Edgar Filing: GULFMARK OFFSHORE INC

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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, 2008


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

Commission file number 000-22853

GulfMark Offshore, Inc.

(Exact name of Registrant as specified in its charter)


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

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

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

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


Common Stock, $0.01 Par Value (Title of each class)		New York Stock Exchange (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 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 þ.

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

Large accelerated filer 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, 2008, the last business day of the registrant’s most recently completed second fiscal quarter was $1,349,853,670, calculated by reference to the closing price of $58.18 for the registrant’s common stock on the New York Stock Exchange on that date.

Number of shares of common stock outstanding as of February 26, 2009: 25,380,589

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 71

TABLE OF CONTENTS


		Page
PART I
Items 1 and 2.	Business and Properties		3
	General Business		3
	The Company		3
	Worldwide Fleet		4
	Operating Segments		10
	Other		14
Item 1A.	Risk Factors		16
Item 1B.	Unresolved Staff Comments		21
Item 3.	Legal Proceedings		21
Item 4.	Submission of Matters to a Vote of Security Holders		22
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		22
Item 6.	Selected Consolidated Financial Data		24
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		26
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		40
Item 8.	Consolidated Financial Statements and Supplementary Data		42
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		70
Item 9A.	Controls and Procedures		70
Item 9B.	Other Information		70
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		71
EX-3.1
EX-12.1
EX-21.1
EX-23.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2

PART I

ITEMS 1. and 2. Business and Properties

GENERAL BUSINESS

GulfMark Offshore, Inc. is a Delaware corporation incorporated in 1996 that, through itself and its subsidiaries, provides offshore marine services primarily to companies involved in offshore exploration and production of oil and natural gas. Unless otherwise indicated, references to “we”, “us”, “our” and the “Company” refer to GulfMark Offshore, Inc. and its subsidiaries. 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 the Americas. We also contract vessels into other regions to meet our customers’ requirements.

We have 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 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 Statement of Financial Accounting Standards (“SFAS”) No. 131, “Disclosures about Segments of an Enterprise and Related Information”. For financial information about our operating segments and geographic areas, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Segment Results” included in Part II, Item 7, and Note 13 to our Consolidated Financial Statements included in Part II, Item 8.

Our principal executive offices are located at 10111 Richmond Avenue, Suite 340, Houston, Texas 77042, and our telephone number at that address is (713) 963-9522. We file annual, quarterly, and current reports, proxy statements and other information with the Securities and Exchange Commission, or SEC. This annual report on Form 10-K for the year ended December 31, 2008 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.

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 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, offshore Trinidad, the Persian Gulf and the Mediterranean Sea. The industry is relatively fragmented, with more than 20 major participants and numerous small regional competitors. We currently operate a fleet of 95 offshore support vessels in the following regions: 43 vessels in the North Sea, 13 vessels offshore Southeast Asia, and 39 vessels in the Americas. Our fleet is one of the world’s youngest, largest and most geographically balanced, high specification offshore support vessel fleets and our owned vessels (excluding specialty 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. Additionally, oil and natural gas prices are affected by a host of geopolitical and economic forces, including the fundamental principles of supply and demand. Although commodity prices have remained high by historical standards over the last several years, the forecasted near-term worldwide demand for energy decreased during the last several months of 2008. As a result of this decrease, energy related commodity prices decreased sharply. Although we did not experience any significant adverse impact during 2008 that can be directly attributable to these conditions, we are evaluating the potential impact of this anticipated decline in activity to our operations and to our financial condition. Nothing we have encountered thus far in our ongoing evaluation of current and anticipated near-term market conditions has caused us to change our existing capital expenditure plans or change our assessment of our financial condition, but we continue to evaluate market conditions and those plans and assessments are subject to change.

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. These restrictions on vessel movement in effect separate various regions into distinct markets.

WORLDWIDE FLEET

The size of our fleet has increased by 34 since December 31, 2007 to 95 vessels, principally as a result of the addition of 22 vessels from the acquisition of Rigdon Marine Corporation and Rigdon Marine Holdings, L.L.C. (collectively, “Rigdon”) on July 1, 2008 (the “Rigdon Acquisition”), but also due to the addition of 10 managed vessels and our fleet upgrade and modernization initiative. That initiative resulted in the addition of seven new build vessels to the fleet, enhancing our capability to service customers in more demanding environments around the world. We also sold five of our older, smaller vessels whose age averaged over 25 years to buyers generally outside of our normal market.

We also 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 fleet changes since December 31, 2007:


	Owned Vessels			Managed Vessels		Total Fleet
December 31, 2007		47			14		61

New Build Program		6			—		6
Vessel Additions		22			10		32
Vessel Sales		(5	)		—		(5	)

December 31, 2008		70			24		94

New Build Program		1			—		1

February 26, 2009		71			24		95

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 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’. Large PSVs (LgPSVs) range up to 300’ 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’ in length, and are designed for speed and to transport personnel. Newer crewboat designs are generally larger, 130’ to 185’ 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 exploitation occurs. These vessels typically remain on station to provide a safety backup to offshore rigs and production facilities and carry special equipment to rescue personnel. They are equipped to provide first aid, shelter and, in some cases, function as support vessels.

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

	•		Utility Vessels are typically 90’ to 150’ in length and are used to provide limited crew transportation, some transportation of oilfield support equipment and, in some locations, standby functions. We do not currently operate any vessels in this category.

The following table sets forth 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		Standby		Total


North Sea (N. Sea)		3		—		20		—		—		—		1		2		26
Southeast Asia (SEA)		4		4		2		1		—		—		—		—		11
Americas		4		—		3		20		4		2		1		0		34

		11		4		25		21		2		4		2		2		71

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

The following table illustrates the expected delivery timeline of our current commitments for the 11 new build vessels currently under construction:


Vessels Currently Under Construction
			Expected		Length						Expected
Vessel	Region	Type		Delivery	(feet)		BHP		DWT⁽²⁾		Cost

											(millions)
Aker 726	N. Sea	PSV		Q4 2009		284		10,600		4,850	$	45.4
Aker 727	N. Sea	PSV		Q2 2010		284		10,600		4,850	$	45.4
Sea Cherokee	SEA	AHTS		Q1 2009		250		10,700		2,700	$	24.5
Sea Comanche	SEA	AHTS		Q2 2009		250		10,700		2,700	$	24.4
Blacktip	Americas	FSV		Q2 2009		181		7,200		543	$	9.2	⁽¹⁾
Tiger	Americas	FSV		Q3 2009		181		7,200		543	$	9.2	⁽¹⁾
Bender 1	Americas	PSV		Q1 2010		245		5,380		3,000	$	25.5
Bender 2	Americas	PSV		Q2 2010		245		5,380		3,000	$	25.5
Bender 3	Americas	PSV		Q3 2010		245		5,380		3,000	$	25.5
Remontowa 20	TBD	AHTS		Q2 2010		230		10,000		2,150	$	26.9
Remontowa 21	TBD	AHTS		Q3 2010		230		10,000		2,150	$	26.9


(1)		The estimated cost does not represent the actual construction costs, but includes our purchase price allocation plus all construction costs payable after the closing of the Rigdon Acquisition.

(2)		Deadweight tons

Vessel Construction and Acquisitions

During the period 2000-2006, we added 15 new vessels to the fleet as part of our long-range growth strategy — nine in the North Sea, three in the Americas and three in Southeast Asia. In continuation of our growth strategy, we committed in 2005 to build six new 10,600 BHP AHTS vessels for a total cost of approximately $140 million. The vessels are of a new design we developed in conjunction with the builder that incorporates Dynamic Positioning 2 (DP-2) certification and Fire Fighting Class 1 (FiFi-1), and a relatively large carrying capacity of approximately 2,700 tons. Keppel Singmarine Pte, Ltd. is building these vessels primarily to meet the growing demand of our customer base offshore Southeast Asia. Four of these vessels have been delivered to date beginning with the Sea Cheyenne in October 2007, the Sea Apache in January 2008, the Sea Kiowa in March 2008, and the Sea Choctaw in July 2008. The final two vessels in this group are scheduled for delivery in the first half of 2009. As a complement to these six new vessels, during 2006 we took delivery of two new construction vessels, the Sea Guardian and the Sea Sovereign. Also during 2006, we exercised a right of first refusal granted under the Sea Sovereign purchase contract for an additional vessel, the Sea Supporter, which was delivered in October 2007.

We also agreed to participate in a joint venture with Aker Yards ASA for the construction of two large PSVs, one of which, the Highland Prestige, was delivered early in the second quarter of 2007 and immediately went to work in the North Sea region on a term contract. The second vessel, the North Promise, was delivered at the end of the third quarter 2007. At the end of 2005, we purchased 100% of the Highland Prestige from the joint venture, and during the second quarter of 2007 we purchased 100% of the North Promise. Additionally, during the first quarter of 2007, we committed to build two new PSVs, similar to the design of the North Promise and Highland Prestige but with a double hull and various environmental enhancements. Aker Yards ASA will build these vessels at a combined cost of approximately $91 million, with estimated delivery dates in late 2009 and the first half of 2010.

In the third quarter of 2007, we entered into agreements with two shipyards to construct five additional vessels. Bender Shipbuilding & Repair Co., Inc., 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. The estimated total cost of the five vessels is $130 million. These vessels are scheduled to be delivered throughout 2010.

In connection with the Rigdon Acquisition in 2008, we acquired construction contracts for six vessels: one PSV; three FSVs; and two crew boats. The Knockout PSV, Albacore crew boat and Mako FSV delivered in 2008 and the Swordfish crew boat delivered in early 2009. The last 2 FSVs are scheduled for delivery in the second quarter of 2009. The total of the remaining construction payments on the vessels in the Rigdon new build program that have yet to be delivered is approximately $5.0 million.

Interest is capitalized in connection with the construction of vessels. During 2008 and 2007, $8.5 million and $6.2 million, respectively, was capitalized.


Vessel Additions Since December 31, 2007
			Year		Length						Month
Vessel	Region	Type	Built		(feet)		BHP		DWT		Delivered

Sea Apache	SEA	AHTS		2008		250		10,700		2,700	Jan-08
Sea Kiowa	SEA	AHTS		2008		250		10,700		2,700	Mar-08
Sea Choctaw	SEA	AHTS		2008		250		10,700		2,700	Jul-08
Knockout	Americas	PSV		2008		190		3,894		1,860	Aug-08
Albacore	Americas	Crew		2008		165		7,200		331	Aug-08
Mako	Americas	FSV		2008		181		7,200		543	Oct-08
Swordfish	Americas	Crew		2009		176		7,200		314	Feb-09

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. In 2005, we entered into a forward contract related to the construction of the Highland Prestige. The contract expired on March 14, 2007 and upon settlement, the positive foreign currency change of $0.9 million resulting from the change in the fair value of the hedge was reflected as a reduction to the overall construction cost of the vessel. During 2007, we entered into a series of forward currency contracts relative to future milestone payments for the construction of the six Keppel vessels and the two Aker Yards vessels. As of December 31, 2008, the positive foreign currency change on the remaining forward contracts was $7.8 million. The forward contracts are designated as fair value hedges and deemed highly effective with the foreign currency change reflected in the overall construction cost of the vessels.

Vessel Divestitures

Our strategy is to sell older vessels in our fleet when the appropriate opportunity arises. Consistent with this strategy, in January 2007, we sold the North Prince, one of our oldest North Sea based vessels. The proceeds from this sale were $5.7 million, and we recognized a gain on the sale of $5.0 million. During the course of 2007, we also completed the sale of three small 1981-built AHTS vessels based in Southeast Asia for net proceeds totaling $10.1 million, recognizing a gain of $7.2 million. In the second quarter of 2008, we completed the sale of two pre-1985 AHTS vessels, the Sea Diligent and North Crusader, generating sales proceeds of $21.0 million and a gain of $16.4 million. Additionally, in the third quarter of 2008, we sold the Sem Valiant and the Sea Eagle, each older Southeast Asia based AHTS vessels, for proceeds of $2.9 million recognizing a gain of $2.3 million. In the fourth quarter of 2008 the North Fortune, a PSV built in 1983, was sold for $19.0 million, generating a gain of $16.1 million.

Vessels Sold Since December 31, 2007

Year

Length

Month

Vessel

Region

Type

Built

(feet)

BHP

DWT

Sold

Sea Diligent

SEA

SmAHTS

1981

192

4,610

1,219

Jun-08

North Crusader

N. Sea

AHTS

1984

236

12,000

2,064

Jun-08

Sem Valiant

SEA

SmAHTS

1981

191

3,900

1,220

Jul-08

Sea Eagle

SEA

SmAHTS

1976

185

3,850

1,215

Sep-08

North Fortune

N. Sea

LgPSV

1983

264

6,120

3,366

Oct-08

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. Our drydocking expenditures for 2008 were $11 million. We anticipate approximately $19 million in drydocking expenditures in 2009.

Vessel Listing

Currently, we operate a fleet of 95 vessels. Of these vessels, 71 are owned by us (see table below) and 24 are under management for other owners.


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		10,000		4,850	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
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		10,000		4,850	Norway
North Stream	N. Sea	LgPSV		1998		276		9,600		4,585	Norway
North Traveller	N. Sea	LgPSV		1998		221		5,450		3,115	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
Highland Trader(e)	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
Clwyd Supporter	N. Sea	SpV		1984		266		10,700		1,350	UK
Highland Spirit	N. Sea	SpV		1998		202		6,000		1,800	UK
Highland Sprite	N. Sea	SpV		1986		194		3,590		1,442	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 Searcher	SEA	SmAHTS		1976		185		3,850		1,215	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		2,500	Panama


Owned Vessel Fleet
			Year		Length
Vessel	Region	Type (a)	Built		(feet)		BHP (b)		DWT (c)		Flag


Austral Abrolhos(d)	Americas	AHTS		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		2,500	Panama
Seapower	Americas	SpV		1974		222		7,040		1,205	Panama
Coloso	Americas	AHTS		2005		199		5,916		1,674	Mexico
Titan	Americas	AHTS		2005		199		5,916		1,674	Mexico
Orleans(f)	Americas	PSV		2004		210		6,342		2,586	USA
Bourbon(f)	Americas	PSV		2004		210		6,342		2,586	USA
Royal(f)	Americas	PSV		2004		210		6,342		2,586	USA
Chartres(f)	Americas	PSV		2004		210		6,342		2,586	USA
Iberville(f)	Americas	PSV		2004		210		6,342		2,586	USA
Bienville(f)	Americas	PSV		2005		210		6,342		2,586	USA
Conti(f)	Americas	PSV		2005		210		6,342		2,586	USA
St. Luis(f)	Americas	PSV		2005		210		6,342		2,586	USA
Toulouse(f)	Americas	PSV		2005		210		6,342		2,586	USA
Esplanade(f)	Americas	PSV		2005		210		6,342		2,586	USA
First and Ten(f)	Americas	PSV		2007		190		3,894		1,860	USA
Double Eagle(f)	Americas	PSV		2007		190		3,894		1,860	USA
Triple Play(f)	Americas	PSV		2007		190		3,894		1,860	USA
Grand Slam(f)	Americas	PSV		2007		190		3,894		1,860	USA
Slam Dunk(f)	Americas	PSV		2008		190		3,894		1,860	USA
Touchdown(f)	Americas	PSV		2008		190		3,894		1,860	USA
Hat Trick(f)	Americas	PSV		2008		190		3,894		1,860	USA
Slap Shot(f)	Americas	PSV		2008		190		3,894		1,860	USA
Homerun(f)	Americas	PSV		2008		190		3,894		1,860	USA
Knockout(g)	Americas	PSV		2008		190		3,894		1,860	USA
Sailfish(f)	Americas	Crew		2008		176		7,200		314	USA
Hammerhead(f)	Americas	FSV		2008		181		7,200		543	USA
Bluefin(f)	Americas	Crew		2008		165		7,200		314	USA
Albacore(g)	Americas	Crew		2008		165		7,200		314	USA
Mako(g)	Americas	FSV		2008		181		7,200		543	USA
Swordfish(g)	Americas	Crew		2009		176		7,200		314	USA


(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 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 May 2, 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.

