect the value, including goodwill, of a segment. 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 based on certain qualitative factors. If those factors indicate that it is more likely than not that impairment of goodwill has occurred, we will proceed to step one of the goodwill impairment process. Under step one, 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.

We have classified one of our North Sea vessels as an asset held for sale. In the fourth quarter of 2011, we determined that the carrying value of this asset was less than our estimate of the amount we would realize in a sale. As a result, we reduced the carrying value by $1.8 million. This amount is included in our results of operations as an impairment charge.

In our 2008 Rigdon Acquisition, we made a significant acquisition of vessels in the U.S. Gulf of Mexico component of our Americas region. In conjunction with the acquisition, we recorded $97.7 million of goodwill. In the second quarter of 2010, we assessed our Americas region goodwill for impairment. In our assessment, we evaluated the impact on the segment’s 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 did 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.

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.

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.

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, 2011 and 2010 we provided an allowance for doubtful accounts of $0.2 million and $0.3 million, respectively. Additional allowances for doubtful accounts may be necessary as a result of our ongoing assessment of our customers’ ability to pay, particularly in the event of 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.

Commitments and Contingencies

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

We have recently been made aware that a Brazilian state in which we have operated vessels has asserted that certain companies could be assessed for state import taxes with respect to vessels that have operated within Brazilian coastal waters. We have neither been formally assessed nor threatened with this tax. No accrual has been recorded as of December 31, 2011 for any liabilities associated with a possible future assessment. We cannot predict whether any such tax assessment may be made in the future.

Multi-employer Pension Obligation

is calculated by an actuarial firm every three years. The last assessment was completed in March 2009 and indicated that the funding level of the MNOPF at that date was between 65 and 80%. The MNOPF annual report dated March 31, 2011, stated that the funding level had improved to over 80% as of that date. The amount and timing of additional potential future obligations relating to underfunding depends on a number of factors, but principally on future fund performance and the underlying actuarial assumptions. Our share of the fund’s deficit is dependent on a number of factors including future actuarial valuations, asset performance, the number of participating employers, and the final method used in allocating the required contribution among participating employers. In addition, our obligation could increase if other employers no longer participated in the plan. We made contributions to the plan of $0.3 million, $0.6 million and $0.5 million for the years ended December 31, 2011, 2010 and 2009, respectively. Our contributions do not make up more than five percent of total contributions to the plan.

Cancellation of Split Dollar Life Insurance Plans

In June 2011, we cancelled the split dollar insurance agreements (the “Collateral Assignments”) under which we paid the split-dollar life insurance policy premiums (the “Premiums”) for our President and Chief Executive Officer and our Executive Vice President – Operations. Upon cancellation and pursuant to the term of the Collateral Assignments, we were repaid the Premiums by each covered individual and are no longer obligated to make any future premium payments on the policies. We continue to have a supplemental income plan with participation agreements, as amended, for each covered individual under which we will provide each covered individual, six months after retirement with the Company, a cash payment equal to the Premiums.

Off-Balance Sheet Arrangements

We have evaluated our off-balance sheet arrangements, 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, 2011 and December 31, 2010

Our consolidated revenue increased from $359.8 million to $381.9 million, or $22.1 million, primarily due to higher day rates in the North Sea and Americas regions. For the year ended December 31, 2011, we had net income of $49.9 million, or $1.91 per diluted share, compared to a net loss of $34.7 million, or $1.36 per diluted share, for the year ended December 31, 2010.

The increase in revenue was primarily the result of increased day rates and the foreign currency impact of a weaker U.S. Dollar. Day rates increased 5.6% in 2011, from $15,758 in 2010 to $16,642 in 2011, contributing $14.6 million to the increase in revenue. The weakening of the U.S. Dollar and other currency movements contributed $8.2 million to the revenue increase. This increase was offset by a small decrease in utilization from 85.5% in 2010 to 85.3% in 2011, decreasing revenue by $0.5 million. Capacity effects decreased revenue by $0.2 million.


	Year Ended December 31,
							Increase
	2011			2010			(Decrease)
	(Dollars in thousands)
Average Rates Per Day Worked (a) (b):
North Sea (c)	$	20,071		$	16,985		$	3,086
Southeast Asia		15,053			16,943			(1,890	)
Americas		14,526			14,281			245
Overall Utilization (a) (b):
North Sea (c)		92.4	%		93.5	%		(1.1	)%
Southeast Asia		85.1	%		84.7	%		0.4	%
Americas		80.5	%		80.1	%		0.4	%
Average Owned or Chartered Vessels (a) (d):
North Sea		24.8			25.1			(0.3	)
Southeast Asia		14.0			13.0			1.0
Americas		35.0			35.3			(0.3	)

Total		73.8			73.4			0.4

(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,
	2011		2010
$1 US=GBP		0.623		0.647
$1 US=NOK		5.600		6.036
$1 US=Euro		0.718		0.754

(d)	Adjusted for vessel additions and dispositions occurring during each period.

Direct operating expenses increased by $11.9 million during 2011 mainly due to an increase in crew salaries and benefits and the foreign currency impact of the weaker U.S. Dollar. In 2011, we recorded a $1.8 million impairment charge to adjust the net realizable value of a North Sea vessel that is held for sale. In 2010, we recorded a $97.7 million dollar impairment of our goodwill as a result of the deteriorating market conditions in the U.S. Gulf of Mexico. Drydock expense decreased by $6.3 million from 2010 to 2011 due to a lower number of drydocks. We had 24 vessels that were drydocked in 2011 compared to 30 in 2010. General and administrative expenses increased by $1.5 million from 2010 due mainly to the increase in salaries and benefits. Depreciation expense increased by $2.6 million year over year as a result of currency effects and our ongoing effort to reduce the average age of our vessel fleet. The gain on sale of assets relates to the sale of one of our North Sea vessels during 2011.

Interest expense increased $0.6 million year over year due mainly to the decrease in capitalized interest resulting from a smaller portion of the year with vessels under construction during 2011 compared to 2010. Interest income decreased $0.2 million due to lower cash amounts available for investment and other expense increased by $2.2 million as a result of foreign currency movements throughout 2011.

The income tax expense for 2011 was $4.7 million, compared to a benefit of $12.7 million from 2010. The 2011 effective tax rate was 8.6% and the 2010 effective tax rate was 26.8%. The 2011 tax expense is primarily due to our mix of profitability in our tax jurisdictions. 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, 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 $1.96 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.


	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 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)


	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.

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 2011, we had $80.8 million in revenue and $393.1 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 segment’s operating performance from its continuing operations, because it represents the results of the ownership interest in operations without regard to financing methods or capital structures. Each segment’s operating income (loss) is summarized in the following table, and further detailed in the following paragraphs.

Operating Income (Loss) by Operating Segment


	Year Ended December 31,
	2011			2010			2009
	(In thousands)
North Sea	$	50,916		$	38,209		$	54,014
Southeast Asia		35,287			39,761			58,105
Americas		16,397			(81,223	)		(19,155	)

Total reportable segment operating income (loss)		102,600			(3,253	)		92,964
Other		(24,060	)		(23,359	)		(23,411	)

Total reportable segment and other operating income (loss)	$	78,540		$	(26,612	)	$	69,553

North Sea Region:


	Year Ended December 31,
	2011			2010			2009
	(In thousands)
Revenue	$	172,393		$	148,740		$	165,415
Direct operating expenses		81,528			78,253			80,854
Drydock expense		8,563			7,598			6,818
General and administrative expense		12,169			11,277			10,598
Depreciation and amortization expense		19,495			18,649			17,186
Impairment charge		1,750			—			—
Gain on sale of assets		(2,028	)		(5,246	)		(4,055	)

Operating income	$	50,916		$	38,209		$	54,014

Comparison of Fiscal Year Ended December 31, 2011 and December 31, 2010

Revenue for the North Sea increased $23.7 million, or 15.9%, compared to 2010. The increase in day rates from $16,985 in 2010 to $20,071 in the current year contributed $18.7 million to the increase in revenue. Currency and other movements as a result of the weakening of the U.S. Dollar contributed $8.4 million to the increase in revenue in 2011. This increase was offset by decreased utilization and capacity during 2011. Utilization decreased in the current year to 92.4% from 93.5% in 2010, resulting in a decrease to revenue of $0.9 million. Decreased capacity from the sale of a vessel in 2010 and another one late in 2011 offset by the delivery of a new-build vessel in early 2010, negatively impacted revenue by $2.5 million compared to the prior year. Operating income of $50.9 million in 2011 was $12.7 million higher than 2010 due to the increase in revenues offset by higher operating costs and lower gains on asset sales in 2011. Direct operating expenses were higher by $3.3 million in 2011 due to the higher crew salaries combined with the impact of the weakening of the U.S. Dollar. Drydock expense increased $1.0 million from 2010 due to a higher drydock cost per day. Depreciation expense increased year over year by $0.8 million primarily due to currency effects. In 2011, we wrote down the value of an asset held for sale by $1.8 million to properly reflect net realizable value. General and administrative expense increased by $0.9 million due primarily to the increase in salaries and professional fees.

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

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.

