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, 2010

OR

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

Commission file number 001-33607

GulfMark Offshore, Inc.

(Exact name of Registrant as specified in its charter)

Delaware	76-0526032
(State or other jurisdiction of	(I.R.S. Employer Identification No.)
incorporation or organization)
10111 Richmond Avenue, Suite 340
Houston, Texas	77042
(Address of principal executive offices)	(Zip Code)

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 o

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

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

   Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

   Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation in S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the 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.  o

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

Large accelerated filer  þ  Accelerated filer  o
Non-accelerated filer  o  (Do not check if a smaller reporting company)  Smaller Reporting Company  o

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

   The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2010, the last business day of the registrant’s most recently completed second fiscal quarter was $603,266,667, calculated by reference to the closing price of $26.20 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 23, 2011: 26,031,962

DOCUMENTS INCORPORATED BY REFERENCE

The information called for by Part III, Items 10, 11, 12, 13 and 14, will be included in a
definitive proxy statement to be filed pursuant to Regulation 14A within 120 days after the end of
the fiscal year covered by this Form 10-K, and is incorporated herein by reference.
Exhibit Index Located on Page 78

TABLE OF CONTENTS

		Page
PART I
Items 1 and 2.	Business and Properties		3
	Reorganization		3
	General Business		3
	The Company		4
	Worldwide Fleet		5
	Operating Segments		10
	Other		13
Item 1A.	Risk Factors		16
Item 1B.	Unresolved Staff Comments		23
Item 3.	Legal Proceedings		23
Item 4.	(Removed and Reserved)		23
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		23
Item 6.	Selected Consolidated Financial Data		25
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		27
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		40
Item 8.	Financial Statements and Supplementary Data		42
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		69
Item 9A.	Controls and Procedures		69
Item 9B.	Other Information		71
PART III
Item 10.	Directors, Executive Officers and Corporate Governance		71
Item 11.	Executive Compensation		71
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		71
Item 13.	Certain Relationships and Related Transactions, and Director Independence		71
Item 14.	Principal Accounting Fees and Services		71
PART IV
Item 15.	Exhibits, Financial Statement Schedules		72
EX-10.34
EX-10.35
EX-10.36
EX-10.37
EX-10.38
EX-10.39
EX-10.40
EX-12.1
EX-21.1
EX-23.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

2

PART I

ITEMS 1. and 2. Business and Properties

REORGANIZATION

     GulfMark Offshore, Inc., a Delaware corporation, was incorporated in 1996. On February 24, 2010, GulfMark Offshore, Inc., (“Old GulfMark”) merged with and into its wholly owned subsidiary, New GulfMark Offshore, Inc., a Delaware corporation (“New GulfMark”), pursuant to an agreement and plan of reorganization, dated as of October 14, 2009 (the “Reorganization Agreement”), with New GulfMark as the surviving corporation (such transaction, the “Reorganization”). The Reorganization was adopted by the requisite vote of stockholders at a special meeting of the stockholders of Old GulfMark on February 23, 2010. Under the U.S. maritime and vessel documentation laws, commonly referred to as the Jones Act, only those vessels that are owned and managed by U.S. citizens (as determined by those laws) and are built in and registered under the laws of the United States are allowed to transport merchandise and passengers for hire in U.S. territorial waters, otherwise known as “Coastwise Trade”. The Reorganization was designed to prevent certain situations from occurring that could jeopardize the Company’s eligibility as a U.S. citizen under the Jones Act and, therefore, its ability to engage in Coastwise Trade. At the effective time of the Reorganization, New GulfMark changed its name from “New GulfMark Offshore, Inc.” to “GulfMark Offshore, Inc”. The business, operations, assets and liabilities of New GulfMark immediately after the Reorganization were the same as business, operations, assets and liabilities of Old GulfMark immediately prior to the Reorganization.

     At the effective time of the Reorganization and pursuant to the Reorganization Agreement, each outstanding and treasury share of the common stock of Old GulfMark automatically converted into one share of Class A common stock of New GulfMark, which are subject to certain transfer and ownership restrictions designed to protect our eligibility to engage in Coastwise Trade (the “Maritime Restrictions”). References to our common stock mean, with respect to Old GulfMark prior to the Reorganization, common stock and, with respect to New GulfMark after the Reorganization, Class A common stock. The issuance of the shares of Class A common stock was registered under the Securities Act of 1933, as amended, pursuant to New GulfMark’s registration statement on Form S-4 (File No. 333-162612), which was declared effective by the U.S. Securities and Exchange Commission (the “SEC”) on January 22, 2010. Shares of Class A common stock of New GulfMark trade on the same exchange, the New York Stock Exchange (the “NYSE”), and under the same symbol, “GLF”, that the shares of Old GulfMark common stock traded on and under prior to the Reorganization.

     Unless otherwise indicated, references to “we”, “us”, “our” and the “Company” refer to New GulfMark, its subsidiaries and its predecessor, Old GulfMark, except that all such references prior to the effective time of the Reorganization on February 24, 2010 are references to Old GulfMark and its subsidiaries.

GENERAL BUSINESS

     We provide offshore marine services primarily to companies involved in the offshore exploration and production of oil and natural gas. Our vessels transport materials, supplies and personnel to offshore facilities, as well as move and position drilling structures. The majority of our operations are conducted in the North Sea, offshore Southeast Asia and offshore in the Americas. We also contract vessels into other regions to meet our customers’ requirements.

     We have the following operating segments: the North Sea (“N. Sea”), Southeast Asia (“SEA”) and the Americas. Our chief operating decision maker regularly reviews financial information about each of these operating segments in deciding how to allocate resources and evaluate our performance. The business within each of these geographic regions has similar economic characteristics, services, distribution methods and regulatory concerns. All of the operating segments are considered reportable segments under Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 280, “Segment Reporting.” For financial information about our operating segments and geographic areas, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Segment Results” included in Part II, Item 7, and Note 14 to our Consolidated Financial Statements included in Part II, Item 8.

     Our principal executive offices are located at 10111 Richmond Avenue, Suite 340, Houston, Texas 77042, and our telephone number at that address is (713) 963-9522. We file annual, quarterly, and current reports, proxy statements and other information with the SEC. This annual report on Form 10-K for the year ended December 31, 2010 includes as exhibits all required Sarbanes-Oxley Act Section 302 certifications by our CEO and CFO regarding the quality of our public disclosure. In addition, our CEO certifies annually to the New York Stock Exchange (“NYSE”) that he is not aware of any violation by the Company of the NYSE corporation governance listing standards. Our SEC filings are available free of charge to the public over the internet on our website at http://www.gulfmark.com and at the 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.

3

THE COMPANY

Offshore Marine Services Industry Overview

     Our customers employ our vessels to provide services supporting the construction, positioning and ongoing operation of offshore oil and natural gas drilling rigs and platforms and related infrastructure, and substantially all of our revenue is derived from providing these services. This industry employs various types of vessels, referred to broadly as offshore support vessels, or OSVs, that are used to transport materials, supplies and personnel, and to move and position drilling structures. Offshore marine service providers are employed by oil and natural gas companies that are engaged in the offshore exploration and production of oil and natural gas and related services. Services provided by companies in this industry are performed in numerous locations worldwide. The North Sea, offshore Southeast Asia, offshore West Africa, offshore Middle East, offshore Brazil and the U.S. Gulf of Mexico are each major markets that employ a large number of vessels. Vessel usage is also significant in other international markets, including offshore India, offshore Australia and offshore Trinidad, the Persian Gulf and the Mediterranean Sea. The industry is relatively fragmented, with more than 20 major participants and numerous smaller regional competitors. We currently operate a fleet of 88 OSVs in the following regions: 37 vessels in the North Sea, 15 vessels offshore Southeast Asia, and 36 vessels offshore the Americas. Our fleet is one of the world’s youngest, largest and most geographically balanced, high specification OSV fleets and our owned vessels have an average age of approximately eight years.

     Our business is directly impacted by the level of activity in worldwide offshore oil and natural gas exploration, development and production, which in turn is influenced by trends in oil and natural gas prices. In addition, oil and natural gas prices are affected by a host of geopolitical and economic forces, including the fundamental principles of supply and demand. The characteristics and current marketing environment in each region are discussed later in greater detail. Our strongest markets in recent years have been in the Southeast Asia region and in the Americas components of Brazil, Mexico and Trinidad. The North Sea region has experienced weak spot but strengthened long-term market conditions. Currently, our most challenging market is in the U.S. Gulf of Mexico, a component of the Americas segment, where several factors have decreased profitability and have made the area highly competitive. In the later half of 2009 and continuing in early 2010, natural gas commodity prices suffered declines compared to the previous couple of years. The lower prices had already affected drilling activity in the U.S. Gulf of Mexico when, in April 2010, a catastrophic fire and explosion sank a deepwater drilling rig and precipitated a major oil spill (the “Macondo Incident”). The Macondo Incident effectively shut down drilling in the U.S. Gulf of Mexico due both to oil spill cleanup efforts and a drilling moratorium. Although the cleanup was largely completed in August 2010 and the moratorium was lifted in October 2010, drilling activity has not recovered in the area and new government regulations continue to limit the possibility of a recovery in the near future. We continue to evaluate the market conditions in each region, and the potential impact these conditions may have on our business.

     Each of the major geographic offshore oil and natural gas production regions has unique characteristics that influence the economics of exploration and production and, consequently, the market demand for vessels in support of these activities. While there is some vessel interchangeability between geographic regions, barriers such as mobilization costs, vessel suitability and cabotage restrict migration of some vessels between regions. This is most notably the case in the North Sea, where vessel design requirements dictated by the harsh operating environment restrict relocation of vessels into that market. Conversely, these same design characteristics make North Sea capable vessels unsuitable for other areas where draft restrictions and, to a lesser degree, higher operating costs, restrict migration.

4

WORLDWIDE FLEET

     In addition to the vessels we own, we manage a number of vessels for third-party owners, providing support services ranging from chartering assistance to full operational management. Although these managed vessels provide limited direct financial contribution, the added market presence can provide a competitive advantage for the manager. The following table summarizes the overall owned, managed and total fleet changes since December 31, 2009:

	Owned			Managed			Total
	Vessels			Vessels			Fleet
December 31, 2009		73			19			92
New Build Program		3			-			3
Vessel Reductions		-			(5	)		(5	)
Vessel Dispositions		(2	)		-			(2	)
December 31, 2010		74			14			88
New Build Program		-			-			-
Vessel Reductions		-			-			-
Vessel Dispositions		-			-			-
February 24, 2011		74			14			88

Vessel Classifications

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

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

• Platform Support Vessels (PSVs) serve drilling and production facilities and support offshore construction and maintenance work. They are differentiated from other offshore support vessels by their cargo handling capabilities, particularly their large capacity and versatility. PSVs utilize space on deck and below deck and are used to transport supplies such as fuel, water, drilling fluids, equipment and provisions. PSVs range in size from 150 to 200 feet. Large PSVs (LgPSVs) typically range up to 300 feet in length, with a few vessels somewhat larger, and are particularly suited for supporting large concentrations of offshore production locations because of their large, clear after deck and below deck capacities. The majority of the LgPSVs we operate function primarily in this classification but are also capable of servicing construction support.

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

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

• Standby Rescue Vessels (Stby) perform a safety patrol function for an area and are required for all manned locations in the North Sea and in some other locations where oil and natural gas exploitation occurs. These vessels typically remain on station

5

	to provide a safety backup to offshore rigs and production facilities and carry special equipment to rescue personnel. They are equipped to provide first aid, shelter and, in some cases, function as support vessels.
•	Construction Support Vessels are vessels such as pipe-laying barges, diving support vessels or specially designed vessels, such as pipe carriers, used to transport the large cargos of material and supplies required to support the construction and installation of offshore platforms and pipelines. A large number of our LgPSVs also function as pipe carriers.
•	Utility Vessels are typically 90 to 150 feet in length and are used to provide limited crew transportation, some transportation of oilfield support equipment and, in some locations, standby functions.

     The following table summarizes our owned vessel fleet by classification and by region:

Owned Vessels by Classification
	AHTS		PSV		FSV/Crewboat
Region	AHTS	SmAHTS	LgPSV	PSV	FSV	Crew	SpV	Total
North Sea	3	-	19	2	-	-	1	25
Southeast Asia	8	3	2	1	-	-	-	14
Americas	3	-	3	20	4	4	1	35
	14	3	24	23	4	4	2	74

New Vessel Construction, Acquisition and Divestiture Program, and Drydocking Obligations

Vessel Construction and Acquisitions

     In 2007, we committed with Aker Yards ASA to build two new PSVs with double hull and various environmental enhancements. The first vessel was delivered in November 2009 and the second vessel was delivered in February 2010.

     Also in 2007, we entered into agreements with two shipyards to construct five vessels. Bender Shipbuilding & Repair Co., Inc. (“Bender”), a Mobile, Alabama based company, was contracted to build three PSVs and Gdansk Shiprepair Yard “Remontowa” SA, a Polish company, was contracted to build two AHTS vessels. In March 2009, we notified Bender that it was in default under our contract as a result of non-performance. We determined that we had a material impairment and recognized a charge of $46.2 million in the first quarter of 2009 relating to the construction in progress recorded under this contract. See Note 2 to the Consolidated Financial Statements included in Part II, Item 8 for more information. The first Remontowa vessel was completed and delivered in the second quarter of 2010, and the second vessel was completed and delivered in the third quarter of 2010. Both vessels were deployed to our Southeast Asia region.

     During 2010, we took delivery of three vessels that were under construction at December 31, 2009. We have no vessels currently under construction.

Vessel Additions Since December 31, 2009
			Year	Length			Month
Vessel	Region	Type	Built	(feet)	BHP	DWT	Delivered
North Purpose	N. Sea	PSV	2010	284	10,738	4,850	Feb-10
Sea Valiant	SEA	AHTS	2010	230	10,188	2,301	Jun-10
Sea Victor	SEA	AHTS	2010	230	10,188	2,301	Jul-10

Foreign Currency Contracts Related to Construction Contracts

     When applicable, we enter into forward currency contracts to minimize our foreign currency exchange risk related to the construction of new vessels. During 2007, we entered into a series of forward currency contracts relative to future milestone payments for the construction of Keppel vessels, all of which were delivered prior to December 31, 2009, and the two Aker Yards vessels

6

described above. These contracts were closed in early 2010 when the last Aker Yards vessel was delivered under the construction contract. As of December 31, 2010, we had no open foreign currency contracts.

Vessel Divestitures/ Vessels Held For Sale (Laid Up)

     In the second quarter of 2010, we sold one of our Americas vessels and recorded a $0.1 million loss. At the end of the third quarter of 2010, we sold one of our North Sea vessels and recorded a $5.2 million gain. As of February 24, 2011, we have one vessel that is held for sale and is not included in our fleet numbers.

Vessels Sold Since December 31, 2009
			Year	Length			Month
Vessel	Region	Type	Built	(feet)	BHP	DWT	Sold
North Traveller	N. Sea	LgPSV	1998	221	5,450	3,115	Sep-10
Seapower	Americas	SpV	1974	222	7,040	1,205	Apr-10

Vessels Held for Sale (Laid Up)
			Year		Length
Vessel	Region	Type	Built		(feet)		BHP		DWT
Clwyd Supporter	N. Sea	SpV		1984		266		10,700		1,350

Maintenance of Our Vessels and Drydocking Obligations

     In addition to repairs, we are required to make expenditures for the certification and maintenance of our vessels, and those expenditures typically increase with age. The demands of the market, the expiration of existing contracts, the start of new contracts, and customer preferences influence the timing of drydocks. Our drydocking expenditures for 2010 were $22.2 million. We anticipate approximately $16.7 million in drydocking expenditures in 2011.

Vessel Listing

     Currently, we operate a fleet of 88 vessels. Of these vessels, 74 are owned by us (see table below, which excludes laid up vessels and the 14 vessels we manage for other owners).

7

Owned Vessel Fleet
			Year	Length
Vessel	Region	Type (a)	Built	(feet)	BHP (b)	DWT (c)	Flag
Highland Bugler	N. Sea	LgPSV	2002	221	5,450	3,115	UK
Highland Champion	N. Sea	LgPSV	1979	265	4,800	3,910	UK
Highland Citadel	N. Sea	LgPSV	2003	236	5,450	3,200	UK
Highland Eagle	N. Sea	LgPSV	2003	236	5,450	3,200	UK
Highland Fortress	N. Sea	LgPSV	2001	236	5,450	3,200	UK
Highland Monarch	N. Sea	LgPSV	2003	221	5,450	3,115	UK
Highland Navigator	N. Sea	LgPSV	2002	275	9,600	4,250	Panama
Highland Pioneer	N. Sea	LgPSV	1983	224	5,400	2,500	UK
Highland Prestige	N. Sea	LgPSV	2007	284	10,767	4,993	UK
Highland Pride	N. Sea	LgPSV	1992	265	6,600	3,080	UK
Highland Rover(d)	N. Sea	LgPSV	1998	236	5,450	3,200	Panama/UK
Highland Star	N. Sea	LgPSV	1991	265	6,600	3,075	UK
North Challenger	N. Sea	LgPSV	1997	221	5,450	3,115	Norway
North Mariner	N. Sea	LgPSV	2002	275	9,600	4,400	Norway
North Promise	N. Sea	LgPSV	2007	284	10,767	4,993	Norway
North Stream	N. Sea	LgPSV	1998	276	9,600	4,585	Norway
North Truck	N. Sea	LgPSV	1983	265	6,120	3,370	Norway
North Vanguard	N. Sea	LgPSV	1990	265	6,600	4,000	Norway
North Purpose	N. Sea	PSV	2010	284	10,738	4,850	Norway
Highland Trader	N. Sea	LgPSV	1996	221	5,450	3,115	UK
Highland Courage	N. Sea	AHTS	2002	260	16,320	2,750	UK
Highland Valour	N. Sea	AHTS	2003	260	16,320	2,750	UK
Highland Endurance	N. Sea	AHTS	2003	260	16,320	2,750	UK
Highland Prince	N. Sea	PSV	2009	284	10,738	4,850	UK
Highland Spirit	N. Sea	SpV	1998	202	6,000	1,800	UK
Highland Guide	SEA	LgPSV	1999	218	4,640	2,800	Panama
Highland Legend	SEA	PSV	1986	194	3,600	1,442	Panama
Highland Drummer	SEA	LgPSV	1997	221	5,450	3,115	Panama
Sea Apache	SEA	AHTS	2008	250	10,700	2,700	Panama
Sea Cheyenne	SEA	AHTS	2007	250	10,700	2,700	Panama
Sea Guardian	SEA	SmAHTS	2006	191	5,150	1,500	Panama
Sea Intrepid	SEA	SmAHTS	2005	191	5,150	1,500	Panama
Sea Sovereign	SEA	SmAHTS	2006	230	5,500	1,800	Panama
Sea Supporter	SEA	AHTS	2007	225	7,954	2,360	Panama
Sea Choctaw	SEA	AHTS	2008	250	10,700	2,700	Panama
Sea Cherokee	SEA	AHTS	2009	250	10,700	2,700	Panama
Sea Comanche	SEA	AHTS	2009	250	10,700	2,700	Panama
Sea Valiant	SEA	AHTS	2010	213	10,188	2,301	Panama
Sea Victor	SEA	AHTS	2010	213	10,188	2,301	Panama
Austral Abrolhos(e)	Americas	SpV	2004	215	7,100	2,000	Brazil
Highland Scout	Americas	LgPSV	1999	218	4,640	2,800	Panama
Highland Piper	Americas	LgPSV	1996	221	5,450	3,115	Panama
Highland Warrior	Americas	LgPSV	1981	265	5,300	4,049	Panama
Sea Kiowa	Americas	AHTS	2008	250	10,700	2,700	Panama
Coloso	Americas	AHTS	2005	199	5,916	1,674	Mexico
Titan	Americas	AHTS	2005	199	5,916	1,674	Mexico

8

Owned Vessel Fleet
			Year	Length
Vessel	Region	Type (a)	Built	(feet)	BHP (b)	DWT (c)	Flag
Orleans	Americas	PSV	2004	210	6,342	2,586	USA
Bourbon	Americas	PSV	2004	210	6,342	2,586	USA
Royal	Americas	PSV	2004	210	6,342	2,586	USA
Chartres	Americas	PSV	2004	210	6,342	2,586	USA
Iberville	Americas	PSV	2004	210	6,342	2,586	USA
Bienville	Americas	PSV	2005	210	6,342	2,586	USA
Conti	Americas	PSV	2005	210	6,342	2,586	USA
St. Louis	Americas	PSV	2005	210	6,342	2,586	USA
Toulouse	Americas	PSV	2005	210	6,342	2,586	USA
Esplanade	Americas	PSV	2005	210	6,342	2,586	USA
First and Ten	Americas	PSV	2007	190	3,894	1,860	USA
Double Eagle	Americas	PSV	2007	190	3,894	1,860	USA
Triple Play	Americas	PSV	2007	190	3,894	1,860	USA
Grand Slam	Americas	PSV	2007	190	3,894	1,860	USA
Sailfish	Americas	Crew	2007	176	7,200	307	USA
Slam Dunk	Americas	PSV	2008	190	3,894	1,860	USA
Touchdown	Americas	PSV	2008	190	3,894	1,860	USA
Hat Trick	Americas	PSV	2008	190	3,894	1,860	USA
Slap Shot	Americas	PSV	2008	190	3,894	1,860	USA
Homerun	Americas	PSV	2008	190	3,894	1,860	USA
Knockout	Americas	PSV	2008	190	3,894	1,860	USA
Hammerhead	Americas	FSV	2008	181	7,200	543	USA
Bluefin	Americas	Crew	2008	165	7,200	337	USA
Albacore	Americas	Crew	2008	165	7,200	337	USA
Mako	Americas	FSV	2008	181	7,200	543	USA
Swordfish	Americas	Crew	2009	176	7,200	307	USA
Blacktip	Americas	FSV	2009	181	7,200	543	USA
Tiger	Americas	FSV	2009	181	7,200	543	USA

          The table above does not include the managed vessels or those vessels being held for sale.

(a)  Legend: LgPSV — Large platform supply vessel

PSV — Platform supply vessel
AHTS — Anchor handling, towing and supply vessel
SmAHTS — Small anchor handling, towing and supply vessel
SpV — Specialty vessel, including towing and oil spill response
FSV – Fast Supply Vessel
Crew – Crewboats

(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.

9

OPERATING SEGMENTS

The North Sea Operating Segment

	Owned			Managed			Total
	Vessels			Vessels			Fleet
December 31, 2009		25			17			42
New Build Program		1			-			1
Vessel Reductions		-			(5	)		(5	)
Vessel Dispositions		(1	)		-			(1	)
December 31, 2010		25			12			37
New Build Program		-			-			-
Vessel Reductions		-			-			-
Vessel Dispositions		-			-			-
February 24, 2011		25			12			37

Market and Segment Overview

     We define the North Sea market as offshore Norway, Denmark, the Netherlands, Germany, Great Britain, Ireland, the Faeroes Islands and Greenland. Historically, this has been the most demanding of all exploration frontiers due to harsh weather, erratic sea conditions, significant water depth and some long sailing distances. Exploration and production operators in the North Sea market have typically been large and well-capitalized entities (such as major and state-owned oil and natural gas companies) in large part because of the significant financial commitment required. However, in recent years, a number of independent operators have established operating bases in the region, thus diversifying the customer base. Projects in the North Sea tend to be fewer in number but larger in scope, with longer planning horizons than projects in regions with less demanding environments. Due to these factors, vessel demand in the North Sea has historically been more stable and less susceptible to abrupt swings than vessel demand in other regions.

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

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

Market Development

     Future visibility with regard to vessel demand is directly related to drilling and development activities in the region, construction work required in support of these activities, as well as demands outside of the region that draw vessels to other international markets. Geopolitical events, the demand for oil and natural gas in both mature and emerging countries and a host of other factors will influence the expenditures of both independent and major oil and gas companies.

     There was a transformation in the customer base in the region that began in 2003 as the major oil and natural gas companies disposed of prospects and mature producing properties in the North Sea to independent oil and natural gas companies. The independent companies typically had smaller capital expenditure budgets and shorter horizons that resulted in a decline in the number of long-term contracts and a corresponding increase in the number of vessels working in the spot market.

     Starting in late 2004 and continuing through early 2008, there was an increase in the number of large projects and long-term charters resulting from new reserve discoveries, an opening of portions of the Barents Sea to exploration activities by the Norwegian government, and a significant improvement in industry fundamentals. These actions triggered the building of a number of new vessels. In mid-2008, the outlook for the global economy became negative and worldwide energy demand forecasts declined. These factors resulted in a noticeable decrease in activity during 2009 and in the early part of 2010. However, exploration and development

10

spending in the North Sea region is expected to increase throughout 2011 and 2012, increasing offshore drilling and subsea construction activity and demand for vessel services in this region.

The Southeast Asia Operating Segment

	Owned		Managed		Total
	Vessels		Vessels		Fleet
December 31, 2009		12		1		13
New Build Program		2		-		2
Vessel Reductions		-		-		-
Vessel Dispositions		-		-		-
December 31, 2010		14		1		15
New Build Program		-		-		-
Vessel Reductions		-		-		-
Vessel Dispositions		-		-		-
February 24, 2011		14		1		15

Market and Segment Overview

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

     Southeast 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.

     During 2010, we took delivery of two vessels that were built in Poland. See further discussion under Vessel Construction and Acquisitions on page 6.

Market Development

     Vessels in this market are often smaller than those operating in areas such as the North Sea. However, the varying weather conditions, annual monsoons, severe typhoons and long distances between supply centers in Southeast Asia have allowed for a variety of vessel designs to compete, each suited for a particular set of operating parameters. Vessels designed for the U.S. Gulf of Mexico and other areas, where moderate weather conditions prevail have historically made up the bulk of the vessels in the Southeast Asia market. Demand for larger, newer and higher specification vessels has developed in the region where deepwater projects occur or where oil and natural gas companies employ larger fleets of vessels. This development led us to mobilize several vessels from the North Sea into this region from 2002 to 2007, to meet the changing market. North Sea vessels are larger than the typical vessels of the region. During the last five years, we have sold 11 of our older vessels serving Southeast Asia and have taken delivery of 12 new vessels.

     Changes in supply and demand dynamics have led, at times, to an excess number of vessels in other geographic markets. It is possible that vessels currently located in the Arabian/Persian Gulf area, Africa or the U.S. Gulf of Mexico could relocate to the Southeast Asia market; however, not all vessels currently located in those regions would be able to operate in Southeast Asia and oil and natural gas operators in this region are continuing to demand newer, higher specification vessels. As with many other regions, Southeast Asia is suffering from the economic downturn, with many vessels lying idle awaiting work.

11

The Americas Operating Segment

	Owned			Managed		Total
	Vessels			Vessels		Fleet
December 31, 2009		36			1		37
New Build Program		-			-		-
Vessel Reductions		-			-		-
Vessel Dispositions		(1	)		-		(1	)
December 31, 2010		35			1		36
New Build Program		-			-		-
Vessel Reductions		-			-		-
Vessel Dispositions		-			-		-
February 24, 2011		35			1		36

Market and Segment Overview

     We define the Americas market as offshore North, Central and South America, specifically including the United States, Mexico, Trinidad and Brazil. Most of our vessels operate in the deepwater areas of the U.S. Gulf of Mexico where we have a significant position. However, during 2010, primarily as a result of the substantially reduced drilling activity in the U.S. Gulf of Mexico as a result of the Macondo Incident and subsequent tightening of U.S. government regulations, we transferred seven vessels to Brazil, Mexico and Trinidad to work on long term contracts. We moved two additional vessels from the U.S. Gulf of Mexico to Trinidad in the first quarter of 2011. All vessels based in the Americas are supported from our onshore bases in St. Rose and Youngsville, Louisiana; Trinidad; Macae, Brazil; and Paraiso, Mexico.

U.S. Gulf of Mexico

     Drilling in the U.S. Gulf of Mexico can be divided into two sectors: the shallow waters of the continental shelf and the deepwater areas. Deepwater drilling is generally considered to be in water depths in excess of 1,000 feet. The continental shelf has been explored since the late 1940s and the existing infrastructure and knowledge of this sector allows for incremental drilling costs to be on the lower end of the range of worldwide offshore drilling costs. A resurgence of deepwater drilling began in the 1990s as advances in technology made this type of drilling economically feasible. Deepwater drilling is on the higher end of the cost range, and the substantial costs and long lead times required in this type of drilling make it less susceptible to short-term fluctuations in the price of crude oil and natural gas. Although the activity level of deepwater drilling had been increasing, the Macondo Incident resulted in a drilling moratorium. This moratorium was specifically centered around “deepwater” drilling, but effectively stopped all developmental drilling. The moratorium was lifted in October 2010, but more restrictive U.S. government regulations have continued to affect drilling operations. As a result, we made the decision to move a number of vessels out of the U.S. Gulf of Mexico to other markets in the Americas region in an effort to increase our vessel utilization. We expect activity in the U.S. Gulf of Mexico to resume and we remain positive about its future potential. As a result, a number of our modern DP-2 vessels remain in the U.S. Gulf of Mexico, some under long term contracts, and others in the spot market.

     In general, the U.S. Gulf of Mexico remains a protected market. The Jones Act requires that all vessels engaged in Coastwise Trade in the U.S. (which includes vessels servicing rigs and platforms in U.S. waters within the Exclusive Economic Zone), must be owned and managed by U.S. citizens, and be built in and registered under the laws of the United States. For more information see “Reorganization” and “Other—Government and Environmental Regulation— Maritime Regulations” in our “Business and Properties” included in this Part I, Items 1 and 2.