		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 April 1, 2010; October 1, 2012; April 1, 2015; and October 1, 2016 provided 120 days notice has been given by the charterer.

(e)		The Highland Trader was formerly named Safe Truck.

(f)		Denotes the 22 completed vessels acquired as part of the Rigdon Acquisition

(g)		Denotes the four vessels from the Rigdon new build program that have been delivered subsequent to the closing of the Rigdon Acquisition.

The table above does not include the 24 managed vessels.

OPERATING SEGMENTS

The North Sea Operating Segment


	Owned			Managed		Total
	Vessels			Vessels		Fleet
December 31, 2007		29			14		43

New Build Program		—			—		—
Vessel Additions		—			3		3
Vessel Sales		(2	)		—		(2	)
Intersegment Transfers		(1	)		—		(1	)

December 31, 2008		26			17		43

Market and Segment Overview

We define the North Sea market as offshore Norway, Denmark, the Netherlands, Germany, Great Britain and Ireland, the Norwegian Sea and the area West of Shetlands. Historically, this has been the most demanding of all exploration frontiers due to harsh weather, erratic sea conditions, significant water depth and long sailing distances. Exploration and production operators in the North Sea market have typically been large and well-capitalized entities (such as major oil and natural gas companies and state-owned oil and natural gas companies) in large part because of the significant financial commitment required in this market. A number of independent operators have established operating bases in the region in the last several years, 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 and field 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. In 2008, we transferred the Highland Piper to the Americas region to work in Brazil.

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.

The North Sea market was a very stable market from the early 1990s through late 2001 and during that time the market was dominated by major oil companies. Beginning in late 2000, as commodity prices and increased drilling activity resulted in improved vessel utilization and day rates, the industry began a capital expansion cycle that resulted in a significant increase to the number of new vessels scheduled to enter the market. However, exploration and development activity in the region experienced a reduction beginning in 2001 and, because the supply of vessels increased as a result of the expansion cycle, day rates and utilization decreased significantly in 2003 and most of 2004.

There was also 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. Since mid 2008, the outlook for the global economy has become negative and worldwide energy demand forecasts have been reduced. These factors did not result in a noticeable decrease in activity during 2008 but could have a negative impact on future demand for vessel services.

The Southeast Asia Operating Segment


	Owned			Managed		Total
	Vessels			Vessels		Fleet
December 31, 2007		12			—		12

New Build Program		3			—		3
Vessel Additions		—			2		2
Vessel Sales		(3	)		—		(3	)
Intersegment Transfers		(1	)		—		(1	)

December 31, 2008		11			2		13

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. This market includes offshore Brunei, Cambodia, Indonesia, Malaysia, Myanmar, the Philippines, Singapore, Thailand and Vietnam. The design requirements for vessels in this market are generally similar to the requirements of the shallow water 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 base in Singapore.

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.

The expansion of our operations in Southeast Asia, along with evolving tax laws, have caused us to reevaluate our corporate structure in the region. In 2008 we implemented a strategic reorganization of our Southeast Asia operations in order to maximize our benefits, including those available under the various tax laws in the jurisdictions in which we operate. During the third quarter of 2008, the Sea Kiowa was transferred to the Americas region to work in Brazil.

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 and long distances between supply centers in Southeast Asia have allowed for a variety of vessel designs to compete in this market, each suited for a particular set of operating parameters. Vessels designed for the Gulf of Mexico and other areas where effectively 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 a North Sea vessel into this region during 2002, another one during 2004 and a third during 2007 to meet the changing market in the region, as these North Sea vessels are larger than the typical vessels of the region. During the last five years we sold 10 of our older vessels serving Southeast Asia and have taken delivery of eight new vessels. We have two additional vessels being built in this region that are scheduled to be delivered in 2009.

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 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.

The Americas Operating Segment


	Owned		Managed		Total
	Vessels		Vessels		Fleet
December 31, 2007		6		—		6

New Build Program		3		—		3
Vessel Additions		22		5		27
Vessel Sales		—		—		—
Intersegment Transfers		2		—		2

December 31, 2008		33		5		38

New Build Program		1		—		1

February 26, 2009		34		5		39

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. Our Americas based fleet now includes 39 vessels. The increase in vessels in this market since December 31, 2007, is due in large part to the Rigdon Acquisition, in which we acquired 22 U.S. flagged vessels and one managed vessel, a substantial majority of which operate in the deepwater Gulf of Mexico. In addition to the Rigdon Acquisition, we transferred to Brazil one vessel from the North Sea and one vessel from Southeast Asia and entered into a vessel management agreement in the second quarter of 2008 to manage four vessels in the Gulf of Mexico. These additional vessels have allowed us to establish and organize a significant position in the Gulf of Mexico market with a focus on the growing deepwater segment. All vessels based in the Americas are supported from our onshore bases in Covington, St. Rose and Youngsville, Louisiana, MaCae, Brazil and Paraiso, Mexico.

Drilling in the Gulf of Mexico can be divided into two sectors: the shallow waters of the continental shelf and the deepwater areas of the Gulf of Mexico. 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 is increasing and has traditionally been less volatile than those of the continental shelf, the majority of drilling in the Gulf of Mexico is still on the continental shelf making the Gulf of Mexico, as a whole, relatively volatile. The Gulf of Mexico is a highly competitive environment, and variations in the prices of crude oil and natural gas have led to substantial shifts in demand and vessel pricing. We presently expect our activity in the Gulf of Mexico to shift towards deepwater drilling and other aspects of the Gulf of Mexico market where modern DP-2 vessels are required.

The Jones Act generally 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 “Other—Government and Environmental Regulation— Government Regulations” in our “Business and Properties” included in this Part I Items 1 and 2.

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, to some extent, 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. In 2008, we transferred the Highland Piper from the North Sea, and the Sea Kiowa from Southeast Asia to the Americas region to work in Brazil under term contracts. In addition, Petrobras, the Brazilian national oil company, continues to expand operations and has recently announced the discovery of several very large reservoirs. This expansion has created, and could continue to create, additional demand for offshore support vessels. We have been active in bidding Brazil’s new offshore support vessel opportunities.

Market Development

Currently, we operate six vessels in Brazil, including the Brazilian built vessel Austral Abrolhos. We have three PSVs, two AHTSs and an SPV operating in the region under contracts of varying lengths, the earliest of which began in 1990 and the most recent on a multi-year contract in the third quarter of 2008.

Since 2005, we have operated two AHTS vessels offshore Mexico on five-year primary-term contracts with Pemex, which contracts expire in February 2010. 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.

In Trinidad, we are supporting a significant drilling campaign for an international operator with three PSVs. Given recent licensing and exploration activity in nearby locations, including Suriname and Guyana, we could see vessel support requirements operating from a Trinidad base for the foreseeable future.

Seasonality

Operations in the North Sea are generally at their highest levels during the months from April to August and at their lowest levels during December to 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 between June and 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, 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, 2008 and February 20, 2009:


	As of February 20, 2009						As of February 23, 2008
	2009			2010			2008			2009
	Vessel Days			Vessel Days			Vessel Days			Vessel Days
North Sea-Based Fleet		71.0	%		37.1	%		85.6	%		44.9	%
Southeast Asia-Based Fleet		67.3	%		40.5	%		69.9	%		50.0	%
Americas-Based Fleet		60.2	%		28.3	%		91.1	%		84.5	%

Overall Fleet		65.3	%		33.5	%		82.6	%		52.7	%

International vessel contracts are typically longer in duration and are generally only cancelable for non-performance. Domestic vessel contracts are typically shorter in duration and generally provide for other additional cancellation provisions, including termination for convenience. The decrease in overall contract cover is the result of more relatively short-duration contracts in the North Sea compared to the prior year and the significant increase in vessels in the U.S. Gulf of Mexico market resulting from the Rigdon Acquisition. The U.S. Gulf of Mexico market typically has contracts of shorter duration than those in the North Sea or Southeast Asia.

Other Markets

We have contracted our vessels outside of our operating segment regions principally on short-term charters in offshore Africa, India and the Mediterranean region. We currently have two of our owned vessels supporting operations offshore India, and two owned and three managed vessels operating offshore West Africa. We also recently completed a multi-vessel, term contract in the Mediterranean. 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 these vessels are generally managed through offices in the North Sea region.

OTHER

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. During 2006, under multiple contracts in the ordinary course of business, one customer, Royal Dutch Shell, accounted for 10.4% of total consolidated revenue. No single customer accounted for 10% or more of our total consolidated revenue for 2007 or 2008.

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 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 24 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 15 competitors in the North Sea market and numerous small and large competitors in the Southeast Asia and Americas markets. We compete principally on the basis of suitability of equipment, price and service. 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. In addition, some of our competitors have significantly greater financial resources than we do.

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.

Government Regulations

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 one of the vessels in our fleet were purchased or requisitioned by the federal government under this law, we would be entitled to be paid the fair market value of the vessel in the case of a purchase or, in the case of a requisition, the fair market value of charter hire. However, we would not be entitled to be compensated for any consequential damages we suffer as a result of the requisition or purchase of any of our vessels.

Under Section 27 of the Merchant Marine Act of 1920, also known as the Jones Act, the privilege of transporting merchandise or passengers for hire in the coastwise trade in U.S. territorial waters is restricted to only those 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,

	•		each of the president or other chief executive officer and the chairman of the board of directors is a U.S. citizen,

	•		no 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 75% of the interest in such corporation is owned by U.S. citizens.

If we should fail to comply with such requirements, our vessels would lose their eligibility to engage in coastwise trade within U.S. territorial waters during the period of such non-compliance. Currently, we meet the requirements to engage in coastwise trade, and are reviewing and evaluating what additional actions, if any, may be implemented to insure compliance with the Jones Act.

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 which became effective on July 1, 2002. IMO has also adopted the International Ship & Port Facility Security Code, or ISPS Code, which became effective on July 1, 2004. 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 on either our vessels or our shore-base facility.

The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, also known as “CERCLA” or “Superfund,” and similar laws, impose liability for releases of hazardous substances into the environment. CERCLA currently exempts crude oil from the definition of hazardous substances for purposes of the statute, but our operations may involve the use or handling of other materials that may be classified as hazardous substances. CERCLA assigns strict liability to each responsible party for all response costs, as well as natural resource damages and thus we could be held liable for releases of hazardous substances that resulted from operations by third parties not under our control or for releases associated with practices performed by us or others that were standard in the industry at the time.

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

We believe that we are in compliance with the laws and regulations to which we are subject. 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. However, 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 increases our costs of doing business. Additionally, these laws change frequently. Therefore, we are unable to predict the future costs or other future impact of Jones Act, environmental, health, safety and vessel and port security laws on our operations. 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.

Employees

At December 31, 2008, we had approximately 1,800 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 930 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 union. 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 located in Houston, Texas. For local operations, we have offices and warehouse facilities in: Singapore; Aberdeen, Scotland; Sandnes, Norway; Macae, Brazil; Paraiso, Mexico; and St. Rose, and Youngsville, Louisiana. In March 2008, we relocated our offices in Aberdeen, Scotland from an owned office facility to a leased facility. The previously owned facility is in the process of being leased or sold. All of our other facilities are leased. 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 generate or otherwise 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 has occurred since late 2008, however, would likely result in reduced exploration and development of offshore areas and a decline in the demand for our offshore marine services. Any such decrease in activity is likely to reduce our day rates and our utilization rates and, therefore, could have a material adverse effect on our financial condition and results of operations.

An increase in the supply of offshore 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; or

	•		converting vessels formerly dedicated to services other than offshore marine services.

In the last ten years, construction of vessels of the types we operate has significantly increased. The addition of new capacity of various types to the worldwide offshore marine fleet is 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 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 are registered. These conventions, laws and regulations govern ownership and operation of vessels; oil spills and other matters of environmental protection; worker health, safety and training; construction and operation of vessels; and vessel and port security. 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 foreign equivalents, and to regulation by independent or industry organizations such as the International Maritime Organization or 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.

Environmental Regulations

Our operations are also subject to federal, state, local and international laws and regulations that control the discharge of pollutants into the environment or otherwise relate to environmental protection. Compliance with such laws, regulations and standards may require installation of costly equipment, increased manning, or operational changes. Violation of these laws may result in civil and criminal penalties, fines, injunctions, imposition of remedial obligations, the suspension or termination of our operations, or other sanctions.

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. Environmental laws and regulations may change in ways that substantially increase costs, impose additional requirements or restrictions which could adversely affect our financial condition and results of operations.

Merchant Marine Act of 1936

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. 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.

Jones Act

We are subject to the Merchant Marine Act of 1920, as amended (the “Jones Act”), which requires that vessels carrying passengers or cargo between U.S. ports, which is known as 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 in U.S. territorial waters during the period in which we were not in compliance, which would adversely affect our operating results. Currently, we meet the requirements to engage in coastwise trade, but there can be no assurance that we will always be in compliance with the Jones Act. In December 2008, our Board of Directors passed a resolution authorizing management to include as a proposal at the 2009 Annual Meeting of Stockholders amendments to our Certificate of Incorporation that should assist and complement our Jones Act citizenship compliance.

The Jones Act’s provisions restricting coastwise trade to vessels controlled by U.S. citizens may have recently been 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 and on our financial condition and results of operations.

Substantial Cost of Compliance

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 and terrorism risks.

These risks present a threat to the safety of 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 2009-2010, and have negotiated terms for renewal in 2010-2011 for our primary coverage. 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.

A substantial portion of our revenue is derived from our international operations and those operations are subject to 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.

Changes in tax legislation in countries in which we operate could result in, and increased operations in the United States are likely to result in, higher tax expense or a higher effective tax rate on our worldwide earnings.

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 the interpretations thereof 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 put in place from January 2007 forward, subjecting us to ordinary corporate tax on accumulated untaxed shipping profits as of December 31, 2006. 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 operations in the United States increased with the Rigdon Acquisition in July 2008, and we have experienced an increase in our tax expense and effective tax rate. Additionally, our tax returns are subject to examination and review by the tax authorities in the jurisdictions in which we operate.

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

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

value of the U.S. Dollar, such as has occurred since late 2008, 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 results of operations. Significant delays could also result in penalties under, or the termination of, most of the long-term contracts under which we operate our vessels. The demand for vessels currently under construction 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 our new construction and the repair of our vessels.

Our current new vessel construction program, 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 million to $100 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. Additionally, the inability to obtain sufficient amount of financing or the inability of one or more of the bank group members to provide committed funding could adversely effect our ability to complete our new vessel construction program. To-date, we have been able to obtain adequate bank group financing to fund all of our commitments. See “Long Term Debt” on page 37 and “Liquidity and Capital Resources” on page 36.

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.

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.

We are subject to war, sabotage and terrorism risk.

War, sabotage, 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 terror. War or risk of war may also have an adverse effect on the economy. Insurance coverage has been difficult to obtain in areas of 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 or terrorism could also affect our ability to raise capital and could also adversely affect the oil, gas and power industries and restrict their future growth.

We depend on key personnel.

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.

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 recent volatility in oil and natural gas prices and substantial uncertainty in the capital markets due to the deteriorating 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 deteriorating 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 downturn. These conditions could have a material adverse effect on our business.

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 our operations. We cannot predict whether any such claims may be made in the future.

ITEM 4. Submission of Matters to a Vote of Security Holders

NONE

PART II

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

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


	2008				2007
	High		Low		High		Low
Quarter ended March 31,	$	56.38	$	33.30	$	44.64	$	31.80
Quarter ended June 30,	$	70.98	$	53.06	$	54.65	$	43.51
Quarter ended September 30,	$	58.90	$	41.71	$	56.94	$	40.00
Quarter ended December 31,	$	44.69	$	20.51	$	53.13	$	40.92

For the period from January 1, 2009 through February 26, 2009, the range of low and high sales prices of our common stock was $19.89 to $28.68, respectively. On February 26, 2009, the closing sale price of our common stock as reported by the NYSE was $21.03 per share and there were 612 stockholders of record.