Southeast Asia Region:


	Year Ended December 31,
	2011		2010		2009
	(In thousands)
Revenue	$	63,754	$	66,533	$	76,544
Direct operating expenses		12,006		10,395		8,865
Drydock expense		3,871		4,796		2,095
General and administration expense		2,852		2,659		1,841
Depreciation and amortization expense		9,738		8,922		7,131
Gain on sale of assets		—		—		(1,493	)

Operating income	$	35,287	$	39,761	$	58,105

Comparison of Fiscal Year Ended December 31, 2011 and December 31, 2010

Revenues for the Southeast Asia based fleet decreased by $2.8 million to $63.8 million in 2011. Day rates decreased from $16,943 in 2010 to $15,053 in the current year, which decreased revenue by $8.1 million. This was offset by an increase in utilization from 84.7% in 2010 to 85.1% in 2011, contributing $1.7 million to revenue. Capacity had a positive impact to revenue of $3.6 million compared to 2010 as a result of the full year effect of two new-build vessels added in 2010. Operating income was lower during 2011 by $4.5 million, due mainly to the lower revenue, coupled with increases to direct operating expense and depreciation expense resulting primarily from the full year effect of the increased fleet. Drydock expense decreased by $0.9 million as a result of fewer drydock days in 2011. General and administrative expense increased by $0.2 million as a result of higher office salaries and benefits and higher bad debt expense.

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.

Americas Region:


	Year Ended December 31,
	2011		2010			2009
	(In thousands)
Revenue	$	145,723	$	144,493		$	146,912
Direct operating expenses		89,051		81,990			76,464
Drydock expense		3,498		9,788			6,783
General and administrative expense		8,376		7,798			8,685
Depreciation and amortization expense		28,391		28,321			27,892
(Gain) loss on sale of assets		10		154			(4	)
Impairment charge		—		97,665			46,247

Operating income (loss)	$	16,397	$	(81,223	)	$	(19,155	)

Comparison of Fiscal Year Ended December 31, 2011 and December 31, 2010

Our Americas region revenue increased $1.2 million from 2010. Day rates increased from $14,281 in 2010 to $14,526 in 2011, which contributed $3.9 million to the increase in revenue. Capacity had a negative revenue impact of $1.4 million as a result of the full year effect of the sale of one of our older vessels during the second quarter of 2010. Utilization increased from 80.1% in 2010 to 80.5% in 2011, however, due to the mix of higher utilization associated with lower day rate contracts, the impact was a negative $1.3 million. Excluding the impairment charge of $97.7 million in 2010, operating income was unchanged in 2011 compared to 2010 as the increase in revenue was effectively offset with higher operating expenses. Operating expenses increased from the prior year due mainly to an increase in crew salaries and benefits. Drydock expense was lower in 2011 by $6.3 million as we incurred 79 fewer drydock days during the current year. General and administrative expense increased by $0.6 million due mainly to increased salaries and benefits, primarily in Brazil.

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 a negative impact on revenue of $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.

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-build 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.

In the third quarter of 2011, our Board of Directors approved the initiation of a new-build construction program. We began the program in the North Sea region where we contracted with three shipyards to build a total of six new platform supply vessels. Remontowa will build three vessels, Rosetti Marino will build two vessels and Simek will build one vessel. The estimated total cost of these initial six vessels is $245.0 million. In addition, in late 2011, we exercised an option under the Simek contract to build an additional vessel with essentially the same specifications as the vessel currently under construction. The cost of the additional vessel is estimated at $60.9 million. Our agreements also include additional options that expire in the first quarter of 2012, to build four more vessels. The Remontowa and Rosetti Marino contracts are denominated in Euros and the Simek contract is denominated in Norwegian Kroner. The first of these vessels is scheduled to be delivered in the second quarter of 2013 and the last is scheduled to be delivered in the first quarter of 2014. All seven vessels currently under construction are capable of international operations and will be managed from our North Sea region.

Interest expense at current rates under our existing debt arrangements, assuming no additional borrowings, will be approximately $18.5 million for 2012. Minimum principal repayments under our existing debt arrangements will be approximately $1.7 million for 2012. 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 $29.0 million in 2012, an increase from the previous year total of $15.9 million. We had 24 drydocks in 2011 and anticipate 35 drydocks in 2012. A substantial number of the vessels acquired in our 2008 Rigdon Acquisition are due for drydocks this year. In addition, a large number of North Sea vessels, each with drydock cost estimates in excess of $1.0 million, are due for drydock as well.

Net working capital at December 31, 2011, was $178.9 million, including $128.8 million in cash. Net cash provided by operating activities was $97.5 million for the year ended December 31, 2011. For the year ended December 31, 2011, net cash used in investing activities was $49.4 million, and net cash used in financing activities was $16.2 million.

At December 31, 2011, we had approximately $128.8 million of cash on hand. We had $6.0 million drawn under our $175.0 million Revolving Loan Facility, $141.7 million borrowed under our Facility Agreement, and $160.0 million outstanding under our Senior Notes.

As of December 31, 2011, substantially all of our cash and cash equivalents were held by our foreign subsidiaries. It is our intention to permanently reinvest all of our earnings generated outside the U.S. prior to December 31, 2011 that through that date had not been remitted (unremitted earnings), and as such we have not provided for U.S. income tax expense on these unremitted earnings.

In recent years, we repatriated cash from our foreign subsidiaries from current year foreign earnings and recognized U.S. tax expense, net of available credits, on those occasions. The incremental tax rate associated with these repatriations is approximately 30% with no U.S. cash tax requirement due to utilization of U.S. net operating losses.

If any portion of the unremitted earnings were ever foreseen to not be permanently reinvested outside the U.S., or if we elect to repatriate additional current year foreign earnings, U.S. income tax expense would be required to be recognized and that expense could be material. Although subject to certain limitations, our U.S. net operating loss carryforwards and foreign tax credit carryforwards could be used to reduce a portion or all of the U.S. cash tax requirements of any such future foreign cash repatriations.

We believe that cash on hand, future cash flow from operations and unused borrowing capacity will be adequate to fund our debt payments, to fund the initial stages of our new-build program, to complete scheduled drydockings, to make normal recurring capital additions and improvements and to meet other operating and working capital requirements. This expectation, however, is dependent upon the success of our operations.

Long-Term Debt

Secured Reducing Revolving Loan Facility

We have a $175.0 million (of which $154.0 million was available for borrowing as of December 31, 2011) 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, 2011, we were in compliance with all covenants and had $6.0 million 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 101.292% of the principal amount and may be called on July 15, 2012 and thereafter at 100% of the principal amount, respectively, plus, in each case, 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, 2011, 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 was to mature on December 31, 2012. We have an interest rate swap agreement hedging 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 through December 31, 2012. This interest rate swap is accounted for as a cash flow hedge. On January 26, 2012, we entered into a funding agreement with RBS to amend the Facility Agreement primarily to extend the maturity to July 1, 2014 and adjust principal payments. The interest rate swap was not extended.

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 Borrower’s 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 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.

As a result of the amendment to our Facility Agreement on January 26, 2012, which extended the maturity of the facility, we have classified as long-term debt the portion of the obligation that was previously scheduled to mature during 2012. Under this agreement, we are not required to make any principal payments until maturity. The interest rate remains LIBOR plus 250 basis points. The $1.7 million difference between the amount currently outstanding and the amount of the refinance agreement was settled at closing. Refer to Note 5 “Long-Term Debt” in our Notes to Consolidated Financial Statements included in Part II, Item 8 for additional information on long-term debt.

Current Year Cash Flow

At December 31, 2011, we had cash on hand of $128.8 million. Cash provided by operating activities for the year ended December 31, 2011, was $97.5 million compared to $91.6 million in the previous year. The increase was primarily attributable to higher operating income resulting from the improving global market conditions.

Cash used in investing activities for the years ended December 31, 2011 and 2010 was $49.4 million and $53.9 million, respectively. In 2011, we spent approximately $52.3 million on asset purchases, primarily new construction. In 2010, we spent approximately $73.4 million. In 2011 and 2010, we sold assets for approximately $2.9 million and $19.6 million, respectively. The proceeds from these asset sales decreased the reported cash used in investing activities.

In 2011, we used $16.2 million in financing activities compared to $32.8 million in 2010. In 2011, we incurred $16.0 million in new long-term debt and repaid $35.0 million of debt. During 2010, we incurred $51.0 million of new long-term debt and repaid $84.3 million in debt.