Brazil

     The Brazilian government presently permits private investment in the petroleum business and the early bid rounds for certain offshore concessions resulted in extensive commitments by major international oil companies and consortia of independents, many of whom have explored and are likely to continue to explore the offshore blocks awarded in the lease sales. This has created a demand for deepwater AHTSs and PSVs in support of the drilling and exploration activities that has been met primarily from mobilization of vessels from other regions. Petrobras, the Brazilian national oil company, as well as several international independents, continue to expand operations and announce discoveries. This expansion has created additional demand for offshore support vessels in the area and in 2010, we transferred four vessels from the U.S. Gulf of Mexico to work in Brazil under long term contracts. Looking forward, we expect continued growth in the area and we will continue to be active in bidding offshore support vessel opportunities as they develop.

12

     Currently, we operate nine vessels in Brazil, including a Brazilian built and flagged vessel. We have four PSVs, three LgPSVs and two AHTSs operating in the area under contracts of varying lengths, the earliest of which began in 1990 and the most recent of which began in the fourth quarter of 2010 under a multi-year contract. In May 2010, we sold one of the oldest vessels in our fleet, the SPV SeaPower for work outside our industry.

Mexico

     Since 2005, we have operated two AHTSs offshore Mexico on five-year primary-term contracts with Pemex, Mexico’s national oil company, that originally expired in February 2010. We recently entered into new long-term contracts with Pemex for these AHTSs. In addition, during 2010, we moved a crew boat into the area from the U.S. Gulf of Mexico on a long term contract with Pemex, bringing our vessel count in Mexico to three. Mexico could be a potentially large market for expanded deepwater activity, provided the government can develop a methodology for operations with non-Mexican international oil companies that works within its constitutional constraints. We will continue to actively bid into the area when opportunities arise.

Trinidad

     In Trinidad, we are supporting a significant drilling campaign for an international operator with five PSVs and three FSVs. During 2010, we moved two vessels into the area from the U.S. Gulf of Mexico, and two additional vessels moved during the first quarter of 2011. These vessels are all working on term charters with international clients. Given recent licensing and exploration activity in nearby locations, including Suriname and Guyana, we expect to see vessel support requirements operating from a Trinidad base for the foreseeable future.

OTHER

Seasonality

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

Fleet Availability

     A portion of our available fleet is committed under contracts of various terms. The following table outlines the percentage of our forward days under contract as of February 23, 2010 and February 24, 2011:

	As of February 24, 2011				As of February 23, 2010
	2011		2012		2010		2011
	Vessel Days		Vessel Days		Vessel Days		Vessel Days
North Sea		75.5%		55.4%		72.5%		37.2%
Southeast Asia		49.8%		22.7%		71.1%		30.6%
Americas		56.0%		29.4%		43.8%		14.0%
Overall Fleet		61.3%		36.7%		58.4%		24.5%

     International vessel contracts are typically longer in duration and are generally only cancelable for non-performance. Domestic vessel contracts are typically shorter in duration and generally provide for other cancellation provisions, including termination for convenience.

Other Markets

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

13

Customers, Contract Terms and Competition

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

     Contract or charter durations vary from single-day to multi-year in length, based upon many different factors that vary by market. Additionally, there are “evergreen” charters (also known as “life of field” or “forever” charters), and at the other end of the spectrum, there are “spot” charters and “short duration” charters, which can vary from a single voyage to charters of less than six months. Longer duration charters are more common where equipment is not as readily available or specific equipment is required. In the North Sea region, multi-year charters have been more common and constitute a significant portion of that market. Term charters in the Southeast Asia region have historically been less common than in the North Sea and generally less than two years in length. Recently, however, consistent with the change in the demand in the region, Southeast Asia contract periods are extending out further in time. In addition, charters for vessels in support of floating production are typically “life of field” or “full production horizon charters”. In the Americas, particularly in the U.S. Gulf of Mexico, charters vary in length from short term to multi-year periods, many with thirty day cancellation clauses. In Brazil, Mexico, and Trinidad, contracts are generally multi-year term contracts with cancellation provisions. We also have other contracts containing non-cancelable provisions except for unsatisfactory vessel performance. As a result of options and frequent renewals, the stated duration of charters may have little correlation with the length of time the vessel is actually contracted to a particular customer.

     Bareboat charters are contracts for vessels, generally for a term in excess of one year, whereby the owner transfers all market exposure for the vessel to the charterer in exchange for an arranged fee. The charterer has the right to market the vessel without direction from the owner. Currently, we have no third party bareboat chartered vessels in our fleet.

     Managed vessels add to the market presence of the manager but provide limited direct financial contribution. Management fees are typically based on a per diem rate and are not subject to fluctuations in the charter hire rates. The manager is typically responsible for disbursement of funds for operating the vessel on behalf of the owner. Currently, we have 14 vessels under management.

     Substantially all of our charters are fixed in British Pounds, or GBP; Norwegian Kroner, or NOK; Euros; U.S. Dollars, or US$; or Brazilian Reais. We attempt to reduce currency risk by matching each 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 Customs Service, and their foreign equivalents, and to regulation by private industry organizations such as the American Bureau of Shipping. The Coast Guard and the National Transportation Safety Board set safety standards and are authorized to investigate vessel accidents and recommend improved safety standards, while the Customs Service is authorized to inspect vessels at will. We believe that we are in material compliance with all applicable laws and regulations.

Maritime Regulations

     We are subject to the Merchant Marine Act of 1936, which provides that, upon proclamation by the President of the United States of a national emergency or a threat to the security of the national defense, the Secretary of Transportation may requisition or purchase any vessel or other watercraft owned by United States citizens (which includes United States corporations), including vessels under construction in the United States. If one of the vessels in our fleet were purchased or requisitioned by the federal government under

14

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.

15

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

Insurance

In mid-2010, we reviewed our insurance coverage, specifically in light of the Macondo Incident. In particular, we assessed our coverage levels and limits for possible marine liabilities, including pollution, personal injury or death, and property damage. Our review did not result in any substantial adjustments to our coverages or limits.

Litigation

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

Employees

     We have approximately 1,700 employees located principally in the United States, the United Kingdom, Norway, Southeast Asia, and Brazil. Through our contract with a crewing agency, we participate in the negotiation of collective bargaining agreements for approximately 840 contract crew members who are members of two North Sea unions, under evergreen employment agreements. Wages are renegotiated annually in the second half of each year for the North Sea unions. We have no other collective bargaining agreements; however, we do employ crew members who are members of national unions but we do not participate in the negotiation of those collective bargaining agreements. Relations with our employees are considered satisfactory. To date, our operations have not been interrupted by strikes or work stoppages.

Properties

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

ITEM 1A. Risk Factors

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

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

• prevailing oil and natural gas prices;

• expectations about future prices and price volatility;

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

• sale and expiration dates of available offshore leases;

• demand for petroleum products;

• current availability of oil and natural gas resources;

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

• local and international political, environmental and economic conditions;

• technological advances; and

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

     The level of offshore exploration, development and production activity has historically been characterized by volatility. Prior to mid-2008, there was a period of high prices for oil and natural gas, and oil and gas companies increased their exploration and development activities. A decline in the worldwide demand for oil and natural gas or prolonged low oil or natural gas prices in the future, such as occurred in late 2008, however, typically results in reduced exploration and development of offshore areas and a

16

decline in the demand for our offshore marine services. Any such decrease in activity is likely to reduce our day rates and our utilization rates and, therefore, could have a material adverse effect on our financial condition and results of operations.

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

     Charter rates for marine support vessels depend in part on the supply of the vessels. We could experience a reduction in demand as a result of an increased supply of vessels. Excess vessel capacity in the industry may result from:

• constructing new vessels;

• moving vessels from one offshore market area to another;

• converting vessels formerly dedicated to services other than offshore marine services; or

• declining offshore oil and gas drilling production activities.

     In the last ten years, construction of vessels of the types we operate has increased. The addition of new capacity of various types to the worldwide offshore marine fleet or declining offshore oil and gas drilling and production activities are likely to increase competition in those markets where we presently operate which, in turn, could reduce day rates, utilization rates and operating margins, which would adversely affect our financial condition and results of operations.

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

     We and our customers are subject to extensive governmental regulation in the form of international conventions, federal, state and local laws and laws and regulations in jurisdictions where our vessels operate and are registered. The risks of incurring substantial compliance costs, liabilities and penalties for noncompliance are inherent in offshore marine services operations. Compliance with Jones Act, as well as with environmental, health, safety and vessel and port security laws can reduce our business opportunities and increase our costs of doing business. Additionally, these laws change frequently. Therefore, we are unable to predict the future costs or other future impact of these laws on our operations and our customers. There can be no assurance that we can avoid significant costs, liabilities and penalties imposed on us as a result of government regulation in the future.

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

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

• catastrophic marine disaster;

• adverse sea and weather conditions;

• mechanical failure;

• navigation errors;

• collision;

• oil and hazardous substance spills, containment and clean up;

• labor shortages and strikes;

• damage to and loss of drilling rigs and production facilities; and

• war, sabotage, piracy and terrorism risks.

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

     We maintain insurance coverage against substantially all of the casualty and liability risks listed above, subject to deductibles and certain exclusions. We have renewed our primary insurance program for the insurance year 2011-2012, and have negotiated terms for renewal of our 2012-2013 primary marine coverages. We can provide no assurance, however, that our insurance coverage will be available beyond the renewal periods, and will be adequate to cover future claims that may arise.

17

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

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

• foreign currency exchange fluctuations;

• legal and government regulatory requirements;

• difficulties and costs of staffing and managing international operations;

• language and cultural differences;

• potential vessel seizure or nationalization of assets;

• import-export quotas or other trade barriers;

• difficulties in collecting accounts receivable and longer collection periods;

• political and economic instability;

• changes to shipping tax regimes;

• imposition of currency exchange controls; and

• potentially adverse tax consequences.

     We cannot predict whether any such conditions or events might develop in the future or whether they might have a material effect on our operations. Also, our subsidiary structure and our operations are in part based on certain assumptions about various foreign and domestic tax laws, currency exchange requirements and capital repatriation laws. While we believe our assumptions are correct, there can be no assurance that taxing or other authorities will reach the same conclusions. If our assumptions are incorrect or if the relevant countries change or modify such laws or the current interpretation of such laws, we may suffer adverse tax and financial consequences, including the reduction of cash flow available to meet required debt service and other obligations.

     Our tax expense and effective tax rate on our worldwide earnings could be higher should there be changes in tax legislation in countries where we operate, should we lose our tonnage tax qualifications or tax exemptions and/or should we increase our operations in high tax jurisdictions where we operate.

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

     For example, our North Sea operations based in the U.K. and Norway have special tax incentives for qualified shipping operations, commonly referred to as tonnage tax, which provides for a tax based on the net tonnage capacity of a qualified vessels, resulting in significantly lower taxes than those that would apply if we were not a qualified shipping company in those jurisdictions. Norway enacted a new tonnage tax system in January 2007, subjecting us to ordinary corporate tax on accumulated untaxed shipping profits as of December 31, 2006. In February 2010, Norway’s Supreme Court ruled that the 2007 legislation to tax prior years’ profits was retroactive taxation and unconstitutional and, accordingly, 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 have decided to elect the simplified tax system, which beginning in 2011 requires three equal annual installment payments of the tax that is calculated as ten percent (10%) of two-thirds of the untaxed tonnage tax profits. There is no guarantee that current tonnage tax regimes will not be changed or modified which could, along with any of the above mentioned factors, materially adversely affect our international operations and, consequently, our business, operating results and financial condition.

     Our U.K. and Norway tonnage tax companies are subject to specific disqualification triggers, which, if we fail to manage them, could jeopardize our qualified tonnage tax status in those countries. Certain of the disqualification events or actions are coupled with one or more opportunities to cure or otherwise maintain the tonnage tax qualification but not all are curable. Our qualified Singapore based vessels are exempt from Singapore taxation through December 2017 with extensions available in certain circumstances beyond 2017, but there is no guarantee that extensions will be granted.

     Our operations in the United States increased with the Rigdon Acquisition in July 2008, and our income tax expense, or benefit, and effective tax rate are impacted by inclusion of related U.S. earnings, or losses, taxed at the combined U.S. federal and state tax rates. Additionally, our tax returns are subject to examination and review by the tax authorities in the jurisdictions in which we operate.

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

     We are exposed to foreign currency exchange rate fluctuations and exchange rate risks as a result of our foreign operations and when we construct vessels abroad. To minimize the financial impact of these risks, we attempt to match the currency of our debt and

18

operating costs with the currency of the revenue streams. We occasionally enter into forward foreign exchange contracts to hedge specific exposures, which include exposures related to firm contractual commitments in the form of future vessel payments, but we do not speculate in foreign currencies. Because we conduct a large portion of our operations in foreign currencies, any increase in the value of the U.S. Dollar in relation to the value of applicable foreign currencies could potentially adversely affect our operating revenue or construction costs when translated into U.S. Dollars.

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

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

• shortages of equipment;

• unforeseen engineering problems;

• work stoppages;

• lack of shipyard availability;

• weather interference;

• unanticipated cost increases;

• shortages of materials or skilled labor; and

• insolvency of the ship repairer or ship builder.

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

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

     Expenditures required for the repair, certification and maintenance of a vessel typically increase with vessel age. These expenditures may increase to a level at which they are not economically justifiable and, therefore, to maintain our current fleet size we may seek to construct or acquire additional vessels. The cost of adding a new vessel to our fleet ranges from under $10.0 million to $100.0 million and potentially higher. We can give no assurance that we will have sufficient capital resources to build or acquire the vessels required to expand or to maintain our current fleet size and vessel configuration.

     While we expect our cash on hand, cash flow from operations and available borrowings under our credit facilities to be adequate to fund our existing commitments, our ability to pay these amounts is dependent upon the success of our operations. To-date, we have been able to obtain adequate financing to fund all of our commitments. See “Long Term Debt” and “Liquidity and Capital Resources” in our Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) included in Part II, Item 7.

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

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

• price, service and reputation of vessel operations and crews;

• national flag preference;

• operating conditions;

• suitability of vessel types;

• vessel availability;

• technical capabilities of equipment and personnel;

• safety and efficiency;

• complexity of maintaining logistical support; and

• cost of moving equipment from one market to another.

19

     Many of our competitors have substantially greater resources than we have. Competitive bidding and downward pressures on profits and pricing margins could adversely affect our business, financial condition and results of operations.

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

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

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

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

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

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

     The Maritime Restrictions imposed as a result of the Reorganization may have an adverse effect on us and our stockholders.

     As a result of the Reorganization, our Class A common stock is now subject to certain transfer and ownership restrictions designed to protect our eligibility to engage in Coastwise Trade, including restrictions that limit the maximum permitted percentage of outstanding shares of Class A common stock that may be owned or controlled in the aggregate by non-U.S. citizens to a maximum of 22 percent (collectively, the “Maritime Restrictions”). These Maritime Restrictions:

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

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

• provide for the automatic transfer of shares in excess of the maximum permitted percentage (“Excess Shares”) to a trust for sale and may result in non-U.S. citizens suffering losses from the sale of Excess Shares;

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

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

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

20

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

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

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

     The Jones 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 recent volatility in oil and gas prices and disruptions in the credit markets and general economy may adversely impact our business.

     As a result of volatility in oil and natural gas prices and ongoing uncertainty of the global economic environment, we are unable to determine whether customers will reduce spending on exploration and development drilling or whether customers and/or vendors and suppliers will be able to access financing necessary to sustain their current level of operations, fulfill their commitments and/or fund future operations and obligations. The current global economic environment may impact industry fundamentals and impact our customers’ abilities to pay for the services of our vessels. The potential resulting decrease in demand for offshore services could cause the industry to cycle into a prolonged downturn. These conditions could have a material adverse effect on our business, financial condition and results of operations.

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

     There is a concern that emissions of greenhouse gases (“GHG”) alter the composition of the global atmosphere in ways that affect the global climate. Climate change, including the impact of global warming, may create physical and financial risk. Physical risks from climate change include an increase in sea level and changes in weather conditions. Given the maritime nature of our business, we do not believe that physical climate change is likely to have a material adverse effect on us.

     Financial risks relating to climate change are likely to arise from increasing legislation and regulation, as compliance with any new rules could be difficult and costly. U.S. federal legislation has been proposed in Congress to reduce GHG emissions. In addition, in the absence of federal GHG legislation, the EPA has taken several recent steps to regulate GHG emissions, which regulations have been challenged. Depending on the outcome of such Congressional legislation or EPA regulations, increased energy, environmental and other costs and capital expenditures could be necessary to comply with the limitations. Our vessels also operate in foreign jurisdictions that are addressing climate changes by legislation or regulation. Unless and until Congressional legislation or EPA regulations are

21

enacted and its terms are finalized, we cannot reasonably or reliably estimate its impact on our financial condition, operating performance or ability to compete.

     Adverse impacts upon the oil and gas industry relating to climate change may also effect us as demand for our services depends on the level of activity in offshore oil and natural gas exploration, development and production. Although we do not expect that demand for oil and gas will lessen dramatically over the short term, in the long term global warming may reduce the demand for oil and gas or increased regulation of GHG may create greater incentives for use of alternative energy sources. Any long term material adverse effect on the oil and gas industry may have a material adverse effect on our financial condition and operating results, but we cannot reasonably or reliably estimate that it will occur, when it will occur or that it will impact us.

       Recent Events in the U.S. Gulf of Mexico Have Adversely Impacted and Are Likely to Continue to Adversely Impact Our Operations and Financial Condition.

     The Macondo Incident resulted in 11 deaths, multiple personal injuries, significant property damage and the release of hydrocarbons that resulted in significant pollution and contamination. In May 2010, the U.S. Department of Interior issued a memorandum imposing a temporary moratorium on deepwater drilling on the outer continental shelf. This moratorium was lifted on October 12, 2010, subject, however, to new standards, requirements and regulations that must be complied with before drilling can commence. The catastrophe and moratorium have significantly and adversely disrupted oil and gas exploration and development activities in the U.S. Gulf of Mexico.

     On January 11, 2011, a federal commission appointed by the President released its report regarding the causes of the catastrophe and made recommendations as to what legislative or regulatory measures should be taken in order to minimize the possibility of a recurrence of a disastrous oil spill. It is currently unclear how any of these recommendations will be implemented and what impact they would have on oil and gas exploration and development activities in the U.S. Gulf of Mexico. It remains uncertain what impact the incident itself and the commission report may have on the regulation of offshore oil and gas exploration and development activity, the cost or availability of insurance coverage to cover the risks of such operations, or what actions may be taken by our customers, governmental agencies, or other industry participants in response to the incident. In addition, we cannot predict whether any possible changes in regulations would affect only deepwater drilling or all operations in the U.S. Gulf of Mexico or would also affect drilling and operations in other regions around the world in which we operate. At this time, various bills are being considered by Congress which, if enacted, could either significantly increase the costs of conducting oil and gas drilling and exploration activities in the U.S. Gulf of Mexico, or potentially eliminate a substantial portion of drilling and operation activity from the U.S. Gulf of Mexico. There is uncertainty as to whether Congress will repeal the $75.0 million limitation for non-reclamation liability under the Oil Pollution Act of 1990 and revise penalties for pollution liabilities, broaden liability under the Jones Act and Death on the High Seas Act, and restrict certain rights to limit liability of a vessel owner under the Limitations of Liability Act of 1851. Significant changes in these laws could have a material adverse effect on our business, financial condition and results of operation.

     The disruption in oil and gas exploration activities from the moratorium had a material adverse impact on our U.S. Gulf of Mexico drilling support operations in the second and third quarters of 2010, and, even with the lifting of the moratorium, continued through the fourth quarter of 2010. Announced and anticipated changes in laws and regulations regarding offshore oil and gas exploration and development activities, the cost or availability of insurance, and decisions by customers, governmental agencies, or other industry participants could further reduce demand for our services or increase our costs of operations. This could further increase the adverse impact on our financial condition and operating results, but we cannot reasonably or reliably estimate to what extent such changes will occur, when they will occur, or how severely they will impact us.

     After cleanup efforts ceased, the portion of our U.S. fleet involved in the effort were released in a more restricted and more competitive market in the U.S. Gulf of Mexico. We have since relocated vessels to Brazil, Mexico and Trinidad where more profitable opportunities existed. However, as a result of the Macondo Incident and the subsequent issues regarding drilling in the region, our competitors could redeploy their vessels into other regions in which we operate, which would increase the competition in that area, potentially resulting in lowered profit margins. In addition, our customers may seek to renegotiate the terms of their contracts or avoid their obligations under the contracts, both of which could adversely affect our business, financial condition and results of operations.

     Although we have no knowledge of any litigation or claims against us relating to the recent events in the U.S. Gulf of Mexico, no assurance can be given that we will not be involved in litigation or claims in the future or that they will not have a material adverse effect on our financial condition or results of operation.

22

ITEM 1B. Unresolved Staff Comments

NONE

ITEM 3. Legal Proceedings

General

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

ITEM 4.  (Removed and Reserved)

PART II

ITEM 5. Market for 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:

	2010				2009
	High		Low		High		Low
Quarter ended March 31,		$29.77		$23.79		$28.36		$16.00
Quarter ended June 30,		$34.47		$24.56		$34.63		$25.12
Quarter ended September 30,		$30.95		$25.69		$33.49		$24.73
Quarter ended December 31,		$33.53		$29.25		$34.88		$25.84

     For the period from January 1, 2011 through February 23, 2011, the range of low and high sales prices of our common stock was $30.30 to $43.10, respectively. On February 23, 2011, the closing sale price of our Class A common stock as reported by the NYSE was $41.25 per share and there were 607 stockholders of record.

     We have not declared or paid cash dividends during the past five years. Pursuant to the terms of the indenture under which the senior notes, as further described in Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Long-Term Debt” and Note 6 of the “Notes to the Consolidated Financial Statements” in Part II, Item 8 are issued, we may be restricted from declaring or paying dividends; however, we currently anticipate that, for the foreseeable future, any earnings will be retained for the growth and development of our business. The declaration of dividends is at the discretion of our Board of Directors. Our dividend policy will be reviewed by the Board of Directors at such time as may be appropriate in light of future operating conditions, dividend restrictions of subsidiaries and investors, financial requirements, general business conditions and other factors.

     Equity incentive plan information required by this item may be found in Note 9 of the “Notes to the Consolidated Financial Statements” in Part II, Item 8 herein.

23

Performance Graph

     The following performance graph and table compare the cumulative return on our common stock to the Dow Jones Total Market Index and the Dow Jones Oilfield Equipment and Services Index for the periods indicated. The graph assumes (i) the reinvestment of dividends, if any, and (ii) the value of the investment of our common stock and each index to have been $100 at December 31, 2005.

Comparison of Cumulative Total Return

	2005	2006	2007	2008	2009	2010
GulfMark Offshore, Inc.	100	119	152	78	91	96
Dow Jones Total Market Index	100	116	123	77	96	110
Dow Jones Oilfield Equipment and Services Index	100	113	164	67	102	126

24

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,
	2010			2009			2008			2007			2006
	(Amounts in thousands, except per share amounts)
Operating Data:
Revenue	$	359,766		$	388,871		$	411,740		$	306,026		$	250,921
Direct operating expenses		170,638			166,183			143,925			108,386			91,874
Drydock expense		22,182			15,696			11,319			12,606			9,049
General and administrative expenses		44,029			43,700			40,244			32,311			24,504
Depreciation and amortization		56,959			53,044			44,300			30,623			28,470
Impairment charge		97,665			46,247			-			-			-
Gain on sale of assets		(5,095	)		(5,552	)		(34,811	)		(12,169	)		(10,237	)
Operating income (loss)		(26,612	)		69,553			206,763			134,269			107,261
Interest expense		(21,693	)		(20,281	)		(14,291	)		(7,923	)		(15,648	)
Interest income		985			377			1,446			3,147			1,263
Other income (expense), net		(126	)		(1,153	)		1,609			(298	)		(95	)
Income tax (provision) benefit (a)		12,701			2,087			(11,743	)		(30,220	)		(3,052	)
Net income (loss)	$	(34,745	)	$	50,583		$	183,784		$	98,975		$	89,729
Amounts per common share (basic) (b):
Net income (loss)	$	(1.36	)	$	2.01		$	7.74		$	4.41		$	4.40
Weighted average common shares (basic)		25,519			25,151			23,737			22,435			20,377
Amounts per common share (diluted) (b):
Net income (loss)	$	(1.36	)	$	1.99		$	7.56		$	4.29		$	4.28
Weighted average common shares (diluted)		25,519			25,446			24,319			23,059			20,975
Statement of Cash Flows Data:
Cash provided by operating activities	$	91,574		$	171,045		$	205,201		$	128,577		$	104,869
Cash used in investing activities		(53,857	)		(68,199	)		(186,787	)		(175,383	)		(28,300	)
Cash provided by (used in) financing activities		(32,837	)		(120,250	)		56,754			373			(20,679	)
Effect of exchange rate changes on cash		236			8,722			(14,526	)		3,793			2,679
Other Data:
Adjusted EBITDA (c)	$	127,760		$	168,844		$	251,063		$	164,892		$	135,731
Cash dividends per share		-			-			-			-			-
Total vessels in fleet as of year end (d)		88			92			94			61			60
Average number of owned or chartered vessels (e)		73.4			71.3			59.5			46.8			48.5
	As of December 31,
	2010			2009			2008			2007			2006
	(In thousands)
Balance Sheet Data:
Cash and cash equivalents	$	97,195		$	92,079		$	100,761		$	40,119		$	82,759
Vessels, equipment and other fixed assets, including construction in progress, net		1,194,200			1,204,416			1,169,513			754,000			571,989
Total assets		1,464,450			1,565,659			1,556,967			934,012			750,829
Long-term debt (f)		293,095			326,361			462,941			159,558			159,490
Total stockholders’ equity		945,957			987,468			854,843			676,091			541,428

(a)	See Note 7 to our “Consolidated Financial Statements – Income Taxes”, included in Part II, Item 8.
(b)	Earnings per share is based on the weighted average number of shares of common stock and common stock equivalents outstanding.
(c)	EBITDA is defined as net income (loss) before interest expense, interest income, income tax (benefit) provision, and depreciation, amortization and impairment. Adjusted EBITDA is calculated by adjusting EBITDA for certain items that we believe are non-cash

25

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,
	2010			2009			2008			2007			2006
	(In thousands)
Net income (loss)	$	(34,745	)	$	50,583		$	183,784		$	98,975		$	89,729
Interest expense		21,693			20,281			14,291			7,923			15,648
Interest income		(985	)		(377	)		(1,446	)		(3,147	)		(1,263	)
Income tax provision (benefit)		(12,701	)		(2,087	)		11,743			30,220			3,052
Depreciation, amortization and impairment		154,624			99,291			44,300			30,623			28,470
EBITDA		127,886			167,691			252,672			164,594			135,636
Adjustments:
Cumulative effect of change in accounting principle		-			-			-			-			-
Debt refinancing costs		-			-			-			-			-
Other *		(126	)		1,153			(1,609	)		298			95
Adjusted EBITDA	$	127,760		$	168,844		$	251,063		$	164,892		$	135,731

*	Includes foreign currency transaction adjustments.
(d)	Includes managed vessels in addition to those that are owned and chartered at the end of the applicable period (excludes vessels held for sale). See “Our Fleet” in Part I, Items 1 and 2 “Business and Properties” for further information concerning our fleet.
(e)	Average number of vessels is calculated based on the aggregate number of vessel days available during each period divided by the number of calendar days in such period. Includes owned and bareboat chartered vessels only, and is adjusted for additions and dispositions occurring during each period.
(f)	Excludes current portion of long-term debt.

26

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. Since 2001, we have increased our owned fleet by more than 50 vessels through either new build programs or acquisitions. In addition, we have sold certain older vessels that no longer meet our objective of maintaining a modern, diversified and technologically advanced fleet. We believe our relatively young fleet, which requires less maintenance and refurbishment work during required drydockings than older fleets, allows for less downtime, resulting in more dependable operations for us and for our customers.

Enhancing fleet utilization through development of specialty applications for our vessels: We operate some of the most technologically advanced vessels available. Our highly efficient, multiple-use vessels provide our customers flexibility and are constructed with design elements such as dynamic positioning, firefighting, moon pools, ROV handling and oil spill response capabilities. In addition, we design and equip new build vessels specifically to meet our customer needs.

Focusing on attractive markets: We conduct our operations mainly in the North Sea, offshore Southeast Asia and offshore Americas markets. Our focus on these regions is driven by what we perceive to be higher barriers to entry, lower volatility of day rates (except in the Americas) and greater potential for increasing day rates in these markets than in other markets. Our operating experience in these markets has enabled us to anticipate and profitably respond to trends, such as the increasing demand for multi-function vessels, which we believe will be met through the additions we have made in the past few years to our North Sea and Southeast Asia fleets. In addition, we have the capacity under appropriate market conditions to alter the geographic focus of our operations to a limited degree by shifting vessels between our existing markets and by entering new markets as they develop economically and become more profitable.

Managing our risk profile through chartering arrangements: We utilize various contractual arrangements in our fleet operations, including long-term charters, short-term charters, sharing arrangements and vessel alliances. Sharing arrangements provide us and our customers the opportunity to benefit from rising charter rates by subchartering the contracted vessels to third parties at prevailing market rates during any downtime in the customers’ operations. We also operate and participate in arrangements where vessels of similar specifications enter into alliances which include technical cooperation. We believe these contractual arrangements help us reduce volatility in both day rates and vessel utilization and are beneficial to our customers.