We have not declared or paid cash dividends during the past five years. Pursuant to the terms of the indenture under which the senior notes, as further described in Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Long-Term Debt” and Note 5 of the “Notes to the Consolidated Financial Statements” in Part II, Item 8 herein 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 compensation plan information required by this item may be found in Note 8 of the “Notes to the Consolidated Financial Statements” in Part II, Item 8 herein.

On December 4, 2006, we raised approximately $76.8 million, net of offering costs of $0.2 million, through the sale of 2,000,000 shares of common stock pursuant to our registration statement on Form S-3, Reg. No. 333-133563, and prospectus supplement. The sale was underwritten by Jefferies & Company, Inc. The proceeds were used to repay the outstanding portion of the credit facility, for corporate working capital needs, and to partly fund future progress payments for the delivery of new build vessels included in our construction program.

Performance Graph

The following performance graph and table compare the cumulative return on the Company’s Common Stock to the Dow Jones Total Market Index and the Dow Jones Oilfield Equipment and Services Index (which consists of Atwood Oceanics Inc., Baker Hughes Inc., BJ Services Co., Bristow Group Inc., Cameron International Corp., Chart Industries Inc., Complete Production Services Inc., Core Laboratories N.V., Diamond Offshore Drilling Inc., Dresser-Rand Group Inc., Dril-Quip Inc., ENSCO International Inc., Exterran Holdings Inc., FMC Technologies Inc., Global Industries Ltd., Halliburton Co., Helix Energy Solutions Group Inc., Helmerich & Payne Inc., Hercules Offshore Inc., ION Geophysical Corp., Key Energy Services Inc., Nabors Industries Ltd., National Oilwell Varco Inc., Newpark Resources Inc., Noble Corp., Oceaneering International Inc., Oil States International Inc., Parker Drilling Co., Patterson-UTI Energy Inc., Pride International Inc., Rowan Cos. Inc., Schlumberger Ltd., SEACOR Holding Inc., Smith International Inc., Superior Energy Services Inc., Tetra Technologies Inc., Tidewater Inc., Transocean Ltd., Unit Corp., and Weatherford International Ltd.) for the periods indicated. The graph assumes (i) the reinvestment of dividends, if any, and (ii) the value of the investment of the Company’s Common Stock and each index to have been $100 at December 31, 2003.

Comparison of Cumulative Total Return


	2003		2004		2005		2006		2007		2008
GulfMark Offshore, Inc.		100		159		212		267		334		170
Dow Jones Total Market Index		100		112		119		138		146		92
Dow Jones Oilfield Equipment and Services Index		100		135		205		233		338		138

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.


	As of December 31,
	2008			2007			2006			2005			2004
	(Amounts in thousands, except per share amounts)
Operating Data:
Revenue	$	411,740		$	306,026		$	250,921		$	204,042		$	139,312
Direct operating expenses		143,925			108,386			91,874			82,803			71,239
Drydock expense (a)		11,319			12,606			9,049			9,192			8,966
Bareboat charter expense		—			—			—			3,864			1,410
General and administrative expenses		40,244			32,311			24,504			19,572			15,666
Depreciation and amortization		44,300			30,623			28,470			28,875			26,137
Gain on sale of assets		(34,811	)		(12,169	)		(10,237	)		—			(2,282	)

Operating income		206,763			134,269			107,261			59,736			18,176
Interest expense		(14,291	)		(7,923	)		(15,648	)		(19,017	)		(17,243	)
Interest income		1,446			3,147			1,263			569			276
Debt refinancing costs		—			—			—			—			(6,524	)
Other income (expense), net		1,609			(298	)		(95	)		484			1,517
Income tax (provision) benefit (b)		(11,743	)		(30,220	)		(3,052	)		(3,382	)		6,476

Income before cumulative effect of change in accounting principle	$	183,784		$	98,975		$	89,729		$	38,390		$	2,678
Cumulative effect on prior years of change in accounting principle — net of $773 related tax effect (a)		—			—			—			—			(7,309	)

Net income (loss)	$	183,784		$	98,975		$	89,729		$	38,390		$	(4,631	)

Amounts per common share (basic):
Income before cumulative effect of change in accounting principle	$	7.74		$	4.41		$	4.40		$	1.92		$	0.13
Cumulative effect on prior years of change in accounting principle		—			—			—			—		$	(0.36	)

Net income (loss)	$	7.74		$	4.41		$	4.40		$	1.92		$	(0.23	)

Weighted average common shares (basic)		23,737			22,435			20,377			20,031			19,938

Amounts per common share (diluted):
Income before cumulative effect of change in accounting principle	$	7.56		$	4.29		$	4.28		$	1.86		$	0.13
Cumulative effect on prior years of change in accounting principle		—			—			—			—		$	(0.36	)

Net income (loss)	$	7.56		$	4.29		$	4.28		$	1.86		$	(0.23	)

Weighted average common shares (diluted) (c)		24,319			23,059			20,975			20,666			19,938

Statement of Cash Flows Data:
Cash provided by operating activities	$	205,201		$	128,577		$	104,869		$	64,913		$	25,561
Cash used in investing activities		(186,787	)		(175,383	)		(28,300	)		(43,343	)		(40,404	)
Cash provided by (used in) financing activities		56,754			373			(20,679	)		(15,674	)		23,005
Effect of exchange rate changes on cash		(14,526	)		3,793			2,679			765			1,031
Other Data:
Adjusted EBITDA (d)	$	251,063		$	164,892		$	135,731		$	88,611		$	44,313
Cash dividends per share		—			—			—			—			—
Total vessels in fleet (e)		94			61			60			59			52
Average number of owned or chartered vessels (f)		59.5			46.8			48.5			47.2			45.6


	As of December 31,
	2008		2007		2006		2005		2004
	(In thousands)
Balance Sheet Data:
Cash and cash equivalents	$	100,761	$	40,119	$	82,759	$	24,190	$	17,529
Vessels and equipment including construction in progress, net		1,169,513		754,000		571,989		510,446		538,978
Total assets		1,556,967		934,012		750,829		613,915		632,718
Long-term debt (g)		462,941		159,558		159,490		247,685		258,022
Total stockholders’ equity		854,843		676,091		541,428		320,096		316,157


(a)		Effective January 1, 2004, we began expensing the costs associated with drydocks. Previously, these costs were capitalized and amortized over 30 months. As a result of this change, in 2004 we recorded a non-cash cumulative effect charge of $7.3 million, net of tax ($0.36 per basic and diluted common share).

(b)		See Note 6 to our “Consolidated Financial Statements — Income Taxes”.

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

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

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

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


	Year Ended December 31,
	2008			2007			2006			2005			2004
	(In thousands)
Net income (loss)	$	183,784		$	98,975		$	89,729		$	38,390		$	(4,631	)
Interest expense		14,291			7,923			15,648			19,017			17,243
Interest income		(1,446	)		(3,147	)		(1,263	)		(569	)		(276	)
Income tax (benefit) provision		11,743			30,220			3,052			3,382			(6,476	)
Depreciation and amortization		44,300			30,623			28,470			28,875			26,137

EBITDA		252,672			164,594			135,636			89,095			31,997
Adjustments:
Cumulative effect of change in accounting principle		—			—			—			—			7,309
Debt refinancing costs		—			—			—			—			6,524
Other *		(1,609	)		298			95			(484	)		(1,517	)

Adjusted EBITDA	$	251,063		$	164,892		$	135,731		$	88,611		$	44,313


*		Includes foreign currency transaction adjustments.

(e)		Includes managed vessels in addition to those that are owned and chartered at the end of the applicable period. See “Our Fleet” in Part I, Items 1 and 2 “Business and Properties” for further information concerning our fleet.


(f)		Average number of vessels is calculated based on the aggregate number of vessel days available during each period divided by the number of calendar days in such period. Includes owned and bareboat chartered vessels only, and is adjusted for additions and dispositions occurring during each period.

(g)		Excludes current portion of long-term debt.

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

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

Our Business Strategy

Our goal is to enhance our position as a premier provider of offshore marine services by achieving higher vessel utilization rates, relatively stable growth rates and returns on investments that are superior to those of our competitors. Key elements in implementing our strategy include:

Developing and maintaining a large, modern, diversified and technologically advanced fleet: Our fleet size, location and profile allow us to provide a full range of services to our customers from platform supply work to specialized floating, production, storage and offloading, or FPSO support, including anchor handling and remotely operated vehicle, or ROV, operations. We regularly upgrade our fleet to improve capability, reliability and customer satisfaction. We also seek to take advantage of attractive opportunities to acquire or build new vessels to expand our fleet. We took delivery of 12 new build vessels between 2001 and 2005, and acquired a vessel in December 2004. During 2005 we committed to build 11 new vessels, one of which was delivered during the fourth quarter of 2005, two during 2006, and four in 2007. In 2007, we committed to build seven new vessels (five PSVs and two AHTS vessels) to be delivered in late 2009 and the first seven months of 2010. In 2008, we acquired 22 vessels and 6 vessels under construction in conjunction with the acquisition of Rigdon. In addition, we have sold certain older, smaller 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: Prior to the Rigdon Acquisition, we elected to conduct our current operations mainly in the North Sea, offshore Southeast Asia and, to a lesser extent, offshore Americas markets. Our focus on these regions was driven by what we perceive to be higher barriers to entry, lower volatility of day rates and greater potential for increasing day rates in these markets than in other markets. With the Rigdon Acquisition we added a strong presence in the U.S. Gulf of Mexico and offshore Trinidad, which are now included in the Americas operating segment. Consistent with our approach prior to the Rigdon Acquisition the high barriers to entry in the U.S. Gulf of Mexico, particularly in the deepwater segment, was a key attribute in our acquisition decision, although historically day rates in that region have been relatively more volatile.

Our operating experience in these markets has enabled us to anticipate and profitably respond to trends in these markets, 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 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. We have 43 vessels based in the North Sea, 39 vessels operating in the Americas and 13 vessels operating offshore Southeast Asia. Our fleet has grown in both size and capability, from an original 11 vessels in 1990 to our present number of 95 vessels, through strategic acquisitions and the new construction of technologically advanced vessels, partially offset by dispositions of certain older, less profitable vessels. At February 26, 2009, our fleet includes 71 owned vessels and 24 managed vessels.

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

From time to time, we bareboat charter vessels with revenue and operating expenses reported in the same income and expense categories as our owned vessels. The chartered vessels, however, incur bareboat charter fees instead of depreciation expense. Bareboat charter fees are generally higher than the depreciation expense on owned vessels of similar age and specification. The operating income realized from these vessels is therefore adversely affected by the higher costs associated with the bareboat charter fees. These vessels are included in calculating fleet day rates and utilization in the applicable periods.

We also provide management services to other vessel owners for a fee. We do not include charter revenue and vessel expenses of these vessels in our operating results; however, management fees are included in operating revenue. These vessels have been 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 and Notes to Consolidated Financial Statements 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 more. 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. In 2005, we wrote-off approximately $1.2 million deemed to be uncollectible, which primarily represented one customer that had been included in the 2004 allowance for doubtful accounts. At December 31, 2008 and 2007, respectively, we provided an allowance for doubtful accounts of $0.4 million and $0.1 million. Additional allowances for doubtful accounts may be necessary as a result of our ongoing assessment of our customers’ ability to pay, particularly in light 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.

Deferred Drydocking, Mobilization and Financing Costs

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

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

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

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 2008 Rigdon Acquisition, the 2001 acquisition of Sea Truck Holding AS and the 1998 acquisition of Brovig Supply AS. Our identifiable intangible assets relates 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.

The implied fair value of any asset or reporting unit is determined by discounting the projected future operating cash flows or by using other fair value approaches based on a multiple of earnings measurement. Management makes critical estimates and judgments to determine projected future operating cash flow, particularly in regard to projected revenue and costs. An impairment indicator is deemed to exist if the implied fair value of the asset or reporting unit is less than the book value.

For the years 2008, 2007, and 2006, we performed our impairment testing and determined there was no goodwill impairment. There are many assumptions and estimates underlying the determination of the implied fair value of the reporting unit, such as future expected utilization and the average day rates for the vessels, vessel additions and dispositions, operating expenses and tax rates. Although we believe our assumptions and estimates are reasonable, deviations from our estimates by actual performance could result in an adverse material impact on our results of operations. Examples of events or circumstances that could give rise to an impairment of an asset (including goodwill) include: prolonged adverse industry or economic changes; significant business interruption; unanticipated competition that has the potential to dramatically reduce our earning potential; legal issues; or the loss of key personnel.

Income Taxes

The majority of our non-US based operations are subject to foreign tax systems that provide significant incentives to qualified shipping activities. Our UK and Norway based vessels are taxed under “tonnage tax” regimes while 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. Even with our mid-2008 entry into the US offshore supply vessel market as a result of the Rigdon Acquisition, these foreign tax beneficial structures continued to result in a large portion of our earnings incurring significantly lower taxes than those that would apply if we were not a qualified shipping company in those jurisdictions.

reduce the cash required for taxes in that region. As a result of this legislation, we are now required to pay the tax on the accumulated untaxed shipping profits as of December 31, 2006 with two-thirds of the liability being payable in equal installments over ten years, while the remaining one-third of the tax liability can be met over fifteen years through qualified environmental expenditures on vessels owned by any of our 90% or greater owned subsidiaries. Any remaining portion of the environmental part of the liability at the end of fifteen years would be payable at that time. However, in January 2009 the Norwegian tax authority announced a change to the environmental fund regulations under which the fifteen year payment period has been abolished with no mandatory time limit on repayment of the environmental portion of the liability. As of December 31, 2008, our total US$ equivalent of the NOK liability for the repealed Norwegian tonnage tax was $17.8 million. The first annual cash payment of $2.0 million was paid in 2008, the second installment due in 2009 is classified on our balance sheet as current income taxes payable, and the $16.5 million remainder is classified on our balance sheet as Other income taxes payable. Of this amount, $10.2 million is payable over eight years and $6.3 million is the one-third environmental portion of the total liability, which we expect will be fully expended in accordance with the regulations and related rules and guidelines. The abolishment of the payment period time limit eliminates the $6.3 million tax liability, which will be recorded as a credit to our tax provision in 2009.

Substantially all of our tax provision is for taxes unrelated to our exempt Singapore based and United Kingdom and Norway tonnage tax qualified shipping activities. 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 $3.0 million of such foreign tax credit carryforwards that begin to expire in 2009. A valuation allowance has been established against the full amount of these credits less the tax benefit of the deduction. We also have certain foreign net operating loss carryforwards that result in net deferred tax assets of approximately $2.5 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 recorded in the period such determination was made.

In 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109”. FIN 48 clarifies the accounting for uncertainty in income taxes recognized under SFAS No. 109. FIN 48 prescribes 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. On January 1, 2007, we adopted FIN 48. 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. FIN 48 also provides 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 balance sheet presentations for accrued income tax assets and liabilities, including any amounts for uncertain tax positions.

See also Note 1 “Nature of Operations and Summary of Significant Accounting Policies — Income Taxes” and Note 6 “Income Taxes” 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 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 of our subsidiaries participate in an industry-wide, multi-employer, defined benefit pension fund based in the U.K., known as the Merchant Navy Officers Pension Fund, or MNOPF, with a requirement to perform an actuarial study every three years. In 2005, we were informed of an estimated £234.0 million, the equivalent of $459.2 million, total fund deficit calculated by the fund’s actuary based on the actuary study of 2003. Under the direction of a court order, the deficit was to be remedied through future funding contributions from all participating employers. The results of the 2006 actuarial study were communicated in the third quarter 2007 indicating a further £151.0 million, or equivalent of $305.9 million, total deficit, which will also be required to be funded by the participating employers.