Debt and Other Contractual Obligations

The following table summarizes our contractual obligations at December 31, 2011, and the effect these obligations are expected to have on liquidity and cash flows in future periods (in millions):


	2012		2013		2014		2015		2016		Thereafter
Purchase Obligations for New-Build Program	$	87.6	$	160.3	$	6.3	$	—	$	—	$	—
Repayment of Long-Term Debt, Excluding Debt Discount of $0.3 million		1.7		6.0		300.0		—		—		—
Interest Payments		20.9		16.9		14.7		—		—		—
Non-Cancelable Operating Leases		1.6		1.1		0.9		0.5		0.2		—
Long-Term Income Taxes Payable		1.8		1.8		—		—		—		—
Other		2.3		1.0		0.8		0.7		—		3.4

Total	$	115.9	$	187.1	$	322.7	$	1.2	$	0.2	$	3.4

Due to the uncertainty with respect to the timing of future cash payments, if any, associated with our unrecognized tax benefits at December 31, 2011, we are unable to make reasonably reliable estimates of the period of cash settlements with the respective taxing authority. Therefore, $18.8 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 $4.4 million and $4.6 million at December 31, 2011 and 2010, 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 45% of our total consolidated revenue for the year ended December 31, 2011. In 2011, the exchange rates of GBP, NOK, Euro, BRL, and SGD against the U.S. Dollar ranged as follows:


	High		Low		Year Average		As of February 21, 2012
$1 US=GBP		0.650		0.599		0.623	0.633
$1 US=NOK		6.023		5.233		5.600	5.689
$1 US=Euro		0.776		0.674		0.718	0.755
$1 US=BRL		1.904		1.534		1.668	1.715
$1 US=SGD		1.317		1.201		1.256	1.257

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

•

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

•

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

•

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

•

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

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

Reflected in the accompanying consolidated balance sheet at December 31, 2011, is $32.5 million in accumulated other comprehensive income primarily relating to the higher exchange rates at December 31, 2011 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 $42.5 million at December 31, 2010. 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 Policies–New 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 “Management’s 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 supply 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 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, “Management’s 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, 2011, our derivative holdings consist of an interest rate swap agreement. Refer to Note 1 “Nature of Operations and Summary of Significant Accounting Policies—Fair 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 operation’s local currency. Adjustments resulting from the translation of the local functional currency financial statements to the U.S. Dollar, which is based on current exchange rates, are included in the Consolidated Statements of Stockholders’ Equity as a separate component of “Accumulated Other Comprehensive Income (Loss)”. Working capital of our international operations may in part be held or denominated in a currency other than the local currency, and gains and 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Currency Fluctuations and Inflation”. Other than trade accounts receivable and trade accounts payable, we do not currently have financial instruments that are sensitive to foreign currency exchange rates.

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

From time to time, we may 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, 2011, 2010 and 2009 were $3.3 million, $0.1 million, and $2.2 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, 2011 and 2010 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, 2011, 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% through December 31, 2012. The consolidated balance sheet classifies the cash flow hedge within current liabilities and as of December 31, 2011, the fair value of the interest rate swap was $3.5 million. We expect to reclassify $2.7 million of deferred loss on the current interest rate swap to interest expense during the next 12 months.

The following table shows our debt principal obligation as of December 31, 2011 and 2010 and the interest rate exposure in subsequent years of the hedged and unhedged components of our debt.

		$000.000			$000.000			$000.000			$000.000		$000.000		$000.000
	2012			2013			2014			2015		2016		Thereafter
	(Dollar amounts in thousands)
December 31, 2011
Long-term Debt:
Fixed rate	$	160,000		$	160,000		$	160,000		$	—	$	—	$	—
Average interest rate		7.75	%		7.75	%		7.75	%		—		—		—

Variable rate-Facility Agreement	$	41,667		$	140,000		$	140,000		$	—	$	—	$	—
Average interest rate		3.17	%		3.05	%		3.21	%		—		—		—

Variable rate—Revolving Loan Facility	$	6,000		$	6,000		$	—		$	—	$	—	$	—
Average interest rate		1.47	%		1.35	%

Interest rate swap-Variable to Fixed	$	100,000		$	—		$	—		$	—			$	—
Average pay rate		4.15	%		—			—			—				—
Average receive rate		0.67	%		—			—			—				—

		$000.000			$000.000			$000.000			$000.000			$000.000		$000.000
	2011			2012			2013			2014			2015		Thereafter
	(Dollar amounts in thousands)
December 31, 2010
Long-term Debt:
Fixed rate	$	160,000		$	160,000		$	160,000		$	160,000		$	—	$	—
Average interest rate		7.75	%		7.75	%		7.75	%		7.75	%		—		—

Variable rate	$	66,667		$	33,333		$	—		$	—		$	—	$	—
Average interest rate		2.92	%		3.61	%		—			—			—		—

Interest rate swap-Variable to Fixed	$	100,000		$	100,000		$	—		$	—				$	—
Average pay rate		4.15	%		4.15	%		—			—					—
Average receive rate		0.42	%		1.11	%		—			—					—

Our fixed rate 7.75 % Senior Notes outstanding at December 31, 2011, 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 $3.6 million.

The fair value of our 7.75% Senior Notes as compared to the carrying value at December 31, 2011 and 2010, was as follows:


	December 31,
	2011				2010
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In millions)
7.75% Senior Notes due 2014	$	159.8	$	161.2	$	159.8	$	164.5

ITEM 8.

Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of GulfMark Offshore, Inc.:

We have audited the accompanying consolidated balance sheet of GulfMark Offshore, Inc. and consolidated subsidiaries as of December 31, 2011, and the related consolidated statements of operations, stockholders’ equity, comprehensive income, and cash flows for the year ended December 31, 2011. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of GulfMark Offshore, Inc. and consolidated subsidiaries as of December 31, 2011, and the results of their operations and their cash flows for the year ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), GulfMark Offshore, Inc. and its subsidiaries’ internal control over financial reporting as of December 31, 2011, 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 23, 2012 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

KPMG LLP

Houston, Texas

February 23, 2012

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 sheet of GulfMark Offshore, Inc. and its subsidiaries as of December 31, 2010 and the related consolidated statements of operations, stockholders’ equity, comprehensive income, and cash flows for each of the years in the two-year period ended December 31, 2010. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the 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 the consolidated results of their operations and their cash flows for each of the years in the two-year period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.

UHY LLP

Houston, Texas

February 24, 2011

GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS


	December 31,
	2011			2010
	(In thousands)
Current assets:
Cash and cash equivalents	$	128,817		$	97,195
Trade accounts receivable, net of allowance for doubtful accounts of $198 and $283, respectively		85,214			66,714
Other accounts receivable		6,314			10,326
Prepaid expenses and other current assets		21,197			20,113

Total current assets		241,542			194,348

Vessels, equipment, and other fixed assets at cost, net of accumulated depreciation of $329,299 and $282,395, respectively		1,143,441			1,191,280
Construction in progress		37,107			2,920
Goodwill		31,153			31,987
Intangibles, net of accumulated amortization of $10,030 and $7,208, respectively		24,569			27,390
Deferred costs and other assets		21,987			20,724

Total assets	$	1,499,799		$	1,468,649

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	1,667		$	33,333
Accounts payable		14,475			15,130
Income and other taxes payable		5,568			5,305
Accrued personnel costs		23,059			23,417
Accrued interest expense		5,777			5,757
Fair value of derivative		3,530			—
Other accrued liabilities		8,565			7,676

Total current liabilities		62,641			90,618


Long-term debt		305,830			293,095
Long-term income taxes:
Deferred tax liabilities		105,131			105,469
Other income taxes payable		22,769			19,400
Fair value of derivative		—			6,807
Other liabilities		6,568			7,303
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; 26,631 and 26,269 shares issued and 26,617 and 26,013 shares outstanding, respectively; Class B Common Stock $.01 par value; 60,000 shares authorized; no shares issued		262			259
Additional paid-in capital		379,673			370,218
Retained earnings		586,402			536,468
Accumulated other comprehensive income		31,105			39,137
Treasury stock, at cost		(8,968	)		(7,228	)
Deferred compensation		8,386			7,103

Total stockholders' equity		996,860			945,957

Total liabilities and stockholders’ equity	$	1,499,799		$	1,468,649

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

GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


	Year Ended December 31,
	2011			2010			2009
	(In thousands, except per share amounts)
Revenue	$	381,870		$	359,766		$	388,871

Costs and expenses:
Direct operating expenses		182,585			170,638			166,183
Drydock expense		15,932			22,182			15,696
General and administrative expenses		45,495			44,029			43,700
Depreciation and amortization		59,586			56,959			53,044
Impairment charge		1,750			97,665			46,247
Gain on sale of assets		(2,018	)		(5,095	)		(5,552	)

Total costs and expenses		303,330			386,378			319,318

Operating income (loss)		78,540			(26,612	)		69,553

Other income (expense):
Interest expense		(22,314	)		(21,693	)		(20,281	)
Interest income		748			985			377
Foreign currency gain (loss) and other		(2,346	)		(126	)		(1,153	)

Total other expense		(23,912	)		(20,834	)		(21,057	)

Income (loss) before income taxes		54,628			(47,446	)		48,496
Income tax (provision) benefit		(4,694	)		12,701			2,087

Net income (loss)	$	49,934		$	(34,745	)	$	50,583

Earnings (loss) per share:
Basic	$	1.92		$	(1.36	)	$	1.98
Diluted	$	1.91		$	(1.36	)	$	1.96
Weighted average shares outstanding:
Basic		25,828			25,519			25,151

Diluted		25,962			25,519			25,447

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

GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

For the Years Ended December 31, 2011, 2010 and 2009

(In thousands)


	Common Stock at $0.01 Par Value		Additional Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Income (loss)			Treasury Stock						Deferred Compen- sation		Total Stockholders’ Equity
												Shares			Share Value
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 loss		—		—			(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
Net income		—		—			49,934			—			—			—			—		49,934
Issuance of common stock		2		6,751			—			—			—			—			—		6,753
Exercise of stock options		1		2,690			—			—			—			—			—		2,691
Deferred compensation plan		—		14			—			—			(39	)		(1,740	)		1,283		(443	)
Gain on cash flow hedge, net of tax		—		—			—			1,954			—			—			—		1,954
Translation adjustment		—		—			—			(9,986	)		—			—			—		(9,986	)

Balance at December 31, 2011	$	262	$	379,673		$	586,402		$	31,105			(295	)	$	(8,968	)	$	8,386	$	996,860

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

GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)


	Year Ended December 31,
	2011			2010			2009
	(In thousands)
Net income (loss)	$	49,934		$	(34,745	)	$	50,583
Comprehensive income:
Gain (loss) on cash flow hedge, net of tax		1,954			(722	)		3,081
Foreign currency gain (loss)		(9,986	)		(14,146	)		68,081