General

     We provide marine support and transportation services to companies involved in the offshore exploration and production of oil and natural gas. Our vessels transport drilling materials, supplies and personnel to offshore facilities, as well as move and position drilling structures. A substantial portion of our operations are international. Our fleet has grown in both size and capability, from an original 11 vessels in 1990 to our present number of 88 active vessels, through strategic acquisitions and the new construction of technologically advanced vessels, partially offset by dispositions of certain older, less profitable vessels. At February 24, 2011, our active fleet includes 74 owned vessels and 14 managed vessels.

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

     From time to time, we bareboat charter vessels with revenue and operating expenses reported in the same income and expense categories as our owned vessels. The chartered vessels, however, incur bareboat charter fees instead of depreciation expense. Bareboat

27

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.

Allowance for Doubtful Accounts

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

     Historically, we have collected appreciably all of our accounts receivable balances. At December 31, 2010 and 2009, respectively, we provided an allowance for doubtful accounts of $0.3 million for both years. Additional allowances for doubtful accounts may be necessary as a result of our ongoing assessment of our customers’ ability to pay, particularly in the event of deteriorating economic conditions. Since amounts due from individual customers can be significant, future adjustments to our allowance for doubtful accounts could be material if one or more individual customer balances are deemed uncollectible. If an account receivable were deemed uncollectible and all reasonable collection efforts were exhausted, the balance would be removed from accounts receivable and the allowance for doubtful accounts.

Drydocking, Mobilization and Financing Costs

     The periodic requirements of the various classification societies requires vessels to be placed in drydock twice in a five-year period. Generally, drydocking costs include refurbishment of structural components as well as major overhaul of operating equipment, subject to scrutiny by the relevant classification society. We expense these costs as incurred.

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

28

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

Long-Lived Assets, Goodwill and Intangibles

     Our long-lived tangible assets consist primarily of vessels and construction-in-progress. Our goodwill primarily relates to the 2001 acquisition of Sea Truck Holding AS and the 1998 acquisition of Brovig Supply AS. Our identifiable intangible assets relate to the value assigned to customer relationships as a result of the Rigdon Acquisition. The determination of impairment of all long-lived assets, goodwill, and intangibles is conducted when indicators of impairment are present and at least annually, for goodwill. Impairment testing on tangible long-lived assets is performed on an asset-by-asset basis and impairment testing on goodwill is performed on a reporting-unit basis for the reporting units where the goodwill is recorded.

     In assessing potential impairment related to our long-lived assets, the assets’ carrying values are compared with undiscounted expected future cash flows. If the carrying value of any long-lived asset is greater than the related undiscounted expected future cash flows, we measure impairment by comparing the fair value of the asset with its carrying value.

     At least annually, we assess whether goodwill is impaired. We assess whether impairment exists by comparing the fair value of each operating segment to its carrying value, including goodwill. We use a combination of two valuation methods, a market approach and an income approach, to estimate the fair value of our operating segments. Fair value computed by these two methods is arrived at using a number of factors, including projected future operating results, economic projections, anticipated future cash flows, comparable marketplace data and the cost of capital. There are inherent uncertainties related to these factors and to our judgment in applying them to this analysis. However, we believe that these two methods provide a reasonable approach to estimating the fair value of our operating segments.

     The market approach estimates fair value by measuring the aggregate market value of publicly-traded companies with similar characteristics of our business as a multiple of their reported cash flows. We then apply that multiple to our operating segment’s cash flows to estimate their fair value. We believe that this approach is appropriate because it provides a fair value estimate using valuation inputs from entities with operations and economic characteristics comparable to our operating segments.

     The income approach is based on the long-term projected future cash flows of our operating segments. We discount the estimated cash flows to present value using a weighted-average cost of capital that considers factors such as the timing of the cash flows and the risks inherent in those cash flows. We believe that this approach is appropriate because it provides a fair value estimate based upon our operating segments’ expected long-term performance considering the economic and market conditions that generally affect our business.

     In the second quarter of 2010, we assessed our Americas region goodwill for impairment. In our assessment, we evaluated the impact on the 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 does not impact our liquidity or debt covenant compliance. See Note 2 to the Consolidated Financial Statements contained in Part II, Item 8.

     In the third quarter of 2007, Bender Shipbuilding and Repair Co., Inc. (“Bender”), a Mobile, Alabama based company, was contracted to build three PSVs. In March 2009, we notified Bender that it was in default under our contract as a result of non-performance. We determined that we had a material impairment and recognized a charge of $46.2 million in the first quarter of 2009 relating to the construction in progress recorded under this contract. See Note 2 to the Consolidated Financial Statements contained in Part II, Item 8.

Income Taxes

     The majority of our non-U.S. based operations are subject to foreign tax systems that provide significant incentives to qualified shipping activities. Our U.K. and Norway based vessels are taxed under “tonnage tax” regimes having a ten year term and are renewable. Our U.K. regime was renewed in November 2010 for another ten years. Our qualified Singapore based vessels are exempt from Singapore taxation through December 2017 with extensions available in certain circumstances beyond 2017. The tonnage tax regimes provide for a tax based on the net tonnage weight of a qualified vessel. These foreign tax beneficial structures continued to result in our earnings incurring significantly lower taxes than those that would apply if we were not a qualified shipping company in those jurisdictions. The tonnage tax regimes in the North Sea significantly reduce the cash required for taxes in that region.

29

     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 an approximately $4.9 million tax provision. The net result of the 2010 Norwegian tonnage tax law changes was a $10.1 million tax benefit recorded in our 2010 tax provision. Our liability to settle under the simplified tax system is included in our December 31, 2010 balance sheet as approximately $1.6 million current income tax payable and approximately $3.3 million as other long term payable. Annually the subsequent 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.

     U.S. foreign tax credits can be carried forward for ten years. We have $7.2 million of such foreign tax credit carryforwards that begin to expire in 2011. We also have certain foreign net operating loss carryforwards that result in net deferred tax assets of approximately $2.3 million for which we have established a valuation allowance. We have considered estimated future taxable income in the relevant tax jurisdictions to utilize these tax credit and loss carryforwards and have considered what we believe to be ongoing prudent and feasible tax planning strategies in assessing the need for the valuation allowance. This information is based on estimates and assumptions including projected taxable income. If these estimates and related assumptions change in the future, or if we determine that we would not be able to realize other deferred tax assets in the future, an adjustment to the valuation allowance would be provided in the period such determination was made.

     Effective January 1, 2008, Mexico legislated a new revenue based tax, which in effect is an alternative minimum tax payable to the extent that the new revenue based tax exceeds the current income tax liability. These revenue based tax rates were 16.5% for 2008, 17% for 2009 and are 17.5% for 2010 and beyond. Effective January 1, 2010, Mexico enacted changes to corporate income tax rates as follows: 2010 through 2012 – 30%; 2013 – 29%; and 2014 and beyond - 28%.

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

     See also Note 1 and Note 7 to our Consolidated Financial Statements included in Part II, Item 8.

Commitments and Contingencies

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

30

nature of the exposure. Such exposures change from period to period based upon updated relevant facts and circumstances, which can cause the estimate to change. In the recent past, our estimates for contingent liabilities have been sufficient to cover the actual amount of our exposure.

Multi-employer Pension Obligation

     Certain current and former U.K. subsidiaries are participating in a multi employer retirement fund known as the Merchant Navy Officers Pension Fund (MNOPF). At December 31, 2010, we had $5.1 million accrued related to this liability, which reflects all obligations assessed by the 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. In addition, we have been advised by the trustee that as of March 31, 2009, the MNOPF was underfunded and as a result there is the potential that in the future participating employers will be assessed additional obligations to correct the underfunding. The amount and timing of additional potential future obligations depends on a number of factors, but principally on future fund performance and the underlying actuarial assumptions. Our share of the fund’s deficit is dependent on a number of factors including future actuarial valuations, the number of participating employers, and the final method used in allocating the required contribution among participating employers.

Split-Dollar Life Insurance Plans

     Our President and Chief Executive Officer and our Executive Vice President – Operations each have split-dollar life insurance policies for which we pay the premiums, with a right to repayment of such premiums paid. We have also entered into a supplemental income plan, as amended in December 2010, with each covered individual to provide him with a cash amount equal to the premiums paid.

Off-Balance Sheet Arrangements

     We have evaluated our off-balance sheet arrangement, and have concluded that we do not have any material relationships with unconsolidated entities or financial partnerships that have been established for the purpose of facilitating off-balance sheet arrangements (as that term is defined in Item 303(a)(4)(ii) of Regulations S-K). Based on this evaluation we believe that no disclosures relating to off-balance sheet arrangements are required.

Consolidated Results of Operations

Comparison of the Fiscal Years Ended December 31, 2010 and December 31, 2009

     Our consolidated revenue decreased from $388.9 million to $359.8 million, or $29.1 million, mainly due to lower day rates in all regions, partially offset by the increased capacity resulting from a full year for vessels added in 2009 and the three new vessels added in 2010. For the year ended December 31, 2010, we had a net loss of $34.7 million or $1.36 per diluted share, compared to net income of $50.6 million or $1.99 per diluted share for the year ended December 31, 2009.

     Day rates decreased 14.3% in 2010, from $18,388 in 2009 to $15,758 in 2010, contributing $48.2 million to the decrease in revenue. This decrease was offset by an increase in utilization from 81.4% in 2009 to 85.5% in 2010, increasing revenue by $3.0 million. In addition, the weakening of the U.S. Dollar contributed $3.0 million to the revenue increase. Capacity resulting from the overall net additions increased revenue by $13.1 million.

31

	Year Ended December 31,
					Increase
	2010		2009		(Decrease)
	(Dollars in thousands)
Average Rates Per Day Worked (a) (b):
North Sea (c)	$	16,985	$	19,930	$	(2,945)
Southeast Asia		16,943		20,780		(3,837)
Americas		14,281		16,098		(1,817)
Overall Utilization (a) (b):
North Sea (c)		93.5%		88.8%		4.7%
Southeast Asia		84.7%		90.0%		(5.3%)
Americas		80.1%		73.3%		6.8%
Average Owned or Chartered Vessels (a) (d):
North Sea		25.1		24.8		0.3
Southeast Asia		13.0		11.5		1.5
Americas		35.3		35.0		0.3
Total		73.4		71.3		2.1

(a)	Includes all owned or bareboat chartered vessels. Managed vessels and vessels held for sale are not included.
(b)	Average rates per day worked is defined as total charter revenue divided by number of days worked. Overall utilization rate is defined as the total number of days worked divided by the total number of days of availability in the period.
(c)	Revenue for vessels in our North Sea fleet are primarily earned in GBP, NOK and Euros, and have been converted to U.S. Dollars at the average exchange rate (US Dollar/GBP, US Dollar/NOK and US Dollar/Euro) for the periods indicated below. The North Sea based fleet also includes vessels working offshore India, offshore Africa and the Mediterranean.

	Year Ended December 31,
		2010	2009
$1 US=GBP		0.647	0.638
$1 US=NOK		6.036	6.244
$1 US=Euro		0.754	0.716

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

     Direct operating expenses increased by $4.5 million during 2010 mainly as a result in the net increase in fleet size compared to 2009. We recorded a $97.7 million dollar impairment of our goodwill during the second quarter of 2010 as a result of the deteriorating market conditions in the U.S. Gulf of Mexico. Drydock expense increased by $6.5 million from 2009 to 2010 due to a higher number of drydock days. General and administrative expenses increased by $0.3 million from 2009 and depreciation expense increased by $3.9 million year over year as a result of the increase in the size of our fleet in 2010. The gain on sale of assets relates to the sale of two of our vessels during 2010.

     Interest expense increased $1.4 million year over year due mainly to the decrease in capitalized interest resulting from the completion of all vessels in our new build program. Interest income increased $0.6 million due to moderately higher market interest rates, and other expense decreased by $1.0 million as a result of foreign currency movements throughout 2010.

     The income tax benefit for 2010 was $12.7 million, compared to a benefit of $2.1 million from 2009. The 2010 effective tax rate was 26.8% and the 2009 effective tax rate was (4.3%). The 2010 tax benefit was mostly the result of our $10.1 million Norwegian net tax benefit coupled with the net effect of tax benefits from operating losses in our high tax jurisdictions exceeding tax expense from our lower taxed operations.

Comparison of the Fiscal Years Ended December 31, 2009 and December 31, 2008

     Our revenue decreased from $411.7 million in 2008 to $388.9 million in 2009, resulting mainly from the decreased utilization related to the overall market downturn and the currency effect of the stronger U.S. Dollar. Overall day rates decreased for the same time period which also negatively impacted revenue. In 2009, we sold two vessels and deemed one vessel a constructive total loss after the vessel was damaged in a fire. In addition, we experienced the full year effect of the five vessel sales that occurred in mid to

32

late 2008. The reduction in vessels is offset by the full year effect of the vessels acquired as part of the Rigdon Acquisition on July 1, 2008 and the addition of six new builds throughout the year. For the year ended December 31, 2009, net income was $50.6 million or $1.99 per diluted share, compared to $183.8 million, or $7.56 per diluted share for the year ended December 31, 2008.

     Overall utilization decreased from 94.3% in 2008 to 81.4% in 2009, contributing $39.9 million to the decrease in revenue. The strengthening of the U.S. Dollar in all regions decreased revenue by $29.1 million. Overall day rates decreased from $19,697 in 2008 to $18,388 in 2009, contributing $12.4 million to the decrease in revenue. Offsetting the decreases to revenue was the capacity increase related to the full year effect of the vessels acquired in the Rigdon Acquisition and the net additions throughout the year. This increased revenue by $58.6 million.

	Year Ended December 31,
					Increase
	2009		2008		(Decrease)
	(Dollars in thousands)
Average Rates Per Day Worked (a) (b):
North Sea (c)	$	19,930	$	22,837	$	(2,907	)
Southeast Asia		20,780		17,723		3,057
Americas		16,098		16,567		(469	)
Overall Utilization (a) (b):
North Sea (c)		88.8%		94.6%		(5.8%)
Southeast Asia		90.0%		94.5%		(4.5%)
Americas		73.3%		93.4%		(20.1%)
Average Owned or Chartered Vessels (a) (d):
North Sea		24.8		27.2		(2.4	)
Southeast Asia		11.5		13.0		(1.5	)
Americas		35.0		19.3		15.7
Total		71.3		59.5		11.8

(a)	Includes all owned or bareboat chartered vessels. Managed vessels are not included.
(b)	Average rates per day worked is defined as total charter revenue divided by number of days worked. Overall utilization rate is defined as the total number of days worked divided by the total number of days of availability in the period.
(c)	Revenue for vessels in our North Sea fleet are primarily earned in GBP, NOK and Euros, and have been converted to U.S. Dollars at the average exchange rate (US Dollar/GBP, US Dollar/NOK and US Dollar/Euro) for the periods indicated below. The North Sea based fleet also includes vessels working offshore India, offshore Africa and the Mediterranean.

	Year Ended December 31,
		2009	2008
$1 US=GBP		0.638	0.541
$1 US=NOK		6.244	5.580
$1 US=Euro		0.716	0.681

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

     Direct operating expenses increased $22.3 million in 2009 when compared to 2008. This increase was mainly due to the full year effect of the increase in vessels as a result of the Rigdon Acquisition, and the delivery of new vessels throughout the year. We reported an impairment charge of $46.2 million in the first quarter of 2009 as a result of a default of the construction contract by the builder of three of our vessels. Drydock expense increased by $4.4 million from 2008 to 2009. General and administrative expenses increased $3.5 million from 2008, and depreciation expense increased $8.7 million year over year. The increase in general and administrative and depreciation expense was mainly a result of the Rigdon Acquisition coupled with higher salary, bonus and employee benefits. The gain on sale of assets of approximately $5.5 million relates to the sale of three vessels.

     Interest expense increased $6.0 million from 2008 due mainly to the increase in debt incurred and assumed as part of the Rigdon Acquisition and the decrease in capitalized interest resulting from the decrease in new build construction. The decrease in interest income of $1.1 million is due to lower interest rates in the year. Other expense of $1.2 million was mainly related to foreign currency movements throughout 2009.

33

     The income tax benefit for 2009 was $2.1 million, compared to an $11.7 million income tax expense in 2008. The 2008 effective tax rate was 6.0%, which included the effect of six months of earnings from operations attributable to the Rigdon Acquisition along with a provision for uncertain tax liabilities in a foreign jurisdiction. The 2009 effective tax rate was (4.3%) with the decrease from the 2008 rate mostly attributable to operating losses in our high tax jurisdictions plus the reversal of certain valuation allowances no longer required, which were somewhat offset by the net tax expense from repatriations to the U.S.

Segment Results

     As discussed in “General Business” included in Part I, Items 1 and 2, we have three operating segments: the North Sea, Southeast Asia and the Americas, each of which is considered a reportable segment under FASB ASC 280. The majority of our revenue is derived from our long-lived assets located in foreign jurisdictions. In 2010, we had $104.5 million in revenue and $462.9 million in long-lived assets attributed to the United States, our country of domicile.

     Management evaluates segment performance primarily based on operating income. Cash and debt are managed centrally, and since the regions do not manage those items, the gains and losses on foreign currency remeasurements associated with these items are excluded from operating income. Management considers segment operating income to be a good indicator of each 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,
	2010			2009			2008
	(In thousands)
North Sea	$	38,209		$	54,014		$	126,486
Southeast Asia		39,761			58,105			62,447
Americas		(81,223	)		(19,155	)		38,344
Total reportable segment operating income (loss)		(3,253	)		92,964			227,277
Other		(23,359	)		(23,411	)		(20,514	)
Total reportable segment and other operating income (loss)	$	(26,612	)	$	69,553		$	206,763

North Sea Region:

	Year Ended December 31,
	2010			2009			2008
	(In thousands)
Revenue	$	148,740		$	165,415		$	226,124
Direct operating expenses		78,253			80,854			86,445
Drydock expense		7,598			6,818			8,237
General and administrative expense		11,277			10,598			11,414
Depreciation and amortization expense		18,649			17,186			22,623
Gain on sale of assets		(5,246	)		(4,055	)		(29,081	)
Operating income	$	38,209		$	54,014		$	126,486

Comparison of Fiscal Year Ended December 31, 2010 and December 31, 2009

     Revenue for the North Sea of $148.7 million decreased $16.7 million, or 10% compared to 2009. The decrease in day rates from $19,930 in 2009 to $16,985 in the current year contributed $24.7 million to the decrease in revenue. This decrease was offset by increased utilization and capacity during 2010. Utilization increased in the current year to 93.5% from 88.8% in 2009, resulting in an increase to revenue of $2.4 million. Increased capacity from the addition of one new build vessel in late 2009 and one new build vessel in early 2010 contributed $5.6 million to revenue compared to the prior year. Operating income of $38.2 million in 2010 was $15.8 million lower than 2009 due mainly to the decrease in revenues. Direct operating expenses were lower by $2.6 million in 2010

34

partly due to the strengthening of the U.S. Dollar, in addition to lower crew salaries and lower supplies expense. Drydock expense increased $0.8 million from 2009 due to a higher drydock cost per day average. Depreciation expense increased year over year by $1.5 million due to the previously mentioned delivery of two new build vessels. General and administrative expense increased by $0.7 million due primarily to increased employee benefits.

Comparison of Fiscal Year Ended December 31, 2009 and December 31, 2008

     Revenue for the North Sea of $165.4 million in 2009 decreased $60.7 million, or 26.8%, compared to 2008. The decrease is attributable to the strengthening of the U.S. Dollar against the GBP and NOK, which reduced revenue by $26.9 million. In addition, due to the weakening of the market, utilization decreased from 94.6% in 2008 to 88.8% in 2009, which reduced revenue by $16.4 million, and day rates also decreased from $22,839 in 2008 to $19,930 in 2009 negatively impacting revenue by $5.4 million. In 2009, the region experienced the full year effect of the sale of two vessels and the mobilization of a vessel to the Southeast Asia region in 2008, which is partially offset by the addition of a new delivery in late 2009 and the overall effect of an increase in capacity of $12.0 million. Operating income decreased by $72.5 million, primarily as a result of the decrease in revenue and the decrease on the gain on sale of assets. Direct operating expenses year over year were lower by $5.6 million due in part by the strengthening of the U.S. Dollar coupled with lower crew salaries and benefits. Drydock expense was also lower by $1.4 million resulting mainly from a lower number of drydock days. Depreciation expense decreased by $5.4 million resulting mainly from the sale of two vessels. General and administrative expense decreased by $0.8 million due to lower salaries and benefits.

Southeast Asia Region:

	Year Ended December 31,
	2010		2009			2008
	(In thousands)
Revenue	$	66,533	$	76,544		$	77,851
Direct operating expenses		10,395		8,865			12,509
Drydock expense		4,796		2,095			250
General and administration expense		2,659		1,841			2,193
Depreciation and amortization expense		8,922		7,131			6,170
Gain on sale of assets		-		(1,493	)		(5,718	)
Operating income	$	39,761	$	58,105		$	62,447

Comparison of Fiscal Year Ended December 31, 2010 and December 31, 2009

     Revenues for the Southeast Asia based fleet decreased by $10.0 million to $66.5 million in 2010. Day rates decreased from $20,780 in 2009 to $16,943 in the current year, which decreased revenue by $14.2 million. Overall utilization decreased from 90% in 2009 to 84.7% in 2010, contributing $3.7 million to the decrease in revenue. Capacity had a positive impact to revenue of $7.9 million compared to 2009 as a result of the full year effect of two new build vessels added in 2009 and one new build vessel added in 2010. Although two new build vessels were added in 2010, only one was utilized in the year. Operating income was lower during 2010 by $18.3 million year over year, due mainly by the lower revenue and the decrease in gain on sale of assets, coupled with increases to direct operating expense and depreciation expense resulting primarily from the increased fleet. Drydock expense increased by $2.7 million as a result of more drydock days in 2010. General and administrative expense increased by $0.8 million as a result of higher office salaries, benefits and higher bad debt expense.

Comparison of Fiscal Year Ended December 31, 2009 and December 31, 2008

     Southeast Asia region revenue decreased by $1.3 million to $76.5 million in 2009, compared to $77.9 million in 2008. The slight decrease in revenue is due mainly to the decrease in utilization which decreased from 94.5% in 2008 to 90% in 2009 contributing $4.5 million to the decrease in revenue. Average day rates increased from $17,723 in 2008 to $20,780 in 2009 due mainly to the additions of four new vessels, however, the mix of days worked on low day rate vessels negatively impacted revenue by $4.9 million. Capacity positively impacted revenue by $8.1 million due to the full year effect of the two new deliveries in 2008 and the two new deliveries in 2009, which was offset by the full year effect of the sale of three older vessels in 2008 and the loss of a vessel as a result of the damage incurred in a fire in 2009. Operating income decreased $4.3 million year over year, primarily as a result of the decrease in revenue and the decrease of the gain on sale of assets. General and administrative cost decreased by $0.4 million as a result of lower salaries and benefits and a decrease in bad debt expense.

35

Americas Region:

	Year Ended December 31,
	2010			2009			2008
	(In thousands)
Revenue	$	144,493		$	146,912		$	107,765
Direct operating expenses		81,990			76,464			44,972
Drydock expense		9,788			6,783			2,832
General and administrative expense		7,798			8,685			6,769
Depreciation and amortization expense		28,321			27,892			14,860
(Gain) loss on sale of assets		154			(4	)		(12	)
Impairment charge		97,665			46,247			-
Operating income (loss)	$	(81,223	)	$	(19,155	)	$	38,344

Comparison of Fiscal Year Ended December 31, 2010 and December 31, 2009

     Our Americas region revenue decreased $2.4 million, from $146.9 in 2009 to $144.5 in 2010. Day rates decreased from $16,098 in 2009 to $14,281 in 2010, which negatively impacted revenue by $6.3 million. Capacity had an overall negative impact to revenue by $0.3 million as a result of the sale of one of our older vessels during the second quarter of the current year, offset by the full year effect of three new build vessels added during 2009. Utilization increased from 73.3% in 2009 to 80.1% in 2010, resulting in $4.2 million of higher revenue. Despite the Macondo Incident and its subsequent effects, we were able to maintain a higher utilization in 2010 due to our involvement in the cleanup effort. In addition, we moved vessels to other areas in the Americas region and kept them fully utilized. Excluding impairment charges in both years, operating income decreased $10.7 million from 2009 resulting from lower revenues and higher direct operating expenses resulting due to increases in fleet costs and higher crew wages and benefits. Drydock expense was also higher in 2010 as we incurred 41 more drydock days during the current year than during 2009. General and administrative expense decreased by $0.9 million due to a combination of lower operating taxes and lower bad debt expense.

Comparison of Fiscal Year Ended December 31, 2009 and December 31, 2008

     Revenue for the Americas region increased year over year by $39.1 million, or 36.3%, from $107.8 million in 2008 to $146.9 million in 2009, primarily as a result of the full year effect of the Rigdon Acquisition that occurred July 1, 2008, the full year effect of the mobilization of two vessels into the region in 2008 and the addition of three new deliveries in 2009 which in total contributed $62.4 million to the increase in revenue. As a result of the market down turn mainly in the U.S. Gulf of Mexico, utilization decreased from 93.4% in 2008 to 73.3% in 2009, decreasing revenue by $18.9 million. Average day rates also decreased from $16,567 in 2008 to $16,098 in 2009, reducing revenue by $4.4 million. Operating income, excluding the impairment charge of $46.2 million decreased by $11.3 million, which resulted from the $31.5 million increase in direct operating expense and the increase in dry dock expense of $4.0 million, both resulting from the increase in the number of vessels. Depreciation expense also increased by $13.0 million due to the increase in fleet. General and administrative expense increased by $1.9 million from the prior year due to increased salaries and benefits, mainly attributable to the Rigdon Acquisition.

Liquidity and Capital Resources

     Our ongoing liquidity requirements are generally associated with our need to service debt, fund working capital, maintain our fleet, finance the construction of new vessels and to acquire or improve equipment or vessels. We plan to continue to be active in the acquisition of additional vessels through both the resale market and new construction. Bank financing, equity capital and internally generated funds have historically provided funding for these activities. Internally generated funds are directly related to fleet activity and vessel day rates, which are generally dependent upon the demand for our vessels which is ultimately determined by the supply and demand for the offshore drilling for crude oil and natural gas.

     We completed our last vessel construction program in 2010 and have no new vessel construction commitments for 2011. Interest expense at current rates under our existing debt arrangements, assuming no additional borrowings, will be approximately $22.9 million for 2011. Minimum repayments under our existing debt arrangements will be approximately $33.3 million for 2011. These amounts are anticipated to be paid from a combination of cash on hand and cash from operations.

     In addition, we are required to make expenditures for the certification and maintenance of our vessels. We expect our drydocking expenditures to be approximately $16.7 million in 2011.

36

     At December 31, 2010, we had approximately $97.2 million of cash on hand, no amounts drawn under our $175.0 million Revolving Loan Facility, $166.7 million borrowed under our Facility Agreement, and $160.0 million outstanding under our Senior Notes.

     We anticipate that cash on hand and future cash flow from operations for 2011 will be adequate to repay our debts due and payable during such period, to complete scheduled drydockings, to make normal recurring capital additions and improvements and to meet operating and working capital requirements. This expectation, however, is dependent upon the success of our operations.

Long-Term Debt

Revolving Loan Facility

     We currently have a $175.0 million Secured Reducing Revolving Loan Facility (the “Revolving Loan Facility”) with a syndicate of financial institutions led by Den Norske Bank, or DNB, as agent. The multi-currency facility is structured as follows: $25.0 million allocated to GulfMark Offshore, Inc.; $60.0 million allocated to Gulf Offshore N.S. Limited, a wholly owned U.K. subsidiary; $30.0 million allocated to GulfMark Rederi AS, a wholly owned Norwegian subsidiary; and $60.0 million allocated to Gulf Marine Far East Pte Ltd., a wholly owned Singapore subsidiary. The facility matures in June 2013 and the maximum availability begins to reduce in increments of $15.0 million every six months beginning in December 2011. Security for the facility is provided by first priority mortgages on certain vessels. The interest rate ranges from LIBOR plus a margin of 0.7% to 0.9% depending on our EBITDA coverage ratio. At December 31, 2010, we were in compliance with all covenants and had no amounts drawn under this facility.

Senior Notes

     In 2004, we issued $160.0 million aggregate principal amount of 7.75% senior notes due July 2014. The 7.75% senior notes pay interest semi-annually on January 15 and July 15. The 7.75% senior notes are currently callable at a redemption price of 102.583%. Beginning on July 15, 2011 the redemption price reduces to 101.292% and after July 15, 2012 the 7.75% senior notes are callable at par, respectively, plus accrued interest.

     The 7.75% senior notes are general unsecured obligations and rank equally in right of payment with all existing and future unsecured senior indebtedness and are senior to all existing and future subordinated indebtedness. The 7.75% senior notes are effectively subordinated to all future secured obligations to the extent of the assets securing such obligations and all existing and future indebtedness and other obligations of our subsidiaries and trade payables incurred in the ordinary course of business. Under certain circumstances, our payment obligations under the 7.75% senior notes may be jointly and severally guaranteed on a senior unsecured basis by one or more of our subsidiaries.

     The indenture under which the 7.75% senior notes are issued imposes operating and financial restrictions on us. These restrictions can limit or prohibit, among other things, our ability to incur additional indebtedness, make capital expenditures, create liens, sell assets and make cash dividends or other payments. At December 31, 2010, we were in compliance with all indenture covenants.

Facility Agreement

     On December 17, 2009, our subsidiary GulfMark Americas, Inc. (the “Borrower”) entered into a $200.0 million facility agreement (the “Facility Agreement”) with the Royal Bank of Scotland PLC (“RBS”). The Facility Agreement bears interest at the rate of LIBOR plus 250 basis points and principal is due in quarterly installments of $8.3 million. The Facility Agreement matures on December 31, 2012. We have an interest rate swap agreement overlaying a portion of the Facility Agreement that has the effect of fixing the interest rate at 4.145% on $100.0 million of this debt. This interest rate swap is accounted for as a cash flow hedge.