In 2005, we received invoices from the MNOPF for $1.8 million, which represents the amount calculated by the fund as our current share of the deficit. Under the terms of the invoice, we paid $0.3 million during 2005 with the remaining due in annual installments over nine years. Accordingly, we recorded the full amount of $1.8 million as a direct operating expense in 2005 and the $1.5 million remaining obligation is recorded as a liability. During 2006 and the first half of 2007, we paid $0.2 million and $0.3 million, respectively, against this liability with the understanding that the amount of our ultimate share of the deficit could change depending on future actuarial valuations and fund calculations, which are due to occur every three years.

At the beginning of 2007, we were advised that there was £25 million unpaid on this balance, and our share of the contribution was approximately $0.3 million to be paid over the next nine years. This amount was booked as a direct operating expense and a liability in the first quarter of 2007. In the third quarter 2007, we received invoices from the MNOPF for £0.9 million, or the equivalent of approximately $1.7 million, for our share of the calculated deficit based on the 2006 valuation, which we have recorded as a direct operating expense and corresponding liability in the third quarter of 2007.

In 2008, we paid $0.3 million against the liability. We have not adjusted our liability to reflect future contributions that might be needed as a result of the fund calculations that will be completed in the first quarter of 2009. Although it is anticipated that an increase may be necessary based on an anticipated reduction in the return on the fund’s assets caused by the world economic downturn, currently a reasonable amount cannot be estimated, therefore, no adjustment has been made.

There currently is no provision within the MNOPF to refund excess contributions, which, if it were to occur in future evaluations, would be anticipated to be adjusted against the remaining liability. Therefore, as allowed under the terms of the assessment, we plan to pay the liability over eight annual installments, with applicable interest charges. 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.

Consolidated Results of Operations

Comparison of the Fiscal Years Ended December 31, 2008 and December 31, 2007

Our revenue increased from $306.0 million in 2007 to $411.7 million in 2008, or 34.5%, mainly as a result of the Rigdon Acquisition that occurred in the third quarter of 2008, coupled with additions to the fleet, with four vessels delivered to the Southeast Asia region, and the full year effect of the two vessels added in the North Sea. The additions are offset in part by the sale of five vessels in 2008, two in the North Sea and three in Southeast Asia, coupled with the full year effect of three vessels sold in late 2007, all in Southeast Asia. For the year ended December 31, 2008, net income was $183.8 million, or $7.56 per diluted share, compared to $99.0 million, or $4.29 per diluted share in fiscal year 2007.

On July 1, 2008, we acquired 100% of the equity interest of Rigdon, which is now considered part of the Americas operating segment. In 2008, primarily as a result of the Rigdon Acquisition, the Americas region revenue increased by $84.7 million, which accounted for 80% of the overall increase in revenue.

Overall utilization increased from 93.2% in 2007 to 94.2% in 2008, which contributed $3.6 million to the increase in revenue. Offsetting the positive impact to the increase in revenue was the strengthening of the US$ against the GBP and the decrease in day rates in the North Sea.


	Year Ended December 31,
							Increase
	2008			2007			(Decrease)
	(Dollars in thousands)
Average Rates Per Day Worked (a) (b):
North Sea-Based Fleet (c)	$	22,837		$	24,120		$	(1,283	)
Southeast Asia-Based Fleet		17,723			10,276			7,447
Americas-Based Fleet		16,567			11,386			5,181
Overall Utilization (a) (b):
North Sea-Based Fleet (c)		94.6	%		92.8	%		1.8	%
Southeast Asia-Based Fleet		94.5	%		93.3	%		1.2	%
Americas-Based Fleet		93.4	%		94.9	%		(1.5	%)
Average Owned or Chartered Vessels (a) (d):
North Sea-Based Fleet		27.2			28.8			(1.6	)
Southeast Asia-Based Fleet		13.0			12.0			1.0
Americas-Based Fleet		19.3			6.0			13.3

Total		59.5			46.8			12.7


(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$/GBP, US$/NOK and US$/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,
	2008		2007
$1 US=GBP		0.541		0.500
$1 US=NOK		5.580		5.844
$1 US=Euro		0.681		0.730


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

Direct operating expenses increased $35.5 million in 2008 when compared to 2007. This increase was mainly to the increase in vessels as a result of the Rigdon Acquisition and the delivery of new vessels throughout the year. Drydock expense decreased by $1.3 million from 2007 to 2008. General and administrative expenses increased $7.9 million from 2007 to 2008, and depreciation expense increased by $13.7 million from 2007 to 2008. The increase in general and administrative and depreciation expense was due mainly as a result of the Rigdon Acquisition coupled with higher salary, bonus and employee benefits. The gain on sale of assets of approximately $34.8 million relates to the sale of five vessels: the North Fortune, North Crusader, Sem Valiant, Sea Diligent, and Sea Eagle.

Interest expense increased $6.4 million from 2007 due mainly to the increase in debt incurred and assumed as part of the Rigdon Acquisition. The decrease in interest income of $1.7 million relates to less interest earned on lower cash balances coupled with lower interest rates in the second half of 2008. Other income of $1.6 million was mainly related to a prior year refund of sales taxes offset by the foreign currency movements throughout 2007.

Income tax expense for 2008 was $11.7 million, compared to $30.2 million for 2007. The 2007 effective tax rate of 23.39% was mostly the result of the impact of the tax law changes in Norway and Mexico enacted in 2007. Excluding the tax expense related to the Norway and Mexico legislative changes, the 2007 effective tax rate would have been 2.0%. For 2008, the effective tax rate was 6.0%. The increase from the prior year period excluding the tax expense related to the Norway and Mexico legislative changes is primarily the result of the Rigdon Acquisition along with a provision for uncertain tax liabilities in a foreign jurisdiction.

Comparison of the Fiscal Years Ended December 31, 2007 and December 31, 2006

Our revenue increased from $250.9 million in 2006 to $306.0 million in 2007, or 22%, mainly as a result of continued increased activity in both the North Sea and Southeast Asia regions, and additions to the fleet, with four new build vessels delivered during 2007 and the full year effect of two new build vessels delivered during 2006, offset in part by the sale of four older vessels in the year. For the year ended December 31, 2007, net income was $99.0 million, or $4.29 per diluted share, compared to $89.7 million, or $4.28 per diluted share in 2006.

Continued strength in the North Sea and Southeast Asia markets accounted for the majority of the year over year increase in day rates. The addition of two technically advanced vessels in both the North Sea and Southeast Asia in 2007 and two additions in Southeast Asia in 2006 impacted our financial results. The Americas day rates increased even with the impact of the return of the North Stream from Brazil back to the North Sea in the middle of 2006, as that vessel, temporarily working in the Americas, had been contracted at a higher average day rate than the smaller vessels which are more common in this region.

Our North Sea and Southeast Asia regions experienced significant increases in revenue year over year, while our Americas region revenue experienced a slight decrease. The overall improvement in revenue resulted primarily from a $40.1 million increase in day rates principally attributable to improved market conditions and stronger exploration and development activities, an increase in capacity of $5.4 million mainly due to vessel additions, and $17.7 million attributable to the strengthening of the GBP and NOK against the US$, partially offset by a $8.1 million decrease in utilization, due to increased drydock days in 2007.


	Year Ended December 31,
							Increase
	2007			2006			(Decrease)
	(Dollars in thousands)
Average Rates Per Day Worked (a) (b):
North Sea-Based Fleet (c)	$	24,120		$	19,164		$	4,956
Southeast Asia-Based Fleet		10,276			7,062			3,214
Americas-Based Fleet		11,386			11,014			372
Overall Utilization (a) (b):
North Sea-Based Fleet (c)		92.8	%		94.9	%		(2.1	%)
Southeast Asia-Based Fleet		93.3	%		92.3	%		1.0	%
Americas-Based Fleet		94.9	%		96.0	%		(1.1	%)
Average Owned or Chartered Vessels (a) (d):
North Sea-Based Fleet		28.8			30.4			(1.6	)
Southeast Asia-Based Fleet		12.0			11.7			0.3
Americas-Based Fleet		6.0			6.4			(0.4	)

Total		46.8			48.5			(1.7	)


(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$/GBP, US$/NOK and US$/Euro) for the periods indicated below. The North Sea based fleet includes vessels working offshore India, offshore Africa and the Mediterranean.


	Year Ended December 31,
	2007		2006
$1 US=GBP		0.500		0.543
$1 US=NOK		5.844		6.406
$1 US=Euro		0.730		0.796


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

Direct operating expenses increased $16.5 million in 2007 when compared to 2006. This increase was mainly due to vessel additions throughout 2007 coupled with salary and travel costs related to more vessels operating in locations that are distant from our regional offices and incentives. Drydock expense increased by $3.6 million from 2006 to 2007 as a result of more drydock days for the fleet. General and administrative expenses increased $7.8 million from 2006 to 2007, largely related to higher salary, bonus and employee benefits. Depreciation expense increased by $2.2 million from 2006 to 2007 due mainly to fleet additions partially offset by the sale of assets. The gain on sale of assets of approximately $12.2 million in 2007 relates to the sale of our four older vessels throughout the year.

Interest expense decreased $7.7 million as we paid off our revolving credit facility, coupled with higher capitalized interest recorded in 2007. The increase in interest income of $1.9 million relates to the interest earned on higher cash balances throughout the year resulting from higher sales. Additionally, the other expense of $0.3 million was mainly related to foreign currency movements throughout 2007.

Income tax expense for 2007 was $30.2 million, compared to $3.1 million for 2006. The 2007 effective tax rate of 23.39% was mostly the result of the impact of the tax law changes in Norway and Mexico enacted in 2007 and 2007 activities that were not UK and Norway tonnage tax qualified shipping operations. Excluding the tax expense related to the Norway and Mexico legislative changes, our 2007 effective tax rate would have been 2.0%. For 2006, the effective tax rate was 3.3%. In addition, our tax provision can fluctuate significantly based on the mix of vessels working in higher tax jurisdictions.

Segment Results

As discussed in “General Business” included in Part I, Items 1 and 2, we operate three operating segments: the North Sea, Southeast Asia and the Americas, each of which is considered a reportable segment under SFAS No. 131. The majority of our revenue is derived from our long-lived assets located in foreign jurisdictions. In 2008, we had $72.5 million in revenue and $593.0 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. Gain on the sale of assets for prior periods has been reclassified to operating income to conform with the current year presentation. Management considers segment operating income to be a good indicator of each segment’s operating performance from its continuing operations, because it represents the results of the ownership interest in operations without regard to financing methods or capital structures. Each segment’s operating income is summarized in the following table, and further detailed in the following paragraphs.

Operating Income by Operating Segment


	Year Ended December 31,
	2008			2007			2006
	(In thousands)
North Sea	$	126,486		$	110,679		$	100,909
Southeast Asia		62,447			35,858			14,998
Americas		38,344			5,136			4,100

Total reportable segment operating income		227,277			151,673			120,007
Other		(20,514	)		(17,404	)		(12,746	)

Total reportable segment and other operating income	$	206,763		$	134,269		$	107,261

North Sea Region:


	Year Ended December 31,
	2008			2007			2006
	(In thousands)
Revenue	$	226,124		$	241,664		$	199,368
Direct operating expenses		86,445			88,277			71,245
Drydock expense		8,237			10,369			6,446
General and administrative expense		11,414			12,439			9,274
Depreciation and amortization expense		22,623			24,914			21,731
Gain on sale of assets		(29,081	)		(5,014	)		(10,237	)

Operating income	$	126,486		$	110,679		$	100,909

Comparison of Fiscal Year Ended December 31, 2008 and December 31, 2007

Revenue for the North Sea of $226.1 million in 2008 decreased $15.5 million or 6.4% compared to 2007, primarily due to the strengthening of the U.S. Dollar against the GBP and NOK which reduced revenue by $9.9 million. In addition the decrease in the average day rate from $24,120 in 2007 to $22,837 in 2008, also contributed $3.3 million to the decrease in revenue. Capacity for the region also decreased by $5.5 million mainly due to the sale of two older vessels, which occurred in 2008, the full year effect of the mobilization of the Highland Drummer to the Southeast Asia region in the second quarter of 2007, and the mobilization of the Highland Piper to the Americas region in the first quarter of 2008. This was partially offset by the full year effect of the delivery of two new vessels, Highland Prestige and North Promise into the region in late 2007. Partially offsetting these decreases was an increase in utilization from 92.8% in 2007 to 94.8% in 2008, resulting in a revenue increase of $3.2 million. Operating income increased by $15.8 million, primarily as a result of the gain on sale of two of the regions older vessels the North Fortune and the North Crusader, offset by the decrease in revenue. Direct operating expenses year over year were lower by $1.8 million due mainly to lower employees benefits resulting from the 2007 U.K. pension adjustment. Drydock expense was also lower by $2.1 million resulting mainly from lower drydock days. Depreciation expense decreased by $2.3 million resulting mainly from the sale of the vessels. General and administrative expense decreased by $1.0 million due to lower salaries and lower professional fees.

Comparison of Fiscal Year Ended December 31, 2007 and December 31, 2006

Revenue for the North Sea of $241.7 million in 2007 increased $42.3 million or 21% compared to 2006, primarily due to a 26% increase in the average day rate from $19,164 in 2006 to $24,120 in 2007, and contributed $54.3 million to the increase in revenue. Utilization decreased from 94.9% in 2006 to 92.8% in 2007, resulting in a revenue decrease of $7.7 million. Capacity for the region also decreased by $4.3 million mainly due to the sale of two older vessels which occurred in late 2006 and early 2007 and the mobilization of the Highland Drummer from the North Sea to the Southeast Asia region in the second quarter of 2007. This was partially offset by the delivery of two new vessels, Highland Prestige and North Promise, into the region. Operating income increased by $9.8 million, primarily as a result of the improvement in revenue, offset by an increase in direct operating expenses year over year of $20.2 million resulting from increased crew wages, benefits, travel and U.K. pension adjustment, as well as a $3.9 million increase in drydock expense. Depreciation expense also increased by $3.2 million from year to year related principally to the new vessel additions. The gain on the sale of vessels in 2007 was lower by $5.2 million compared to 2006.

Southeast Asia Region:


	Year Ended December 31,
	2008			2007			2006
	(In thousands)
Revenue	$	77,851		$	41,257		$	27,385
Direct operating expenses		12,509			6,946			6,445
Drydock expense		250			1,832			1,775
General and administration expense		2,193			1,118			1,613
Depreciation and amortization expense		6,170			2,657			2,554
Gain on sale of assets		(5,718	)		(7,154	)		—

Operating income	$	62,447		$	35,858		$	14,998

Comparison of Fiscal Year Ended December 31, 2008 and December 31, 2007

Southeast Asia region revenue increased by 89% or $36.6 million, to $77.9 million in 2008, compared to $41.3 million in 2007. Capacity contributed $35.4 million to the revenue increase due to the three new deliveries in 2008 of the Sea Apache, Sea Kiowa and Sea Choctaw, coupled with the full year effect of the Sea Cheyenne and Sea Supporter delivered in the fourth quarter of 2007 and the positive impact of the full year effect of the mobilization into the region of the Highland Drummer in 2007 and the North Crusader in 2008, both from the North Sea. Utilization also contributed $0.8 million to the increase in revenue increasing from 93.3% in 2007 to 94.5% in 2008. The positive contribution to revenue was offset by the sale of three older vessels, the Sem Valiant, Sea Diligent and Sea Eagle. Day rates contributed $0.4 million to the improvement in revenue, increasing from an average day rate of $10,276 in 2007 to $17,723 in 2008. Operating income increased $26.6 million year over year, primarily as a result of the increase in revenue offset by the increase in direct operating expense as a result of the net additions to the fleet. General and administrative cost increased $1.1 million from 2007 as a result of higher salaries and benefits and an increase in bad debt expense.