Total comprehensive income (loss)	$	41,902		$	(49,613	)	$	121,745

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

GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended December 31,
	2011			2010			2009
	(In thousands)
Cash flows from operating activities:
Net income (loss)	$	49,934		$	(34,745	)	$	50,583
Adjustments to reconcile net income (loss) from operations to net cash provided by operating activities
Depreciation and amortization		59,586			56,959			53,044
Amortization of deferred financing costs		1,685			1,598			780
Amortization of stock-based compensation		6,159			5,670			7,115
Provision for doubtful accounts receivable, net of write offs		(84	)		(1	)		(73	)
Deferred income tax provision (benefit)		(232	)		(8,371	)		(3,459	)
Gain on sale of assets		(2,018	)		(5,095	)		(5,552	)
Impairment charge		1,750			97,665			46,247
Foreign currency transaction loss		3,051			1,195			2,901
Change in operating assets and liabilities — Accounts receivable		(15,983	)		3,287			29,054
Prepaids and other		(1,236	)		(7,906	)		(2,286	)
Accounts payable		(464	)		(4,118	)		2,781
Other accrued liabilities and other		(4,677	)		(14,564	)		(10,090	)

Net cash provided by operating activities		97,471			91,574			171,045

Cash flows from investing activities:
Purchases of vessels, equipment and other fixed assets		(52,258	)		(73,439	)		(77,438	)
Proceeds from disposition of equipment		2,850			19,582			9,239

Net cash used in investing activities		(49,408	)		(53,857	)		(68,199	)

Cash flows from financing activities:
Proceeds from secured credit facilities		—			—			200,000
Repayment of secured credit facilities		(25,000	)		(33,334	)		(238,035	)
Proceeds from revolving loan facility		16,000			51,000			—
Repayment of revolving loan facility		(10,000	)		(51,000	)		(84,250	)
Debt refinancing cost		—			(2,000	)		(278	)
Proceeds from exercise of stock options		2,131			1,838			718
Proceeds from issuance of stock		638			659			1,595

Net cash used in financing activities		(16,231	)		(32,837	)		(120,250	)

Effect of exchange rate changes on cash		(210	)		236			8,722

Net increase (decrease) in cash and cash equivalents		31,622			5,116			(8,682	)
Cash and cash equivalents at beginning of year		97,195			92,079			100,761

Cash and cash equivalents at end of year	$	128,817		$	97,195		$	92,079

Supplemental cash flow information:
Interest paid, net of interest capitalized	$	21,673		$	21,285		$	20,010

Income taxes paid, net	$	6,023		$	4,712		$	3,438

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

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 effected primarily to better position us to benefit from and adhere to U.S. maritime laws and regulations. See Reorganization in Note 10.

Principles of Consolidation

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

Use of Estimates

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

Cash and Cash Equivalents

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

Vessels and Equipment

Vessels and equipment are stated at cost, net of accumulated depreciation, which is provided by the straight-line method over their estimated useful life of 25 years for all vessels other than crew boats which are depreciated over 20 years. Interest is capitalized in connection with the construction of vessels. The capitalized interest is included as part of the asset to which it relates and is depreciated over the asset’s estimated useful life. In 2011, 2010, and 2009, interest of $0.4 million, $1.4 million, and $3.6 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 2011, 2010 and 2009, are $21.9 million, $20.6 million, and $20.1 million, respectively, of costs for maintenance and repairs.

Goodwill and Intangibles

At December 31, 2011, our goodwill consisted of $31.2 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 assessing goodwill for impairment, we analyze certain qualitative factors that affect the value, including goodwill of a segment. If those factors indicate that it is more likely than not that impairment of goodwill has occurred, we will proceed to step one of the goodwill impairment process.

In 2008, we acquired assets in the Americas region that included $97.7 million of goodwill. 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.

Impairment of Long-Lived Assets

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

Fair Value of Financial Instruments

As of December 31, 2011 and 2010, our financial instruments consist primarily of accounts receivable and payable (which are stated at carrying value which approximates fair value), long-term debt and an interest rate swap for a portion of the Facility Agreement.

On December 17, 2009 we entered into the $200.0 million Facility Agreement (See Note 5) and terminated the existing senior indebtedness and the interest rate swaps that were 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 a 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 $3.5 million at December 31, 2011 based on expected cash inflows and outflows associated with the contracts. We expect to reclassify $1.9 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 associated with our previous senior indebtedness 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 in 2010, $1.3 million was amortized to interest expense in 2011 and the remaining $0.5 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 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 our 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, 2011, 2010 and 2009, we reported net foreign currency losses in the amount of $3.3 million, $0.1 million and $2.2 million, respectively.

Concentration of Credit Risk

We extend credit to various companies in the energy industry that may be affected by changes in economic or other external conditions. Our policy is to manage our exposure to credit risk through credit approvals and limits. Our trade accounts receivable are aged based on contractual payment terms and an allowance for doubtful accounts is established in accordance with our written corporate policy. The age of the trade accounts receivable, customer collection history and management’s judgment as to the customer’s ability to pay are considered in determining whether an allowance is necessary. Historically, write-offs for doubtful accounts have been insignificant. For the year ended December 31, 2011, we had revenue from one customer in our Americas region totaling $57.0 million or 14.9% of our total consolidated revenue. In 2010 and 2009, no single customer accounted for 10% or more of total consolidated revenue.

Stock-Based Compensation

We have share-based compensation plans covering officers and other employees as well as our Board of Directors. Stock-based grants made under our stock plans are recorded at fair value on the date of the grant and the cost is recognized ratably over the vesting period of the restricted stock. Our stock-based compensation plans are more fully described in Note 8.

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

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, 2011, 2010 and 2009 is as follows (in thousands, except per share amounts):


	Year ended December 31,
	2011			2010			2009
Income (loss):
Net income (loss) attributable to common stockholders	$	49,934		$	(34,745	)	$	50,583
Undistributed income allocated to participating securities		(470	)		—			(811	)

Basic		49,464			(34,745	)		49,772

Undistributed income allocated to participating securities		470			—			811
Undistributed income reallocated to participating securities		(468	)		—			(801	)

Diluted	$	49,466		$	(34,745	)	$	49,782

Shares:
Basic
Weighted-average common shares outstanding		25,828			25,519			25,151
Dilutive effect of stock options and restricted stock awards		134			—			296

Diluted		25,962			25,519			25,447

Income (loss) per common share:
Basic	$	1.92		$	(1.36	)	$	1.98
Diluted	$	1.91		$	(1.36	)	$	1.96

Reclassifications

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

New Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04, “Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS” (“ASU 2011-04”). ASU 2011-04 changes the wording used to describe many of the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements to ensure consistency between U.S. GAAP and International Financial Reporting Standards (“IFRS”). ASU 2011-04 also expands the disclosures for fair value measurements that are estimated using significant unobservable (Level 3) inputs. This new guidance is to be applied prospectively. ASU 2011-04 will be effective for interim and annual periods beginning after Dec. 15, 2011, with early adoption permitted. We believe that the adoption of this standard will not materially expand our consolidated financial statement footnote disclosures.

In June 2011, the FASB issued ASU No. 2011-05, “Comprehensive Income (ASC Topic 220): Presentation of Comprehensive Income” (“ASU 2011-05”), which amends current comprehensive income guidance. This ASU eliminates the option to present the components of other comprehensive income as part of the statement of shareholders’ equity. Instead, we must report comprehensive income in either a single continuous statement of comprehensive income which contains two sections, net income and other comprehensive income, or in two separate but consecutive statements. ASU 2011-05 will be effective for interim and annual periods beginning after Dec. 15, 2011, with early adoption permitted. The adoption of ASU 2011-05 will not have a material impact on our consolidated financial statements.

In September 2011, the FASB issued ASU 2011-08, “Testing Goodwill for Impairment” (“ASU 2011-08”), which amends the guidance in ASC 350-20, “Intangibles—Goodwill and Other – Goodwill”. Under ASU 2011-08, entities have the option of performing a qualitative assessment before calculating the fair value of the reporting unit when testing goodwill for impairment. If the fair value of the reporting unit is determined, based on qualitative factors, to be more likely than not less than the carrying amount of the reporting unit, then entities are required to perform the two-step goodwill impairment test. ASU 2011-08 is effective for fiscal years beginning after December 15, 2011, with early adoption permitted. We adopted ASU 2011-08 in the third quarter of 2011 with no material impact on our consolidated financial statements.

In September 2011, the FASB issued ASU No. 2011-09, “Compensation — Retirement Benefits — Multiemployer Plans (Subtopic 715-80)” (“ASU 2011-09”). ASU 2011-09 requires that employers provide additional separate disclosures for multiemployer pension plans and multiemployer other postretirement benefit plans. The additional quantitative and qualitative disclosures will provide users with more detailed information about an employer’s involvement in multiemployer pension plans. ASU 2011-09 will be effective for fiscal years ending after December 15, 2011. We adopted the provisions of this standard in the fourth quarter of 2011 and have included the appropriate disclosures in our notes to the consolidated financial statements.