     The Facility Agreement is secured by a majority of our U.S. flagged vessels. We have unconditionally guaranteed all existing and future indebtedness and liabilities of the Borrower arising under the Facility Agreement and other loan documents. Such guarantee also covers obligations of the Borrower arising under any interest rate swap contract and other security documentation related to the Facility Agreement. The collateral that secures the loans under the Facility Agreement will secure all of the 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

37

that all obligations under the Facility Agreement are due and payable and exercise its rights with respect to the collateral under the Facility Agreement.

     The Facility Agreement contains customary financial covenants, representations, and warranties. We have been and continue to be in compliance with the requirements of the Facility Agreement and we anticipate that we will be in compliance with these covenants throughout the term of the agreement.

Current Year Cash Flow

     At December 31, 2010, we had cash on hand of $97.2 million. Cash provided by operating activities for the year ended December 31, 2010, was $91.6 million compared to $171.0 million in the previous year. The decrease was primarily attributable to lower operating income resulting from the downturn in the global market conditions.

     Cash used in investing activities for the years ended December 31, 2010 and 2009 was $53.9 million and $68.2 million, respectively. In 2010, we spent approximately $73.4 million on asset purchases, primarily new construction. In 2009, we spent approximately $77.4 million. In 2010 and 2009, we sold assets for approximately $19.6 million and $9.2 million, respectively. The proceeds from these asset sales decreased the reported cash used in investing activities.

     In 2010, we used $32.8 million in financing activities, compared to providing $120.3 million in 2009. In 2010, we incurred $51.0 million in new long-term debt and repaid $84.3 million of debt. During 2009, we incurred $200.0 million of new long-term debt and repaid $322.3 million in debt.

Debt and Other Contractual Obligations

     The following table summarizes our contractual obligations at December 31, 2010, and the effect these obligations are expected to have on liquidity and cash flows in future periods (in millions):

	2011		2012		2013		2014		2015		Thereafter
Repayment of Long-Term Debt, Excluding Debt Discount of $0.3 million	$	33.3	$	133.3	$	-	$	160.0	$	-	$	-
Interest Payments	$	21.5	$	19.8	$	12.4	$	12.4	$	-	$	-
Purchase Obligations for New Build Program		-		-		-		-		-		-
Non-Cancelable Operating Leases		1.7		1.3		0.9		0.8		0.5		0.7
Long Term Income Taxes Payable		1.8		1.8		1.8		-		-		5.4
Other		0.8		0.8		1.0		0.8		0.7		3.4
Total	$	59.1	$	157.0	$	16.1	$	174.0	$	1.2	$	9.5

     Due to the uncertainty with respect to the timing of future cash payments, if any, associated with our unrecognized tax benefits at December 31, 2010, we are unable to make reasonably reliable estimates of the period of cash settlements with the respective taxing authority. Therefore, $15.7 million of unrecognized tax benefits have been excluded from the contractual obligations table above.

Other Commitments

     We execute letters of credit, performance bonds and other guarantees in the normal course of business that ensure our performance or payments to third parties. The aggregate notional value of these instruments was $4.6 million and $0.2 million at December 31, 2010 and 2009, respectively. In the past, no significant claims have been made against these financial instruments. We believe the likelihood of demand for payment is minimal and expect no material cash outlays to occur from these instruments.

Currency Fluctuations and Inflation

     A majority of our operations are international; therefore we are exposed to currency fluctuations and exchange rate risks. Charters for vessels in our North Sea fleet are primarily denominated in GBP, with a portion denominated in NOK or Euros. In areas where currency risks are potentially high, we normally accept only a small percentage of charter hire in local currency, with the remainder paid in U.S. Dollars. Operating costs are substantially denominated in the same currency as charter hire in order to reduce the risk of currency fluctuations. The North Sea fleet generated 41% of our total consolidated revenue for the year ended December 31, 2010. In 2010, the exchange rates of GBP, NOK and Euros against the U.S. Dollar ranged as follows:

38

					Year		As of
	High		Low		Average		February 23, 2011
$1 US=GBP		0.701		0.611		0.647		0.616
$1 US=NOK		6.705		5.610		6.036		5.629
$1 US=Euro		0.839		0.689		0.754		0.727

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

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

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

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

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

     One or more of these factors may change and, in response, we may begin to use financial instruments to hedge risks of currency fluctuations. We will from time to time hedge known liabilities denominated in foreign currencies to reduce the effects of exchange rate fluctuations on our financial results, such as a fair value hedge associated with the construction of vessels. In this regard, in 2007, we entered into forward currency contracts to specifically hedge the foreign currency exposure related to firm contractual commitments in the form of future vessel payments. As a result, by design, there is an exact offset between the gain or loss exposure in the related underlying contractual commitment. These contracts expired in early 2010 and there are no outstanding contracts at December 31, 2010. See Part I, Items 1 and 2 “Business and Properties – New Vessel Construction, Acquisition and Divestiture Program, and Drydocking Obligations”. We do not use foreign currency forward contracts for trading or speculative purposes.

     Reflected in the accompanying consolidated balance sheet at December 31, 2010, is $39.1 million in accumulated other comprehensive income primarily relating to the higher exchange rate at December 31, 2010 in comparison to the exchange rate when we invested capital in these markets. Accumulated other comprehensive income related to the changes in foreign currency exchange rates was $54.0 million at December 31, 2009. Changes in the accumulated other comprehensive income are non-cash items that are primarily attributable to investments in vessels and U.S. Dollar-based capitalization between our parent company and our foreign subsidiaries. The current year activity reflects the changes in the U.S. Dollar compared to the functional currencies of our major operating subsidiaries, particularly in the U.K. and Norway.

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

New Accounting Pronouncements

     Refer to Note 1 “Nature of Operations and Summary of Significant Accounting 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 support and transportation services and future capital expenditures. Such statements are subject to certain risks, uncertainties and assumptions, including, without limitation, operational risk, catastrophic or adverse sea or weather conditions, dependence on the oil and natural gas industry, volatility in oil and gas prices, delay or cost overruns on construction projects or insolvency of the shipbuilders, lack of shipyard or equipment availability, ongoing capital expenditure requirements, uncertainties surrounding environmental and government regulation, risks relating to compliance with the Jones Act, risks relating to leverage, risks of foreign operations, risk of war, sabotage, piracy or terrorism, assumptions concerning competition, and risks of currency fluctuations and other matters. These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate under the circumstances. Such statements are subject to risks and uncertainties, including the risk factors discussed above and in Part I, Item 1A “Risk Factors”, general economic and business conditions, the business opportunities that may be presented to and pursued by us, changes in law or regulations and other factors, many of which are beyond our control. There can be no assurance that we have accurately identified and properly weighed all

39

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, 2010, 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” and Part I, Items 1 and 2 “Business and Properties – New Vessel Construction, Acquisition and Divestiture Program, and Drydocking Obligations”. Other than trade accounts receivable and trade accounts payable, we do not currently have financial instruments that are sensitive to foreign currency exchange rates.

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

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

     Net foreign currency losses, including derivative activity, for the years ended December 31, 2010, 2009 and 2008 were $0.1 million, $2.2 million, and $2.0 million, respectively.

Interest Rates

     We are and will be subject to market risk for changes in interest rates related primarily to our long-term debt. The following table, which presents principal cash flows by expected maturity dates and weighted average interest rates, summarizes our fixed and variable rate debt obligations at December 31, 2010 and 2009 that are sensitive to changes in interest rates. The floating portion of our variable debt is based on LIBOR.

     We utilize interest rate swap agreements to fix a portion of our exposure to floating interest rates. These agreements are classified as cash flow hedges and we report changes in the fair value of these cash flow hedges in accumulated other comprehensive income. At December 31, 2010, we had a $100.0 million interest rate swap agreement that fixed the interest rate for a portion of our Facility Agreement at 4.145% and which matures on December 31, 2012. The consolidated balance sheet classifies cash flow hedges within other long-term liabilities and as of December 31, 2010, the fair value of the interest rate swap was $6.8 million. We expect to reclassify $1.7 million of deferred loss on the current interest rate swap to interest expense during the next 12 months.

40

	2011		2012		2013		2014		2015		Thereafter
	(Dollar amounts in thousands)
2010 Long-term Debt:
Fixed rate	$	-	$	-	$	-	$	160,000	$	-	$	-
Average interest rate		7.75%		7.75%		7.75%		7.75%		-		-
Variable rate	$	33,333	$	133,334	$	-	$	-	$	-	$	-
Average interest rate		2.49%		2.60%		-		-		-		-
2010 Notional Value:
Interest Rate Swap-Variable to Fixed	$	100,000	$	100,000	$	-	$	-			$	-
Average pay rate		4.15%		4.15%		-		-				-
Average receive rate		2.49%		2.60%		-		-				-
	2010		2011		2012		2013		2014		Thereafter
	(Dollar amounts in thousands)
2009 Long-term Debt:
Fixed rate	$	-	$	-	$	-	$	-	$	160,000	$	-
Average interest rate		7.75%		7.75%		7.75%		7.75%		7.75%		-
Variable rate	$	33,333	$	33,333	$	133,334	$	-	$	-	$	-
Average interest rate		0.97%		2.49%		2.60%		-		-		-
2009 Notional Value:
Interest Rate Swap-Variable to Fixed	$	100,000	$	100,000	$	100,000	$	-	$	-	$	-
Average pay rate		4.15%		4.15%		4.15%		-		-		-
Average receive rate		0.97%		2.49%		2.60%		-		-		-

     Our fixed rate 7.75% Senior Notes outstanding at December 31, 2010, subjects us to risks related to changes in the fair value of the debt and exposes us to potential gains or losses if we were to repay or refinance such debt. A 1% change in market interest rates would increase or decrease the fair value of our fixed rate debt by approximately $4.9 million.

     The fair value of our 7.75% Senior Notes as compared to the carrying value at December 31, 2010 and 2009, was as follows:

	December 31,
	2010				2009
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
7.75% Senior Notes due 2014	$	159.8	$	164.5	$	159.6	$	159.6

41

ITEM 8. Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

     To the Board of Directors and Stockholders of GulfMark Offshore, Inc. and its subsidiaries:

     We have audited the accompanying consolidated balance sheets of GulfMark Offshore, Inc. and its subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2010. These consolidated financial statements are the responsibility of the 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 2009, and the consolidated results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.

     We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of GulfMark Offshore, Inc. and its subsidiaries’ internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 24, 2011 expressed an unqualified opinion.

UHY LLP
Houston, Texas
February 24, 2011

42

GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

	December 31,
	2010			2009
	(In thousands)
Current assets:
Cash and cash equivalents	$	97,195		$	92,079
Trade accounts receivable, net of allowance for doubtful accounts of $283 and $334, respectively		66,714			76,554
Other accounts receivable		10,326			4,235
Prepaid expenses and other current assets		16,645			12,206
Total current assets		190,880			185,074
Vessels, equipment, and other fixed assets at cost, net of accumulated depreciation of $282,395 and $239,518, respectively		1,191,280			1,164,067
Construction in progress		2,920			40,349
Goodwill		31,987			129,849
Fair value hedges		-			6,886
Intangibles, net of accumulated amortization of $7,208 and $4,325, respectively		27,390			30,273
Deferred costs and other assets		19,993			9,161
Total assets	$	1,464,450		$	1,565,659
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	33,333		$	33,333
Accounts payable		15,130			19,519
Income and other taxes payable		4,066			4,815
Accrued personnel costs		23,417			26,312
Accrued interest expense		5,757			5,966
Other accrued liabilities		7,676			7,088
Total current liabilities		89,379			97,033
Long-term debt		293,095			326,361
Long-term income taxes:
Deferred tax liabilities		102,509			112,960
Other income taxes payable		19,400			24,029
Fair value hedges		-			6,886
Cash flow hedges		6,807			6,422
Other liabilities		7,303			4,500
Stockholders’ equity:
Preferred stock, no par value; 2,000 shares authorized; no shares issued		-			-
Class A Common stock, $0.01 par value; 60,000 shares authorized; 26,269 and 25,906 shares issued and 26,013 and 25,697 shares outstanding, respectively; Class B Common Stock $.01 par value; 60,000 shares authorized; no shares issued		259			255
Additional paid-in capital		370,218			362,022
Retained earnings		536,468			571,213
Accumulated other comprehensive income		39,137			54,005
Treasury stock, at cost		(7,228	)		(5,865	)
Deferred compensation expense		7,103			5,838
Total stockholders’ equity		945,957			987,468
Total liabilities and stockholders’ equity	$	1,464,450		$	1,565,659

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

43

GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2010			2009			2008
	(In thousands, except per share amounts)
Revenue	$	359,766		$	388,871		$	411,740
Costs and expenses:
Direct operating expenses		170,638			166,183			143,925
Drydock expense		22,182			15,696			11,319
General and administrative expenses		44,029			43,700			40,244
Depreciation and amortization		56,959			53,044			44,300
Impairment charge		97,665			46,247			-
Gain on sale of assets		(5,095	)		(5,552	)		(34,811	)
Total costs and expenses		386,378			319,318			204,977
Operating income (loss)		(26,612	)		69,553			206,763
Other income (expense):
Interest expense		(21,693	)		(20,281	)		(14,291	)
Interest income		985			377			1,446
Foreign currency gain (loss) and other		(126	)		(1,153	)		1,609
Total other expense		(20,834	)		(21,057	)		(11,236	)
Income (loss) before income taxes		(47,446	)		48,496			195,527
Income tax (provision) benefit		12,701			2,087			(11,743	)
Net income (loss)	$	(34,745	)	$	50,583		$	183,784
Earnings (loss) per share:
Basic	$	(1.36	)	$	2.01		$	7.74
Diluted	$	(1.36	)	$	1.99		$	7.56
Weighted average shares outstanding:
Basic		25,519			25,151			23,737
Diluted		25,519			25,446			24,319

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

44

GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
For the Years Ended December 31, 2010, 2009 and 2008
(In thousands)

	Common								Accumulated									Deferred
	Stock at		Additional						Other									Compen-		Total
	$0.01 Par		Paid-in			Retained			Comprehensive									sation		Stockholders’
	Value		Capital			Earnings			Income (loss)			Treasury Stock						Expense		Equity
															Share
												Shares			Value
Balance at December 31, 2007	$	227	$	211,004		$	336,846		$	128,308			(172	)	$	(4,200	)	$	3,906	$	676,091
Net income		-		-			183,784			-			-			-			-		183,784
Issuance of common stock		22		139,757			-			-			-			-			-		139,779
Exercise of stock options		1		2,082			-			-			-			-			-		2,083
Deferred compensation plan		-		-			-			-			(39	)		(2,652	)		1,223		(1,429	)
Loss on cash flow hedge, net of tax		-		-			-			(6,062	)		-			-			-		(6,062	)
Translation adjustment		-		-			-			(139,403	)		-			-			-		(139,403	)
Balance at December 31, 2008		250		352,843			520,630			(17,157	)		(211	)		(6,852	)		5,129		854,843
Net income		-		-			50,583			-			-			-			-		50,583
Issuance of common stock		3		8,523			-			-			-			-			-		8,526
Exercise of stock options		2		1,743			-			-			-			-			-		1,745
Deferred compensation plan		-		(1,087	)		-			-			2			987			709		609
Gain on cash flow hedge, net of tax		-		-			-			3,081			-			-			-		3,081
Translation adjustment		-		-			-			68,081			-			-			-		68,081
Balance at December 31, 2009		255		362,022			571,213			54,005			(209	)		(5,865	)		5,838		987,468
Net income		-		-			(34,745	)		-			-			-			-		(34,745	)
Issuance of common stock		2		6,224			-			-			-			-			-		6,226
Exercise of stock options		2		1,836			-			-			-			-			-		1,838
Deferred compensation plan		-		136			-			-			(47	)		(1,363	)		1,265		38
Loss on cash flow hedge, net of tax		-		-			-			(722	)		-			-			-		(722	)
Translation adjustment		-		-			-			(14,146	)		-			-			-		(14,146	)
Balance at December 31, 2010	$	259	$	370,218		$	536,468		$	39,137			(256	)	$	(7,228	)	$	7,103	$	945,957

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

45

GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2010, 2009 and 2008

	Year Ended December 31,
	2010			2009		2008
	(In thousands)
Net income (loss)	$	(34,745	)	$	50,583	$	183,784
Comprehensive income:
Gain (loss) on cash flow hedge, net of tax		(722	)		3,081		(6,062	)
Foreign currency gain (loss)		(14,146	)		68,081		(139,403	)
Total comprehensive income (loss)	$	(49,613	)	$	121,745	$	38,319

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

46

GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2010			2009			2008
	(In thousands)
Cash flows from operating activities:
Net income	$	(34,745	)	$	50,583		$	183,784
Adjustments to reconcile net income from operations to net cash provided by operations
Depreciation and amortization		56,959			53,044			44,300
Amortization of deferred financing costs		1,598			780			711
Amortization of stock-based compensation		5,670			7,115			5,853
Provision for doubtful accounts receivable, net of write offs		(1	)		(73	)		336
Deferred income tax provision (benefit)		(8,371	)		(3,459	)		7,225
Gain on sale of assets		(5,095	)		(5,552	)		(34,811	)
Impairment charge		97,665			46,247			-
Foreign currency transaction loss		1,195			2,901			3,123
Change in operating assets and liabilities —
Accounts receivable		3,287			29,054			(6,631	)
Prepaids and other		(1,775	)		(2,286	)		1,095
Accounts payable		(4,118	)		2,781			(8,259	)
Other accrued liabilities and other		(20,695	)		(10,090	)		8,475
Net cash provided by operating activities		91,574			171,045			205,201
Cash flows from investing activities:
Purchases of vessels, equipment and other fixed assets		(73,439	)		(77,438	)		(108,626	)
Proceeds from disposition of equipment		19,582			9,239			43,432
Cash received with acquisition of business		-			-			31,028
Consideration paid for acquired business		-			-			(152,621	)
Net cash used in investing activities		(53,857	)		(68,199	)		(186,787	)
Cash flows from financing activities:
Proceeds from secured credit facilities		-			200,000			-
Repayment of secured credit facilities		(33,334	)		(238,035	)		(42,156	)
Proceeds from revolving loan facility		51,000			-			163,399
Repayment of revolving loan facility		(51,000	)		(84,250	)		(65,135	)
Debt refinancing cost		(2,000	)		(278	)		-
Proceeds from exercise of stock options		1,838			718			163
Proceeds from issuance of stock		659			1,595			483
Net cash provided by (used in) financing activities		(32,837	)		(120,250	)		56,754
Effect of exchange rate changes on cash		236			8,722			(14,526	)
Net increase (decrease) in cash and cash equivalents		5,116			(8,682	)		60,642
Cash and cash equivalents at beginning of year		92,079			100,761			40,119
Cash and cash equivalents at end of year	$	97,195		$	92,079		$	100,761
Supplemental cash flow information:
Interest paid, net of interest capitalized	$	21,285		$	20,010		$	12,590
Income taxes paid, net	$	4,712		$	3,438		$	3,294

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

47

GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Nature of Operations

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

     On February 23, 2010, we reorganized the Company. The Reorganization was designed to prevent certain situations from occurring that could jeopardize our ability to engage in Coastwise Trade. See Reorganization in Note 11.

Principles of Consolidation

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

Use of Estimates

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

Cash and Cash Equivalents

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

Vessels and Equipment

     Vessels and equipment are stated at cost, net of accumulated depreciation, which is provided by the straight-line method over their estimated useful life of 25 years for all vessels other then crew boats which are depreciated over 20 years. Interest is capitalized in connection with the construction of vessels. The capitalized interest is included as part of the asset to which it relates and is depreciated over the asset’s estimated useful life. In 2010, 2009, and 2008, interest of $1.4 million, $3.6 million, and $8.5 million respectively, was capitalized. Office equipment, furniture and fixtures, and vehicles are depreciated over two to five years.

     Major renovation costs and modifications that extend the life or usefulness of the related assets are capitalized and depreciated over the assets’ estimated remaining useful lives. Maintenance and repair costs are expensed as incurred. Included in the consolidated statements of operations for 2010, 2009 and 2008, are $20.6 million, $20.1 million, and $16.7 million, respectively, of costs for maintenance and repairs.

Goodwill and Intangibles

     At December 31, 2009, our goodwill consisted of $97.7 million related to an acquisition in our Americas region and $32.1 million related to acquisitions in the North Sea region. The determination of impairment of all long-lived assets, goodwill, and intangibles is conducted when indicators of impairment are present and at least annually for goodwill. Impairment testing for goodwill is performed on a reporting segment basis.

     In the second quarter of 2010, we assessed our Americas region goodwill for impairment and, as a result, recorded a $97.7 million impairment charge, reflecting all of our Americas region goodwill. See Note 2 for a discussion of the goodwill impairment charge.

48

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. We did not record any significant impairment write-downs of our long-lived assets during 2010 or 2008. See Note 2 for discussion of an impairment of assets under construction in the first quarter of 2009.

Fair Value of Financial Instruments

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

     As of December 31, 2009, we had forward currency exchange contracts that were designated as fair value hedges and were highly effective, as the terms of the forward contracts were the same as the purchase commitments under a new build contract. Any gains or losses resulting from changes in fair value were recognized in income with an offsetting adjustment to income for changes in the fair value of the hedged item such that there was no net impact on the statement of operations. As of December 31, 2010, no contracts remained open under such agreements.

     We also had interest rate swap agreements that hedged the interest rate associated with a portion of our previous senior indebtedness. We reported changes in the fair value of these cash flow hedges in accumulated other comprehensive income. On December 17, 2009 we entered into the $200.0 million Facility Agreement (See Note 6) and terminated the existing senior indebtedness and the swaps associated with that debt. Concurrently, we entered into an interest rate swap agreement for approximately $100.0 million of the Facility Agreement indebtedness that has fixed the interest rate at 4.145%. The interest rate swap is accounted for as cash flow hedge. We report changes in the fair value of the cash flow hedges in accumulated other comprehensive income. The consolidated balance sheet contains a cash flow hedge reflecting the fair value of the interest rate swap, which was $6.8 million at December 31, 2010 based on expected cash inflows and outflows associated with the contracts. We expect to reclassify $3.1 million of deferred loss related to the interest rate swaps to interest expense during the next 12 months.

     In addition, when we terminated the interest rate swaps discussed above, there was a $4.3 million balance remaining in other comprehensive income representing expected future interest payments. Of this amount, $0.1 million was amortized to interest expense in 2009, $2.4 million was amortized to interest expense in 2010 and the remaining $1.8 million will be amortized into interest expense through December 31, 2012 based on forecasted payments as of the settlement date.

Deferred Costs and Other Assets

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

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

Revenue Recognition

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

Income Taxes

     We recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in the financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the difference between the financial statement carrying amounts and tax bases of assets and liabilities using enacted tax rates and laws in effect in the years in which the differences are expected to reverse. The likelihood and amount of future taxable income and tax planning strategies

49

are included in the criteria used to determine the timing and amount of tax benefits recognized for net operating loss and tax credit carryforwards in the consolidated financial statements.

     In addition, we also account for uncertainty in income taxes by determining a more likely than not, or greater than 50% probability, recognition threshold and criteria for measurement of a tax position taken or expected to be taken in a tax return. Numerous factors contribute to our evaluation and estimation of our tax positions and related tax liabilities and/or benefits, which may be adjusted periodically and may ultimately be resolved differently than we anticipate.

Foreign Currency Translation

     The local currencies of the majority of our foreign operations have been determined to be their functional currencies, except for certain foreign operations whose functional currency has been determined to be the U.S. Dollar, based on an assessment of the economic circumstances of the foreign operations. Assets and liabilities of our foreign affiliates are translated at year-end exchange rates, while revenue and expenses are translated at average rates for the period. As a result, amounts related to changes in assets and liabilities reported in the consolidated statements of cash flows will not necessarily agree to changes in the corresponding balances on the consolidated balance sheets. We consider most intercompany loans to be long-term investments; accordingly, the related translation gains and losses are reported as a component of stockholders’ equity. Transaction gains and losses are reported directly in the consolidated statements of operations. During the years ended December 31, 2010, 2009 and 2008, we reported net foreign currency losses in the amount of $0.1 million, $2.2 million and $2.0 million, respectively.

Concentration of Credit Risk

     We extend credit to various companies in the energy industry that may be affected by changes in economic or other external conditions. Our policy is to manage our exposure to credit risk through credit approvals and limits. Our trade accounts receivable are aged based on contractual payment terms and an allowance for doubtful accounts is established in accordance with our written corporate policy. The age of the trade accounts receivable, customer collection history and 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. In 2010, 2009 and 2008, no single customer accounted for 10% or more of total consolidated revenue.

Stock-Based Compensation

     We account for stock-based compensation using the modified prospective application method where compensation cost will be recognized related to new awards and to awards modified, repurchased, or cancelled after the required effective date. Additionally, compensation cost for portions of awards for which the requisite service has not been rendered that are outstanding at January 1, 2006 shall be recognized as if the requisite service is rendered on or after the required effective date. At January 1, 2006, all of our stock option awards were fully vested. Under the modified prospective method, vested equity awards outstanding at the effective date create no additional compensation expense. Only new awards granted after January 1, 2006 would continue to be measured and charged to expense over remaining requisite service. Our employee stock purchase plan would be considered compensatory whereby it allows all of our U.S. employees and participating subsidiaries to acquire shares of common stock at 85% of the fair market value of the common stock under a qualified plan as defined by Section 423 of the Internal Revenue Service. The plan has a look-back option that establishes the purchase price as an amount based on the lesser of the common 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.

     Pro forma information regarding net income and earnings per share, or EPS, and has been determined as if we had accounted for our employee stock options under the fair-value method described above. The last granted stock options were in October 2003. The fair value calculations at the date of grant using the Black-Scholes option pricing model were calculated with the following weighted average assumptions:

	2003
Risk-free interest rate		2.2%
Volatility factor of stock price		0.28
Dividends		-
Option life	4 years
Calculated fair value per share	$	3.58

50

Earnings Per Share

     Basic EPS is computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the year. Diluted EPS is computed using the treasury stock method for common stock equivalents. The detail of the earnings per share calculations for continuing operations for the years ended December 31, 2010, 2009 and 2008 is as follows (in thousands, except per share amounts):

	Year ended December 31, 2010
	Net			Weighted		Per Share
	Loss			Average Shares		Amount
Loss per share, basic	$	(34,745	)		25,519	$	(1.36	)
Dilutive effect of common stock options		-			-
Loss per share, diluted	$	(34,745	)	$	25,519	$	(1.36	)
	Year ended December 31, 2009
	Net			Weighted		Per Share
	Income			Average Shares		Amount
Income per share, basic	$	50,583			25,151	$	2.01
Dilutive effect of common stock options		-			295
Income per share, diluted	$	50,583		$	25,446	$	1.99
	Year ended December 31, 2008
	Net			Weighted		Per Share
	Income			Average Shares		Amount
Income per share, basic	$	183,784			23,737	$	7.74
Dilutive effect of common stock options		-			582
Income per share, diluted	$	183,784			24,319	$	7.56

Reclassifications

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

New Accounting Pronouncements

     In June 2009, the Financial Accounting Standards Board (“FASB”) amended its accounting guidance on Accounting Standards Codification (“ASC”) Topic 810, Consolidations relating to the consolidation of variable interest entities (“VIE”). Among other things, the new guidance requires a qualitative rather than a quantitative assessment to determine the primary beneficiary of a VIE based on whether the entity (1) has the power to direct matters that most significantly impact the activities of the VIE and (2) has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE. In addition, the amended guidance requires an ongoing reconsideration of the primary beneficiary. The provisions of this new guidance were effective as of the beginning of our 2010 fiscal year, and the adoption did not have a material impact on our consolidated financial statements.

     In April 2010, the FASB issued additional guidance relating to the ASC Topic 718, Compensation — Stock Compensation to clarify classification of an employee stock-based payment award when the exercise price is denominated in the currency of a market in which the underlying equity security trades. This guidance becomes effective for us on January 1, 2011 and will not have a material effect on our consolidated financial statements.

     In January 2010, the FASB amended ASC Topic 820, Fair Value Measurement and Disclosure to require additional disclosures on (1) transfers between levels, (2) Level 3 activity presented on a gross basis, (3) valuation techniques, and (4) inputs into the valuation. The additional disclosure has no impact on our consolidated financial statements.

51

(2) IMPAIRMENT CHARGES

Goodwill

     At December 31, 2009, our goodwill consisted of $97.7 million related to an acquisition in our Americas region and $32.1 million related to acquisitions in the North Sea region. The determination of impairment of all long-lived assets, goodwill, and intangibles is conducted when indicators of impairment are present and at least annually for goodwill. Impairment testing for goodwill is performed on a reporting segment basis.

     In the second quarter of 2010, we assessed our Americas region goodwill for impairment. In our assessment, we evaluated the impact on the segment’s fair value due to the recent events in the U.S. Gulf Of Mexico relating to the Macondo Incident, the resulting oil spill and the drilling moratorium. The U.S. Gulf of Mexico market is generally divided into two distinct areas: shallow-water and deepwater. The deepwater market has historically been less volatile and more profitable. Our long-term strategy has been to become more focused on the deepwater business. The ban on new drilling permits issued on April 30 and the deepwater drilling moratorium issued on May 30, 2010 negatively impacted our outlook for deepwater drilling. Based on these factors, which were incorporated into our evaluations and testing as prescribed under U.S. GAAP, we determined that an impairment of our Americas region goodwill existed. As a result, we recorded a $97.7 million impairment charge as of June 30, 2010, reflecting all of our Americas region goodwill. The non-cash charge does not impact our liquidity or debt covenant compliance.