Comparison of Fiscal Year Ended December 31, 2007 and December 31, 2006

Southeast Asia region revenue increased by 51% or $13.9 million, to $41.3 million in 2007, compared to 2006. Capacity contributed $9.8 million to the revenue increase due to the full year effect of the 2006 delivery of the Sea Guardian and Sea Sovereign, the fourth quarter 2007 delivery of the Sea Supporter and Sea Cheyenne, and mobilization of the Highland Drummer into the region from the North Sea, partially offset by the sale of the Sem Courageous, Sea Explorer, and Sea Endeavor in the second half of 2007. Day rates contributed $4.1 million to the improvement in revenue, increasing from an average day rate of $7,062 in 2006 to $10,276 in 2007. Operating income increased $20.9 million year over year, primarily as a result of the increase in revenue and a gain on the sale of the older vessels in 2007.

Americas Region:


	Year Ended December 31,
	2008			2007		2006
	(In thousands)
Revenue	$	107,765		$	23,105	$	24,168
Direct operating expenses		44,972			13,163		14,185
Drydock expense		2,832			405		828
General and administrative expense		6,769			1,488		1,176
Depreciation and amortization expense		14,860			2,913		3,879
Gain on sale of assets		(12	)		—		—

Operating income	$	38,344		$	5,136	$	4,100

Comparison of Fiscal Year Ended December 31, 2008 and December 31, 2007

Revenue for the Americas region increased year over year by $84.7 million, from $23.1 million in 2007 to $107.8 million in 2008, primarily as a result of the Rigdon Acquisition that occurred July 1, 2008. The Rigdon Acquisition contributed $72.0 million or 85% to the increase in revenue. Also contributing $10.8 million to the increase was the mobilization into the region of the Highland Piper from the North Sea and the Sea Kiowa from Southeast Asia. Excluding the vessels acquired as part of the Rigdon Acquisition, day rates increased from $11,386 in 2007 to $15,492 in 2008, contributing $2.3 million to the increase in revenue. Utilization, excluding the acquired vessels, decreased from 94.9% in 2007 to 89.2% in 2008, decreasing revenue by $0.4 million. Operating income increased $33.2 million mainly as a result of the Rigdon Acquisition which contributed $30.2 million of the increase, the difference resulting in the increase in revenue from the non-acquired vessels. General and administrative expense increased by $5.3 million from year to year due mainly to the Rigdon Acquisition and higher salaries and benefit expense.

Comparison of Fiscal Year Ended December 31, 2007 and December 31, 2006

Revenue for the Americas region decreased year over year by $1.1 million, from $24.2 million in 2006 to $23.1 million in 2007, primarily as a result of a $2.4 million in capacity loss from the mobilization of a vessel out of the region in 2006. Overall utilization decreased from 96.0% in 2006 to 94.9% in 2007, which was offset by an increase in average day rates of $11,014 in 2006 to $11,386 in 2007 contributing a net increase to revenue of $1.3 million. Even with the decreased revenue, operating income increased by $1.0 million due to lower operating expenses, drydock expense and depreciation expense.

Liquidity and Capital Resources

Our ongoing liquidity requirements are generally associated with our need to service debt, fund working capital, maintain our fleet, finance our new build construction program, acquire or improve equipment and make other investments. We 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 crude oil and natural gas.

New build commitments were approximately $92.3 million for 2008, and are approximately $111.0 million for 2009 and $57.3 million for 2010. Interest expense at current rates under our existing debt arrangements, assuming no additional draws, will be approximately $25 million for 2009. Minimum repayments under our existing debt arrangements will be approximately $19 million for 2009. These amounts are anticipated to be paid by 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, and those expenditures typically increase with age. We expect our drydocking expenditures to be approximately $19 million in 2009.

At December 31, 2008, we had approximately $100.8 million of cash on hand, approximately $90.7 million of borrowing capacity under our Revolving Loan Facility, and the ability to borrow approximately $34.3 million under our Senior Facility upon the delivery of the remaining crew boats and fast supply vessels currently under construction. It is currently anticipated that excess cash on hand will be used to reduce borrowings in advance of their stated maturities.

We anticipate that cash on hand and future cash flow from operations for 2009 and 2010 will be adequate to repay our debts due and payable during such period, to fund our new build commitments, 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 million Secured Reducing 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 million allocated to GulfMark Offshore, Inc.; $60 million allocated to Gulf Offshore N.S. Limited, a wholly owned U.K. subsidiary; $30 million allocated to GulfMark Rederi AS, a wholly owned Norwegian subsidiary; and $60 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, with a final reduction of $115.0 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. During the second quarter of 2008 we borrowed approximately $140.9 million under this facility to fund the cash portion of the Rigdon Acquisition and as of December 31, 2008 have approximately $84.2 million borrowed under this facility.

Senior Notes

On July 21, 2004, we issued $160 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, commencing January 15, 2005, and contain the following redemption provisions:

	•		Prior to July 15, 2009, we may redeem all or part of the 7.75% senior notes by paying a make-whole premium, plus accrued and unpaid interest and, if any, liquidation damages.

	•		The 7.75% senior notes may be called beginning on July 15 of 2009, 2010, 2011, and 2012 and thereafter at redemption prices of 103.875%, 102.583%, 101.292% and 100% of the principal amount 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 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 affect, and in many cases 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. We are currently in compliance with all indenture covenants.

On July 1, 2008, in conjunction with the Rigdon Acquisition, we assumed and restructured the following:

Senior Secured Credit Facility Agreement (“Senior Facility”)

The $224 million Senior Facility is with a syndicate of banks led by DVB Bank NV, as Agent. The Senior Facility matures on June 30, 2010. As of December 31, 2008, approximately $153 million was outstanding under the Senior Facility. The Senior Facility bears interest at the rate of LIBOR plus 125 basis points and is due at the rate of 0.833% per month of the outstanding principal on each vessel beginning one month after delivery of the vessel with a final payment due on maturity. We have interest rate swap agreements for a portion of the Senior Facility indebtedness that has the effect of fixing the interest rate at 4.725% on approximately $98.3 million of the Senior Facility. The interest rate swaps are accounted for as cash flow hedges.

The Senior Facility is subject to financial covenants consistent with those of our Secured Reducing Revolving Credit Loan Facility, contains other customary covenants and events of default, and is secured by a Preferred Fleet Mortgage on each vessel financed under the Senior Facility. Twenty-three vessels currently secure the Senior Facility. Additional fees will be due to the lenders if the Senior Facility is not refinanced prior to December 31, 2009. At December 31, 2008 we were in compliance with all covenants.

Subordinated Secured Credit Facility Agreement (“Subordinated Facility”)

The $85 million Subordinated Facility is solely provided by DVB Bank NV and is fully drawn. The Subordinated Facility bears interest at the rate of LIBOR plus 200 basis points and matures on June 30, 2010. There are no scheduled principal repayments before the maturity date and no principal payments may be made until the Senior Facility is repaid in full.

The Subordinated Facility is also subject to the same financial covenants as the Senior Facility and contains customary other covenants and events of default. The facility is secured by a Subordinated Second Fleet Mortgage on 20 vessels and a subordination agreement which grants the Senior Facility lenders certain preferences over the Subordinated Facility lenders for payments of principal and interest and in exercising remedies over the security interests held by them. Additional fees will be due to the lenders if the Subordinated Facility is not refinanced prior to December 31, 2009. At December 31, 2008 we were in compliance with all covenants.

Current Year Cash Flow

At December 31, 2008, we had cash on hand of $100.8 million. Cash provided by operating activities for the year ended December 31, 2008 was $205.2 million compared to $128.6 million in the previous year. The increase was primarily attributable to higher operating income primarily resulting from the Rigdon Acquisition coupled with improvement in Southeast Asia resulting from the addition of new vessels.

Cash used in investing activities for the years ended December 31, 2008 and 2007 was $186.8 million and $175.4 million, respectively. In 2008 and 2007, we sold assets, for approximately $43.4 million and $15.8 million, respectively. The proceeds from these sales decreased the reported cash used in investing activities.

In 2008, we provided $56.8 million in financing activities, compared to using $0.4 million in 2007. In 2008, we repaid $107.3 million debt that was borrowed and received proceeds from the exercise of stock options of $0.2 million. During 2007, we borrowed $20.3 million and repaid $21.1 million in debt, and received proceeds from the issuance of stock of approximately $0.9 million.

Debt and Other Contractual Obligations

The following table summarizes our contractual obligations at December 31, 2008 and the effect these obligations are expected to have on liquidity and cash flows in future periods (in millions):


	2009		2010		2011		2012		2013		Thereafter
Repayment of Long-Term Debt, Excluding Debt Discount of $0.6 million	$	19.0	$	219.1	$	—	$	—	$	—	$	160.0
Purchase Obligations for New Build Program		111.0		57.3		—		—		—		—
Non-Cancelable Operating Leases		1.7		1.5		1.2		1.1		1.0		2.3
Long-Term Income Taxes Payable		1.3		1.3		1.3		1.3		1.3		5.2
Other		0.5		0.5		0.5		0.5		0.5		0.9

Total	$	133.5	$	279.7	$	3.0	$	2.9	$	2.8	$	168.4

Due to the uncertainty with respect to the timing of future cash payments, if any, associated with our unrecognized tax benefits at December 31, 2008, we are unable to make reasonably reliable estimates of the period of cash settlements with the respective taxing authority. Therefore, $11.4 million of unrecognized tax benefits have been excluded from the contractual obligations table above. Included above as Long Term Income Taxes Payable is our liability for income taxes resulting from the repeal of the Norway tonnage tax law for the years 1996 — 2006 with nine annual payments remaining as of December 31, 2008, which is payable over ten years beginning in 2008. Refer to Note 6 “Income Taxes” in our “Notes to Consolidated Financial Statement” included in Part II, Item 8.

Other Commitments

have been made against these financial instruments. Management believes the likelihood of demand for payment under these instruments is minimal and expects no material cash outlays to occur from these instruments.

Transactions with Related Parties

For information regarding transactions with related parties, see Note 12 “Related Party Transactions” in our “Notes to Consolidated Financial Statements” included in Part II, Item 8.

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 55% of our total consolidated revenue for the year ended December 31, 2008. In 2008, the exchange rates of GBP, NOK and Euros against the US$ ranged as follows:


					Year		As of
	High		Low		Average		February 26, 2009
$1 US=GBP		0.692		0.492		0.541		0.700
$1 US=NOK		7.287		4.965		5.580		6.960
$1 US=Euro		0.804		0.626		0.681		0.786

Our outstanding debt is denominated in U.S. Dollars. A substantial portion of our revenue is generated in GBP. 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 GBP-denominated vessel day rates over time to compensate for changes in the purchasing power of GBP 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 the fair value hedge associated with the construction of vessels. See Part I, Items 1 and 2 “Business and Properties — New Vessel Construction and Acquisition Program”. We do not use foreign currency forward contracts for trading or speculative purposes.

Reflected in the accompanying balance sheet at December 31, 2008, is a ($17.2) million accumulated other comprehensive income primarily relating to the lower exchange rate at December 31, 2008 in comparison to the exchange rate when we invested capital in these markets. Accumulated other comprehensive income was $128.3 million at December 31, 2007. 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 change reflects the strengthening in the U.S. Dollar compared to the functional currencies of our major operating subsidiaries, particularly in the U.K. and Norway.

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, 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, 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 or terrorism, assumptions concerning competition, and risks of currency fluctuations and other matters. These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate under the circumstances. Such statements are subject to risks and uncertainties, including the risk factors discussed above and in Part I, Item 1A “Risk Factors”, general economic and business conditions, the business opportunities that may be presented to and pursued by us, changes in law or regulations and other factors, many of which are beyond our control. There can be no assurance that we have accurately identified and properly weighed all of the factors which affect market conditions and demand for our vessels, that the information upon which we have relied is accurate or complete, that our analysis of the market and demand for our vessels is correct or that the strategy based on such analysis will be successful. Important factors that could cause actual results to differ materially from our expectations are disclosed within Part I, Item 1A “Risk Factors”, this Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, and Part I, Items 1 and 2 “Business and Properties” and elsewhere in this Form 10-K.

ITEM 7A. Quantitative and Qualitative Disclosures about Market Risk

Financial Instruments

We are subject to financial market risks, including fluctuations in foreign currency exchange rates and interest rates. In order to manage and mitigate our exposure to these risks, we may use derivative financial instruments in accordance with established policies and procedures. At December 31, 2008, our derivative holdings consisted of foreign currency forward contracts and interest rate swap agreements. 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 and Acquisition Program”. 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 gains (losses), including derivative activity, for the years ended December 31, 2008, 2007 and 2006 were ($2.0) million, ($2.0) million, and ($1.7) 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, 2008 and 2007 that are sensitive to changes in interest rates. The floating portion of our variable debt is based on LIBOR, which is assumed to be 3% for all periods presented.


	2009			2010			2011			2012			2013			Thereafter
							(In thousands)
2008 Long-term Debt:
Fixed rate	$	—		$	—		$	—		$	—		$	—		$	160,000
Average interest rate		7.75	%		7.75	%		7.75	%		7.75	%		7.75	%		7.75	%

Variable rate	$	18,969		$	219,065		$	—		$	—		$	—		$	84,250
Average interest rate		4.30	%		4.30	%		3.70	%		3.70	%		3.70	%		3.70	%


	2009			2010			2011		2012		2013		Thereafter
							(In thousands)
2008 Notional Value:
Interest Rate Swaps-Variable to Fixed	$	98,341		$	85,201		$	—	$	—	$	—	$	—
Average pay rate		4.72	%		4.72	%		—		—		—		—
Average receive rate		4.25	%		4.25	%		—		—		—		—


	2008			2009			2010			2011			2012			Thereafter
							(In thousands)
2007 Long-term Debt:
Fixed rate	$	—		$	—		$	—		$	—		$	—		$	160,000
Average interest rate		7.75	%		7.75	%		7.75	%		7.75	%		7.75	%		7.75	%

Our fixed rate Senior Notes outstanding at December 31, 2008 subject us to risks related to changes in the fair value of the debt and expose us to potential gains or losses if we were to repay or refinance such debt. A 1% change in market interest rates would increase or decrease the fair value of our fixed rate debt by approximately $5.3 million.

The fair value of our 7.75% Senior Notes as compared to the carrying value at December 31, 2008 and 2007, was as follows:

December 31,

2008

2007

Carrying

Fair

Carrying

Fair

Value

(In millions)

7.75% Senior Notes due 2014

159.6

120.8

159.6

161.2

ITEM 8. Consolidated 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, 2008 and 2007, 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, 2008. 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, 2008 and 2007, and the consolidated results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2008, 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, 2008, 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 27, 2009 expressed an unqualified opinion.

UHY LLP

Houston, Texas

February 27, 2009

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, 2008, 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, 2008, 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 27, 2009 expressed an unqualified opinion.