In December 2011, the FASB issued ASU No. 2011-12, " Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 " ("ASU 2011-012"). The amendments to the Codification in ASU No. 2011-12 are effective at the same time as the amendments in ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income, so that entities will not be required to comply with the presentation requirements in ASU No. 2011-05 that ASU No. 2011-12 is deferring. The amendments are being made to allow the FASB time to redeliberate whether to present on the face of the financial statements the effects of reclassifications out of accumulated other comprehensive income on the components of net income and other comprehensive income for all periods presented. ASU 2011-12 will be effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. The adoption of ASU 2011-12 will not have a material impact on our consolidated financial statements.

In December 2011, the FASB issued ASU No. 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities” (“ASU 2011-11”). Offsetting, otherwise known as netting, is the presentation of assets and liabilities as a single net amount in the statement of financial position (balance sheet). U.S. GAAP allows companies the option to present net in their balance sheets derivatives that are subject to a legally enforceable netting arrangement with the same party where rights of set-off are only available in the event of default or bankruptcy. The amendments to the FASB Accounting Standards Codification in this ASU require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. An entity is required to apply the amendments for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. The adoption of ASU 2011-11 will not have a material impact on our consolidated financial statements.

(2) IMPAIRMENT CHARGES

Asset Held for Sale

In the fourth quarter of 2011, we determined that the carrying value of our asset held for sale was less than our estimate of the amount we would realize in a sale. As a result, we reduced the carrying value by $1.8 million. This amount is included in our income statement as an impairment charge.

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 segment’s fair value due to the April 2010 catastrophic fire and explosion that sank a deepwater drilling rig in the U.S. Gulf Of Mexico, and the resulting oil spill and drilling moratorium. Based on these events, 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 did not impact our liquidity or debt covenant compliance. The impairment charge was based on fair value measurements classified as Level 3 of the valuation hierarchy. As of December 31, 2010, the implied fair value of the Americas goodwill was zero.

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 was terminated. 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) VESSEL ACQUISITIONS, DISPOSITIONS AND NEW-BUILD PROGRAM

During 2010, we took delivery of three vessels that were under construction at December 31, 2009. 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.

At the beginning of the fourth quarter of 2011, we sold one of our North Sea vessels and recorded a $2.0 million gain. We did not take delivery of any new-build vessels during 2011. Subsequent to December 31, 2011, we purchased a vessel for operation in the Americas region for a total price of $22.3 million, and we sold one of our Americas vessels and recorded a gain of $1.2 million.

In the third quarter of 2011, our Board of Directors approved the initiation of a new-build construction program. We began the program in the North Sea region where we contracted with three shipyards to build a total of six new platform supply vessels. Remontowa Shipbuilding SA ("Remontowa"), a Polish company, will build three vessels, Rosetti Marino S.p.A. ("Rosetti Marino"), an Italian company, will build two vessels and Simek A/S ("Simek"), a Norwegian company, will build one vessel. The estimated total cost of these initial six vessels is $245.0 million. In addition, in late 2011, we exercised an option under the Simek contract to build an additional vessel with essentially the same specifications as the vessel currently under construction. The cost of the additional vessel is estimated at $60.9 million. Our agreements also include additional options that expire in the first quarter 2012, to build four more vessels. The Remontowa and Rosetti Marino contracts are denominated in Euros and the Simek contract is denominated in Norwegian Kroner. The first of these vessels is scheduled to be delivered in the second quarter of 2013 and the last is scheduled to be delivered in the first quarter of 2014. All seven vessels currently under construction are capable of international operations and will be managed from our North Sea region.

The following tables illustrate the details of the vessels under construction, the vessels disposed of, the vessels acquired and the vessels classified as held for sale as indicated.


Vessels Under Construction at December 31, 2011
Construction Yard	Region		Type⁽¹⁾		Expected Delivery		Length (feet)		BHP⁽²⁾		DWT⁽³⁾		Expected Cost
													(in millions)
Remontowa		North Sea		LgPSV		Q2 2013		291		9120		5100	$	41.0
Remontowa		North Sea		LgPSV		Q3 2013		291		9120		5100	$	41.1
Remontowa		North Sea		LgPSV		Q3 2013		260		9120		4000	$	37.7
Rosetti Marino		North Sea		LgPSV		Q4 2013		246		7483		3000	$	32.1
Rosetti Marino		North Sea		LgPSV		Q2 2014		246		7483		3000	$	32.1
Simek		North Sea		LgPSV		Q2 2013		304		11265		4700	$	60.9
Simek		North Sea		LgPSV		Q3 2013		304		11265		4700	$	60.9

⁽¹⁾

LgPSV—Large Platform Supply Vessel

⁽²⁾

BHP—Breakhorse Power

⁽³⁾

DWT—Deadweight Tons

Vessels Acquired Since December 31, 2010

Vessel

Region

Type⁽¹⁾

Year
Built

Length
(feet)

BHP⁽²⁾

DWT⁽³⁾

Cost

(in millions)

Thomas Wainwright

Americas

PSV

2010

242

4,200

2,700

22.3

Vessels Disposed of Since December 31, 2010

Vessel

Region

Type⁽¹⁾

Year
Built

Length
(feet)

BHP⁽²⁾

DWT⁽³⁾

Month
Disposed

Highland Pioneer

N.Sea

LgPSV

1983

224

5,400

2,500

Oct-11

Bluefin

Americas

Crew

2008

165

7,200

337

Jan-12

Vessels Held for Sale (Laid Up)

Vessel

Region

Type(1)

Year
Built

Length
(feet)

BHP⁽²⁾

DWT⁽³⁾

Clwyd Supporter

N. Sea

SpV

1984

266

10,700

1,350

(4) GOODWILL AND INTANGIBLES

Changes to goodwill are as follows:


	2011			2010			2009
	(In thousands)
Balance, January 1,	$	31,987		$	129,849		$	123,981
Adjustment related to acquisition		—			—			463
Impact on foreign currency translation and adjusment		(834	)		(197	)		5,405
Impairment (see Note 2)		—			(97,665	)		—

Balance, December 31,	$	31,153		$	31,987		$	129,849

Intangible assets of $24.6 million, net of accumulated amortization of $10.0 million, as of December 31, 2011 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, 2011, 2010 and 2009. Annual amortization expense related to existing intangible assets for years 2012 through 2016 is expected to be $2.9 million per year.

(5) LONG-TERM DEBT

Our long-term debt at December 31, 2011 and 2010 consisted of the following:


	2011			2010
	(In thousands)
Senior Notes	$	160,000		$	160,000
Facility Agreement		141,667			166,667
Secured Reducing Revolving Loan Facility		6,000			—

		307,667			326,667

Less: Current maturities of long-term debt		(1,667	)		(33,333	)
Debt discount, net		(170	)		(239	)

Total	$	305,830		$	293,095

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


Year	Debt Maturity
	(In thousands)
2012	$	1,667
2013		6,000
2014		300,000
2015		—
2016		—

Total	$	307,667

Senior Notes

On July 21, 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 101.292% of the principal amount and may be called on July 15, 2012, and thereafter at 100% of the principal amount, respectively, plus, in each case, accrued interest.

At December 31, 2011, the fair value of these notes, based on quoted market prices, was approximately $161.2 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, prior to the January 26, 2012 amendment, was December 31, 2012, and amounts borrowed were repayable in quarterly installments of $8.3 million with a final installment of $108.3 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 Borrower’s 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.

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 Borrower’s 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 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, 2011, we were in compliance with all covenants, and had $141.7 million borrowed under the facility. At December 31, 2011, the fair value of borrowings under this facility is considered to be book value as the interest is at market rates.

On January 26, 2012, we entered into a financing agreement with RBS to amend the Facility Agreement primarily to extend the maturity to July 1, 2014 and adjust principal payments. As a result, we have re-classified as long-term debt the portion of the obligation that was previously scheduled to mature during 2012. Under this agreement, we are not required to make any principal payments until maturity. The interest rate remains LIBOR plus 250 basis points. The $1.7 million difference between the amount currently outstanding and the amount of the refinance agreement was settled at closing.

Secured Reducing Revolving Loan Facility

We currently have a $175.0 million (of which $154.0 million was available for borrowing at December 31, 2011) 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 $15.0 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, 2011, we were in compliance with all covenants and had $6.0 million drawn under this facility.