Assets Under Construction

     In March 2009, we notified a shipyard building three of the vessels in our new build program that they were in default under the construction contract. The default arose as a result of non-performance under the terms of the contract caused by financial difficulties of the shipyard. Construction on these vessels has stopped and we are evaluating our remedies under the contract and under applicable law. We determined that we had a material impairment and recognized a charge of $46.2 million in the first quarter of 2009 pertaining to the construction in progress related to this contract. That charge represented the full amount of our investment in these vessels. The shipyard building the three vessels is in Chapter 11 bankruptcy proceedings.

(3) RIGDON ACQUISITION

     On July 1, 2008, we acquired 100% of the membership interests of Rigdon Marine Holdings, L.L.C. and 100% of the outstanding common stock of Rigdon Marine Corporation for consideration of $554.7 million, consisting of $152.6 million in cash and approximately 2.1 million shares of GulfMark Offshore, Inc. common stock valued at $133.2 million, plus the assumption of $268.9 million in debt (the “Rigdon Acquisition”).

     The pro forma effect of the acquisition and the associated financing on the historical results for the year ended December 31, 2008 is presented in the following table (in thousands, except earnings per share):

	Year Ended
	December 31,
	2008
Revenue	$	466,787
Operating income		226,887
Net income		188,939
Basic earnings per share	$	7.96

(4) VESSEL ACQUISITIONS AND DISPOSITIONS

     During 2010, we have taken delivery of three vessels that were under construction at December 31, 2009. As of February 24, 2011, we have one vessel that is being held for sale that is not included in our fleet numbers and have no vessels under construction. In the second quarter of 2010, we sold one of our Americas vessels and recorded a $0.1 million loss. At the end of the third quarter of 2010, we sold one of our North Sea vessels and recorded a $5.2 million gain.

52

     The following tables illustrate the details of the vessels added, disposed of and classified as held for sale since December 31, 2009.

Vessel Additions Since December 31, 2009
			Year	Length			Month
Vessel	Region	Type (1)	Built	(feet)	BHP (2)	DWT (3)	Delivered
North Purpose	N. Sea	PSV	2010	284	10,738	4,850	Feb-10
Sea Valiant	SEA	AHTS	2010	230	10,188	2,301	Jun-10
Sea Victor	SEA	AHTS	2010	230	10,188	2,301	Jul-10

1)	AHTS - Anchor handling, towing and supply vessel
	FSV - Fast supply vessel
	PSV - Platform supply vessel
	SpV - Specialty vessel, including towing and oil response
	SmAHTS - Small anchor handling, towing and supply vessel
2)	BHP - Breakhorse power
3)	DWT - Deadweight tons

Vessels Disposed of Since December 31, 2009
			Year	Length			Month
Vessel	Region	Type	Built	(feet)	BHP	DWT	Disposed
Seapower	Americas	SpV	1974	222	7,040	1,205	May-10
North Traveller	N.Sea	LgPSV	1998	221	5,450	3,115	Sep-10

Vessels Held for Sale (Laid Up)
			Year	Length
Vessel	Region	Type	Built	(feet)	BHP	DWT
Clwyd Supporter	N. Sea	SpV	1984	266	10,700	1,350

(5) GOODWILL AND INTANGIBLES

     Changes to goodwill are as follows:

	2010			2009		2008
	(In thousands)
Balance, January 1,	$	129,849		$	123,981	$	34,264
Adjustment related to acquisition		-			463		97,202
Impact on foreign currency translation and adjusment		(197	)		5,405		(7,485	)
Impairment (see Note 2)		(97,665	)		-		-
Balance, December 31,	$	31,987		$	129,849	$	123,981

     Intangible assets of $27.4 million, net of accumulated amortization of $7.2 million, as of December 31, 2010 are recorded at cost and are amortized on a straight-line basis over the years expected to be benefited, currently estimated to be 10 years. Amortization expense related to intangible assets was $2.9 million for the years ended December 31, 2010 and 2009 and $1.4 million for the year ended December 31, 2008. Annual amortization expense related to existing intangible assets for years 2011 through 2015 is expected to be $2.9 million per year.

53

(6) LONG-TERM DEBT

     Our long-term debt at December 31, 2010 and 2009 consisted of the following:

	2010			2009
	(In thousands)
7.75% Senior Notes due 2014	$	160,000		$	160,000
Facility Agreement		166,667			200,000
Secured Reducing Revolving Loan Facility		-			-
	$	326,667		$	360,000
Less: Current maturities of long-term debt		(33,333	)		(33,333	)
Debt discount, net		(239	)		(306	)
Total	$	293,095		$	326,361

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

Year	Debt Maturity
	(In thousands)
2011		33,333
2012		133,334
2013		-
2014		160,000
2015		-
Total	$	326,667

Senior Notes

     On July 21, 2004, we issued $160.0 million aggregate principal amount of 7.75% senior notes due 2014. The 7.75% senior notes pay interest semi-annually on January 15 and July 15. The 7.75% senior notes may be called beginning on July 15, 2011 at a redemption price of 101.292% and on July 15, 2012 and thereafter at 100% of the principal amount, plus accrued interest.

     At December 31, 2010, the fair value of these notes, based on quoted market prices, was approximately $164.5 million, compared to a carrying amount of $159.8 million.

Facility Agreement

     On December 17, 2009, one of our wholly-owned subsidiaries (the “Borrower”) entered into a $200.0 million facility agreement (the “Facility Agreement”) with The Royal Bank of Scotland plc (“RBS”). The termination date under the Facility Agreement is December 31, 2012 and amounts borrowed are repayable in quarterly installments of $8.3 million with a final installment of $108.33 million. Loans under the Facility Agreement bear interest at the three month LIBOR rate, plus a margin of 2.5% per annum. The Facility Agreement is secured by certain vessels and GulfMark Management, Inc., the 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.

     The Facility Agreement is secured by certain vessels. We have unconditionally guaranteed all existing and future indebtedness and liabilities of the Borrower arising under the Facility Agreement and other loan documents. Such guarantee also covers obligations of the Borrower arising under any interest rate swap contract and other security documentation related to the Facility Agreement. The collateral that secures the loans under the Facility Agreement will secure all of the 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

54

of default. Upon the occurrence of an event of default, RBS may terminate the Facility Agreement, declare that all obligations under the Facility Agreement are due and payable and exercise its rights with respect to the collateral under the Facility Agreement.

     At December 31, 2010, we were in compliance with all covenants, and had $166.7 million borrowed under the facility. At December 31, 2010, the fair value of borrowings under this facility is considered to be book value as the interest is at market rates.

Revolving Loan Facility

     We currently have a $175.0 million Secured Reducing Revolving Loan Facility with a syndicate of financial institutions led by Den Norske Bank, as agent. The multi-currency facility is structured as follows: $25.0 million allocated to GulfMark Offshore, Inc.; $60.0 million allocated to Gulf Offshore N.S. Limited, a U.K. wholly owned subsidiary; $30.0 million allocated to GulfMark Rederi AS, a Norwegian wholly owned subsidiary; and $60.0 million allocated to Gulf Marine Far East Pte Ltd., a wholly owned Singapore subsidiary. The facility matures in 2013 and the maximum availability begins to reduce in increments of $15.2 million every six months beginning in December 2011, with a final reduction of $129.5 million in June 2013. Security for the facility is provided by first priority mortgages on certain vessels. The interest rate ranges from LIBOR plus a margin of 0.7% to 0.9% depending on our EBITDA coverage ratio. The Secured Reducing Revolving Loan Facility is subject to financial covenants. At December 31, 2010, we were in compliance with all covenants and had no amounts drawn under this facility.

Other Debt

     As part of the Rigdon Acquisition, we acquired the right to purchase a mortgaged vessel owned by one of our joint ventures in the event of the joint venture’s default on that mortgage obligation. The purchase price of the vessel would be the outstanding balance on the mortgage, which was $2.9 million at December 31, 2010.

(7) INCOME TAXES

     The majority of our non-U.S. based operations are subject to foreign tax systems that provide significant incentives to qualified shipping activities. Our U.K. and Norway based vessels are taxed under ten year “tonnage tax” regimes and in late 2010 we renewed our U.K. tonnage tax election through November 2020. Our qualified Singapore based vessels are exempt from Singapore taxation through December 2017 with extensions available in certain circumstances beyond 2017. The tonnage tax regimes provide for a tax based on the net tonnage weight of a qualified vessel. These foreign tax beneficial structures continued to result in our earnings incurring significantly lower taxes than those that would apply if we were not a qualified shipping company in those jurisdictions.

     In late 2007, Norway enacted legislation that created a new tonnage tax system from January 2007 forward and repealed the previous tonnage tax regime effective December 31, 2006 resulting in a mandatory exit from 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 an approximately $4.9 million tax provision. The net result of the 2010 Norwegian tonnage tax law changes was a $10.1 million tax benefit recorded in our 2010 tax provision. Our liability to settle under the simplified tax system is included in our December 31, 2010 balance sheet as approximately $1.6 million current income tax payable and approximately $3.3 million as other long term payable. Annually the subsequent 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 2011. We also have certain foreign net operating loss carryforwards that result in net deferred tax assets of approximately $2.3 million for which we have established a valuation allowance. We have considered estimated future taxable income

55

in the relevant tax jurisdictions to utilize these tax credit and loss carryforwards and have considered what we believe to be ongoing prudent and feasible tax planning strategies in assessing the need for the valuation allowance. This information is based on estimates and assumptions including projected taxable income. If these estimates and related assumptions change in the future, or if we determine that we would not be able to realize other deferred tax assets in the future, an adjustment to the valuation allowance would be recorded in the period such determination was made.

     Effective January 1, 2008, Mexico legislated a new revenue based tax, which in effect is an alternative minimum tax payable to the extent that the new revenue based tax exceeds the current income tax liability. These revenue based tax rates are16.5% for 2008, 17% for 2009 and 17.5% for 2010 and beyond. Effective January 1, 2010, Mexico enacted changes to corporate income tax rates as follows: 2010 through 2012 – 30%; 2013 – 29%; and 2014 and beyond - 28%.

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

	Year Ended December 31,
	2010			2009			2008
U.S.	$	(121,938	)	$	(66,854	)	$	7,109
Foreign		74,492			115,350			188,418
	$	(47,446	)	$	48,496		$	195,527

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

	2010											2009											2008
	Current		Deferred			Other (a)			Total			Current		Deferred			Other (a)			Total			Current		Deferred		Other (a)		Total
U.S.	$	65	$	(7,519	)	$	-		$	(7,454	)	$	20	$	(2,988	)	$	(254	)	$	(3,222	)	$	432	$	2,437	$	-	$	2,869
Foreign		3,576		(851	)		(7,972	)	$	(5,247	)		5,223		(5,314	)		1,226		$	1,135			2,385		981		5,508		8,874
	$	3,641	$	(8,370	)	$	(7,972	)	$	(12,701	)	$	5,243	$	(8,302	)	$	972		$	(2,087	)	$	2,817	$	3,418	$	5,508	$	11,743

(a) Income tax effects determined under a more likely than not, or greater than 50% probability, threshold.

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

	2010			2009			2008
U.S. federal statutory income tax rate		35.0%			35.0%			35.0%
Effect of foreign operations		66.0			(36.6	)		(29.3	)
US state income taxes		(0.7	)		4.5			-
Valuation allowance		-			(9.2	)		0.5
Impairment		(72.0	)		-			-
Other		(1.5	)		1.0			(0.2	)
Total		26.8%			(4.3%)			6.0%

     Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities for financial reporting purposes and such amounts as measured by tax laws and regulations. The components of the net deferred tax assets and liabilities at December 31, 2010 and 2009 are as follows:

56

	December 31,
	2010			2009
	(In thousands)
Deferred tax assets
Accruals currently not deductible for tax purposes	$	26,083		$	24,773
Net operating loss carryforwards		44,549			25,357
Foreign and other tax credit carryforwards		10,686			11,793
		81,318			61,923
Less valuation allowance		(4,468	)		(5,192	)
Net deferred tax assets	$	76,850		$	56,731
Deferred tax liabilities
Depreciation	$	(151,912	)	$	(142,674	)
Foreign income not currently recognizable		-			-
Other		(27,447	)		(27,017	)
Total deferred tax liabilities	$	(179,359	)	$	(169,691	)
Net deferred tax liability	$	(102,509	)	$	(112,960	)

     As of December 31, 2010 and 2009, the total net deferred tax liability of $102.5 million and $113.0 million, respectively, is included in non-current liabilities in the consolidated balance sheet. The net change in the total valuation allowance for the years ended December 31, 2010 and 2009 was a decrease of $0.7 million and a decrease of $4.6 million, respectively. As of December 31, 2010, we had net operating loss carryforwards, or NOLs, for income tax purposes totaling $115.1 million in the U.S., $10.6 million in Brazil, $5.9 million in Norway, and $4.6 million in Mexico that are, subject to certain limitations, available to offset future taxable income. The U.S. NOLs, which we expect to fully utilize, will begin to expire beginning in 2023 through 2029. The NOLs in Mexico will begin to expire in 2016, however as a result of the Mexico legislation described above, it is more likely than not that the Mexican NOLs will not be utilized and a $0.3 million valuation allowance has been established for these NOLs. In addition, it is more likely than not that the Norway NOLs will not be utilized and a full valuation allowance has been established for such NOLs. Except for the amounts related to Brazilian temporary differences, it is also more likely than not that the Brazilian NOLs will not be utilized and a $2.5 million valuation allowance has been established for such NOLs. Based on future expected U.S. taxable income, in 2009 we reversed $4.5 million of valuation allowance previously recorded against U.S. foreign tax credits.

     Currently, our intention is to permanently reinvest the unremitted earnings of our non-U.S. subsidiaries. As a result, we have not provided for U.S. deferred taxes on the cumulative unremitted earnings of $766.3 million at December 31, 2010. In addition, as of December 31, 2010, we had $84.3 million of cash held by our foreign subsidiaries which is subject to U.S. tax upon repatriation.

     Based on a more likely than not, or greater than 50% probability, recognition threshold and criteria for measurement of a tax position taken or expected to be taken in a tax return, we evaluate and record in certain circumstances an income tax asset/liability for uncertain income tax positions. Numerous factors contribute to our evaluation and estimation of our tax positions and related tax liabilities and/or benefits, which may be adjusted periodically and may ultimately be resolved differently than we anticipate. We also consider existing accounting guidance on de-recognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition. Accordingly, we continue to recognize income tax related penalties and interest in our provision for income taxes and, to the extent applicable, in the corresponding balance sheet presentations for accrued income tax assets and liabilities, including any amounts for uncertain tax positions included in other income taxes payable in the consolidated balance sheets and which total $15.7 million at December 31, 2010 and $13.3 million at December 31, 2009.

57

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

	2010			2009
	(in thousands)
Unrecognized tax benefits balance at January 1,	$	10,786		$	9,810
Gross increases for tax positions taken in prior years		645			1,265
Gross decreases for tax positions taken in prior years		(795	)		(289	)
Decreases for settlements		-			-
Lapse of statute of limitations		-			-
Unrecognized tax benefits balance at December 31,	$	10,636		$	10,786

     We expect a foreign tax examination issue representing approximately $1.6 million of our unrecognized tax benefits as of December 31, 2010 will be settled within twelve months. As of December 31, 2010, we are under tax examination, or may be subject to examination in the U. S. for years after 2001 and in seven major foreign tax jurisdictions with open years for one after 1999, one after 2000, one after 2003, one after 2004, two after 2005 and one after the year 2006.

     We accrue interest and penalties related to unrecognized tax benefits in our provision for income taxes. At December 31, 2010, we had accrued interest and penalties related to unrecognized tax benefits of $11.4 million. The amount of interest and penalties recognized in our tax provision for the year ended December 31, 2010 was $1.6 million.

(8) COMMITMENTS AND CONTINGENCIES

     At December 31, 2010, we had long-term operating leases for office space, automobiles, temporary residences, and office equipment. Aggregate operating lease expense for the years ended December 31, 2010, 2009 and 2008 was $2.2 million, $2.0 million, and $1.8 million, respectively. Future minimum rental commitments under these leases are as follows (in thousands):

	Minimum Rental
Year	Commitments
2011		1,664
2012		1,296
2013		938
2014		822
2015		461
Thereafter		722
Total	$	5,903

     The Austral Abrolhos is subject to an annual right of its charterer to purchase the vessel during the term of the charter, which commenced May 2, 2003 and, subject to the 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 $4.6 million and $0.2 million at December 31, 2010 and 2009, respectively. In the past, no significant claims have been made against these financial instruments. We believe the likelihood of demand for payment under these instruments is remote and expect no material cash outlays to occur from these instruments.

     We have contingent liabilities and future claims for which we have made estimates of the amount of the eventual cost to liquidate these liabilities or claims. These liabilities and claims may involve threatened or actual litigation where damages have not been specifically quantified but we have made an assessment of our exposure and recorded a provision in our accounts for the expected loss. Other claims or liabilities, including those related to taxes in foreign jurisdictions, may be estimated based on our experience in these matters and, where appropriate, the advice of outside counsel or other outside experts. Upon the ultimate resolution of the uncertainties surrounding our estimates of contingent liabilities and future claims, our future reported financial results will be

58

impacted by the difference, if any, between our estimates and the actual amounts paid to settle the liabilities. In addition to estimates related to litigation and tax liabilities, other examples of liabilities requiring estimates of future exposure include contingencies arising out of acquisitions and divestitures. Our contingent liabilities are based on the most recent information available to us regarding the nature of the exposure. Such exposures change from period to period based upon updated relevant facts and circumstances, which can cause the estimate to change. In the recent past, our estimates for contingent liabilities have been sufficient to cover the actual amount of our exposure. We do not believe that the outcome of these matters will have a material adverse effect on our business, financial condition, or results of operations.

(9) EQUITY INCENTIVE PLANS

Stock Options and Stock Option Plans

     Under the terms of our Amended and Restated 1993 Non-Employee Director Stock Option Plan, or 1993 Director Plan, options to purchase 20,000 shares of our common stock were granted to each of our five non-employee directors in 1993, 1996, 1999 and 2002, and to a newly appointed director in 2001 and 2003. The exercise price of options granted under the 1993 Director Plan is fixed at the market price at the date of grant. A total of 800,000 shares were reserved for issuance under the 1993 Director Plan. The options have a term of ten years. On April 21, 2006, the 1993 Director Plan was terminated and, therefore, no additional shares were reserved for granting of options under this plan, though options remain outstanding under this plan.

     In May 1998, the stockholders approved the GulfMark Offshore, Inc. 1997 Incentive Equity Plan that replaced the 1987 Employee Plan. A total of 814,000 shares were reserved for issuance of options or awards of restricted stock under this plan. Stock options generally become exercisable in 1/3 increments over a three-year period and to the extent not exercised, expire on the tenth anniversary of the date of grant. Under the terms of the 2010 Omnibus Equity Incentive Plan (described below) which replaced the 1997 Incentive Equity Plan, no further shares have been awarded.

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

     On June 8, 2010, the stockholders approved the GulfMark Offshore, Inc. 2010 Omnibus Equity Incentive Plan that replaced the 1997 Incentive Equity Plan. A total of 1,000,000 shares of common stock were reserved for issuance of stock options, stock appreciation rights, restricted stock, stock units and performance cash awards under this plan.

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

	2010				2009				2008
			Weighted				Weighted				Weighted
			Average				Average				Average
			Exercise				Exercise				Exercise
	Shares		Price		Shares		Price		Shares		Price
Outstanding at beginning of year		457,650	$	15.75		673,650	$	13.94		789,650	$	14.33
Granted		-		-		-		-		-		-
Forfeitures		-		-		-		-		-		-
Exercised		158,000		11.63		216,000		10.09		116,000		16.56
Outstanding at end of year		299,650	$	17.92		457,650	$	15.75		673,650	$	13.94
Exercisable shares and weighted average exercise price		299,650	$	17.92		457,650	$	15.75		673,650	$	13.94
Shares available for future grants at December 31:
2005 Director Plan		37,000				54,600				77,900
2010 Omnibus Equity Incentive Plan		985,294				-				-

59

     The following table summarizes information about stock options outstanding at December 31, 2010:

	Outstanding					Exercisable
			Weighted		Weighted			Weighted
			Average		Average			Average
Range of Exercise Prices	Shares		Exercise Price		Remaining Life	Shares		Exercise Price
$13.10 to $17.44		216,000	$	16.67	0.91 years		216,000	$	16.67
$19.37 to $21.25		83,650	$	21.17	1.35 years		83,650	$	21.17
		299,650	$	17.92			299,650	$	17.92

     Historically, we have used stock options as a long-term incentive for our employees, officers and directors under the above-mentioned stock option plans. The exercise price of options granted is equal to or greater than the market price of the underlying stock on the date of the grant. Accordingly, consistent with the provisions of U.S. GAAP no compensation expense has been recognized in the accompanying financial statements for these options. See Note 1 “Nature of Operations and Summary of Significant Accounting Policies-Stock-Based Compensation”.

ESPP

     We have an employee stock purchase plan, or ESPP, that is available to all our U.S. employees and certain subsidiaries and is qualified under Section 423 of the Internal Revenue Code. At the end of each fiscal quarter, or Option Period, during the term of the ESPP, the employee contributions are used to acquire shares of common stock at 85% of the fair market value of the common stock on the first or the last day of the Option Period, whichever is lower. Prior to 2006, these plans were considered non-compensatory and as such, our financial statements did not reflect any related expense through December 31, 2005. However, effective January 1, 2006, we adopted FASB ASC 718, Stock Compensation, and expense these costs as compensation. We have authorized the issuance of up to 400,000 shares of common stock through these plans. At December 31, 2010, there were 277,265 shares remaining in reserve for future issuance. See Note 1 “Nature of Operations and Summary of Significant Accounting Policies – Stock-Based Compensation”.

U.K. ESPP

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

Executive Deferred Compensation Plan

     We maintain an executive deferred compensation plan, or EDC Plan. Under the EDC Plan, a portion of the compensation for certain of our key employees, including officers and directors, can be deferred for payment after retirement or termination of employment. Under the EDC Plan, deferred compensation can be used to purchase our common stock or may be retained by us and earn interest at Prime plus 2%. The first 7.5% of compensation deferred must be used to purchase common stock and may be matched by us. At December 31, 2010, a total of $2.8 million had been deferred into the Prime plus 2% portion of the plan.

     We have established a “Rabbi” trust to hold the stock portion of benefits under the EDC Plan. The funds provided to the trust are invested by a trustee independent of us in our common stock, which is purchased by the trustee on the open market. The assets of the trust are available to satisfy the claims of all general creditors in the event of bankruptcy or insolvency. Accordingly, the common stock held by the trust and our liabilities under the EDC Plan are included in the accompanying consolidated balance sheets as treasury stock and deferred compensation expense.

(10) EMPLOYEE BENEFIT PLANS

401(k)

     We offer a 401(k) plan to all of our U.S. employees and provide matching contribution to those employees that participate. The matching contributions paid by us totaled $1.4 million, $1.3 million and $0.8 million for the years ended December 31, 2010, 2009 and 2008, respectively.

60

Multi-employer Pension Obligation

     Certain current and former U.K. subsidiaries are participating in a multi-employer retirement fund known as the Merchant Navy Officers Pension Fund (MNOPF). At December 31, 2010, we had $5.1 million accrued related to this liability, which reflects all obligations assessed by the fund’s trustee on the Company. We continue to have employees who participate in the MNOPF and will as a result continue to have routine payments to the fund as those employees accrue additional benefits over time. In addition, we have been advised by the trustee that as of March 31, 2009, the MNOPF was underfunded and as a result there is the potential that in the future participating employers will be assessed additional obligations to correct the underfunding. The amount and timing of additional potential future obligations depends on a number of factors, but principally on future fund performance and the underlying actuarial assumptions.

Norwegian Pension Plans

     The Norwegian benefit pension plans include approximately seven of our office employees and 260 seamen and are defined benefit, multiple-employer plans, insured with Nordea Liv. We also have instituted a defined contribution plan in 2008 for shore based personnel that existing personnel could elect to participate in while discontinuing any further obligations in the defined benefit plan. All newly hired shore based personnel are required to join the defined contribution plan. Benefits under the defined benefit plans are based primarily on participants’ years of credited service, wage level at age of retirement and the contribution from the Norwegian National Insurance. A December 31, 2010 measurement date is used for the actuarial computation of the defined benefit pension plans. The following tables provide information about changes in the benefit obligation and plan assets and the funded status of the Norwegian defined benefit pension plans (in thousands):

	2010			2009
Change in Benefit Obligation
Benefit obligation at beginning of the year	$	8,083		$	5,615
Benefit periodic cost		933			698
Interest cost		334			284
Benefits paid		(337	)		(499	)
Actuarial gain (loss)		(574	)		842
Translation adjustment		(50	)		1,143
Benefit obligation at year end	$	8,389		$	8,083

	2010			2009
Change in Plan Assets
Fair value of plan assets at beginning of the year	$	5,350		$	3,741
Actual return on plan assets		311			276
Contributions		518			1,116
Benefits paid		(147	)		-
Administrative fee		(50	)		(37	)
Actuarial gain (loss)		45			(570	)
Translation adjustment		(8	)		824
Fair value of plan assets at end of year	$	6,019		$	5,350

	2010		2009
Funded status	$	2,370	$	2,733
Social security		401		385
Net obligation including social security	$	2,771	$	3,118

61

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

	December 31,
	2010			2009
Deferred costs and other assets	$	406		$	58
Other liabilities		2,078			190
	Year Ended December 31,
	2010			2009
Components of Net Period Benefit Cost
Service cost	$	900		$	647
Interest cost		323			263
Return on plan assets		(311	)		(276	)
Administrative fee		50			37
National insurance (social security) contribution		136			117
Recognized net actuarial gain (loss)		(618	)		1,337
Net periodic benefit cost	$	480		$	2,125

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

Weighted-average assumptions	2010			2009
Discount rate		3.2	%		4.3	%
Return on plan assets		4.6	%		5.6	%
Rate of compensation increase		3.0	%		4.3	%

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

	2010			2009
Equity securities		13	%		10	%
Debt securities		66	%		69	%
Property		19	%		20	%
Other		2	%		1	%
All asset categories		100	%		100	%

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

     The projected benefit obligation and the fair value of plan assets for the Norwegian pension plan were approximately $8.4 million and $6.0 million, respectively as of December 31, 2010, and $8.1 million and $5.4 million, respectively as of December 31, 2009. We expect to contribute approximately $0.6 million to the Norwegian pension plan in 2011. No plan assets are expected to be returned to us in 2011.

62

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

Year ended December 31,	Benefit Payments
2011	$	337
2012		357
2013		368
2014		379
2015		390
Total	$	1,831

(11) STOCKHOLDERS’ EQUITY

Common Stock Issuances

     During 2010, 25,021 shares were issued through the ESPP, generating approximately $0.6 million in proceeds. The provisions of the ESPP are described above in Note 9 in more detail.

     As a result of the Rigdon Acquisition on July 1, 2008, we issued approximately 2.1 million shares of our common stock valued at $133.2 million.

     A total of 167,096 and 326,207 restricted shares of our stock were granted to certain officers and key employees in 2010 and 2009, respectively, pursuant to our 1997 Incentive Equity Plan and 2010 Omnibus Equity Incentive Plan described above in Note 9, with an aggregate market value of $4.7 million and $5.8 million, respectively, on the grant dates. The restrictions terminate at the end of three years and the value of the restricted shares is being amortized to expense over that period.

Preferred Stock

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

Dividends

     We have not declared or paid cash dividends during the past five years. Pursuant to the terms of the indenture under which the senior notes are issued, we may be restricted from declaring or paying cash dividends; however, we currently anticipate that, for the foreseeable future, any earnings will be retained for the growth and development of our business. The declaration of dividends is at the discretion of our Board of Directors. Our dividend policy will be reviewed by the Board of Directors at such time as may be appropriate in light of future operating conditions, dividend restrictions of subsidiaries and investors, financial requirements, general business conditions and other factors.

Reorganization

     On February 23, 2010, our stockholders approved a corporate reorganization (the “Reorganization”) and as a result, we have a new Certificate of Incorporation.

     The Certificate of Incorporation created two classes of common stock: Class A and Class B. All existing shares were converted to Class A common stock in the Reorganization. These shares contain restrictions that among other things, limit the maximum permitted percentage of outstanding shares of Class A common stock that may be owned or controlled in the aggregate by non-U.S. citizens to a maximum of 22 percent, collectively, the “Maritime Restrictions”. Any purported transfer that would result in more than 22 percent of the outstanding shares of Class A common stock being owned (of record or beneficially) or controlled by non-U.S. citizens will be void and ineffective. In the event such transfers are unable to be voided, shares in excess of the maximum permitted percentage are subject to automatic sale by a trustee appointed by the Company or, if such sale is ineffective, redemption by the Company. In any event such non-U.S. citizen will not be entitled to any voting, dividend or distribution rights with respect to the excess shares and may be required to disgorge any profits, dividends or distributions received with respect to the excess shares. The Class B shares do not have the Maritime Restrictions noted above.

63

     The Certificate of Incorporation also authorized 60 million shares of each class of common stock. Pursuant to the Reorganization, the Certificate of Incorporation and the Bylaws of the Company now require that the Chairman of the Board and chief executive officer, by whatever title, must each be U.S. citizens and not more than a minority of the minimum number of directors of the Board of Directors necessary to constitute a quorum of the Board of Directors (or such other portion as the Board of Directors may determine is necessary to comply with the Jones Act) may be non-U.S. citizens so long as shares of New GulfMark Class A common stock remain outstanding.