UHY LLP

Houston, Texas

February 27, 2009

GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31,
	2008			2007
	(In thousands)
ASSETS

Current assets:
Cash and cash equivalents	$	100,761		$	40,119
Trade accounts receivable, net of allowance for doubtful accounts of $408 in 2008 and $149 in 2007		101,434			87,243
Other accounts receivable		3,467			3,399
Prepaid expenses and other current assets		7,236			3,273

Total current assets		212,898			134,034

Vessels and equipment at cost, net of accumulated depreciation of $182,283 in 2008 and $218,342 in 2007		1,035,436			641,333
Construction in progress		134,077			112,667
Goodwill		123,981			34,264
Fair value hedges		7,801			6,740
Intangibles, net of amortization of $1,442 in 2008		33,156			—
Deferred costs and other assets		9,618			4,974

Total assets	$	1,556,967		$	934,012


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	18,970		$	—
Accounts payable		15,085			21,409
Income taxes payable		3,037			2,516
Accrued personnel costs		22,341			17,872
Accrued interest expense		6,422			5,793
Accrued professional fees		1,090			982
Other accrued liabilities		7,947			1,906

Total current liabilities		74,892			50,478

Long-term debt		462,941			159,558
Long-term income taxes:
Deferred tax liabilities		116,172			2,731
Income tax liabilities — FIN 48		11,445			9,060
Other income taxes payable		16,468			23,602
Fair value hedges		7,801			6,740
Cash flow hedges		7,982			—
Other liabilities		4,423			5,752
Stockholders’ equity:
Preferred stock, no par value; 2,000 shares authorized; no shares issued		—			—
Common stock, $0.01 par value; 30,000 shares authorized; 25,355 and 22,983 shares issued		250			227
Additional paid-in capital		352,843			211,004
Retained earnings		520,630			336,846
Accumulated other comprehensive income (loss)		(17,157	)		128,308
Treasury stock, at cost		(6,852	)		(4,200	)
Deferred compensation expense		5,129			3,906

Total stockholders’ equity		854,843			676,091

Total liabilities and stockholders’ equity	$	1,556,967		$	934,012

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

GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


	Year Ended December 31,
	2008			2007			2006
	(In thousands, except per share amounts)
Revenue	$	411,740		$	306,026		$	250,921

Costs and expenses:
Direct operating expenses		143,925			108,386			91,874
Drydock expense		11,319			12,606			9,049
Bareboat charter expenses		—			—			—
General and administrative expenses		40,244			32,311			24,504
Depreciation		44,300			30,623			28,470
Gain on sale of assets		(34,811	)		(12,169	)		(10,237	)

Total costs and expenses		204,977			171,757			143,660

Operating income		206,763			134,269			107,261

Other income (expense):
Interest expense		(14,291	)		(7,923	)		(15,648	)
Interest income		1,446			3,147			1,263
Foreign currency gain (loss) and other		1,609			(298	)		(95	)

Total other expense		(11,236	)		(5,074	)		(14,480	)

Income from continuing operations		195,527			129,195			92,781
Income tax provision		(11,743	)		(30,220	)		(3,052	)

Net income	$	183,784		$	98,975		$	89,729

Earnings per share:
Basic	$	7.74		$	4.41		$	4.40
Diluted	$	7.56		$	4.29		$	4.28
Weighted average shares outstanding:
Basic		23,737			22,435			20,377

Diluted		24,319			23,059			20,975

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

GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
For the Years Ended December 31, 2008, 2007 and 2006
(In thousands)


	Common							Accumulated									Deferred
	Stock at		Additional					Other			Treasury Stock						Compen-		Total
	$0.01 Par		Paid-in		Retained			Comprehensive						Share			sation		Stockholders’
	Value		Capital		Earnings			Income (loss)			Shares			Value			Expense		Equity
Balance at December 31, 2005	$	202	$	125,177	$	153,004		$	41,713			(116	)	$	(2,017	)	$	2,017	$	320,096
Net income		—		—		89,729			—			—			—			—		89,729
Issuance of common stock		21		79,148		—			—			—			—			—		79,169
Exercise of stock options		2		661		—			—			—			—			—		663
Deferred compensation plan		—		—		—			—			(34	)		(995	)		995		—
Translation adjustment		—		—		—			51,771			—			—			—		51,771

Balance at December 31, 2006	$	225	$	204,986	$	242,733		$	93,484			(150	)	$	(3,012	)	$	3,012	$	541,428
Net income		—		—		98,975			—			—			—			—		98,975
Issuance of common stock		1		4,476		—			—			—			—			—		4,477
Exercise of stock options		1		1,542		—			—			—			—			—		1,543
Deferred compensation plan		—		—		—			—			(22	)		(1,188	)		894		(294	)
FIN 48		—		—		(4,862	)		—			—			—			—		(4,862	)
Translation adjustment		—		—		—			34,824			—			—			—		34,824

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	)
Gain (Loss) on cash flow hedge		—		—		—			(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

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

GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2008, 2007 and 2006


	Year Ended December 31,
	2008			2007		2006
	(In thousands)
Net income	$	183,784		$	98,975	$	89,729
Comprehensive income:
Gain (Loss) on cash flow hedge		(6,062	)		—		—
Foreign currency gain (loss)		(139,403	)		34,824		51,771

Total comprehensive income	$	38,319		$	133,799	$	141,500

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

GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended December 31,
	2008			2007			2006
	(In thousands)
Cash flows from operating activities:
Net income	$	183,784		$	98,975		$	89,729
Adjustments to reconcile net income from operations to net cash provided by operations
Depreciation		44,300			30,623			28,470
Amortization of deferred financing costs		711			704			903
Amortization of stock-based compensation		5,853			4,215			1,969
Provision for doubtful accounts receivable, net of write offs		336			(287	)		410
Deferred income tax provision (benefit)		7,225			454			(2,397	)
Gain on sale of assets		(34,811	)		(12,169	)		(10,237	)
Foreign currency transaction loss		3,123			1,273			1,277
Change in operating assets and liabilities —
Accounts receivable		(6,631	)		(30,013	)		(11,068	)
Prepaids and other		1,095			(349	)		1,159
Accounts payable		(8,259	)		3,686			(85	)
Other accrued liabilities and other		9,382			7,863			4,739
Norwegian income taxes payables		(907	)		23,602			—

Net cash provided by operating activities		205,201			128,577			104,869
Cash flows from investing activities:
Purchases of vessels and equipment		(108,626	)		(191,158	)		(47,466	)
Proceeds from disposition of equipment		43,432			15,775			19,166
Cash received with acquisition of business		31,028			—			—
Consideration paid for acquired business		(152,621	)		—			—

Net cash used in investing activities		(186,787	)		(175,383	)		(28,300	)
Cash flows from financing activities:
Proceeds from debt, net of direct financing costs		163,399			20,257			80,794
Repayments of debt		(107,291	)		(21,104	)		(179,265	)
Proceeds from exercise of stock options		163			852			663
Proceeds from issuance of stock		483			368			77,129

Net cash provided by (used in) financing activities		56,754			373			(20,679	)
Effect of exchange rate changes on cash		(14,526	)		3,793			2,679

Net increase (decrease) in cash and cash equivalents		60,642			(42,640	)		58,569
Cash and cash equivalents at beginning of year		40,119			82,759			24,190

Cash and cash equivalents at end of year	$	100,761		$	40,119		$	82,759

Supplemental cash flow information:
Interest paid, net of interest capitalized	$	12,590		$	6,597		$	15,120

Income taxes paid, net	$	3,294		$	4,695		$	1,853

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

GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Nature of Operations

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

Principles of Consolidation

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

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the 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 2008, 2007, and 2006, interest of $8.5 million, $6.2 million, and $2.4 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 2008, 2007 and 2006, are $16.7 million, $14.0 million, and $11.8 million, respectively, of costs for maintenance and repairs.

Goodwill and Intangibles

Goodwill primarily relates to the 2008 Rigdon Acquisition, the 2001 acquisition of Sea Truck Holding AS, and the 1998 acquisition of Brovig Supply AS. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 142, “Goodwill and Other Intangible Assets”, goodwill is tested for impairment using a fair value approach, at least annually. Management performed the required impairment testing and determined that there have been no impairments of goodwill during the years presented.

Our identifiable intangible assets are related to the value assigned to customer relationships as a result of the Rigdon Acquisition and will be amortized over a 12 year period. They will be reviewed for impairment when circumstances indicate their value may not be recoverable based on a comparison of fair value to carrying value. See Note 4 for further discussion related to the company’s identifiable intangible assets.

Fair Value of Financial Instruments

As of December 31, 2008, our financial instruments consist primarily of long-term debt, fair value hedges associated with firm contractual commitments for future vessel payments denominated in a foreign currency and interest rate swaps for a portion of the Senior Facility.

The forward contracts 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 new build contract. Additionally, during August 2007, we entered into a series of forward currency contracts relative to future milestone payments for six Keppel vessels under construction and two Aker Yard vessels in progress. 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 operation. As of December 31, 2008, the consolidated balance sheet has “Fair value hedges” on both the assets and liabilities sections reflecting the change in the fair value of the foreign currency contracts and purchase commitments.

The interest rate swap agreements are for a portion of the Senior Facility indebtedness that has fixed the interest rate at 4.725% on approximately $98.3 million of the Senior Facility. The interest rate swaps are accounted for as cash flow hedges. We report changes in the fair value of the cash flow hedges in accumulated other comprehensive income. The consolidated balance sheet also contains “Cash flow hedges” on the liability section reflecting the fair value of the interest rate swaps.

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 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

Income taxes are accounted for in accordance with the provisions of SFAS No. 109, “Accounting for Income Taxes”. We recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in the financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the difference between the financial statement carrying amounts and tax bases of assets and liabilities using enacted tax rates and laws in effect in the years in which the differences are expected to reverse. The likelihood and amount of future taxable income and tax planning strategies are included in the criteria used to determine the timing and amount of tax benefits recognized for net operating loss and tax credit carryforwards in the consolidated financial statements.

In 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109.” FIN 48 clarifies the accounting for uncertainty in income taxes recognized under SFAS No. 109. FIN 48 prescribes 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. On January 1, 2007, we adopted FIN 48. 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, in accordance with SFAS No. 52, “Foreign Currency Translation”. 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. 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, 2008, 2007 and 2006, we reported net foreign currency gains (losses) in the amount of $(2.0) million, $(2.0) million and ($1.7) 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; however, allowances for doubtful accounts and write-offs in 2009 may be larger than they have been in the past if economic conditions continue to deteriorate.

In 2008 and 2007, no single customer accounted for 10% or more of total consolidated revenue. Under multiple contracts in the ordinary course of business, Royal Dutch Shell accounted for 10.4% of total consolidated revenue in 2006.

Stock-Based Compensation

We adopted SFAS No. 123R effective January 1, 2006 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 under SFAS No. 123R 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 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, is required by SFAS No. 123 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

Earnings Per Share

Basic EPS is computed by dividing net income 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, 2008, 2007 and 2006 is as follows (in thousands, except per share amounts):


	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


	Year ended December 31, 2007
	Net		Weighted		Per Share
	Income		Average Shares		Amount
Income per share, basic	$	98,975		22,435	$	4.41

Dilutive effect of common stock options		—		624

Income per share, diluted	$	98,975		23,059	$	4.29


	Year ended December 31, 2006
	Net		Weighted		Per Share
	Income		Average Shares		Amount
Income per share, basic	$	89,729		20,377	$	4.40

Dilutive effect of common stock options		—		598

Income per share, diluted	$	89,729		20,975	$	4.28

Impairment of Long-Lived Assets

SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”, requires that long-lived assets be reviewed 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 in accordance with SFAS No. 144 is permanent and may not be restored. We did not record any significant impairment write-downs of our long-lived assets during 2008, 2007 or 2006.

Reclassifications

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

New Accounting Pronouncements

In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141 (revised 2007), “Business Combinations” (“SFAS No. 141R”) which replaces SFAS No. 141, “Business Combinations”. SFAS No. 141R applies to all transactions or other events in which an entity obtains control of one or more businesses, and combinations achieved without the transfer of consideration. SFAS No. 141R establishes principles and requirements for how the acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any noncontrolling interest in the acquiree, and if applicable the goodwill acquired in the business combination. SFAS No. 141R also determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. This Statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008, and an entity may not apply it before that date.

In December 2007, the FASB issued Statement of Financial Accounting Standards No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an Amendment of ARB No. 51” (“SFAS No. 160”). SFAS No. 160 amends Accounting Research Bulletin No. 51, “Consolidated Financial Statements” to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. Where applicable, this statement provides guidance for consistency in reporting noncontrolling interests. SFAS No. 160 is effective for financial statements issued for fiscal years beginning on or after December 15, 2008. We have evaluated SFAS No. 160 and have determined that it will not have an impact on our results of operations or financial position.

In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161 “Disclosures about Derivatives Instruments and Hedging Activities”. Over the last several years the use of derivative instruments and hedging activities have increased significantly. There is some concern that the existing disclosure requirements in FASB statement No. 133 “Accounting for Derivatives Instruments and Hedging Activities” do not provide adequate information about how derivative and hedging affect an entity’s financial position, financial performance, and cash flow. SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities, and thereby improves the transparency of financial reporting. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The new standard will require disclosures only and will have no impact on our consolidated financial position.

In February 2008, the FASB issued FASB Staff Position No. (FSP) FAS 157-2 “Effective Date of FASB Statement No. 157”, which delays the effective date of SFAS No. 157, “Fair Value Measurements” for non financial assets and non financial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis. FSP FAS 157-2 defers the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008 and interim periods within those fiscal years for items within the scope of this FSP. We have evaluated FSP FAS 157-2 and have determined that it will not have an impact on our results of operations or financial position.

In April 2008, the FASB issued FSP FAS 142-3, “Determination of the Useful Life of Intangible Assets”. FSP FAS 142-3 amends the factor that should be considered in developing renewal or extension assumptions used to determine the useful life of recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets”. FSP FAS 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years. We have evaluated FSP FAS 142-3 and have determined that it will not have an impact on our results of operations or financial position.

In June 2008, the FASB released FSP EITF 03-06-1 on Emerging Issues Task Force Issue No. 03-6, “Participating Securities and the Two-Class Method under FASB Statement No. 128”. FSP EITF 03-06-1 staff position concluded that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of EPS pursuant to the two-class method. FSP EITF 03-06-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. We have evaluated FSP EITF 03-06-1 and have determined that it will not have an impact on our results of operations or financial position.

In October 2008, the FASB issued FSP FAS 157-3 “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active”. FSP FAS 157-3 clarifies the application of the SFAS No. 157, “Fair Value Measurements”, in a market that is not active and illustrates key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. FSP FAS 157-3 is effective upon issuance. We have evaluated FSP FAS 157-3 and have determined that it will not have an impact on our results of operations or financial position.

In December 2008, the FASB issued FSP FAS 132(R)-1, “Employers’ Disclosures about Pensions and Other Postretirement Benefits”, to provide guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. The objectives of the disclosures about plan assets in an employer’s defined benefit pension or other postretirement plan are to provide users of financial statements with an understanding of how investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies, the major categories of plan assets, the inputs and valuation techniques used to measure the fair value of plan assets, the effect of fair value measurements and significant concentrations of risk within plan assets. The new standard will require disclosures only and will have no impact on our consolidated financial position. The disclosures about plan assets required by FSP FAS 132 (R)-1 shall be provided for fiscal years ending after December

15, 2009. Upon initial application, the provisions of FSP FAS 132 (R)-1 are not required for earlier periods that are presented for comparative purposes.

(2) RIGDON ACQUISITION

On July 1, 2008, under the terms of a Membership Interest and Stock Purchase Agreement, we acquired 100% of the membership interests of Rigdon Marine Holdings, L.L.C. (“Rigdon Holdings”) and all the shares of common stock of Rigdon Marine Corporation (“Rigdon Marine”, together with Rigdon Holdings, “Rigdon”) not owned by Rigdon Holdings 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”). We financed the cash portion of the consideration with cash on hand and borrowing of $140.9 million under our current $175 million revolver, which borrowing took place during the second quarter of 2008. In conjunction with the Rigdon Acquisition, we assumed and immediately repaid the outstanding balance of $32.8 million on a construction loan facility maintained by Rigdon Holdings. At July 1, 2008, Rigdon operated a fleet of 22 technologically advanced offshore supply vessels primarily in the domestic Gulf of Mexico, with six additional vessels under construction to be delivered by the second quarter of 2009, four of which have been delivered.