(6) INCOME TAXES

The majority of our non-U.S. based operations are subject to foreign tax systems that provide significant incentives to qualified shipping activities. Our U.K. and Norway based vessels are taxed under 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 Norway’s 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, Norway’s 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 a $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 remaining liability to settle under the simplified tax system is included in our December 31, 2011 balance sheet as $1.8 million current income tax payable and $1.8 million as other long term payable. Annually, the subsequent year’s 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 2012. In 2011 we established a $0.8 million valuation allowance for certain of our foreign tax credits. We also have certain foreign net operating loss carryforwards that result in net deferred tax assets of approximately $1.4 million after 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 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 are 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,
	2011			2010			2009
U.S.	$	(33,742	)	$	(121,938	)	$	(66,854	)
Foreign		88,370			74,492			115,350

	$	54,628		$	(47,446	)	$	48,496

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


	2011										2010											2009
	Current		Deferred			Other (a)		Total			Current		Deferred			Other (a)			Total			Current		Deferred			Other (a)			Total
U.S.	$	65	$	(2,989	)	$	—	$	(2,924	)	$	65	$	(7,519	)	$	—		$	(7,454	)	$	20	$	(2,988	)	$	(254	)	$	(3,222	)
Foreign		1,439		2,757			3,422		7,618			3,576		(852	)		(7,972	)		(5,247	)		5,223		(5,314	)		1,226			1,135

	$	1,504	$	(232	)	$	3,422	$	4,694		$	3,641	$	(8,371	)	$	(7,972	)	$	(12,701	)	$	5,243	$	(8,302	)	$	972		$	(2,087	)

(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:


	2011			2010			2009
U.S. federal statutory income tax rate		35.0	%		35.0	%		35.0	%
Effect of foreign operations		(26.7	)		66.0			(36.6	)
US state income taxes		0.5			(0.7	)		4.5
Valuation allowance		1.9			—			(9.2	)
Impairment		—			(72.0	)		—
Other		(2.1	)		(1.5	)		1.0

Total		8.6	%		26.8	%		(4.3	%)

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, 2011 and 2010 are as follows:


	December 31,
	2011			2010
	(In thousands)
Deferred tax assets
Net operating loss carryforwards	$	42,997		$	44,549
Items currently not deductible for tax purposes		27,730			26,083
Foreign and other tax credit carryforwards		10,338			10,686

		81,065			81,318
Less valuation allowance		(5,867	)		(4,468	)

Net deferred tax assets	$	75,198		$	76,850

Deferred tax liabilities
Depreciation	$	(148,697	)	$	(151,912	)
Other		(30,242	)		(27,447	)

Total deferred tax liabilities	$	(178,939	)	$	(179,359	)

Net deferred tax liability	$	(103,741	)	$	(102,509	)

The net change in the total valuation allowance for the years ended December 31, 2011 and 2010 was an increase of $1.4 million and a decrease of $0.7 million, respectively. As of December 31, 2011, we had net operating loss carryforwards, or NOLs, for income tax purposes totaling $123.3 million in the U.S., $11.3 million in Brazil, $4.5 million in Norway, and $2.0 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 and the NOLs in Mexico will begin to expire in 2016. It is more likely than not that the Mexican and Norway NOLs will not be utilized and a full valuation allowance has been established for these 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.

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


	December 31,
	2011		2010
	(In thousands)
Prepaid expenses and other current assets	$	3,708	$	3,468
Deferred costs and other assets		1,155		731

Total tax assets		4,863		4,199


Income taxes and other taxes payable	$	5,568	$	5,305
Other accrued liabilities		1,112		—
Deferred tax liabilities		105,130		105,469
Other income taxes payable		22,769		19,400

Total tax liabilities	$	134,579	$	130,174

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 $833.3 million at December 31, 2011. In addition, as of December 31, 2011, we had $115.2 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 $19.9 million at December 31, 2011 and $15.7 million at December 31, 2010.

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


	2011			2010
	(in thousands)
Unrecognized tax benefits balance at January 1,	$	10,636		$	10,786
Gross increases for tax positions taken in prior years		695			645
Gross decreases for tax positions taken in prior years		(596	)		(795	)
Decreases for settlements		—			—
Lapse of statute of limitations		—			—

Unrecognized tax benefits balance at December 31,	$	10,735		$	10,636

We expect a foreign tax examination issue representing approximately $0.9 million of our unrecognized tax benefits as of December 31, 2011 will be settled within twelve months. As of December 31, 2011, 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 from 2000 to 2010.

We accrue interest and penalties related to unrecognized tax benefits in our provision for income taxes. At December 31, 2011, we had accrued interest and penalties related to unrecognized tax benefits of $13.0 million. The amount of interest and penalties recognized in our tax provision for the year ended December 31, 2011 was $1.9 million.

(7) COMMITMENTS AND CONTINGENCIES

At December 31, 2011, 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, 2011, 2010 and 2009 was $2.3 million, $2.2 million, and $2.0 million, respectively. Future minimum rental commitments under these leases are as follows (in thousands):


Year	Minimum Rental Commitments
2012	$	1,562
2013		1,056
2014		912
2015		507
2016		172
Thereafter		—

Total	$	4,209

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 charterer’s 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 $4.4 million and $4.6 million at December 31, 2011 and 2010, 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 recently been made aware that a Brazilian state in which we have operated vessels has asserted that certain companies could be assessed for state import taxes with respect to vessels that have operated within Brazilian coastal waters. We have neither been formally assessed nor threatened with this tax. No accrual has been recorded as of December 31, 2011 for any liabilities associated with a possible future assessment. We can't predict whether any such tax assessment may be made in the future.

(8) EQUITY INCENTIVE PLANS

Stock Options, Restricted Stock 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, although 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 under the 1997 Equity Incentive Plan, although options and nonvested restricted stock remain outstanding under this plan.

In June 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.

In June 2011, the stockholders approved the GulfMark Offshore, Inc. 2011 Non-Employee Director Plan, or 2011 Director Plan. The 2011 Director Plan replaced the GulfMark Offshore, Inc. 2005 Non-Employee Director Plan. The terms of our 2011 Director Plan provide that each non-employee director will receive an annual grant of 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 2011 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 2011 Director Plan is 150,000.

A summary of the nonvested restricted stock awarded pursuant to our 1997 Incentive Equity Plan and our 2010 Omnibus Equity Incentive Plan as of December 31, 2011 and changes during the year, is presented below:


	Shares			Weighted- Average Grant Date Fair Value
Nonvested at December 31, 2010		401,209		$	26.14
Granted		191,462			42.42
Vested		(203,099	)		28.38
Cancelled		(9,833	)		34.65

Nonvested at December 31, 2011		379,739			32.91


	2011		2010		2009
Weighted average grant date fair value of restricted stock awards granted	$	42.42	$	27.52	$	18.84
Fair value of restricted stock vested (in millions)	$	8.5	$	6.1	$	3.8

The restrictions terminate at the end of three years from the date of grant and the value of the restricted shares is amortized to expense over that period. Total amortization of stock based compensation related to restricted stock was $6.0 million, $5.5 million and $7.1 million for the years ended December 31, 2011, 2010, and 2009, respectively. As of December 31, 2011 the total unrecognized compensation expense for nonvested restricted stock awards was $7.9 million. This expense is expected to be recorded over a weighted-average period of 2.2 years.

The following table summarizes the activity of our stock incentive plans during the indicated periods.


	2011				2010				2009
	Shares		Weighted Average Exercise Price		Shares		Weighted Average Exercise Price		Shares		Weighted Average Exercise Price
Outstanding at beginning of year		299,650	$	17.92		457,650	$	15.75		673,650	$	13.94
Granted		—		—		—		—		—		—
Forfeitures		—		—		—		—		—		—
Exercised		159,650		16.85		158,000		11.63		216,000		10.09

Outstanding at end of year		140,000	$	19.14		299,650	$	17.92		457,650	$	15.75

Exercisable shares and weighted average exercise price		140,000	$	19.14		299,650	$	17.92		457,650	$	15.75
Shares available for future grants at December 31:
2011 Director Plan		132,535				—				—
2010 Omnibus Equity Incentive Plan		812,909				985,294				—

The following table summarizes information about stock options outstanding at December 31, 2011:


	Outstanding						Exercisable
Range of Exercise Prices	Shares		Weighted Average Exercise Price		Weighted Average Remaining Life		Shares		Weighted Average Exercise Price
$13.10 to $17.44		60,000	$	16.33		0.71 years		60,000	$	16.33
$19.37 to $21.25		80,000	$	21.25		0.39 years		80,000	$	21.25

		140,000	$	19.14				140,000	$	19.14

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 of our U.S. employees and certain subsidiaries and is qualified under Section 423 of the Internal Revenue Code. At the end of each fiscal quarter, or Option Period, during the term of the ESPP, the employee contributions are used to acquire shares of 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. Total compensation expense related to the ESPP was $0.1 million, $0.1 million and $0.2 million during the years ended December 31, 2011, 2010 and 2009, respectively. We have authorized the issuance of up to 400,000 shares of common stock through these plans. At December 31, 2011, there were 259,611 shares remaining in reserve for future issuance. See Note 1 “Nature of Operations and Summary of Significant Accounting Policies—Stock-Based Compensation”.

U.K. ESPP

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

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, 2011, a total of $3.3 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.

(9) EMPLOYEE BENEFIT PLANS

401(k)

We offer a 401(k) plan to all of our U.S. employees and provide matching contribution to those employees that participate. The matching contributions paid by us totaled $1.3 million, $1.4 million and $1.3 million for the years ended December 31, 2011, 2010 and 2009, respectively.

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, 2011, we had $4.5 million accrued related to this liability, which reflects all obligations assessed by the fund’s 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. The status of the fund is calculated by an actuarial firm every three years. The last calculation was completed in March 2009 and indicated that the funding level of the MNOPF at that date was between 65 and 80%. The MNOPF annual report dated March 31, 2011, stated that the funding level had improved to over 80% as of that date. The amount and timing of additional potential future obligations relating to underfunding depends on a number of factors, but principally on future fund performance and the underlying actuarial assumptions. Our share of the fund’s deficit is dependent on a number of factors including future actuarial valuations, asset performance, the number of participating employers, and the final method used in allocating the required contribution among participating employers. In addition, our obligation could increase if other employers no longer participated in the plan. We made contributions to the plan of $0.3 million, $0.6 million and $0.5 million for the years ended December 31, 2011, 2010 and 2009, respectively. Our contributions do not make up more than five percent of total contributions to the plan.