     Initially, the shares of Class B common stock may only be issued upon conversion of all of the outstanding and treasury shares of our Class A common stock into shares of Class B common stock automatically following a determination by our Board of Directors that either the U.S. ownership requirements of the applicable U.S. maritime and vessel documentation laws are no longer applicable to (or have been amended so that the Maritime Restrictions are no longer necessary) or that the elimination of such restrictions is in the best interests of our stockholders. Upon conversion of the outstanding and treasury shares of Class A common stock into outstanding or treasury shares of Class B common stock, as the case may be, such shares of Class A common stock will be canceled, will no longer be outstanding and will not be reissued. There are currently no shares of Class B common stock outstanding.

     The business, assets, liabilities, directors and executive officers of the Company did not change as a result of the reorganization.

(12) DERIVATIVE FINANCIAL INSTRUMENTS

     Derivative instruments are accounted for at fair value. The accounting for changes in the fair value of a derivative depends on the intended use and designation of the derivative instrument. For a derivative instrument designated as a fair value hedge, the gain or loss on the derivative is recognized in earnings in the period of change in fair value together with the offsetting gain or loss on the hedged item. For a derivative instrument designated as a cash flow hedge, the effective portion of the 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, 2010, we have no open foreign currency contracts.

     We entered into an interest rate swap with the objective of reducing our exposure to interest rate risk for $100.0 million of our $200.0 million Facility Agreement variable-rate debt. At December 31, 2010, our interest rate derivative instruments have an outstanding notional amount of $100.0 million and have been designated as cash flow hedges. The critical terms of these swaps, including reset dates and floating rate indices match those of our underlying variable-rate debt and no ineffectiveness has been recorded.

Early Hedge Settlement

     During December 2009, we cash settled certain interest rate swap contracts prior to their scheduled settlement dates. As a result of these transactions, we paid $6.4 million in cash, which represented the fair value of these contracts at the date of settlement. Unrecognized losses of $1.8 million are recorded as of December 31, 2010 in accumulated OCI related to these interest rate swaps. This balance will be amortized into interest expense through December 31, 2012 based on forecasted payments as of the settlement date.

64

     The following table quantifies the fair values, on a gross basis, of all our derivative contracts and identifies the consolidated balance sheet location as of December 31 (dollars in thousands):

	Asset Derivatives						Liability Derivatives
	2010			2009			2010			2009
Derivaties designated as	Balance Sheet			Balance Sheet			Balance Sheet			Balance Sheet
hedging instruments	Location	Fair Value		Location	Fair Value		Location	Fair Value		Location	Fair Value
Foreign exchange contracts	Fair value hedges	$	-	Fair value hedges	$	6,886	Fair value hedges	$	-	Fair value hedges	$	6,886
Interest Rate Swaps			-			-	Cash flow hedges		6,807	Cash flow hedges		6,422
		$	-		$	6,886		$	6,807		$	13,308

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

	Location of Gain or Loss		Amount of Gain or Loss
Derivatives in fair value	Recognized in Income on		Recognized in Income on
hedging relationships		Derivative	Derivative
			2010		2009
			(in thousands)
Foreign exchange contracts	See note.		$	-	$	-

						Location of Gain or (Loss)	Amount of Gain or (Loss)
	Amount of Gain or (Loss)					Reclassified from	Reclassified from
Derivatives in cash flow	Recognized in OCI on					Accumulated OCI into	Accumulated OCI into
hedging relationships	Derivative					Income	Income
	2010			2009			2010			2009
	(in thousands)						(in thousands)
Interest rate contracts	$	(4,351	)	$	1,448	Interest expense	$	(2,716	)	$	(3,976	)

(13) FAIR VALUE MEASUREMENTS

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

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

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

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

Financial Instruments

     As of December 31, 2009, we had open fair value hedges associated with firm contractual commitments for future vessel payments denominated in a foreign currency. These forward contracts were designated as fair value hedges and were highly effective, as the terms of the forward contracts were the same as the purchase commitment under the new build contract. We recognized the fair value of our derivative assets as Level 2 valuations. We determined the fair value of our financial instrument position based upon the forward contract price and the foreign currency exchange rate as of December 31, 2009. At December 31, 2009, the fair value of our derivatives was approximately $6.9 million. There are no open fair value hedges at December 31, 2010.

65

     We had interest rate swap agreements that hedged the interest rate associated with a portion of our previous senior indebtedness. These cash flow hedges fixed the interest rate at 4.725% on approximately $85.0 million of the senior debt facility. On December 17, 2009, we entered into the $200.0 million Facility Agreement and terminated the existing senior indebtedness and the swaps associated with that debt. As a result, we entered into an interest rate swap agreement for approximately $100.0 million of the Facility Agreement indebtedness that has fixed the interest rate at 4.145%. The interest rate swap is accounted for as cash flow hedge. We report changes in the fair value of the cash flow hedges in accumulated other comprehensive income. The consolidated balance sheet contains cash flow hedges within other long term liabilities, reflecting the fair value of the interest rate swap which was $6.8 million at December 31, 2010. We report changes in the fair value of these cash flow hedges in accumulated other comprehensive income. For the year ended December 31, 2010, $2.7 million was reclassified from other comprehensive income to interest expense. We expect to reclassify $3.1 million of deferred loss related to the interest rate swaps to interest expense during the next 12 months. We recognize the fair value of our derivative swaps as a Level 2 valuation. We determined the fair value of our interest rate swap based on the contractual fixed rate in the swap agreement and the forward curve of three month LIBOR supplied by the bank as of December 31, 2010.

     The following table presents information about our assets (liabilities) measured at fair value on a recurring basis as of December 31, 2010, and indicates the fair value hierarchy we utilized to determine such fair value (in millions).

	Level 1		Level 2			Level 3		Total
Cash Flow Hedges	$	-	$	(6.8	)	$	-	$	(6.8	)

     The following table presents information about our assets (liabilities) measured at fair value on a recurring basis as of December 31, 2009, and indicates the fair value hierarchy we utilized to determine such fair value (in millions).

	Level 1		Level 2			Level 3		Total
Fair Value Hedges	$	-		$6.9		$	-	$	6.9
Purchase Commitments		-		(6.9	)		-		(6.9	)
Cash Flow Hedges		-		(6.4	)		-		(6.4	)
	$	-	$	(6.4	)	$	-	$	(6.4	)

     The purchase commitments and cash flow hedges are included in other long term liabilities on the consolidated balance sheet as of December 31, 2010 and 2009.

(14) OPERATING SEGMENT INFORMATION

Business Segments

     We operate our business based on geographical locations and maintain the following operating segments: the North Sea, Southeast Asia and the Americas. Our chief operating decision-maker regularly reviews financial information about each of these operating segments in deciding how to allocate resources and evaluate performance. The business within each of these geographic regions has similar economic characteristics, services, distribution methods and regulatory concerns. All of the operating segments are considered reportable segments under FASB ASC 280, “Segment Reporting”.

     Management evaluates segment performance primarily based on operating income. Cash and debt are managed centrally. Because the regions do not manage those items, the gains and losses on foreign currency remeasurements associated with these items are excluded from operating income. Management considers segment operating income to be a good indicator of each 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):

66

	North			Southeast
	Sea			Asia			Americas			Other			Total
Year Ended December 31, 2010
Revenue	$	148,740		$	66,533		$	144,493		$	-		$	359,766
Direct operating expenses		78,253			10,395			81,990			-			170,638
Drydock expense		7,598			4,796			9,788			-			22,182
General and administrative expense		11,277			2,659			7,798			22,295			44,029
Depreciation and amortization		18,649			8,922			28,321			1,067			56,959
Impairment charge		-			-			97,665			-			97,665
(Gain) loss on sale of assets		(5,246	)		-			154			(3	)		(5,095	)
Operating income (loss)	$	38,209		$	39,761		$	(81,223	)	$	(23,359	)	$	(26,612	)
Cash and cash equivalents	$	47,628		$	16,532		$	16,123		$	16,912		$	97,195
Long-lived assets(a)(b)	$	408,798		$	249,678		$	590,436		$	4,665		$	1,253,577
Total assets	$	505,062		$	292,189		$	635,582		$	31,617		$	1,464,450
Capital expenditures	$	31,997		$	34,959		$	4,456		$	2,027		$	73,439
Year Ended December 31, 2009
Revenue	$	165,415		$	76,544		$	146,912		$	-		$	388,871
Direct operating expenses		80,854			8,865			76,464			-			166,183
Drydock expense		6,818			2,095			6,783			-			15,696
General and administrative expense		10,598			1,841			8,685			22,576			43,700
Depreciation and amortization		17,186			7,131			27,892			835			53,044
Impairment charge		-			-			46,247			-			46,247
Gain on sale of assets		(4,055	)		(1,493	)		(4	)		-			(5,552	)
Operating income (loss)	$	54,014		$	58,105		$	(19,155	)	$	(23,411	)	$	69,553
Cash and cash equivalents	$	29,207		$	16,215		$	25,680		$	20,977		$	92,079
Long-lived assets(a)(b)	$	443,598		$	202,461		$	710,565		$	8,115		$	1,364,739
Total assets	$	519,228		$	245,160		$	768,345		$	32,926		$	1,565,659
Capital expenditures	$	44,901		$	15,289		$	16,820		$	428		$	77,438
Year Ended December 31, 2008
Revenue	$	226,124		$	77,851		$	107,765		$	-		$	411,740
Direct operating expenses		86,445			12,509			44,972			-			143,926
Drydock expense		8,237			250			2,832			-			11,319
General and administrative expense		11,414			2,193			6,769			19,867			40,243
Depreciation and amortization		22,623			6,170			14,860			647			44,300
Gain on sale of assets		(29,081	)		(5,718	)		(12	)		-			(34,811	)
Operating income (loss)	$	126,486		$	62,447		$	38,344		$	(20,514	)	$	206,763
Cash and cash equivalents	$	46,080		$	19,707		$	7,723		$	27,251		$	100,761
Long-lived assets(a)(b)	$	341,553		$	159,288		$	684,601		$	141,208		$	1,326,650
Total assets	$	436,758		$	209,179		$	738,181		$	172,850		$	1,556,968
Capital expenditures	$	23,805		$	45,089		$	39,733		$	1,072		$	109,699

a. Goodwill is included in the North Sea and Americas segments. The Americas segment goodwill was charged to impairment expense in the second quarter of 2010.

b. Most vessels under construction are included in Other until delivered. Revenue, long-lived assets and capital expenditures presented in the table above are allocated to segments based on the location the vessel is employed, which in some instances differs from the segment that legally owns the vessel. In 2010, we had $104.5 million in revenue and $462.9 million in long-lived assets attributed to business in the United States, our country of domicile. In 2009, we had $106.5 million in revenue and $603.9 million in long-lived assets attributed to the United States.

67

(15) UNAUDITED QUARTERLY FINANCIAL DATA

     Summarized quarterly financial data for the two years ended December 31, 2010 and 2009 are as follows:

	Quarter
	First		Second			Third		Fourth
	(In thousands, except per share amounts)
2010
Revenues	$	84,651	$	92,782		$	94,479	$	87,854
Operating income (loss)		8,912		(79,239	)		25,981		17,734
Net income (loss)		21,543		(90,731	)		19,207		15,236
Per share (basic)		$0.85		($3.55	)		$0.75		$0.59
Per share (diluted)		$0.84		($3.55	)		$0.75		$0.59
2009
Revenue	$	108,795	$	104,656		$	90,764	$	84,656
Operating income		1,550		39,040			19,765		9,197
Net income (loss)		14,221		34,923			12,702		(11,263	)
Per share (basic)		$0.57		$1.39			$0.50		($0.45	)
Per share (diluted)		$0.56		$1.38			$0.50		($0.45	)

68

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, 2010, and in making this assessment, used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on this assessment, management determined that our internal control over financial reporting was effective as of December 31, 2010. UHY LLP has issued the following opinion on the Company’s internal control over financial reporting.

69

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

     To the Board of Directors and Stockholders of GulfMark Offshore, Inc. and its Subsidiaries:

     We have audited GulfMark Offshore, Inc. and its subsidiaries’ internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). GulfMark Offshore, Inc. and its subsidiaries’ management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying 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 of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

     A 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 its subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

     We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets and the related consolidated statements of income, stockholders’ equity, comprehensive income, and cash flows of GulfMark Offshore, Inc. and its subsidiaries, and our report dated February 24, 2011 expressed an unqualified opinion.

UHY LLP
Houston, Texas
February 24, 2011

70

(c) Changes in Internal Control Over Financial Reporting. There were no changes in our internal control over financial reporting during the quarter ended December 31, 2010, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. Other Information

     NONE

PART III

ITEM 10. Directors, Executive Officers and Corporate Governance(1)

ITEM 11. Executive Compensation(1)

ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters(1)

ITEM 13. Certain Relationships and Related Transactions, and Director Independence(1)

ITEM 14. Principal Accounting Fees and Services(1)

(1) The information required by ITEMS 10, 11, 12, 13 and 14 will be included in our definitive proxy statement to be filed with the Securities and Exchange Commission within 120 days of the close of our fiscal year and is hereby incorporated by reference herein.

71

PART IV

ITEM 15. Exhibits, Financial Statement Schedules

(a) Exhibits, Financial Statements and Financial Statement Schedules.

     (1) and (2) Financial Statements and Financial Statement Schedules.

     Consolidated Financial Statements of the Company are included in Part II, Item 8 “Consolidated Financial Statements and Supplementary Data”. All schedules have been omitted because the required information is not present or not present in an amount sufficient to require submission of the schedule, or because the information required is included in the Consolidated Financial Statements or the notes thereto.

(3) Exhibits

		Filed Herewith or
		Incorporated by Reference
Exhibits	Description	from the
		Following Documents
3.1	Certificate of Incorporation, as amended	Exhibit 3.1 to our current report on Form 8-K filed on February 24, 2010
3.2	Bylaws, as amended	Exhibit 3.2 to our current report on Form 8-K filed on February 24, 2010
4.1	Description of GulfMark Offshore, Inc. Common Stock	Exhibit 4.1 to our current report on Form 8-K filed on February 24, 2010
4.2	Form of U.S. Citizen Stock Certificates	Exhibit 4.2 to our current report on Form 8-K filed on February 24, 2010
4.3	Form of Non-U.S. Citizen Stock Certificates	Exhibit 4.3 to our current report on Form 8-K filed on February 24, 2010
4.4	Indenture, dated as of July 21, 2004, between GulfMark Offshore, Inc., as the Company, and U.S. Bank National Association, as Trustee, including a form of the Company’s 7.75% Senior Notes due 2014	Exhibit 4.4 to our quarterly report on Form 10-Q for the quarter ended September 30, 2004
4.5	First Supplemental Indenture, dated as of February 24, 2010, between GulfMark Offshore, Inc. (f/k/a New GulfMark Offshore, Inc.), as the Company and U.S. Bank Association, as Trustee, for the Company’s 7.75% Senior Notes due 2014	Exhibit 10.1 to our Form 8-K filed February 24, 2010
4.6	Registration Rights Agreement, dated July 1, 2008, among GulfMark Offshore, Inc. and certain of the Rigdon Shareholders	Exhibit 4.5 to our current report on Form 8-K filed on July 7, 2008
10.1	GulfMark International, Inc. Amended and Restated 1993 Non-Employee Director Stock Option Plan*	Exhibit 10.7 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997
10.2	Amendment No. 1 to the GulfMark International, Inc. Amended and Restated 1993 Non-Employee Director Stock Option Plan*	Exhibit 10.8 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997
10.3	GulfMark Offshore, Inc. Instrument of Assumption and Adjustment (Amended and Restated 1993 Non-Employee Director Stock Option Plan)*	Exhibit 10.9 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997

72

10.4	Form of Stock Option Agreement (Amended and Restated 1993 Non-Employee Director Stock Option Plan)*	Exhibit 10.12 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997
10.5	Form of Amendment No. 1 to Stock Option Agreement (Amended and Restated 1993 Non-Employee Director Stock Option Plan)*	Exhibit 10.11 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997
10.6	GulfMark Offshore, Inc. 1997 Incentive Equity Plan*	Exhibit 10.16 to our annual report on Form 10-K for the year ended December 31, 1998
10.7	Amendment No. 1 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan*	Exhibit 4.4.2 to our Registration Statement on Form S-8, Registration No. 333-57294 filed on March 20, 2001
10.8	Amendment No. 2 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan*	Exhibit 4.8.3 to our Post-Effective Amendment No. 1 to our Registration Statement on Form S-8, Registration No. 333-57294 filed on May 25, 2007
10.9	Amendment No. 3 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan*	Exhibit 4.8.4 to our Post-Effective Amendment No. 1 to our Registration Statement on Form S-8, Registration No. 333-57294 filed on May 25, 2007
10.10	Amendment No. 4 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan *	Exhibit 10.1 to our current report on Form 8-K filed on March 26, 2008
10.11	Amendment No. 5 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan*	Exhibit 10.4 to our current report on Form 8-K filed on October 19, 2009
10.12	Form of Incentive Stock Option Agreement (1997 Incentive Equity Plan)*	Exhibit 10.17 to our annual report on Form 10-K for the year ended December 31, 1998
10.13	GulfMark Offshore, Inc. 2010 Omnibus Equity Incentive Plan*	Exhibit A to our Proxy Statement on Form DEF 14A filed on April 30, 2010
10.14	Amendment No. 1 to the GulfMark Offshore, Inc. 2010 Omnibus Equity Incentive Plan*	Exhibit 10.2 to our current report on Form 8-K filed on June 11, 2010
10.15	Form of Notice of Stock Option Award and Form of Stock Option Agreement (2010 Omnibus Equity Incentive Plan)*	Exhibit 10.3 to our current report on Form 8-K filed on June 11, 2010
10.16	Form of Notice of Restricted Stock Award and Form of Restricted Stock Agreement (2010 Omnibus Equity Incentive Plan)*	Exhibit 10.4 to our current report on Form 8-K filed on June 11, 2010
10.17	GulfMark Offshore, Inc. 2005 Non-Employee Director Share Incentive Plan*	Exhibit A to our Proxy Statement on Form DEF 14A, filed on April 11, 2005
10.18	Amendment No. 1 to the GulfMark Offshore, Inc. 2005 Non-Employee Director Share Incentive Plan*	Exhibit 4.8.2 to our Registration Statement on Form S-8, Registration No. 333-143258 filed on May 25, 2007
10.19	Amendment No. 2 to the GulfMark Offshore, Inc. 2005 Non-Employee Director Share Incentive Plan*	Exhibit 10.5 to our current report on Form 8-K filed on October 19, 2009
10.20	Amendment No. 3 to the GulfMark Offshore, Inc. 2005 Non-Employee Director Share Incentive Plan*	Exhibit 10.2 to our current report on Form 8-K filed on March 23, 2010
10.21	Form of Restricted Stock Award Agreement (2005 Non-Employee Director Share Incentive Plan)*	Exhibit 10.1 to our current report on Form 8-K filed on May 18, 2006

73

10.22	Form of Stock Award Agreement (2005 Non-Employee Director Share Incentive Plan)*	Exhibit 10.3 to our Form 8-K filed on March 23, 2010
10.23	GulfMark Offshore, Inc. Employee Stock Purchase Plan*	Exhibit 4.4.3 to our Registration Statement on Form S-8, Registration No. 333-84110 filed on March 11, 2002
10.24	Amendment No. 1 to Employee Stock Purchase Plan*	Exhibit 10.1 to our current report on Form 8-K filed on March 23, 2010
10.25	Executive Nonqualified Excess Plan Document*	Exhibit 10.1 to our quarterly report on Form 10-Q for the quarter ended September 30, 2010
10.26	Executive Nonqualified Excess Plan Adoption Agreement, amended effective January 1, 2010*	Exhibit 10.2 to our quarterly report on Form 10-Q for the quarter ended September 30, 2010
10.27	Form of the Executive Nonqualified Excess Plan Participation Agreement*	Exhibit 10.3 to our quarterly report on Form 10-Q for the quarter ended September 30, 2010
10.28	Amended and Restated Employment Agreement dated October 14, 2009, made by and between GulfMark Americas, Inc. and Bruce A. Streeter*	Exhibit 10.1 to our current report on Form 8-K filed on October 19, 2009
10.29	Amended and Restated Employment Agreement dated October 14, 2009, made by and between GulfMark Americas, Inc. and John E. Leech*	Exhibit 10.2 to our current report on Form 8-K filed on October 19, 2009
10.30	Employment Agreement dated October 14, 2009, made by and between GulfMark Americas, Inc. and Quintin V. Kneen*	Exhibit 10.3 to our current report on Form 8-K filed on October 19, 2009
10.31	GulfMark Offshore, Inc. Severance Benefits Policy, effective as of August 1, 2001*	Exhibit 10.6 to our current report on Form 8-K filed on October 19, 2009
10.32	Amendment to GulfMark Offshore, Inc. Severance Benefits Policy, effective as of October 13, 2009*	Exhibit 10.7 to our current report on Form 8-K filed on October 19, 2009
10.33	Form of Indemnification Agreements*	Exhibit 10.2 to our current report on Form 8-K filed on February 24, 2010
10.34	GM Offshore, Inc. Supplemental Income Plan effective as of January 1, 2000*	Filed herewith
10.35	Split-Dollar Insurance Agreement (Collateral Assignment) dated January 1, 2000, between GM Offshore, Inc. and Bruce A. Streeter*	Filed herewith
10.36	Participation Agreement Supplemental Income Plan of GulfMark Offshore Inc. dated January 1, 2000 by Bruce A. Streeter*	Filed herewith
10.37	Amendment One to Participation Agreement Supplemental Income Plan of GulfMark Offshore, Inc. dated December 28, 2010, between GulfMark Offshore, Inc. and Bruce A. Streeter*	Filed herewith
10.38	Split-Dollar Insurance Agreement (Collateral Assignment) dated January 1, 2000, between GM Offshore, Inc. and John E. Leech*	Filed herewith

74

10.39	Participation Agreement Supplemental Income Plan of GulfMark Offshore Inc. dated January 1, 2000 by John E. Leech*	Filed herewith
10.40	Amendment One to Participation Agreement Supplemental Income Plan of GulfMark Offshore, Inc. dated December 29, 2010, between GulfMark Offshore, Inc. and John E. Leech*	Filed herewith
10.41	U.S. $25.0 million Secured Reducing Revolving Loan Facility Agreement between GulfMark Offshore, Inc. and DnB NOR Bank ASA and others dated June 1, 2006, as Amended and Restated by a First Supplemental Agreement dated June 5, 2008	Exhibits 10.24 and 10.25 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008
10.42	U.S. $60.0 million Secured Reducing Revolving Loan Facility Agreement between Gulf Offshore N.S. Limited and DnB NOR Bank ASA and others dated June 1, 2006	Exhibit 10.29 to our current report on Form 8-K filed on June 9, 2006
10.43	U.S. $30.0 million Secured Reducing Revolving Loan Facility Agreement between GulfMark Rederi AS and DnB NOR Bank ASA and others dated June 1, 2006	Exhibit 10.30 to our current report on Form 8-K filed on June 9, 2006
10.44	U.S. $60.0 million Secured Reducing Revolving Loan Facility Agreement between GulfMark Marine Far East Pte. Ltd. And DnB NOR Bank ASA and others dated June 5, 2008	Exhibit 10.26 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008
10.45	Membership Interest and Stock Purchase Agreement among GulfMark Offshore, Inc., Rigdon Marine Corporation, Rigdon Marine Holdings, L.L.C., all the members of Rigdon Marine Holdings, L.L.C., Sherwood Investment, L.L.C., John J. Tennant III Irrevocable Trust, Brian M. Bowman Irrevocable Trust, and Bourbon Offshore, dated May 28, 2008	Exhibit 10.6 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008
10.46	Assignment and Assumption Agreement between GulfMark Offshore, Inc. and GulfMark Management, Inc., dated June 30, 2008	Exhibit 10.7 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008
10.47	Non-Competition and Non-Solicitation Agreement between GulfMark Offshore, Inc. and Larry T. Rigdon, dated July 1, 2008	Exhibit 10.8 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008
10.48	Operating Agreement and By-laws of Jackson Offshore, LLC, by and between Rigdon Marine Corporation, Lee Jackson, and Bourbon Offshore Holdings SAS, dated August 16, 2006	Exhibit 10.9 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008
10.49	Delphin Marine Logistics Limited Joint Venture Agreement, by and between Rigdon Marine Corporation, Mariners Haven Limited and Delphin Marine Logistics Limited, dated February 29, 2008	Exhibit 10.10 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008
10.50	U.S. $200.0 million Facility Agreement among GulfMark Americas, Inc., as borrower, GulfMark Offshore, Inc., as guarantor, The Royal Bank of Scotland plc, as arranger, as agent of the Finance Parties and as security trustee for the Secured Parties, and the lenders that are parties thereto, dated December 17, 2009	Exhibit 10.1 to our current report on Form 8-K filed on December 17, 2009
12.1	Computation of Ratio of Earnings to Fixed Charges	Filed herewith
21.1	Subsidiaries of GulfMark Offshore, Inc.	Filed herewith

75

23.1	Consent of UHY LLP	Filed herewith
31.1	Section 302 Certification for B.A. Streeter	Filed herewith
31.2	Section 302 Certification for Q.V. Kneen	Filed herewith
32.1	Section 906 Certification furnished for B.A. Streeter	Filed herewith
32.2	Section 906 Certification furnished for Q.V. Kneen	Filed herewith
101	The following materials from GulfMark Offshore, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2010, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Stockholders’ Equity, (iv) Consolidated Statements of Comprehensive Income (Loss), (v) Consolidated Statements of Cash Flows and (vi) Notes to Consolidated Financial Statements, tagged as blocks of text.	Filed herewith

76

SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto duly authorized.