As of July 1, 2008, the purchase price was allocated to the acquired company based on the fair values as follows (in thousands):


Consideration:
Cash	$	150,000
Purchase price adjustments		2,621
Common stock		133,151

Net consideration		285,772
Debt assumed		268,935

Purchase Price	$	554,707


Net book value of acquisition	$	57,139
Elimination of minority interest		7,661
Vessels step-up to fair market value		172,201
Construction in progress step-up for fair market value		10,500
Intangibles step-up to fair market value		34,598
Deferred income taxes		(83,138	)
Pre-acquisition goodwill		(7,200	)
Restructuring liabilities		(1,970	)
Goodwill		97,202
Adjustment to book value		(1,221	)

	$	285,772

The purchase price allocation of the Rigdon Acquisition has been recorded at fair value at the completion of the acquisition, with the excess of the purchase price over the sum of these fair values recorded as goodwill. The amounts reflected in the table below are based on estimates of fair market values (in thousands).


Depreciable vessels and equipment	$	441,415
Construction in progress		46,982
Customer relationships		34,598

Customer relationships represent a key intangible asset that has a separate and distinct value apart from both the purchased tangible assets and goodwill. The customer relationships are primarily with large, stable customers with whom Rigdon has had long-term relationships based on the experience of management in the industry, the nature and size of the customers, and the nature of the industry. The customer relationships were valued using the excess earning method under the income approach. The method reflects the present value of the operating cash flows generated by the existing customer relationships after taking into account the cost to realize the revenue, and an appropriate discount rate to reflect the time value and risk associated with the invested capital. This balance will be amortized using the straight-line method over a 12 year period based on the estimated attrition rates and computation of the incremental value derived from the existing relationships.

In conjunction with the Rigdon Acquisition we acquired a 24.5% interest in a joint venture that provides crew boat services to the U.S. Gulf of Mexico market. The joint venture is accounted for under the equity method and the investment amount is included in Deferred costs and other assets on our balance sheet. We have also entered into an arrangement with the joint venture’s lender that requires us, in the event of a default by the joint venture on its obligation to a bank, to purchase the joint venture’s indebtedness from the bank. The maximum exposure under this potential obligation is $3.5 million.

The pro forma effect of the acquisition and the associated financing on the historical results for the twelve months periods ending December 31, 2008, 2007 and 2006 are presented in the following table (in thousands, except earnings per share):


	Twelve Months Ended
	December 31,
	2008		2007		2006
Revenue	$	466,787	$	377,707	$	308,632
Operating income		226,887		154,536		127,001
Net income		188,939		98,278		90,299
Basic earnings per share	$	7.96	$	4.38	$	4.43

With operations in the U.S. Gulf of Mexico, we are subject to the Merchant Marine Act of 1920 (Jones Act), which requires that vessels carrying cargo between U.S. ports, which is known as coastwise trade, be documented under the laws of the United States and controlled by U.S. citizens.

(3) VESSEL ACQUISITIONS AND DISPOSITIONS

From our inception, we have actively expanded our fleet through the purchase of existing vessels as well as through new construction. During 2006, we took delivery of two new construction vessels, the Sea Guardian and the Sea Sovereign. In 2007 and 2008, we added another seven new build vessels to our fleet.

In connection with the Rigdon Acquisition, we acquired construction contracts for six vessels, three which delivered in 2008, one which has been delivered in the first quarter of 2009, and the remaining two of which are expected to be delivered during the second quarter of 2009. In total, we spent approximately $108.6 million related to new vessels construction in 2008.

The following table illustrates the delivery timeline of the new build vessels:


Vessels Currently Under Construction

			Expected	Length						Expected
Vessel	Region	Type	Delivery	(feet)		BHP		DWT		Cost

										(millions)
Aker 726	N. Sea	PSV	Q4 2009		284		10,600		4,850	$	45.4
Aker 727	N. Sea	PSV	Q2 2010		284		10,600		4,850	$	45.4
Sea Cherokee	SEA	AHTS	Q1 2009		250		10,700		2,700	$	24.5
Sea Comanche	SEA	AHTS	Q2 2009		250		10,700		2,700	$	24.4
Blacktip	Americas	FSV	Q2 2009		181		7,200		543	$	9.2	⁽¹⁾
Tiger	Americas	FSV	Q3 2009		181		7,200		543	$	9.2	⁽¹⁾
Bender 1	Americas	PSV	Q1 2010		245		5,380		3,000	$	25.5
Bender 2	Americas	PSV	Q2 2010		245		5,380		3,000	$	25.5
Bender 3	Americas	PSV	Q3 2010		245		5,380		3,000	$	25.5
Remontowa 20	TBD	AHTS	Q2 2010		230		10,000		2,150	$	26.9
Remontowa 21	TBD	AHTS	Q3 2010		230		10,000		2,150	$	26.9


(1)		The estimated cost does not represent the actual construction costs, but includes our purchase price allocation plus all construction costs payable after the closing of the Rigdon Acquisition.

Our strategy has been to sell older vessels in our fleet when the appropriate opportunity arises. Consistent with this strategy, in September 2006 we completed the sale of one of our older Southeast Asia based PSVs, the Highland Patriot, and in October 2006 we sold the North Sea based Sentinel. During 2007, we sold the North Sea based North Prince and Southeast Asia based Sem Courageous, Sea Explorer and Sea Endeavor. In the second quarter of 2008, we completed the sale of two pre-1985 built AHTS vessels, the Sea Diligent and the North Crusader, for proceeds of $21.0 million recognizing a gain of $16.4 million. Additionally, in

the third quarter of 2008, we sold the Sem Valiant and the Sea Eagle, each older Southeast Asia based AHTS, for proceeds of $2.9 million recognizing a gain of $2.3 million. In the fourth quarter of 2008 the North Fortune, a PSV built in 1983, was sold for $19.0 million, generating a gain of $16.1 million. We feel the sale of these older vessels fits our long-term strategy of selling older vessels when attractive opportunities arise.

(4) GOODWILL AND INTANGIBLES

Changes to goodwill are as follows:


	2008			2007		2006
	(In thousands)
Balance, January 1,	$	34,264		$	29,883	$	27,628
Adjustment related to current year acquisition		97,202			—		—
Impact on foreign currency translation and adjusment		(7,485	)		4,381		2,255

Balance, December 31,	$	123,981		$	34,264	$	29,883

Intangible assets of $33.2 million, including accumulated amortization of $1.4 million, as of December 31, 2008 are recorded at cost and are amortized on a straight-line basis over the years expected to be benefited, currently estimated to be 12 years. Amortization expense related to intangible assets for the year ended December 31, 2008, was $1.4 million. Annual amortization expense related to existing intangible assets for years 2009 through 2013 is expected to be $2.9 million per year.

(5) LONG-TERM DEBT

Our long-term debt at December 31, 2008 and 2007 consisted of the following:


	2008			2007
	(In thousands)
Secured Reducing Revolving Loan Facility	$	84,250		$	—
Senior Facility		153,035			—
Subordinated Facility		85,000			—
7.75% Senior Notes due 2014		160,000			160,000

	$	482,285		$	160,000

Less: Current maturities of long-term debt		(18,970	)		—
Debt discount, net		(374	)		(442	)

Total	$	462,941		$	159,558

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


Year	Debt Maturity
	(In thousands)
2009	$	18,970
2010		219,065
2011		—
2012		—
2013		84,250
Thereafter		160,000

Total	$	482,285

Senior Notes

	•		Prior to July 15, 2009, we may redeem all or part of the 7.75% senior notes by paying a make-whole premium, plus accrued and unpaid interest, and, if any, liquidated damages.

	•		The 7.75% senior notes may be callable beginning on July 15 of 2009, 2010, 2011, and 2012 and thereafter at redemption prices of 103.875%, 102.583%, 101.292%, and 100% of the principal amount, respectively, plus accrued interest.

At December 31, 2008, we had financial instruments that are potentially sensitive to changes in interest rates including the 7.75% senior notes, which are due July 15, 2014. They have a stated interest rate of 7.75% and an effective interest rate of 7.77%. At December 31, 2008, the fair value of these notes, based on quoted market prices, was approximately $120.8 million, as compared to a carrying amount of $159.6 million.

Bank Credit Facilities

We currently have a $175 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 million allocated to GulfMark Offshore, Inc.; $60 million allocated to Gulf Offshore N.S. Limited, a U.K. wholly owned subsidiary; $30 million allocated to GulfMark Rederi AS, a Norwegian wholly owned subsidiary; and $60 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, 2008, we were in compliance with all covenants.

$224 Million Senior Secured Credit Facility Agreement (“Senior Facility”) and $85 Million Subordinated Secured Credit Facility Agreement (“Subordinated Facility”)

The Senior Facility bears interest at the rate of LIBOR plus 125 basis points and principal is due at the rate of 0.833% per month of the outstanding principal on each vessel beginning one month after delivery of the vessel with a final payment due on maturity (currently $19 million per year). The Senior Facility is subject to financial covenants consistent with those of our Secured Reducing Revolving Credit Loan Facility, contains customary other covenants and events of default, and is secured by a Preferred Fleet Mortgage on the 23 vessels financed under the Senior Facility. At December 31, 2008, we were in compliance with all covenants.

The Subordinated Facility bears interest at the rate of LIBOR plus 200 basis points. There are no scheduled principal repayments before the maturity date and no principal payments may be made until the Senior Facility is repaid in full. The Subordinated Facility is also subject to the same financial covenants as the Senior Facility and contains other customary covenants and events of default. The facility is secured by a Subordinated Second Fleet Mortgage on 20 vessels and a subordination agreement which grants the Senior Facility lenders certain preferences over the Subordinated Facility lenders for payments of principal and interest and in exercising remedies over the security interests held by them. At December 31, 2008 we were in compliance with all covenants.

There are two interest rate swap agreements for a portion of both the Senior Facility and the Subordinated Facility that have the effect of fixing the interest rate at 4.725% on approximately $98.3 million of the outstanding indebtedness. The interest rate swaps are accounted for as cash flow hedges.

Both facilities mature on June 30, 2010 and an additional fee of 0.15% of the facility amount is due to the lenders if either facility is not refinanced prior to December 31, 2009. In addition, we have agreed to financial covenants that are consistent with those in our existing Secured Reducing Revolving Credit Loan Facility.

Other Debt

In 2006 we had debt related to a joint venture interest we entered into in conjunction with our new build vessel program. The joint venture was created for the construction of two North Sea vessels. We purchased 100% of the vessels out of the joint venture in 2007.

As part of the Rigdon Acquisition, we acquired an obligation to assume from a bank the debt of an equity method joint venture partner in the event of a default by the joint venture. The maximum potential obligation is $3.5 million.

(6) INCOME TAXES

In late 2007, Norway enacted tonnage tax legislation that repealed the previous tonnage tax system which had been in effect from 1996 to 2006, and created a new tonnage tax system from January 2007 forward. Excluding the ten year pay-out described below of Norwegian taxes resulting from the repeal of the pre-2007 tonnage tax law, the tonnage tax regimes in the North Sea significantly reduce the cash required for taxes in that region. As a result of this legislation, we are now required to pay the tax on the accumulated untaxed shipping profits as of December 31, 2006 with two-thirds of the liability being payable in equal installments over ten years, while the remaining one-third of the tax liability can be met over fifteen years through qualified environmental expenditures on vessels owned by any of our 90% or greater owned subsidiaries. Any remaining portion of the environmental part of the liability at the end of fifteen years would be payable at that time. However, in January 2009, the Norwegian tax authority announced a change to the environmental fund regulations under which the fifteen year payment period has been abolished with no mandatory time limit on repayment of the environmental portion of the liability. As of December 31, 2008, our total US$ equivalent of the NOK liability for the repealed Norwegian tonnage tax was $17.8 million. The first annual cash payment of $2.0 million was paid in 2008, the second installment due in 2009 is classified on our balance sheet as current income taxes payable and the $16.5 million remainder is classified on our balance sheet as Other income taxes payable. Of this amount, $10.2 million is payable over eight years and $6.3 million is the one-third environmental portion of the total liability, which we expect will be fully expended in accordance with the regulation, and related rules and guidelines. The abolishment of the payment period time limit eliminates the $6.3 million tax liability, which will be recorded as a credit to our tax provision in 2009.

Substantially all of our tax provision is for taxes unrelated to our exempt Singapore based and UK and Norway tonnage tax qualified shipping activities. 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.

Effective January 1, 2008, Mexico legislated a new revenue based tax, which in effect creates an alternative minimum tax payable to the extent that the new revenue based tax exceeds the current income tax liability. The enacted tax rates are as follows: 16.5% for 2008, 17% for 2009 and 17.5% for 2010 and beyond. Additionally, in light of this legislation we determined that it is more likely than not we will not realize any economic benefit from the future utilization of our Mexican tax loss carryforwards, and as such we established a net valuation allowance as described below.

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


	Year Ended December 31,
	2008		2007			2006
U.S.	$	7,109	$	(9,748	)	$	(10,583	)
Foreign		188,418		138,943			103,364

	$	195,527	$	129,195		$	92,781

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


	2008								2007										2006
	Current		Deferred		FIN 48		Total		Current		Deferred			FIN 48		Total			Current		Deferred			Total
U.S.	$	432	$	2,437	$	—	$	2,869	$	53	$	(3,955	)	$	—	$	(3,902	)	$	—	$	(6,309	)	$	(6,309	)
Foreign		2,385		981		5,508		8,874		29,814		3,565			743		34,122			5,449		3,912			9,361

	$	2,817	$	3,418	$	5,508	$	11,743	$	29,867	$	(390	)	$	743	$	30,220		$	5,449	$	(2,397	)	$	3,052

The mix of our operations within various taxing jurisdictions affects our overall tax provision. As a result of the Rigdon Acquisition, in 2008 our U.S. federal statutory income tax rate increased from 34% to 35%. 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:


	2008			2007			2006
U.S. federal statutory income tax rate		35.0	%		34.0	%		34.0	%
Effect of foreign operations		(29.3	)		(10.2	)		(30.0	)
Valuation allowance		0.5			0.4			0.7
Other		(0.2	)		(0.8	)		(1.4	)

Total		6.0	%		23.4	%		3.3	%

Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities for financial reporting purposes and such amounts as measured by tax laws and regulations. The components of the net deferred tax assets and liabilities at December 31, 2008 and 2007 are as follows:


	December 31,
	2008			2007
	(In thousands)
Deferred tax assets
Accruals currently not deductible for tax purposes	$	6,166		$	3,762
Net operating loss carryforwards		30,741			18,727
Foreign and other tax credit carryforwards		6,860			4,364

		43,767			26,853
Less valuation allowance		(9,763	)		(9,092	)

Net deferred tax assets	$	34,004		$	17,761


Deferred tax liabilities
Depreciation	$	(119,201	)	$	(16,714	)
Foreign income not currently recognizable		(1,586	)		(2,655	)
Other		(29,389	)		(1,124	)

Total deferred tax liabilities	$	(150,176	)	$	(20,493	)

Net deferred tax liability	$	(116,172	)	$	(2,731	)

As of December 31, 2008 and 2007, the total net deferred tax liability of $116.2 million and $2.7 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, 2008 and 2007 was an increase of $0.7 million and $4.2 million, respectively. As of December 31, 2008, we had net operating loss carryforwards, or NOLs, for income tax purposes totaling $67.8 million in the U.S., $7.6 million in Brazil, $6.3 million in Norway, and $9.1 million in Mexico that are, subject to certain limitations, available to offset future taxable income. The US NOLs, which we expect to fully utilize, will begin to expire beginning in 2019 through 2027. 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 $1.7 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 $1.8 million valuation allowance has been established for such NOLs. We also have foreign tax credit carryforwards of $3.0 million that will begin to expire in 2009. A valuation allowance has been established against the full amount of these credits less the tax benefit of the deduction.

We intend to permanently reinvest a portion of the unremitted earnings of our non-U.S. subsidiaries in their businesses. As a result, we have not provided for U.S. deferred taxes on the cumulative unremitted earnings of $661.1 million at December 31, 2008.