Norwegian Pension Plans

The Norwegian benefit pension plans include approximately seven of our office employees and 216 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, 2011 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):

		$0000.00			$0000.00
	2011			2010
Change in Benefit Obligation
Benefit obligation at beginning of the year	$	8,389		$	8,083
Benefit periodic cost		684			933
Interest cost		256			334
Benefits paid		(324	)		(337	)
Actuarial loss		(160	)		(574	)
Translation adjustment		(220	)		(50	)

Benefit obligation at year end	$	8,625		$	8,389

		$0000.00			$0000.00
	2011			2010
Change in Plan Assets
Fair value of plan assets at beginning of the year	$	6,019		$	5,350
Actual return on plan assets		293			311
Contributions		646			518
Benefits paid		(149	)		(147	)
Administrative fee		(68	)		(50	)
Actuarial loss		(175	)		45
Translation adjustment		(193	)		(8	)

Fair value of plan assets at end of year	$	6,373		$	6,019


	2011			2010
Funded status	$	(2,252	)	$	(2,370	)

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


	December 31,
	2011			2010
Deferred costs and other assets	$	108		$	406
Other liabilities		1,922			2,078

	Year Ended December 31,
	2011			2010
Components of Net Period Benefit Cost
Service cost	$	730		$	900
Interest cost		273			323
Return on plan assets		(292	)		(311	)
Administrative fee		68			50
Recognized net actuarial loss		(8	)		(618	)

Net periodic benefit cost	$	771		$	344

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.

		$0000.00			$0000.00
	2011			2010
Weighted-average assumptions
Discount rate		3.1	%		3.2	%
Return on plan assets		4.8	%		4.6	%
Rate of compensation increase		3.5	%		3.0	%

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:


	2011			2010
Equity securities		6	%		14	%
Property		18	%		20	%
Held-to-Maturity bonds		44	%		45	%
Bonds		29	%		19	%
Other		3	%		2	%

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 $8.6 million and $6.4 million, respectively as of December 31, 2011, and $8.4 million and $6.0 million, respectively as of December 31, 2010. We expect to contribute approximately $0.6 million to the Norwegian pension plan in 2012. No plan assets are expected to be returned to us in 2012.

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


Year ended December 31,	Benefit Payments
2012	$	334
2013		344
2014		354
2015		365
2016		376

Total	$	1,773

(10) STOCKHOLDERS’ EQUITY

Common Stock Issuances

During 2011, 10,606 shares were issued through the ESPP, generating approximately $0.3 million in proceeds. The provisions of the ESPP are described above in Note 8 in more detail.

A total of 170,252 and 167,096 restricted shares of our stock were granted to certain officers and key employees in 2011 and 2010, respectively, pursuant to our 1997 Incentive Equity Plan and 2010 Omnibus Equity Incentive Plan described above in Note 8, with an aggregate market value of $7.3 million and $4.7 million, respectively, on the grant dates.

Preferred Stock

We are authorized by our Certificate of Incorporation, as amended, to issue up to 2,000,000 shares of 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, and authorized 60 million shares of each class of common stock. 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.

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.

(11) 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 derivative’s 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, 2011, 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 amounts outstanding under our Facility Agreement. At December 31, 2011, our interest rate derivative instrument has an outstanding notional amount of $100.0 million and has been designated as a cash flow hedge. The terms of the swap, 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 $0.5 million are recorded as of December 31, 2011 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.

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
	2011				2010				2011				2010
Derivaties designated as hedging instruments		Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value
Interest Rate Swaps				—				—		Fair value of derivative		3,530		Fair value of derivative		6,807

			$	—			$	—			$	3,530			$	6,807

The following table quantify the amount of gain or loss recognized during the year ended December 31 and identifies the consolidated statement of operations location:


Derivatives in cash flow hedging relationships	Amount of Gain or (Loss) Recognized in OCI on Derivative						Location of Gain or (Loss) Reclassified from Accumulated OCI into Income		Amount of Gain or (Loss) Reclassified from Accumulated OCI into Income
	2011			2010					2011			2010
	(in thousands)								(in thousands)
Interest rate contracts	$	(604	)	$	(4,351	)		Interest expense	$	(3,208	)	$	(2,716	)

(12) 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

In December 2009, 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 $3.5 million at December 31, 2011. We report changes in the fair value of these cash flow hedges in accumulated other comprehensive income. For the year ended December 31, 2011, $3.2 million was reclassified from other comprehensive income to interest expense. We expect to reclassify $3.3 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, 2011.

In the fourth quarter of 2011, we wrote down the value of our asset held for sale from its $3.5 million carrying value to its $1.7 million estimated fair value. The $1.8 million loss is included in our statement of operations under impairment charges. The fair value was based on third party appraisals.

The following table presents information about our assets (liabilities) measured at fair value on a recurring and non-recurring basis as of December 31, 2011, and indicates the fair value hierarchy we utilized to determine such fair value (in millions).


	Level 1		Level 2			Level 3		Total
Fair value of derivative	$	—	$	(3.5	)	$	—	$	(3.5	)

Asset held for sale	$	—	$	1.8		$	—	$	1.8

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
Fair value of derivative	$	—	$	(6.8	)	$	—	$	(6.8	)

The fair value of derivative is included in current liabilities on the consolidated balance sheet as of December 31, 2011 and in other long term liabilities as of December 31, 2010. The asset held for sale is included in other current assets on our consolidated balance sheet as of December 31, 2011.

(13) 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 segment’s operating performance from its continuing operations, as it represents the results of the ownership interest in operations without regard to financing methods or capital structures. All significant transactions between segments are conducted on an arms-length basis based on prevailing market prices and are accounted for as such. Operating income and other information regularly provided to our chief operating decision-maker is summarized in the following table (all amounts in thousands):


	North Sea			Southeast Asia			Americas			Other			Total
Year Ended December 31, 2011
Revenue	$	172,393		$	63,754		$	145,723		$	—		$	381,870
Direct operating expenses		81,528			12,006			89,051			—			182,585
Drydock expense		8,563			3,871			3,498			—			15,932
General and administrative expense		12,169			2,852			8,376			22,098			45,495
Depreciation and amortization		19,495			9,738			28,391			1,962			59,586
Impairment charge		1,750			—			—			—			1,750
(Gain) loss on sale of assets		(2,028	)		—			10			—			(2,018	)

Operating income (loss)	$	50,916		$	35,287		$	16,397		$	(24,060	)	$	78,540


Cash and cash equivalents	$	32,554		$	22,721		$	20,730		$	52,812		$	128,817
Long-lived assets(a)(b)		424,115			239,985			567,546			4,624			1,236,270
Total assets		521,675			285,027			626,071			67,026			1,499,799
Capital expenditures		40,776			552			8,756			2,174			52,258

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			35,816			1,468,649
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

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.

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 2011, we had $80.8 million in revenue and $393.1 million in long-lived assets attributed to business in the United States, our country of domicile. In 2010, we had $104.5 million in revenue and $462.9 million in long-lived assets attributed to the United States. In 2009, we had $106.5 million in revenue and $603.9 million in long-lived assets attributed to the United States.

(14) UNAUDITED QUARTERLY FINANCIAL DATA

Summarized quarterly financial data for the two years ended December 31, 2011 and 2010 are as follows:


	Quarter
	First			Second			Third		Fourth
	(In thousands, except per share amounts)
2011
Revenues	$	81,289		$	96,911		$	103,778	$	99,892
Operating income (loss)		4,339			20,428			23,194		30,579
Net income (loss)		(1,167	)		13,291			14,165		23,645
Per share (basic)	($	0.05	)	$	0.51		$	0.54	$	0.91
Per share (diluted)	($	0.05	)	$	0.51		$	0.54	$	0.90

2010
Revenue	$	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)	$	0.84		($	3.55	)	$	0.74	$	0.59
Per share (diluted)	$	0.84		($	3.55	)	$	0.73	$	0.58

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 SEC’s 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 Company’s 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) Management’s Annual Report on Internal Control over Financial Reporting. Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rules 13a-15(f).

Our management assessed the effectiveness of our internal control over financial reporting at December 31, 2011, 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, 2011. KPMG LLP has issued the following opinion on the Company’s internal control over financial reporting.

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of GulfMark Offshore, Inc.:

We have audited GulfMark Offshore, Inc. and consolidated subsidiaries’ internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). GulfMark Offshore, Inc. and consolidated subsidiaries’ management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

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

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

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

In our opinion, GulfMark Offshore, Inc. and consolidated subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of GulfMark Offshore, Inc. and consolidated subsidiaries as of December 31, 2011, and the related consolidated statements of operations, stockholders’ equity, comprehensive income, and cash flows for the year ended December 31, 2011, and our report dated February 23, 2012 expressed an unqualified opinion on those consolidated financial statements.

KPMG LLP

Houston, Texas

February 23, 2012

(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, 2011, 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.