	GulfMark Offshore, Inc. (Registrant)
By:	/s/ Bruce A. Streeter
	Bruce A. Streeter
	Chief Executive Officer, President and Director (Principal Executive Officer)

Date: February 24, 2011

     Pursuant to the requirements of the Securities Exchange Act of 1934, this report had been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:

/s/ Bruce A. Streeter	Chief Executive Officer, President and Director	February 24, 2011
Bruce A. Streeter	(Principal Executive Officer)
/s/ Quintin V. Kneen	Executive Vice President and Chief Financial Officer	February 24, 2011
Quintin V. Kneen	(Principal Financial Officer)
/s/ Samuel R. Rubio	Vice President, Controller and Chief Accounting Officer	February 24, 2011
Samuel R. Rubio	(Principal Accounting Officer)
/s/ David J. Butters	Director	February 24, 2011
David J. Butters
/s/ Peter I. Bijur	Director	February 24, 2011
Peter I. Bijur
/s/ Brian R. Ford	Director	February 24, 2011
Brian R. Ford
/s/ Louis S. Gimbel, 3rd	Director	February 24, 2011
Louis S. Gimbel 3rd
/s/ Sheldon S. Gordon	Director	February 24, 2011
Sheldon S. Gordon
/s/ Robert B. Millard	Director	February 24, 2011
Robert B. Millard
/s/ Robert T. O’Connell	Director	February 24, 2011
Robert T. O’Connell
/s/ Rex C. Ross	Director	February 24, 2011
Rex C. Ross

77

INDEX TO EXHIBITS

		Filed Herewith or
		Incorporated by Reference
Exhibits	Description	from the
		Following Documents
3.1	Certificate of Incorporation, as amended	Exhibit 3.1 to our current report on Form 8-K filed on February 24, 2010
3.2	Bylaws, as amended	Exhibit 3.2 to our current report on Form 8-K filed on February 24, 2010
4.1	Description of GulfMark Offshore, Inc. Common Stock	Exhibit 4.1 to our current report on Form 8-K filed on February 24, 2010
4.2	Form of U.S. Citizen Stock Certificates	Exhibit 4.2 to our current report on Form 8-K filed on February 24, 2010
4.3	Form of Non-U.S. Citizen Stock Certificates	Exhibit 4.3 to our current report on Form 8-K filed on February 24, 2010
4.4	Indenture, dated as of July 21, 2004, between GulfMark Offshore, Inc., as the Company, and U.S. Bank National Association, as Trustee, including a form of the Company’s 7.75% Senior Notes due 2014	Exhibit 4.4 to our quarterly report on Form 10-Q for the quarter ended September 30, 2004
4.5	First Supplemental Indenture, dated as of February 24, 2010, between GulfMark Offshore, Inc. (f/k/a New GulfMark Offshore, Inc.), as the Company and U.S. Bank Association, as Trustee, for the Company’s 7.75% Senior Notes due 2014	Exhibit 10.1 to our Form 8-K filed February 24, 2010
4.6	Registration Rights Agreement, dated July 1, 2008, among GulfMark Offshore, Inc. and certain of the Rigdon Shareholders	Exhibit 4.5 to our current report on Form 8-K filed on July 7, 2008
10.1	GulfMark International, Inc. Amended and Restated 1993 Non-Employee Director Stock Option Plan*	Exhibit 10.7 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997
10.2	Amendment No. 1 to the GulfMark International, Inc. Amended and Restated 1993 Non-Employee Director Stock Option Plan*	Exhibit 10.8 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997
10.3	GulfMark Offshore, Inc. Instrument of Assumption and Adjustment (Amended and Restated 1993 Non-Employee Director Stock Option Plan)*	Exhibit 10.9 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997
10.4	Form of Stock Option Agreement (Amended and Restated 1993 Non-Employee Director Stock Option Plan)*	Exhibit 10.12 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997
10.5	Form of Amendment No. 1 to Stock Option Agreement (Amended and Restated 1993 Non-Employee Director Stock Option Plan)*	Exhibit 10.11 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997
10.6	GulfMark Offshore, Inc. 1997 Incentive Equity Plan*	Exhibit 10.16 to our annual report on Form 10-K for the year ended December 31, 1998
10.7	Amendment No. 1 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan*	Exhibit 4.4.2 to our Registration Statement on Form S-8, Registration No. 333-57294 filed on March 20, 2001

78

10.8	Amendment No. 2 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan*	Exhibit 4.8.3 to our Post-Effective Amendment No. 1 to our Registration Statement on Form S-8, Registration No. 333-57294 filed on May 25, 2007
10.9	Amendment No. 3 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan*	Exhibit 4.8.4 to our Post-Effective Amendment No. 1 to our Registration Statement on Form S-8, Registration No. 333-57294 filed on May 25, 2007
10.10	Amendment No. 4 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan *	Exhibit 10.1 to our current report on Form 8-K filed on March 26, 2008
10.11	Amendment No. 5 to the GulfMark Offshore, Inc. 1997 Incentive Equity Plan*	Exhibit 10.4 to our current report on Form 8-K filed on October 19, 2009
10.12	Form of Incentive Stock Option Agreement (1997 Incentive Equity Plan)*	Exhibit 10.17 to our annual report on Form 10-K for the year ended December 31, 1998
10.13	GulfMark Offshore, Inc. 2010 Omnibus Equity Incentive Plan*	Exhibit A to our Proxy Statement on Form DEF 14A filed on April 30, 2010
10.14	Amendment No. 1 to the GulfMark Offshore, Inc. 2010 Omnibus Equity Incentive Plan*	Exhibit 10.2 to our current report on Form 8-K filed on June 11, 2010
10.15	Form of Notice of Stock Option Award and Form of Stock Option Agreement (2010 Omnibus Equity Incentive Plan)*	Exhibit 10.3 to our current report on Form 8-K filed on June 11, 2010
10.16	Form of Notice of Restricted Stock Award and Form of Restricted Stock Agreement (2010 Omnibus Equity Incentive Plan)*	Exhibit 10.4 to our current report on Form 8-K filed on June 11, 2010
10.17	GulfMark Offshore, Inc. 2005 Non-Employee Director Share Incentive Plan*	Exhibit A to our Proxy Statement on Form DEF 14A, filed on April 11, 2005
10.18	Amendment No. 1 to the GulfMark Offshore, Inc. 2005 Non-Employee Director Share Incentive Plan*	Exhibit 4.8.2 to our Registration Statement on Form S-8, Registration No. 333-143258 filed on May 25, 2007
10.19	Amendment No. 2 to the GulfMark Offshore, Inc. 2005 Non-Employee Director Share Incentive Plan*	Exhibit 10.5 to our current report on Form 8-K filed on October 19, 2009
10.20	Amendment No. 3 to the GulfMark Offshore, Inc. 2005 Non-Employee Director Share Incentive Plan*	Exhibit 10.2 to our current report on Form 8-K filed on March 23, 2010
10.21	Form of Restricted Stock Award Agreement (2005 Non-Employee Director Share Incentive Plan)*	Exhibit 10.1 to our current report on Form 8-K filed on May 18, 2006
10.22	Form of Stock Award Agreement (2005 Non-Employee Director Share Incentive Plan)*	Exhibit 10.3 to our Form 8-K filed on March 23, 2010
10.23	GulfMark Offshore, Inc. Employee Stock Purchase Plan*	Exhibit 4.4.3 to our Registration Statement on Form S-8, Registration No. 333-84110 filed on March 11, 2002
10.24	Amendment No. 1 to Employee Stock Purchase Plan*	Exhibit 10.1 to our current report on Form 8-K filed on March 23, 2010
10.25	Executive Nonqualified Excess Plan Document*	Exhibit 10.1 to our quarterly report on Form 10-Q for the quarter ended September 30, 2010
10.26	Executive Nonqualified Excess Plan Adoption Agreement, amended effective January 1, 2010*	Exhibit 10.2 to our quarterly report on Form 10-Q for the quarter ended September 30, 2010

79

10.27	Form of the Executive Nonqualified Excess Plan Participation Agreement*	Exhibit 10.3 to our quarterly report on Form 10-Q for the quarter ended September 30, 2010
10.28	Amended and Restated Employment Agreement dated October 14, 2009, made by and between GulfMark Americas, Inc. and Bruce A. Streeter*	Exhibit 10.1 to our current report on Form 8-K filed on October 19, 2009
10.29	Amended and Restated Employment Agreement dated October 14, 2009, made by and between GulfMark Americas, Inc. and John E. Leech*	Exhibit 10.2 to our current report on Form 8-K filed on October 19, 2009
10.30	Employment Agreement dated October 14, 2009, made by and between GulfMark Americas, Inc. and Quintin V. Kneen*	Exhibit 10.3 to our current report on Form 8-K filed on October 19, 2009
10.31	GulfMark Offshore, Inc. Severance Benefits Policy, effective as of August 1, 2001*	Exhibit 10.6 to our current report on Form 8-K filed on October 19, 2009
10.32	Amendment to GulfMark Offshore, Inc. Severance Benefits Policy, effective as of October 13, 2009*	Exhibit 10.7 to our current report on Form 8-K filed on October 19, 2009
10.33	Form of Indemnification Agreements*	Exhibit 10.2 to our current report on Form 8-K filed on February 24, 2010
10.34	GM Offshore, Inc. Supplemental Income Plan effective as of January 1, 2000*	Filed herewith
10.35	Split-Dollar Insurance Agreement (Collateral Assignment) dated January 1, 2000, between GM Offshore, Inc. and Bruce A. Streeter*	Filed herewith
10.36	Participation Agreement Supplemental Income Plan of GulfMark Offshore Inc. dated January 1, 2000 by Bruce A. Streeter*	Filed herewith
10.37	Amendment One to Participation Agreement Supplemental Income Plan of GulfMark Offshore, Inc. dated December 28, 2010, between GulfMark Offshore, Inc. and Bruce A. Streeter*	Filed herewith
10.38	Split-Dollar Insurance Agreement (Collateral Assignment) dated January 1, 2000, between GM Offshore, Inc. and John E. Leech*	Filed herewith
10.39	Participation Agreement Supplemental Income Plan of GulfMark Offshore Inc. dated January 1, 2000 by John E. Leech*	Filed herewith
10.40	Amendment One to Participation Agreement Supplemental Income Plan of GulfMark Offshore, Inc. dated December 29, 2010, between GulfMark Offshore, Inc. and John E. Leech*	Filed herewith
10.41	U.S. $25.0 million Secured Reducing Revolving Loan Facility Agreement between GulfMark Offshore, Inc. and DnB NOR Bank ASA and others dated June 1, 2006, as Amended and Restated by a First Supplemental Agreement dated June 5, 2008	Exhibits 10.24 and 10.25 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

80

10.42	U.S. $60.0 million Secured Reducing Revolving Loan Facility Agreement between Gulf Offshore N.S. Limited and DnB NOR Bank ASA and others dated June 1, 2006	Exhibit 10.29 to our current report on Form 8-K filed on June 9, 2006
10.43	U.S. $30.0 million Secured Reducing Revolving Loan Facility Agreement between GulfMark Rederi AS and DnB NOR Bank ASA and others dated June 1, 2006	Exhibit 10.30 to our current report on Form 8-K filed on June 9, 2006
10.44	U.S. $60.0 million Secured Reducing Revolving Loan Facility Agreement between GulfMark Marine Far East Pte. Ltd. And DnB NOR Bank ASA and others dated June 5, 2008	Exhibit 10.26 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008
10.45	Membership Interest and Stock Purchase Agreement among GulfMark Offshore, Inc., Rigdon Marine Corporation, Rigdon Marine Holdings, L.L.C., all the members of Rigdon Marine Holdings, L.L.C., Sherwood Investment, L.L.C., John J. Tennant III Irrevocable Trust, Brian M. Bowman Irrevocable Trust, and Bourbon Offshore, dated May 28, 2008	Exhibit 10.6 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008
10.46	Assignment and Assumption Agreement between GulfMark Offshore, Inc. and GulfMark Management, Inc., dated June 30, 2008	Exhibit 10.7 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008
10.47	Non-Competition and Non-Solicitation Agreement between GulfMark Offshore, Inc. and Larry T. Rigdon, dated July 1, 2008	Exhibit 10.8 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008
10.48	Operating Agreement and By-laws of Jackson Offshore, LLC, by and between Rigdon Marine Corporation, Lee Jackson, and Bourbon Offshore Holdings SAS, dated August 16, 2006	Exhibit 10.9 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008
10.49	Delphin Marine Logistics Limited Joint Venture Agreement, by and between Rigdon Marine Corporation, Mariners Haven Limited and Delphin Marine Logistics Limited, dated February 29, 2008	Exhibit 10.10 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008
10.50	U.S. $200.0 million Facility Agreement among GulfMark Americas, Inc., as borrower, GulfMark Offshore, Inc., as guarantor, The Royal Bank of Scotland plc, as arranger, as agent of the Finance Parties and as security trustee for the Secured Parties, and the lenders that are parties thereto, dated December 17, 2009	Exhibit 10.1 to our current report on Form 8-K filed on December 17, 2009
12.1	Computation of Ratio of Earnings to Fixed Charges	Filed herewith
21.1	Subsidiaries of GulfMark Offshore, Inc.	Filed herewith
23.1	Consent of UHY LLP	Filed herewith
31.1	Section 302 Certification for B.A. Streeter	Filed herewith
31.2	Section 302 Certification for Q.V. Kneen	Filed herewith
32.1	Section 906 Certification furnished for B.A. Streeter	Filed herewith
32.2	Section 906 Certification furnished for Q.V. Kneen	Filed herewith
101	The following materials from GulfMark Offshore, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2010, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Stockholders’ Equity, (iv) Consolidated Statements of Comprehensive Income (Loss), (v) Consolidated Statements of Cash Flows and (vi) Notes to Consolidated Financial Statements, tagged as blocks of text.	Filed herewith

81

EX-10.34

Exhibit 10.34

GM OFFSHORE, INC.
SUPPLEMENTAL INCOME PLAN

1.	Establishment and Purpose of Plan
1.1	Establishment and Duration of Plan. The Board of Directors of GM Offshore, Inc., (the “Company”), a Delaware corporation, hereby establish the Supplemental income Plan of GulfMark Offshore, Inc. and its successors, effective as of the first day of January, 2000. By executing a Participation Agreement, an Executive agrees to the terms of the Plan. The Plan shall continue until terminated by the Board of Directors of the Company, subject to the provisions of Section 7.1.
1.2	Purpose of Plan. The Company has entered or intends to enter into collateral assignment split-dollar insurance agreements with certain of its executive or highly-compensated employees whereby the Company will pay the premiums on a whole life insurance policy on the life of the employee. The purpose of the Plan is to provide a means of vesting in the participating employees an amount measured by the outstanding cash value of the life insurance policy, which amount may vary among participating employees and which will increase over time, such that at the end of a certain term of continuous, full time employment with the Company, the participating employee will have earned an amount in his or her Deferred Benefit Account equal to the full cash value of the policy less the cash value in excess of the amount owed to the company under the Split-Dollar Insurance Agreement for premiums paid by the Company. When the participating employee is fully vested, the amount of his or her Deferred Benefit Account, when added to the employee’s ownership of excess cash value in the employee’s policy, will equal one hundred percent of the cash value of the policy. The Plan will also provide each participating employee’s beneficiaries with certain benefits in the event the employee’s employment is terminated on account of death.
2.	Definitions
2.1	“Annual Vesting Percentage” means the fixed amount, expressed as a number of percentage points, established in an Executive’s Participation Agreement, by which the Cumulative Vested Percentage increases at the beginning of each year of continuous, full time employment, beginning on the first anniversary of the Executive’s Entry Date. If an Executive’s Annual Vesting Percentage is specified as one hundred percent (100%), the Executive shall be fully vested in his or her Deferred Benefit Account as of the Executive’s Entry Date.
2.2	“Beneficiary” means, with respect to an Executive, the person or persons who are designated as such in the Executive’s Participation Agreement. The Executive shall have the right to amend or change the designation of the Executive’s Beneficiary from time to time by written notice provided to the Company, signed by the Executive.
2.3	“Cause” means, with respect to the termination of Executive’s employment by the Company, anyone or more of the following: a breach by Executive of one or more of his duties to the Company, which breach is material to the purposes or business of the Company; gross neglect by Executive of his duties or obligations to the Company which results in substantial damage to the business or operations of the Company; the intentional infliction by Executive of substantial damage to the business or operations of the Company; Executive’s conviction of a federal or state felony offense or his conviction of any other criminal offense that would impair his ability to

	perform his duties hereunder or would impair the Company; and Executive’s commission of a willful serious act, such as fraud, embezzlement or theft against the Company. For purposes of this definition of “Cause,” the company shall be deemed to include the Company, its parent and any subsidiary or affiliate of the Company and its parent by which Executive may be employed.
2.4	“Company” means GM Offshore, Inc., a Delaware corporation having its registered address at 5 Post Oak Park, Suite 1170, Houston, Texas 77027, or any successor thereto, and its subsidiaries.
2.5	“Cumulative Vested Percentage” means the cumulative number of percentage points, not to exceed 100, which begins at a certain number (which may be zero) as of the entry Date and which increases annually by the Annual Vesting Percentage on the first day of each year of employment beginning with the first anniversary of an Executive’s Entry Date. The Cumulative Vested Percentage is used to determine the credit to an Executive’s Deferred Benefit Account as of any time under the Plan.
2.6	“Deferred Benefit Account” means the account being administered for the benefit of Executive under Article 3 of the Plan. Such account shall consist of amounts credited to such account pursuant to the Plan. Such account shall not actually be funded but shall be a bookkeeping account established on the Company’s records.
2.7	“Employed” or “employment,” when used with regard to an Executive’s employment with the Company its parent and any subsidiary or affiliate of the Company or its parent, shall mean and refer to active, continuous employment on a full-time basis.
2.8	“Entry Date” with regard to any Executive means the date established as such in the Executive’s Participation Agreement under the Plan.
2.9	“Excess Cash Value” means the amount of cash surrender value in an Executive’s Policy in excess of the amount owed to the Company under the Executive’s Split-Dollar Agreement, after deduction of any loans to the Company against cash value.
2.10	“Executive” means any employee who is designated as eligible to participate in the Plan by the Board of directors of the Company, who has executed a Participation Agreement, and who has a Split-Dollar Insurance Agreement with the Company. Only management and highly paid employees within the meaning of the Employee Retirement Income and Security Act of 1974 shall be eligible to participate.
2.11	“Gross Cash Value” means the cash value of a Policy without consideration or deduction of any loans against cash value.
2.12	“Participation Agreement” means the agreement executed by an Executive upon being admitted to the Plan. The Participation Agreement shall be an integral part of the Plan with respect to the Executive who executes such Participation Agreement.
2.13	“Plan” means the Supplemental Income Plan of the Company and its successors as established and described herein as the same may hereafter from time to time be amended.
2.14	“Policy” means a policy of whole life insurance on the life of an Executive, owned by the Executive, the premiums of which are being paid by the Company, and which has been collaterally assigned to the Company to secure the repayment of the premiums paid by the Company.

2.15	“Normal Retirement Age” means, with respect to an Executive, the date established as such in his Participation Agreement.
2.16	“Split-Dollar Insurance Agreement” means, for purposes of the Plan, an agreement between the Company and an Executive pursuant to which the Company agrees to advance the premiums due on a Policy owned by Executive, which advances are secured by a collateral assignment of the Policy.
2.17	“Retirement Date” means, with respect to an Executive, the earlier of (a) the date on which he attains his Normal Retirement Age or (b) the date of termination of his employment with the Company for any reason other than termination for Cause or the Executive’s death.
3.	Administration of Accounts
	Subject to all other terms and conditions of the Plan, if an Executive remains employed by the company, then on each anniversary of an Executive’s Entry Date, beginning with the first such anniversary, the amount of the Cumulative Vested percentage applicable to the Executive shall increase by the Annual Vesting Percentage until such time that the Executive’s Cumulative Vested Percentage shall not exceed one hundred percent (100%). The Cumulative Vested percentage shall not exceed one hundred percent. To determine the amount of the credit in an Executive’s Deferred Benefit Account as of any time, the then-outstanding Gross Cash Value of the Executive’s Policy shall be multiplied by the Cumulative Vested Percentage as of that time and from the result thus obtained there shall be subtracted an amount equal to the Excess Cash Value in the Executive’s Policy; the remaining amount after such subtraction shall be the amount of the credit in the Executive’s Deferred Benefit Account, which in no event shall be less than zero.
4.	Payment of Benefits
4.1	If an Executive has remained employed by the Company from the Executive’s Entry Date, then on the Executive’s Retirement Date the Company will pay to the Executive the full balance of his or her Deferred Benefit Account, determined as of that date in the manner provided in Article 3, in a lump sum less any required withholding of taxes or other sums. Nothing in this Plan shall affect the Company’s rights under the Executive’s Split-Dollar Insurance Agreement which shall be and remain a separate agreement between the Company and the Executive, and the Company shall retain whatever rights and interest it may then have to repayment of the premiums paid by the Company pursuant to the Executive’s Split-Dollar Insurance Agreement and the related collateral assignment of the Policy, but in no event shall the Executive personally owe any portion of the premiums so paid.
4.2	If an Executive’s employment with the Company is terminated on account of his or her death, and the Executive has not received and is not entitled to receive the benefits payable under Section 4.1 as of his or her death, then the Company will make a lump-sum payment to the Executive’s Beneficiary, within thirty (30) days following the date of payment of proceeds under the Executive’s Policy, of an amount in cash equal to that portion of the Policy Proceeds payable to the Company under the terms of the Executive’s Split-Dollar Insurance Agreement and related collateral assignment for premiums advanced by the Company.

5.	Rights and Duties of Executives
5.1	No Executive or any other person shall have any interest in any fund or in any specific asset or assets of the Company by reason of this Plan, or for any other reason, or have any right to receive any distributions under the Plan except as and to the extent expressly provided under the Plan. An Executive is a general creditor of the Company.
5.2	Each Executive shall receive an updated copy of the Plan and shall receive copies of any modifications or amendments to the Plan within ten (10) days after their adoption.
5.3	No right of any Executive to receive a payment under this Plan shall be subject to alienation, transfer, sale, assignment, pledge, attachment, garnishment or encumbrance of any kind. Any attempt to alienate, sell, transfer, assign, pledge or otherwise encumber any such payments whether presently or hereafter payable shall be void. No payment under this Plan shall be subject to debts or liabilities of any Executive.
5.4	No payment of any kind shall be due under this Plan to any Executive or the Beneficiary of such Executive, whose employment with the Company is terminated for cause.
5.5	Every Executive receiving or claiming a payment under this Plan shall be presumed to be mentally competent until the date on which the Company receives a written notice in a form and manner acceptable to the Company that such person is incompetent and that a guardian, conservator or other person legally vested with the interest of his or her estate has been appointed. If a guardian or conservator of the estate of any person receiving or claiming a payment under this Plan is appointed, the payment may be made to such guardian or conservator provided that the proper proof of appointment and continuing qualification is furnished in a form and manner acceptable to the Company. Any payment so made shall be a discharge and satisfaction of any liability of the Company for such payment.
5.6	Each Executive entitled to receive a credit or payment under the Plan shall provide the Company with such information it may from time to time deem necessary or in its best interest in administering the Plan. Any such person shall also furnish the Company with such documents, evidence, data or other information as the Company may from time to time deem necessary of advisable.
6.	Duties of the Plan Administrator
6.1	The Plan shall be administered by the Plan Administrator.
6.2	The Plan Administrator may from time to time establish rules and regulations for the administration of the Plan and adopt standard forms for such matters as elections, beneficiary designations and applications for benefits, provided such rules and forms are not inconsistent with the provisions of the Plan.
6.3	All determinations of the Plan Administrator shall be binding on all parties, subject to the rights of any party to obtain de novo review of the Plan Administrator’s interpretations of the Plan or its terms and the Plan Administrator’s factual determinations, by any’ court of competent jurisdiction under applicable law. The Plan Administrator shall not be deemed to have discretion in the interpretation of the Plan and its terms. In construing or applying the provisions of the Plan, the Company shall have the right to rely upon a written opinion of legal counsel, which may be

	independent legal counsel or legal counsel regularly employed by the Company, whether or not any question or dispute has arisen as to any distribution from the Plan.
6.4	The Plan Administrator shall be responsible for maintaining books and records for the Plan. Each Executive shall be notified once annually upon request of the applicable credit amount of his Deferred Benefit Account.
7.	Amendment or Termination
7.1	The Company reserves the right to amend, modify, terminate or discontinue the Plan at any time. However, no such amendment, modification, termination or discontinuance shall have the effect of:
	(a) Reducing the value of an Executive’s Deferred Benefit Account below the amount of the credit in such account as of the date of such amendment, modification, termination or discontinuance.
	(b) Deferring the time at which benefits shall be paid to an Executive pursuant to the Plan.
	(c) Eliminating, reducing or diminishing in any way an Executive’s Annual Vesting Percentage, or any increases to an Executive’s Cumulative Vested percentage or Deferred Benefit Account which the Executive would otherwise have been entitled to receive under the Plan if the amendment, modification, termination or discontinuance had not occurred.
7.2	An Executive’s participation in this Plan shall terminate upon the Executive’s death, and the deceased Executive’s Deferred Benefit Account will be reduced to zero (0) effective immediately upon such termination. No distribution or payment of benefits of any kind shall be due to the heirs, successors or beneficiaries of the deceased Executive under this Plan except as expressly provided in Section 4.2 above, however, nothing in this Plan shall in any way affect, limit or restrict the payment of the death benefit payable under the Policy to the beneficiaries named in the policy, subject to the Company’s rights under the Executive’s Split-Dollar Insurance Agreement.
8.	Not a Contract of Employment
8.1	This Plan is not a contract of employment between an Executive and the Company, nor does this Plan modify the “at-will” nature of an executive’s employment with the Company. No provision of this Plan restricts the right of the Company to discharge an Executive, whether with or without Cause, for any lawful reason, or restricts the right of an Executive to terminate his employment.
9.	Claims Procedure
9.1	If a benefit under this Plan is not paid to an Executive and such person believes that he or she is entitled to receive it, a claim shall be made in writing the Plan Administrator within sixty (60) days from the date the payment was to be made. Such claim shall be reviewed by the Plan Administrator and the Company. If the Claim is denied, in full or in part, the Plan Administrator shall provide written notice within ninety (90) days of the submission of the claim setting forth the specific reasons for denial. The notice shall include specific reference to the provisions of the Plan upon which the denial is based and any additional material or information necessary to perfect the claim, if any. Such written notice shall also indicate the steps to be taken if a review of the denial is desired.

9.2	If the claim is denied and a review is desired, the claimant shall notify the Plan Administrator in writing within sixty (60) days following the giving of notice of denial. A claim shall be treated as denied if the Plan Administrator does not take action in the aforesaid ninety (90) day period. In requesting review, the claimant may review this Plan or any documents relating to it and submit any written issues and comments he or she may feel appropriate. In his or her sole discretion, the Plan Administrator shall then review the claim and provide a written decision within sixty (60) days of the request for review. This decision likewise shall state the specific provisions of this Plan on which the decision is based. Nothing in this Article 9 is intended to limit the right of any Executive or Beneficiary to obtain de novo review of any interpretation of the Plan or its terms or any factual determination made by the Plan Administrator from a court of competent jurisdiction, in accordance with applicable law. The Plan Administrator shall not be deemed to have discretion in the interpretation of the Plan and its terms.
9.3	The Chairman of the Board, provided he or she is not the Executive, in which event it shall be the President or a Vice President who is not the Executive of the Company, is hereby designated as the Named Fiduciary and Plan Administrator of this Plan.
9.4	Any notice which any party mayor is required to give under this Plan shall be given in writing to the other party, at the address hereafter provided or at such other address as may be designated in writing by the party from time to time in a notice given pursuant to this paragraph, by (a) certified or registered mail, return receipt requested, postage prepaid, in which event notice shall be deemed given upon deposit in the United States Mail or (b) in the case of a notice to the Company, hand delivery to the representative of the Company designated below or such other representative as may be designated in writing by the company from time to time in a notice given to each Executive or Beneficiary, as the case may be, pursuant to this paragraph, or, in the case of a notice to an Executive or Beneficiary, hand delivery to the Executive or Beneficiary in either of which cases notice shall be deemed given upon delivery. Rejection or other refusal to accept or the inability to delivery because of a changed address of which no notice was given, shall be nevertheless effective notice for all purposes under this agreement.

Notices to the Company should be addressed to GM Offshore, Inc.,
Attn.: Chairman of the Board, 5 Post Oak Park, #1170, Houston, TX 77027.

	Notices to an Executive or Beneficiary shall be sent to the address stated in the Executive’s Participation Agreement.
10.	Construction and Expense
10.1	Whenever the context so requires, words in the masculine include the feminine and words in the feminine include the masculine and the definition of any terms in the singular may include the plural.
10.2	An Executive’s Split-Dollar Insurance Agreement is a separate agreement to which this Plan refers. In the event of any conflict between the terms, provisions or interpretation of the Plan and the terms, provisions or interpretation of an Executive’s Split-Dollar Insurance Agreement, the Split-Dollar Insurance Agreement shall control unless the parties have expressly agreed in writing otherwise.
10.3	All expenses of administering the Plan shall be paid by the Company unless the Plan provides to the contrary.

EX-10.35

Exhibit 10.35

SPLIT-DOLLAR INSURANCE AGREEMENT
(Collateral Assignment)

          THIS AGREEMENT is entered into this 1st day of January, 2000, effective as of January 1, 2000, by and between GM Offshore, Inc., a Delaware corporation, hereinafter call “the Company,” and Bruce A. Streeter hereinafter call “Employee.”

          WHEREAS, Employee, is a valued employee of the Company and the Company wishes to retain him in its employ, and

          WHEREAS, the Company, as an inducement to such continued employment, previously provided the Employee with a split-dollar life insurance plan intended to assist him with his personal life insurance, and,

          WHEREAS, the parties now desire to document and memorialize the parties’ existing split-dollar life insurance plan and incorporate same into this Agreement, which shall supersede the prior agreement of the parties.

          NOW THEREFORE, the Company and Employee agree as follows:

          1. The life insurance policy with which this agreement deals is Policy Number 11-604-649, having a policy date of November 29, 1990 (hereinafter called the “Policy”) issued by the Northwestern Mutual Life Insurance Company (hereinafter called “Insurer”) on the life of Employee. Employee is and shall remain sole owner of the Policy.

          2. The entire premium on the Policy has been and shall continue to be paid by the Company as it becomes due.

          3. The Policy may, at the Company’s discretion, provide a waiver of premium for disability benefit. If it does so provide, the cost shall be borne by the Company and the Company shall remit that amount to the Insurer when due.

          4. Dividends payable on the Policy shall be used to purchase additional paid-up insurance protection.

          5. To secure the premiums paid by the Employer pursuant to paragraph 2 above (including all premiums on the Policy previously paid and all premiums to be paid pursuant to this Agreement), Employee has executed and filed with the Insurer a collateral assignment of the Policy. Employee agrees that the collateral assignment agreement shall remain in effect during the term of this Agreement, failing which the Company shall have no obligation to make the premium payments on the Policy. The Company’s interest in the Policy shall not exceed the total amount of premiums paid by it on the Policy.

          6. In the event the Policy becomes claim by reason of Employee’s death, the Company shall have an interest in the proceeds of the Policy equal to the total value of the premiums paid on the Policy under paragraph 2 of this Agreement, less any policy indebtedness to the Insurer. The balance, if any, of the proceeds of the Policy shall be paid directly by the Insurer to the beneficiary designated by the Employee.

          7. This Agreement may be terminated, subject to the provisions of paragraphs 8, 9 and 10 below, by Employee, with or without the consent of the Company, by giving notice in writing to the Company. This Agreement may be terminated by the Company, subject to the provisions of paragraphs 8, 9 and 10 below, at any time with the written consent of Employee or, without the consent of Employee, for cause as hereafter defined. Termination shall be effective three (3) days following the date of giving of notice of such termination. For purposes of this agreement, “cause” means: a breach by Employee of one or more of his duties to the Company, which breach is material to the purposes of business of the Company; gross neglect by Employee of his duties or obligations to the Company which results in substantial damage to the business or operations of the Company; the intentional infliction by employee of substantial damage to the business or operations of the Company; Employee’s conviction of a federal or state felony offense or his conviction of any other criminal offense that would impair his ability to perform his duties hereunder or would impair the Company; and Employee’s commission of a willful serious act, such as fraud, embezzlement or theft against the Company. For purposes of this definition of “cause,” the Company shall be deemed to include the Company, its parent and any subsidiary or affiliate of the Company and its parent by which employee may be employed. Notwithstanding anything herein to the contrary, in the event this agreement is terminated by the Company for cause, the termination shall become effective upon the giving of notice of the termination in writing by the Company to Employee specifying the cause on which the termination is based.

          8. In the event of termination of this agreement as provided above, the Company shall no longer be obligated to make payments of the premiums on the policy, effectively immediately upon such termination, and Employee shall have the right and option for a period of 90 days after the date of termination to purchase from the Company all interest of the Company in the Policy upon payment to the Company within that time of an amount equal to the premiums paid by the Company on the Policy under paragraph 2 of this Agreement, less any policy indebtedness to the Insurer or other indebtedness secured by the cash value of the Policy. If Employee exercises such right and option to purchase, the Company shall execute all necessary documents required by the Insurer to effect a release of interest, or absolute assignment of the Policy by the Company to Employee. Notwithstanding anything contained herein to the contrary, except for the price due upon purchase of the Company’s interest by Employee, should Employee so elect, Employee shall not be personally obligated to repay any portion of the premiums on the Policy paid by the Company, but the Company shall retain in full its right to repayment of the premiums paid by it, it being understood and agreed that Company’s repayment shall come solely out of the proceeds of the Policy as herein provided.

          9. If Employee fails to exercise his right and option granted in paragraph 8 and to repay to the Company, to the extent required, the amounts specified in that paragraph within 90 days of the date of termination of the agreement pursuant to the provisions of paragraph 7 above, the

Company shall have the right, at its sole option, to exercise the rights provided in the collateral assignment granted pursuant to paragraph 5 to cause the Policy cash value to be paid to Company or to cancel the policy and receive the cash value thereof, up to the full amount of the premiums paid by the Company pursuant to paragraph 2, less any policy or other indebtedness secured by the cash value of the Policy; Employee shall execute any and all instruments that may be required to allow the Company to exercise those rights.

          10. Any payments under the Policy to the Company in connection with the rights granted to the Company in the collateral assignment referred to in paragraph 5 shall first be made from Policy cash value attributable to the paid-up additional life insurance purchased by the dividends on the Policy. Employee shall have no interest in the paid-up additional life insurance protection except to the extent the death benefit or cash value thereof exceeds the total of the premiums on the Policy paid by the Company.

          11. Employee shall have the right to assign any part or all of employee’s retained interest in the Policy and this Agreement to any person, entity or trust by execution of a written assignment delivered to the Company and to the Insurer.

          12. The Company and Employee can mutually agree to amend this agreement and such amendment shall be in writing and signed by the Company and Employee in order to have legal effect.

          13. This agreement shall bind and inure to the benefit of the Company and its successors and assigns; Employee and his heirs, executors, administrators and assigns; and any beneficiary of the Policy.

          14. In the event of any conflict between a provision of this Agreement and any provision or provisions of any employment agreement or supplemental income plan between the Company and Employee, this agreement shall control, unless the parties expressly declare otherwise in the employment agreement or plan.

          15. Any notice which either party mayor is required to give hereunder shall be given in writing to the other party, each at the address set forth below, or at such other address as may be designated in writing by the party from time to time in a notice given pursuant to this paragraph, by (a) certified or registered mail, return receipt requested, postage prepaid, in which event notice shall be deemed given upon deposit in the United States Mail or (b) in the case of a notice to the Company, hand delivery to the representative of the Company designated below or such other representative as may be designated in writing by the Company from time to time in a notice given pursuant to this paragraph, or, in the case of a notice to Employee, hand delivery to Employee, in either of which cases notice shall be deemed given upon delivery. Rejection or other refusal to accept or the inability to deliver because of a changed address of which no notice was given, shall be nevertheless effective notice for all purposes under this agreement.

If to Company:	GM Offshore, Inc.
	Attn.: Chairman of the Board
	5 Post Oak Park, Suite 1170

	Houston, Texas 77027
If to Employee:	Bruce A. Streeter
	108 Hanover Square
	Lafayette, Louisiana 70508

          16 This Agreement is intended to constitute the complete agreement of the parties and to integrate all agreements and understandings with regard to its subject matter, and replaces and supersedes all prior verbal and written agreements, understandings, promises or representations with regard to its subject matter.

          17. The following provisions are part of this agreement and are intended to meet the requirements of the Employee Retirement Income Security Act of 1974:

(a) The Plan: This agreement.

(b) The named fiduciary: The Company.

(b) The funding policy under this Plan is that all premiums on the Policy be remitted to the Insurer when due.

(c) Direct payment by the Insurer is the basis of payment of benefits under this Plan, with those benefits in turn being based on the payment of premiums as provided in the Plan.

(d) For claims procedure purposes, the “Claims Manager” shall be the Company’s Chairman of the Board provided he or she is not the Employee, in which event, it shall be the President or a Vice President who is not the Employee.

(1) If for any reason a claim for benefits under this Plan is denied by the Company, the Claims Manager shall deliver to the claimant a written explanation setting for the specific reasons for the denial, pertinent references to the Plan section on which the denial is based, such other data as may be pertinent and information on the procedures to be followed by the claimant in obtaining a review of his claim, all written in a manner calculated to be understood by the claimant. For this purpose:

(i) The claimant’s claim shall be deemed filed when presented orally or in writing to the Claims Manager.

(ii) The Claims Manager’s explanation shall be in writing delivered to the claimant within 90 days of the date the claim is filed.

(2) The claimant shall have 60 days following his receipt of the denial of the claim to file with the Claims Manager a written request for review of the denial. For such review, the claimant or his representative may submit pertinent documents and written issues and comments.

(3) The Claims Manager shall decide the issue on review and furnish the claimant with a copy within 60 days of receipt of the claimant’s request for review of his claim. The decision on review shall be in writing and shall include specific reasons for the decision, written in a manner calculated to be understood by the claimant, as well as specific references to the pertinent Plan provisions on which the decision is based. If a copy of the decision is not so furnished to the claimant within such 60 days, the claim shall be deemed denied on review.

(4) Factual determinations and interpretations of the Plan and its terms by the Claims Manager shall be subject to de novo review by a court of competent jurisdiction, in accordance with applicable law, and the Claims Manager shall not be deemed to have discretion in interpreting the Plan.

          18. This Agreement shall be governed by the laws of the United States of American, and to the extent state law is applicable, by the laws of the State of Louisiana.

          IN WITNESS WHEREOF the parties have signed this agreement.

In the presence of

  GM Offshore, Inc.

/s/ Edward A. Guthrie, Jr.

  Edward A. Guthrie, Jr.

/s/ Bruce A. Streeter

  Bruce A. Streeter

EX-10.36

Exhibit 10.36

PARTICIPATION AGREEMENT
SUPPLEMENTAL INCOME PLAN OF
GULFMARK OFFSHORE, INC.

Invitation to Participate in Plan

          As provided in the above referenced Plan dated January 1, 2000 you, Bruce A. Streeter, are hereby invited to participate. By accepting the invitation to participate in the Plan, you acknowledge that you have read the Plan, understand its terms, understand that benefits will be paid pursuant to the Plan only under specific circumstances described therein, understand that you are a general creditor of the Company and that you have no interest in specific assets owned by the Company. Capitalized terms used herein shall have the same meaning defined in the Plan.

Entry Date

          Your Entry Date under the Plan will be January 1, 2000 for all purposes.

Establishment of Annual Vesting Percentage

          The Annual Vesting Percentage applicable to your participation in the Plan will be one hundred percent (100%). Assuming that you remain continuously and actively employed as a full time employee of the Company, your Cumulative Vested Percentage will be one hundred percent (100%) and will not change. The credits to our Deferred Benefit Account will be determined by reference to the cash value of your Policy. specifically, as of any time that the Plan is in effect and you are participating in the Plan, the amount of the credit in your Deferred Benefit Account will be equal to an amount in dollars determined by multiplying the Cumulative Vested percentage as of that date times the then-outstanding Gross Cash Value of the Policy Less the Excess Cash Value of the Policy, in no event less than zero.

Establishment of Normal Retirement Age

          For purposes of the Plan, your “Normal Retirement Age” shall be age 65.

Acceptance of Invitation to Participate

          I hereby accept the invitation of GulfMark Offshore, Inc. to participate in its supplemental Income Plan, on this 1st day of January, 2000.

Address for Notices

          The address which should be used for notices sent to me under the Plan is:

          108 Hanover Square
          Lafayette, LA 70508

Designation of Beneficiary

          My Beneficiary for purposes of the Plan shall be (attach additional sheets if necessary for multiple beneficiaries):

Name:	Janice Streeter
Address:	108 Hanover Square
City:	Lafayette, LA 70508
State:

In the event that more than one person is named as Beneficiary, such persons shall share equally in any benefits payable to my Beneficiary under the Plan. If a Beneficiary dies, then the amount that would have been paid to that Beneficiary if living shall be paid in one sum and in equal shares to the children of that Beneficiary who survive, if any, and, if there are not such children, then to the remaining Beneficiary if any, in equal shares if more than one, and if there is no other Beneficiary, then to the estate of the Beneficiary who died.

	/s/ Bruce A. Streeter
Witness	Bruce A. Streeter

EX-10.37

Exhibit 10.37

AMENDMENT ONE TO PARTICIPATION AGREEMENT

SUPPLEMENTAL INCOME PLAN OF GULFMARK OFFSHORE, INC.

Compliance with IRC § 409A for post-2004 deferrals

          You, Bruce A. Streeter, became a participant in the Supplemental Income Plan of Gulfmark Offshore, Inc. (the “Plan”) effective January 1, 2000. Effective generally as of January 1, 2005 for amounts deferred under the Plan after 2004, Section 409A of the Internal Revenue Code of 1986, as amended (“Section 409A”) imposed new requirements on nonqualified deferred compensation. This Amendment One to Participation Agreement (this “Amendment”) conforms your participation in the Plan to the requirements of Section 409A for amounts deferred under the Plan after 2004.

          By executing our signatures below, you and Gulfmark Offshore, Inc. (the “Company”) indicate our agreement that this Amendment shall be binding on us with respect to amounts deferred under the Plan for you after 2004.

          Effective January 1, 2005, for amounts deferred after December 31, 2004, we agree that the Plan is amended as follows with respect to your participation:

          1. The following sentence is added at the end of Section 2.7:

Additionally, for amounts deferred after December 31, 2004 (determined in accordance with the rules under Section 409A of the Internal Revenue Code of 1985, as amended (“Section 409A” of the “Code”)), an Executive shall not be deemed to have undergone a “termination of employment” for purposes of determining his “Retirement Date” unless and until the Executive has undergone a “separation from service” under Section 409A.

          2. The following sentence is added at the end of Section 4.1 of the Plan:

Additionally, the portion of the Executive’s Deferred Benefit Account attributable to amounts deferred after December 31, 2004 shall in no event be later than the later of (a) December 31 of the calendar year in which the Executive’s Retirement Date occurs or (b) the 75th day following the Executive’s Retirement Date; provided, however, that if the Executive is a “specified employee” under Section 409A and his “Retirement Date” occurs because of his separation from service, then the portion of his Deferred Benefit Account attributable to amounts deferred after December 31 , 2004 shall not be paid to him until the later of (a) the date six months after his separation from service or (b) the date 18 months

after the date on which the Plan was amended by its Amendment One to Participation Agreement.

3. A new Section 7.3 is added to the Plan, to read as follows:

7.3 Notwithstanding any other provision of this Plan, in no case shall any amendment to the Plan, including its termination, result in the payment to the Executive of any portion of the his Deferred Benefit Account before his Retirement Date, except in compliance with the requirements under Section 409A.

GULFMARK OFFSHORE, INC.
By:	/s/ Quintin V. Kneen
Its:	CFO
Date:	12-28-2010
/s/ Bruce A. Streeter
Bruce A. Streeter, Participant
Date:	12-28-10

EX-10.38

Exhibit 10.38

SPLIT-DOLLAR INSURANCE AGREEMENT
(Collateral Assignment)

          THIS AGREEMENT is entered into this 1st day of January, 2000, effective as of January 1, 2000, by and between GM Offshore, Inc., a Delaware corporation, hereinafter call “the Company,” and John E. Leech, hereinafter call “Employee.”

          WHEREAS, Employee, is a valued employee of the Company and the Company wishes to retain him in its employ, and

          WHEREAS, the Company, as an inducement to such continued employment, previously provided the Employee with a split-dollar life insurance plan intended to assist him with his personal life insurance, and,

          WHEREAS, the parties now desire to document and memorialize the parties’ existing split-dollar life insurance plan and incorporate same into this Agreement, which shall supersede the prior agreement of the parties.

          NOW THEREFORE, the Company and Employee agree as follows:

          1. The life insurance policy with which this agreement deals is Policy Number 11-604- 671, having a policy date of November 29, 1990 (hereinafter called the “Policy”) issued by the Northwestern Mutual Life Insurance Company (hereinafter called “Insurer”) on the life of Employee. Employee is and shall remain sole owner of the Policy.

          2. The entire premium on the Policy has been and shall continue to be paid by the Company as it becomes due.

          3. The Policy may, at the Company’s discretion, provide a waiver of premium for disability benefit. If it does so provide, the cost shall be borne by the Company and the Company shall remit that amount to the Insurer when due.

          4. Dividends payable on the Policy shall be used to purchase additional paid-up insurance protection.

          5. To secure the premiums paid by the Employer pursuant to paragraph 2 above (including all premiums on the Policy previously paid and all premiums to be paid pursuant to this Agreement), Employee has executed and filed with the Insurer a collateral assignment of the Policy. Employee agrees that the collateral assignment agreement shall remain in effect during the term of this Agreement, failing which the Company shall have no obligation to make the premium payments on the Policy. The Company’s interest in the Policy shall not exceed the total amount of premiums paid by it on the Policy.

          6. In the event the Policy becomes claim by reason of Employee’s death, the Company shall have an interest in the proceeds of the Policy equal to the total value of the premiums paid on the Policy under paragraph 2 of this Agreement, less any policy indebtedness to the Insurer. The balance, if any, of the proceeds of the Policy shall be paid directly by the Insurer to the beneficiary designated by the Employee.

          7. This Agreement may be terminated, subject to the provisions of paragraphs 8, 9 and 10 below, by Employee, with or without the consent of the Company, by giving notice in writing to the Company. This Agreement may be terminated by the Company, subject to the provisions of paragraphs 8, 9 and 10 below, at any time with the written consent of Employee or, without the consent of Employee, for cause as hereafter defined. Termination shall be effective three (3) days following the date of giving of notice of such termination. For purposes of tills agreement, “cause” means: a breach by Employee of one or more of his duties to the Company, which breach is material to the purposes of business of the Company; gross neglect by Employee of ills duties or obligations to the Company which results in substantial damage to the business or operations of the Company; the intentional infliction by employee of substantial damage to the business or operations of the Company; Employee’s conviction of a federal or state felony offense or ills conviction of any other criminal offense that would impair ills ability to perform ills duties hereunder or would impair the Company; and Employee’s commission of a willful serious act, such as fraud, embezzlement or theft against the Company. For purposes of tills definition of “cause,” the Company shall be deemed to include the Company, its parent and any subsidiary or affiliate of the Company and its parent by which employee may be employed. Notwithstanding anything herein to the contrary, in the event this agreement is terminated by the Company for cause, the termination shall become effective upon the giving of notice of the termination in writing by the Company to Employee specifying the cause on which the termination is based.

          8. In the event of termination of this agreement as provided above, the Company shall no longer be obligated to make payments of the premiums on the policy, effectively immediately upon such termination, and Employee shall have the right and option for a period of 90 days after the date of termination to purchase from the Company all interest of the Company in the Policy upon payment to the Company within that time of an amount equal to the premiums paid by the Company on the Policy under paragraph 2 of this Agreement, less any policy indebtedness to the Insurer or other indebtedness secured by the cash value of the Policy. If Employee exercises such right and option to purchase, the Company shall execute all necessary documents required by the Insurer to effect a release of interest, or absolute assignment of the Policy by the Company to Employee. Notwithstanding anything contained herein to the contrary, except for the price due upon purchase of the Company’s interest by Employee, should Employee so elect, Employee shall not be personally obligated to repay any portion of the premiums on the Policy paid by the Company, but the Company shall retain in full its right to repayment of the premiums paid by it, it being understood and agreed that Company’s repayment shall come solely out of the proceeds of the Policy as herein provided.

          9. If Employee fails to exercise his right and option granted in paragraph 8 and to repay to the Company, to the extent required, the amounts specified in that paragraph within 90 days of the date of termination of the agreement pursuant to the provisions of paragraph 7 above, the

Company shall have the right, at its sole option, to exercise the rights provided in the collateral assignment granted pursuant to paragraph 5 to cause the Policy cash value to be paid to Company or to cancel the policy and receive the cash value thereof, up to the full amount of the premiums paid by the Company pursuant to paragraph 2, less any policy or other indebtedness secured by the cash value of the Policy; Employee shall execute any and all instruments that may be required to allow the Company to exercise those rights.

          10. Any payments under the Policy to the Company in connection with the rights granted to the Company in the collateral assignment referred to in paragraph 5 shall first be made from Policy cash value attributable to the paid-up additional life insurance purchased by the dividends on the Policy. Employee shall have no interest in the paid-up additional life insurance protection except to the extent the death benefit or cash value thereof exceeds the total of the premiums on the Policy paid by the Company.

          11. Employee shall have the right to assign any part or all of employee’s retained interest in the Policy and this Agreement to any person, entity or trust by execution of a written assignment delivered to the Company and to the Insurer.

          12. The Company and Employee can mutually agree to amend this agreement and such amendment shall be in writing and signed by the Company and Employee in order to have legal effect.

          13. This agreement shall bind and inure to the benefit of the Company and its successors and assigns; Employee and his heirs, executors, administrators and assigns; and any beneficiary of the Policy.

          14. In the event of any conflict between a provision of this Agreement and any provision or provisions of any employment agreement or supplemental income plan between the Company and Employee, this agreement shall control, unless the parties expressly declare otherwise in the employment agreement or plan.

          15. Any notice which either party mayor is required to give hereunder shall be given in writing to the other party, each at the address set forth below, or at such other address as may be designated in writing by the party from time to time in a notice given pursuant to this paragraph, by (a) certified or registered mail, return receipt requested, postage prepaid, in which event notice shall be deemed given upon deposit in the United States Mail or (b) in the case of a notice to the Company, hand delivery to the representative of the Company designated below or such other representative as may be designated in writing by the Company from time to time in a notice given pursuant to this paragraph, or, in the case of a notice to Employee, hand delivery to Employee, in either of which cases notice shall be deemed given upon delivery. Rejection or other refusal to accept or the inability to deliver because of a changed address of which no notice was given, shall be nevertheless effective notice for all purposes under this agreement.

(2) The claimant shall have 60 days following his receipt of the denial of the claim to file with the Claims Manager a written request for review of the denial.

For such review, the claimant or his representative may submit pertinent documents and written issues and comments.

(3) The Claims Manager shall decide the issue on review and furnish the claimant with a copy within 60 days of receipt of the claimant’s request for review of his claim. The decision on review shall be in writing and shall include specific reasons for the decision, written in a manner calculated to be understood by the claimant, as well as specific references to the pertinent Plan provisions on which the decision is based. If a copy of the decision is not so furnished to the claimant within such 60 days, the claim shall be deemed denied on review.

(4) Factual determinations and interpretations of the Plan and its terms by the Claims Manager shall be subject to de novo review by a court of competent jurisdiction, in accordance with applicable law, and the Claims Manager shall not be deemed to have discretion in interpreting the Plan.

          18. This Agreement shall be governed by the laws of the United States of American, and to the extent state law is applicable, by the laws of the State of Louisiana.

          IN WITNESS WHEREOF the parties have signed this agreement.

In the presence of

   GM Offshore, Inc.

   /s/ Bruce A. Streeter   Bruce A. Streeter

   /s/ John E. Leech   John E. Leech

EX-10.39

Exhibit 10.39

PARTICIPATION AGREEMENT
SUPPLEMENTAL INCOME PLAN OF
GULFMARK OFFSHORE, INC.

Invitation to Participate in Plan

          As provided in the above referenced Plan dated January 1, 2000 you, John E. Leech, are hereby invited to participate. By accepting the invitation to participate in the Plan, you acknowledge that you have read the Plan, understand its terms, understand that benefits will be paid pursuant to the Plan only under specific circumstances described therein, understand that you are a general creditor of the Company and that you have no interest in specific assets owned by the Company. Capitalized terms used herein shall have the same meaning defined in the Plan.

Entry Date

          Your Entry Date under the Plan will be January 1, 2000 for all purposes.

Establishment of Annual Vesting Percentage

          The Annual Vesting Percentage applicable to your participation in the Plan will be one hundred percent (100%). Assuming that you remain continuously and actively employed as a full time employee of the Company, your Cumulative Vested Percentage will be one hundred percent (100%) and will not change. The credits to our Deferred Benefit Account will be determined by reference to the cash value of your Policy. Specifically, as of any time that the Plan is in effect and you are participating in the Plan, the amount of the credit in your Deferred Benefit Account will be equal to an amount in dollars determined by multiplying the Cumulative Vested percentage as of that date times the then-outstanding Gross Cash Value of the Policy Less the Excess Cash Value of the Policy, in no event less than zero.

Establishment of Normal Retirement Age

          For purposes of the Plan, your “Normal Retirement Age” shall be age 65.

Acceptance of Invitation to Participate

          I hereby accept the invitation of GulfMark Offshore, Inc. to participate in its supplemental Income Plan, on this 1st day of January, 2000.

Address for Notices

          The address which should be used for notices sent to me under the Plan is:

Designation of Beneficiary

          My Beneficiary for purposes of the Plan shall be (attach additional sheets if necessary for multiple beneficiaries):

Name:	John Eugene Leech Family Trust
Address:	107 Winged Foot Dr.
City:	Broussard
State:	LA 70518

          In the event that more than one person is named as Beneficiary, such persons shall share equally in any benefits payable to my Beneficiary under the Plan. If a Beneficiary dies, then the amount that would have been paid to that Beneficiary if living shall be paid in one sum and in equal shares to the children of that Beneficiary who survive, if any, and, if there are not such children, then to the remaining Beneficiary if any, in equal shares if more than one, and if there is no other Beneficiary, then to the estate of the Beneficiary who died.

	/s/ John E. Leech
Witness	John E. Leech

EX-10.40

Exhibit 10.40

AMENDMENT ONE TO PARTICIPATION AGREEMENT

SUPPLEMENTAL INCOME PLAN OF GULFMARK OFFSHORE, INC.

Compliance with IRC § 409A for post-2004 deferrals

          You, John E. Leech, became a participant in the Supplemental Income Plan of Gulfmark Offshore, Inc. (the “Plan”) effective January 1, 2000. Effective generally as of January 1, 2005 for amounts deferred under the Plan after 2004, Section 409A of the Internal Revenue Code of 1986, as amended (“Section 409A”) imposed new requirements on nonqualified deferred compensation. This Amendment One to Participation Agreement (this “Amendment”) conforms your participation in the Plan to the requirements of Section 409A for amounts deferred under the Plan after 2004.

          By executing our signatures below, you and Gulfmark Offshore, Inc. (the “Company”) indicate our agreement that this Amendment shall be binding on us with respect to amounts deferred under the Plan for you after 2004.

          Effective January 1, 2005, for amounts deferred after December 31, 2004, we agree that the Plan is amended as follows with respect to your participation:

          1. The following sentence is added at the end of Section 2.7:

Additionally, for amounts deferred after December 31, 2004 (determined in accordance with the rules under Section 409A of the Internal Revenue Code of 1985, as amended (“Section 409A” of the “Code”)), an Executive shall not be deemed to have undergone a “termination of employment” for purposes of determining his “Retirement Date” unless and until the Executive has undergone a “separation from service” under Section 409A.

          2. The following sentence is added at the end of Section 4.1 of the Plan:

Additionally, the portion of the Executive’s Deferred Benefit Account attributable to amounts deferred after December 31, 2004 shall in no event be later than the later of (a) December 31 of the calendar year in which the Executive’s Retirement Date occurs or (b) the 75th day following the Executive’s Retirement Date; provided, however, that if the Executive is a “specified employee” under Section 409A and his “Retirement Date” occurs because of his separation from service, then the portion of his Deferred Benefit Account attributable to amounts deferred after December 31, 2004 shall not be paid to him until the later of (a) the date six

months after his separation from service or (b) the date 18 months after the date on which the Plan was amended by its Amendment One to Participation Agreement.

          3. A new Section 7.3 is added to the Plan, to read as follows:

7.3 Notwithstanding any other provision of this Plan, in no case shall any amendment to the Plan, including its termination, result in the payment to the Executive of any portion of the his Deferred Benefit Account before his Retirement Date, except in compliance with the requirements under Section 409A.

GULFMARK OFFSHORE, INC.
By:	/s/ Quintin V. Kneen
Its:	EVP & CFO
Date:	12-29-10
/s/ John E. Leech
John E. Leech, Participant
Date:	12-29-10

EX-12.1

Exhibit 12.1     

Ratio of Earnings to Fixed Charges

(Dollars in thousands)

	Year Ended December 31,
	2006			2007			2008			2009			2010
Income (Loss) from Continuing Operations	$	89,729		$	98,975		$	183,784		$	50,583		$	(34,745	)
Plus: Income Taxes		3,052			30,220			11,743			(2,087	)		(12,701	)
Fixed Charges		18,272			14,424			23,412			24,560			23,833
Less: Capitalized Interest		(2,400	)		(6,200	)		(8,516	)		(3,612	)		(1,421	)
Earnings Before Fixed Charges		108,653			137,419			210,423			69,444			(25,034	)
Fixed Charges:
Interest Expense	$	15,648		$	7,923		$	14,291		$	20,281		$	21,693
Capitalized Interest		2,400			6,200			8,516			3,612			1,421
Estimated Portion of Rental Expense Equivalent to Interest		224			301			605			667			719
Total Fixed Charges		18,272			14,424			23,412			24,560			23,833
Ratio of Earnings to Fixed Charges		5.95			9.53			8.99			2.83		NA

NA – The ratio is less than 1.0. A deficiency of $48.9 million exists for the year ended December 31, 2010. The calculation of earnings includes $60.0 million of non-cash depreciation and amortization expense and $97.7 million of impairment.

EX-21.1

Exhibit 21.1

SUBSIDIARIES OF THE COMPANY

SUBSIDIARIES OF GULFMARK OFFSHORE, INC.

Name of Subsidiary or Organization	State or Country of Incorporation
Gulf Offshore N.S. Limited	United Kingdom
GulfMark North Sea Limited	United Kingdom
S.E.A. Personnel Services Limited	United Kingdom
Sea Truck (UK) Ltd.	United Kingdom
Gulf Offshore Guernsey, Ltd.	Guernsey
Gulf Offshore International Guernsey Limited	Guernsey
Gulf Marine Far East PTE, Ltd.	Singapore
Gulf Offshore Marine International, S. de R.L.	Panama
Gulf Marine (Servicos Maritimos) do Brasil Limitada	Brazil
Semaring Logistics (M) Sdn. Bhd.	Malaysia
Gulf Marine Malaysia Inc.	Malaysia
Chalvoyage (M) Sdn. Bhd.	Malaysia
GulfMark Servicios de Mexico, S. de R.L. de C.V.	Mexico
GulfMark de Mexico, S. de R.L. de C.V.	Mexico
Gulf Channel Offshore Servicos LDA	Angola
GulfMark Norge AS	Norway
Gulf Offshore Norge AS	Norway
GulfMark Rederi AS	Norway
Gulf Offshore Marine International B.V.	Netherlands
GulfMark Oceans, L.P.	Cayman Islands
GM Offshore, Inc.	Delaware
GulfMark Capital, LLC	Delaware
GulfMark Management, Inc.	Delaware
GulfMark Resources, LLC	Delaware
GulfMark Shipping, LLC	Delaware
GulfMark Americas, Inc.	Delaware

82

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement (Form S-3 No. 333-153459) of GulfMark Offshore, Inc. and in the related Prospectus of our report dated February 24, 2011, with respect to the consolidated financial statements of GulfMark Offshore, Inc. and subsidiaries included in this Annual Report (Form 10-K) for the year ended December 31, 2010.

We hereby consent to the incorporation by reference in the Registration Statements (Form S-8) pertaining to the Amended and Restated 1993 Non-Employee Director Stock Option Plan and Non-Employee Director Stock Options (No. 333-33719), the GulfMark Offshore, Inc. Employee Stock Purchase Plan (No. 333-84110), the GulfMark Offshore, Inc. 1997 Incentive Equity Plan (Nos. 333-57294 and 333-144183), the GulfMark Offshore, Inc. 2005 Non-Employee Director Share Incentive Plan (No. 333-143258), and the GulfMark Offshore, Inc. 2010 Omnibus Equity Incentive Plan (No. 333-167497) of our report dated February 24, 2011, with respect to the consolidated financial statements of GulfMark Offshore, Inc. and subsidiaries included in this Annual Report (Form 10-K) for the year ended December 31, 2010.

UHY LLP
/s/ UHY LLP

Houston, Texas
February 24, 2011

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO EXCHANGE ACT RULES 13a-14(a),
AS ADOPTED PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Bruce A. Streeter, certify that:

1.   I have reviewed this annual report on Form 10-K for the year ended December 31, 2010 of GulfMark Offshore, Inc.;

2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.   The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.   The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 24, 2011

By:	/s/ Bruce A. Streeter
	Bruce A. Streeter
	President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO EXCHANGE ACT RULES 13a-14(a),
AS ADOPTED PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Quintin V. Kneen, certify that:

1.  I have reviewed this annual report on Form 10-K for the year ended December 31, 2010 of GulfMark Offshore, Inc.;

2.  Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.  Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.  The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.  The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 24, 2011

By:	/s/ Quintin V. Kneen
	Quintin V. Kneen
	Executive Vice President   and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO EXCHANGE ACT RULES 13a-14(a),
AS ADOPTED PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of GulfMark Offshore, Inc. (the “Company”) on Form 10-K for the year ended December 31, 2010, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Bruce A. Streeter, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge:

(1)     The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)     The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 24, 2011

By:	/s/ Bruce A. Streeter
	Bruce A. Streeter
	President and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO EXCHANGE ACT RULES 13a-14(a),
AS ADOPTED PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of GulfMark Offshore, Inc. (the “Company”) on Form 10-K for the year ended December 31, 2010, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Quintin V. Kneen, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge:

(1)     The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)     The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 24, 2011

By:	/s/ Quintin V. Kneen
	Quintin V. Kneen
	Executive Vice President   and Chief Financial Officer