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


Exhibits		Description	Filed Herewith or Incorporated by Reference from the Following Documents

	3.1	Certificate of Incorporation, as amended	Exhibit 3.1 to our current report on Form 8-K filed on February 24, 2010

	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 Company’s 7.75% Senior Notes due 2014	Exhibit 4.4 to our quarterly report on Form 10-Q filed on November 9, 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 Company’s 7.75% Senior Notes due 2014	Exhibit 10.1 to our current report on Form 8-K filed on 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*	Filed herewith

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)*	Filed herewith

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	Executive Nonqualified Excess Plan*	Exhibit 10.1 to our quarterly report on Form 10-Q filed on October 27, 2010

10.18	Executive Nonqualified Excess Plan Adoption Agreement, amended effective January 1, 2010*	Exhibit 10.2 to our quarterly report on Form 10-Q filed on October 27, 2010

10.19	Form of the Executive Nonqualified Excess Plan Participation Agreement*	Exhibit 10.3 to our quarterly report on Form 10-Q filed on October 27, 2010

10.20	GulfMark Offshore, Inc. Deferred Compensation Plan *	Appendix C to our Proxy Statement on Form DEF 14A filed on April 29, 2011

10.21	GulfMark Offshore, Inc. 2011 Non-Employee Director Share Incentive Plan *	Appendix B of our Proxy Statement on Form DEF 14A filed on April 29, 2011

10.22	GulfMark Offshore, Inc. 2011 Employee Stock Purchase Plan*	Appendix A of our Proxy Statement on Form DEF 14A filed on April 29, 2011


10.23	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

10.24	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

10.25	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

10.26	Employment Agreement between Richard M. Safier and GulfMark Offshore, Inc. dated effective as of March 15, 2011*	Exhibit 10.1 to our current report on Form 8-K filed on March 21, 2011

10.27	Change of Control Agreement between Richard M. Safier and GulfMark Offshore, Inc. dated effective as of March 15, 2011*	Exhibit 10.2 to our current report on Form 8-K filed on March 21, 2011

10.28	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

10.29	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

10.30	Form of Indemnification Agreements*	Exhibit 10.2 to our current report on Form 8-K filed on February 24, 2010

10.31	GM Offshore, Inc. Supplemental Income Plan effective as of January 1, 2000*	Exhibit 10.34 to our annual report on Form 10-K filed on February 24, 2011

10.32	Participation Agreement Supplemental Income Plan of GulfMark Offshore Inc. dated January 1, 2000 by Bruce A. Streeter*	Exhibit 10.36 to our annual report on Form 10-K filed on February 24, 2011

10.33	Amendment One to Participation Agreement Supplemental Income Plan of GulfMark Offshore, Inc. dated December 28, 2010, between GulfMark Offshore, Inc. and Bruce A. Streeter*	Exhibit 10.37 to our annual report on Form 10-K filed on February 24, 2011

10.34	Amended and Restated Amendment Two to Participation Agreement Supplemental Income Plan of GulfMark Offshore, Inc. dated February 10, 2012, between GulfMark Offshore, Inc. and Bruce A. Streeter *	Exhibit 10.1 to our current report on Form 8-K filed on February 15, 2012

10.35	Participation Agreement Supplemental Income Plan of GulfMark Offshore Inc. dated January 1, 2000 by John E. Leech*	Exhibit 10.39 to our annual report on Form 10-K filed February 24, 2011

10.36	Amendment One to Participation Agreement Supplemental Income Plan of GulfMark Offshore, Inc. dated December 29, 2010, between GulfMark Offshore, Inc. and John E. Leech*	Exhibit 10.40 to our annual report on Form 10-K filed February 24, 2011

10.37	Amended and Restated Amendment Two to Participation Agreement Supplemental Income Plan of GulfMark Offshore, Inc. dated February 9, 2012, between GulfMark Offshore, Inc. and John E. Leech*	Exhibit 10.2 to our current report on Form 8-K filed on February 15, 2012


10.38	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 filed on July 31, 2008

10.39	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	Filed herewith

10.40	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	Filed herewith

10.41	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

10.42	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

10.43	Amendment Agreement dated January 26, 2012, among The Royal Bank of Scotland PLC as original lender arranger, agent and security agent and GulfMark Americas, Inc., as borrower, and GulfMark Offshore, Inc. as guarantor	Exhibit 10.1 to our current report on Form 8-K filed on February 1, 2012

12.1	Computation of Ratio of Earnings to Fixed Charges	Filed herewith

21.1	Subsidiaries of GulfMark Offshore, Inc.	Filed herewith

23.1	Consent of KPMG LLP	Filed herewith

23.2	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, 2011, 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.	Filed herewith

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 23, 2012

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 Bruce A. Streeter	Chief Executive Officer, President and Director (Principal Executive Officer)	February 23, 2012

/s/ Quintin V. Kneen Quintin V. Kneen	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	February 23, 2012

/s/ Samuel R. Rubio Samuel R. Rubio	Vice President, Controller and Chief Accounting Officer (Principal Accounting Officer)	February 23, 2012

/s/ David J. Butters David J. Butters	Director	February 23, 2012

/s/ Peter I. Bijur Peter I. Bijur	Director	February 23, 2012

/s/ Brian R. Ford Brian R. Ford	Director	February 23, 2012

/s/ Louis S. Gimbel, 3rd Louis S. Gimbel 3rd	Director	February 23, 2012

/s/ Sheldon S. Gordon Sheldon S. Gordon	Director	February 23, 2012

/s/ Robert B. Millard Robert B. Millard	Director	February 23, 2012

/s/ Rex C. Ross Rex C. Ross	Director	February 23, 2012


Exhibits		Description	Filed Herewith or Incorporated by Reference from the Following Documents

	3.1	Certificate of Incorporation, as amended	Exhibit 3.1 to our current report on Form 8-K filed on February 24, 2010

	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 Company’s 7.75% Senior Notes due 2014	Exhibit 4.4 to our quarterly report on Form 10-Q filed on November 9, 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 Company’s 7.75% Senior Notes due 2014	Exhibit 10.1 to our current report on Form 8-K filed on 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*	Filed herewith

	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)*	Filed herewith

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	Executive Nonqualified Excess Plan*	Exhibit 10.1 to our quarterly report on Form 10-Q filed on October 27, 2010

10.18	Executive Nonqualified Excess Plan Adoption Agreement, amended effective January 1, 2010*	Exhibit 10.2 to our quarterly report on Form 10-Q filed on October 27, 2010

10.19	Form of the Executive Nonqualified Excess Plan Participation Agreement*	Exhibit 10.3 to our quarterly report on Form 10-Q filed on October 27, 2010

10.20	GulfMark Offshore, Inc. Deferred Compensation Plan *	Appendix C to our Proxy Statement on Form DEF 14A filed on April 29, 2011

10.21	GulfMark Offshore, Inc. 2011 Non-Employee Director Share Incentive Plan *	Appendix B of our Proxy Statement on Form DEF 14A filed on April 29, 2011

10.22	GulfMark Offshore, Inc. 2011 Employee Stock Purchase Plan*	Appendix A of our Proxy Statement on Form DEF 14A filed on April 29, 2011

10.23	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

10.24	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

10.25	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

10.26	Employment Agreement between Richard M. Safier and GulfMark Offshore, Inc. dated effective as of March 15, 2011*	Exhibit 10.1 to our current report on Form 8-K filed on March 21, 2011


10.27	Change of Control Agreement between Richard M. Safier and GulfMark Offshore, Inc. dated effective as of March 15, 2011*	Exhibit 10.2 to our current report on Form 8-K filed on March 21, 2011

10.28	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

10.29	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

10.30	Form of Indemnification Agreements*	Exhibit 10.2 to our current report on Form 8-K filed on February 24, 2010

10.31	GM Offshore, Inc. Supplemental Income Plan effective as of January 1, 2000*	Exhibit 10.34 to our annual report on Form 10-K filed on February 24, 2011

10.32	Participation Agreement Supplemental Income Plan of GulfMark Offshore Inc. dated January 1, 2000 by Bruce A. Streeter*	Exhibit 10.36 to our annual report on Form 10-K filed on February 24, 2011

10.33	Amendment One to Participation Agreement Supplemental Income Plan of GulfMark Offshore, Inc. dated December 28, 2010, between GulfMark Offshore, Inc. and Bruce A. Streeter*	Exhibit 10.37 to our annual report on Form 10-K filed on February 24, 2011

10.34	Amended and Restated Amendment Two to Participation Agreement Supplemental Income Plan of GulfMark Offshore, Inc. dated February 10, 2012, between GulfMark Offshore, Inc. and Bruce A. Streeter *	Exhibit 10.1 to our current report on Form 8-K filed on February 15, 2012

10.35	Participation Agreement Supplemental Income Plan of GulfMark Offshore Inc. dated January 1, 2000 by John E. Leech*	Exhibit 10.39 to our annual report on Form 10-K filed February 24, 2011

10.36	Amendment One to Participation Agreement Supplemental Income Plan of GulfMark Offshore, Inc. dated December 29, 2010, between GulfMark Offshore, Inc. and John E. Leech*	Exhibit 10.40 to our annual report on Form 10-K filed February 24, 2011

10.37	Amended and Restated Amendment Two to Participation Agreement Supplemental Income Plan of GulfMark Offshore, Inc. dated February 9, 2012, between GulfMark Offshore, Inc. and John E. Leech*	Exhibit 10.2 to our current report on Form 8-K filed on February 15, 2012

10.38	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 filed on July 31, 2008

10.39	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	Filed herewith

10.40	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	Filed herewith

10.41	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


10.42	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

10.43	Amendment Agreement dated January 26, 2012, among The Royal Bank of Scotland PLC as original lender arranger, agent and security agent and GulfMark Americas, Inc., as borrower, and GulfMark Offshore, Inc. as guarantor	Exhibit 10.1 to our current report on Form 8-K filed on February 1, 2012

12.1	Computation of Ratio of Earnings to Fixed Charges	Filed herewith

21.1	Subsidiaries of GulfMark Offshore, Inc.	Filed herewith

23.1	Consent of KPMG LLP	Filed herewith

23.2	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, 2011, 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.	Filed herewith