In 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109.” FIN 48 clarifies the accounting for uncertainty in income taxes recognized under SFAS No. 109. FIN 48 prescribes a more likely than not, or likelihood greater than 50%, recognition threshold and criteria for measurement of a tax position taken or expected to be taken in a tax return. On January 1, 2007, we adopted FIN 48. 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. FIN 48 also provides 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 balance sheet presentations for accrued income tax assets and liabilities, including any amounts for uncertain tax positions.

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


	2008		2007
	(in thousands)

Unrecognized tax benefits balance at January 1,	$	6,803	$	8,883
Gross increases for tax positions taken in prior years		3,007		1,713
Gross decreases for tax positions taken in prior years		—		(2,706	)
Decreases for settlements		—		(1,087	)
Lapse of statute of limitations		—		—

Unrecognized tax benefits balance at December 31, 2008	$	9,810	$	6,803

As of January 1, 2007, we had unrecognized net tax benefits of $8.9 million, including $4.9 million that was recorded as a reduction to retained earnings in connection with the adoption of FIN 48. We expect $1.3 million of our unrecognized tax benefits as of December 31, 2008 will be settled within twelve months. As of December 31, 2008, we are under tax examination, or may be subject to examination in the U. S. for years after 1998 and in seven major foreign tax jurisdictions with open years for one after 1995, one after 1998, one after 2000, one after 2003, two after 2004 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, 2008, we had accrued interest and penalties related to unrecognized tax benefits of $8.6 million. The amount of interest and penalties recognized in our tax provision for the year ended December 31, 2008 was $2.8 million.

(7) COMMITMENTS AND CONTINGENCIES

At December 31, 2008, 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, 2008, 2007 and 2006 was $1.8 million, $0.9 million, and $0.7 million, respectively. Future minimum rental commitments under these leases are as follows (in thousands):


	Minimum Rental
Year	Commitments
2009	$	1,684
2010		1,454
2011		1,244
2012		1,136
2013		982
Thereafter		2,288

Total	$	8,788

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 May 2, 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 April 1, 2010; 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 $0.4 million and $1.0 million at December 31, 2008 and 2007, respectively. All of these instruments have an expiration date within the next year. In the past, no significant claims have been made against these financial instruments. Management believes the likelihood of demand for payment under these instruments is remote and expects no material cash outlays to occur from these instruments.

(8) EQUITY INCENTIVE PLANS

Stock Options and Stock Option Plans

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.

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.

Under the terms of our 1987 Employee Stock Option Plan, or 1987 Employee Plan, options were granted to employees to purchase our common stock at specified prices. On May 20, 1997, the 1987 Employee Plan expired and, therefore, no additional shares were reserved for granting of options under this plan, and at December 31, 2008, no options remained 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. The following table summarizes the activity of our stock option incentive plans during the indicated periods.


	2008				2007					2006
			Weighted					Weighted					Weighted
			Average					Average					Average
			Exercise					Exercise					Exercise
	Shares		Price		Shares			Price		Shares			Price

		789,650	$	14.33		904,150		$	13.63		1,083,470		$	11.98
Granted		—		—		—			—		—			—
Forfeitures		—		—		—			—		—			—
Exercised		116,000		16.56		(114,500	)		8.78		(179,320	)		3.70

Outstanding at end of year		673,650	$	13.94		789,650		$	14.33		904,150		$	13.63

Exercisable shares and weighted average exercise price		673,650	$	13.94		789,650		$	14.33		904,150		$	13.63
Shares available for future grants at December 31, 2008:
1993 Non-Employee Director Stock Option Plan		360,000				360,000					360,000
1997 Incentive Equity Plan		1,084,795				1,218,914					190,100
2005 Non-Employee Director Share Incentive Plan		77,900				99,000					120,100

The following table summarizes information about stock options outstanding at December 31, 2008:


	Outstanding					Exercisable
			Weighted		Weighted			Weighted
			Average		Average			Average
Range of Exercise Prices	Shares		Exercise Price		Remaining Life	Shares		Exercise Price

$6.58 to $10.06		244,000	$	7.26	0.56 years		244,000	$	7.26
$13.10 to $17.44		327,650	$	16.63	2.78 years		327,650	$	16.63
$19.37 to $21.25		102,000	$	21.21	3.37 years		102,000	$	21.21

		673,650	$	13.94			673,650	$	13.94

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 SFAS No. 123R, 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” of the “Notes to the Consolidated Financial Statements”.

ESPP

In May 2002, the shareholders approved our employee stock purchase plan, or ESPP. The ESPP is available to all our U.S. employees and our participating subsidiaries and is a qualified plan as defined by 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. Our U.K. employees are eligible to purchase our stock through a separate plan modified to meet the requirements of the U.K. tax authorities. The benefits available to those employees are substantially similar to those in the U.S. 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 SFAS No. 123R, Share-Based Payment, 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, 2008, there were 294,379 shares remaining in reserve for future issuance. See Note 1 “Nature of Operations and Summary of Significant Accounting Policies — Stock-Based Compensation” of the “Notes to the Consolidated Financial Statements”.

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, 2008, a total of $2.3 million had been deferred into the Prime plus 2% portion of the plan.

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

(9) EMPLOYEE BENEFIT PLANS

401(k)

We offer a 401(k) plan to all of our U.S. employees and provide matching contribution to those employees that participate. The matching contributions paid by us totaled $839,655, $90,000 and $24,000 for the years ended December 31, 2008, 2007 and 2006, respectively.

Multi-employer Pension Obligation

There currently is no provision within the plan to refund excess contributions, which, if it were to occur in future evaluations, would be anticipated to be adjusted against the remaining liability. Therefore, as allowed under the terms of the assessment, we plan to pay the liability over eight annual installments, with applicable interest charges. 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.

Norwegian Pension Plans

The Norwegian benefit pension plans include approximately seven of our office employees and 248 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, 2008 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):


	2008			2007
Change in Benefit Obligation
Benefit obligation at beginning of the period	$	6,707		$	5,545
Benefit periodic cost		517			683
Interest cost		229			284
Benefits paid		(248	)		(298	)
Actuarial gain/loss		(114	)		(327	)
Translation adjustment		(1,476	)		820

Benefit obligation at year end	$	5,615		$	6,707


	2008			2007
Change in Plan Assets
Fair value of plan assets at beginning of the period	$	4,103		$	3,326
Actual return on plan assets		185			208
Contributions		703			835
Benefits paid		(99	)		(112	)
Administrative fee		(32	)		(41	)
Actuarial gain/loss		(216	)		(605	)
Translation adjustment		(903	)		492

Fair value of plan assets at end of year	$	3,741		$	4,103


	2008		2007

Funded status	$	1,874	$	2,603
Social security		286		400
Unrecognized net actuarial gain and other prepaid benefit cost		—		—

Net obligation including social security	$	2,160	$	3,003

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


	2008		2007

Deferred costs and other assets	$	152	$	233
Other liabilities		2,312		3,237


	2008			2007
Components of Net Period Benefit Cost
Service cost	$	517		$	684
Interest cost		229			284
Return on plan assets		(185	)		(208	)
Administrative fee		32			41
National Insurance (social security) contribution		50			127
Recognized net actuarial loss		145			299

Net periodic benefit cost	$	788		$	1,227

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	2008			2007
Discount rate		4.3	%		4.7	%
Return on plan assets		6.3	%		5.8	%
Rate of compensation increase		4.5	%		4.5	%

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 was reviewed. The asset allocations at the measurement date were as follows:


	2008			2007
Equity securities		9	%		21	%
Debt securities		65	%		56	%
Property		23	%		18	%
Other		3	%		6	%

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 $5.6 million and $3.7 million, respectively for December 31, 2008, and $6.7 million and $4.1 million, respectively for December 31, 2007. We expect to contribute approximately $0.7 million to the Norwegian pension plan in 2009. No plan assets are expected to be returned to us in 2009.

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


Year ended December 31,	Benefit Payments
2009	$	257
2010		267
2011		277
2012		288
2013		299

Total	$	1,388

(10) STOCKHOLDERS’ EQUITY

Common Stock Issuances

We have established an Employee Stock Purchase Plan, or ESPP, which provides employees with a means of purchasing our common stock. During 2008, 14,973 shares were issued through the ESPP, generating approximately $0.5 million in proceeds. The provisions of the ESPP are described above in Note 8 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 159,256 and 158,102 restricted shares of our stock were granted to certain officers and key employees in 2008 and 2007, respectively, pursuant to our 1997 Incentive Equity Plan described above in Note 8, with an aggregate market value of $7.4 million and $6.2 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.

On December 4, 2006, we raised approximately $76.8 million, net of offering costs of $0.2 million, through the sale of 2,000,000 shares of common stock pursuant to our registration statement on Form S-3, Reg. No. 333-133563, and prospectus supplement. The sale was underwritten by Jefferies & Company, Inc. The proceeds were used to repay the outstanding portion of the credit facility, corporate working capital needs, and to partly fund future progress payments for the delivery of new build vessels included in our construction program.

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.

(11) FAIR VALUE MEASUREMENTS

In the first quarter of 2008, we adopted SFAS Statement No. 157 Fair Value Measurements. It established a framework for measuring fair value and expanded disclosures about fair value measurements. The adoption of SFAS 157 had no impact on our financial position or results of operations

SFAS 157 applies to all assets and liabilities that are measured and reported on a fair value basis. This enables the reader to assess the inputs used to develop those measurements by establishing a hierarchy for ranking the quality and reliability of the information used to determine fair values. The statement requires that each asset and liability carried at fair value be classified into one of the following categories:

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

Strategy and Risk — When applicable we may use derivative financial instruments in limited instances for other than trading purposes to assist in managing our overall exposure to fluctuations in interest rates and foreign currency. By policy we do not use derivative financial instruments for speculative purposes. Derivative financial instruments qualifying for hedge accounting must maintain a specified level of effectiveness between the hedging instrument and the item being hedged, both at inception and through out the hedged period. We formally document the nature and relationships between the hedging instruments and hedged items at inception, as well as our risk-management objectives, strategies for undertaking the various hedge transactions and method of assessing hedge effectiveness. Changes in the fair market value of derivative financial instruments that do not qualify for hedge accounting are charged to earnings.

Market and Credit Risk — We address market risk related to derivative financial instruments by selecting instruments with value fluctuations that correlate with the underlying hedged item. We manage credit risk related to derivative financial instruments, which is minimal, by requiring high credit standards for counterparties and periodic settlements. At December 31, 2008 and 2007, we were not required to provide collateral, nor had we received collateral, related to our hedging activities.

Fair Value Hedges for Purchase Commitment — We maintain fair value hedges associated with firm contractual commitments for future vessel payments denominated in a foreign currency. These forward contracts are designated as fair value hedges and are highly effective, as the terms of the forward contracts are the same as the purchase commitment under the new build contract. As prescribed by FAS 157, we recognize the fair value of our derivative assets as a Level 2 valuation. 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, 2008. At December 31, 2008, the fair value of our derivates was approximately $7.8 million.

Interest Rate Cash Flow Hedges — We have interest rate swap agreements for a portion of the Senior Facility indebtedness that has the effect of fixing interest rate at 4.725% on approximately $98.3 million of the Senior Facility. The interest rate swaps are accounted for as cash flow hedges. As prescribed by SFAS 157, we recognize the fair value of our derivative assets as a Level 2 valuation. We determined the fair value of our derivative financial instrument position based upon a series of calculations that include present value calculations, involving our principal amount and estimated future LIBOR rates. We report changes in the fair value of cash flow hedges in accumulated other comprehensive income and as of December 31, 2008, $6.1 million has been recorded.

(12) RELATED PARTY TRANSACTIONS

We entered into a purchase and sale agreement with one of our officers to purchase his former residence in connection with his relocation to our corporate office in Houston, Texas. We entered into a sale contract for the residence and closed the transaction during 2006.

(13) OPERATING SEGMENT INFORMATION

Business Segments

We operate our business based on geographical locations and maintain the following operating segments: the North Sea, Southeast Asia and the Americas. Our chief operating decision-maker regularly reviews financial information about each of these operating segments in deciding how to allocate resources and evaluate performance. The business within each of these geographic regions has similar economic characteristics, services, distribution methods and regulatory concerns. All of the operating segments are considered reportable segments under SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information”.

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


	North			Southeast
	Sea			Asia			Americas			Other			Total
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


Total assets	$	390,678		$	189,472		$	730,458		$	246,360		$	1,556,967
Long-lived assets(a)(b)	$	341,553		$	159,288		$	651,445		$	141,208		$	1,293,494
Capital expenditures	$	23,805		$	45,089		$	39,733		$	1,072		$	108,626

Year Ended December 31, 2007
Revenue	$	241,664		$	41,257		$	23,105		$	—		$	306,026
Direct operating expenses		88,277			6,946			13,163			—			108,386
Drydock expense		10,369			1,832			405			—			12,606
General and administrative expense		12,439			1,118			1,488			17,266			32,311
Depreciation and amortization		24,914			2,657			2,913			139			30,623
Gain on sale of assets		(5,014	)		(7,154	)		—			(1	)		(12,169	)

Operating income (loss)	$	110,679		$	35,858		$	5,136		$	(17,404	)	$	134,269


Total assets	$	594,779		$	117,819		$	79,510		$	141,904		$	934,012
Long-lived assets(a)(b)	$	512,230		$	104,613		$	76,085		$	95,338		$	788,264
Capital expenditures	$	85,781		$	50,688		$	123		$	54,566		$	191,158

Year Ended December 31, 2006
Revenue	$	199,368		$	27,385		$	24,168		$	—		$	250,921
Direct operating expenses		71,245			6,445			14,185			—			91,875
Drydock expense		6,446			1,775			828			—			9,049
General and administrative expense		9,274			1,613			1,176			12,440			24,503
Depreciation and amortization		21,731			2,554			3,879			306			28,470
Gain on sale of assets		(10,237	)		—			—			—			(10,237	)

Operating income (loss)	$	100,909		$	14,998		$	4,100		$	(12,746	)	$	107,261


Total assets	$	476,342		$	59,163		$	84,877		$	130,447		$	750,829
Long-lived assets(a)(b)	$	427,677		$	51,246		$	81,851		$	41,098		$	601,872
Capital expenditures	$	4,484		$	22,198		$	148		$	20,636		$	47,466


(a)		Goodwill is included in the North Sea and Americas segment.

(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 2008, we had $72.5 million in revenue and $593.0 million in long-lived assets attributed to the United States, our country of domicile.

(14) UNAUDITED QUARTERLY FINANCIAL DATA

Summarized quarterly financial data for the two years ended December 31, 2008 and 2007 are as follows:


	Quarter
	First		Second		Third		Fourth
	(In thousands, except per share amounts)
2008
Revenue	$	83,348	$	81,893	$	124,616	$	121,883
Operating income		34,436		46,822		52,391		73,114
Net income		32,264		46,781		45,419		59,320
Per share (basic)		1.43		2.06		1.83		2.39
Per share (diluted)		1.40		2.00		1.78		2.35

2007
Revenues	$	65,513	$	74,341	$	74,717	$	91,455
Operating income		27,413		33,881		33,807		39,168
Net income		24,353		30,721		31,232		12,669
Per share (basic)		1.09		1.37		1.39		0.56
Per share (diluted)		1.06		1.32		1.35		0.55

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, 2008, 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, 2008. UHY LLP has issued an attestation report on management’s assessment of internal control over financial reporting, a copy of which is included in Part II, Item 8 of this annual report on Form 10-K.

(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, 2008, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. Other Information

NONE

PART III

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

ITEM 11. Executive Compensation(1)

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

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

ITEM 14. Principal Accounting Fees and Services(1)

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

PART IV

ITEM 15. Exhibits, Financial Statement Schedules

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

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

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

(3) Exhibits


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

3.1	Certificate of Incorporation, dated December 4, 1996	Filed herewith

3.2	Certificate of Amendment of Certificate of Incorporation, dated March 6, 1997	Exhibit 4.2 to our Registration Statement on Form S-3, Registration No. 333-153459 filed on September 12, 2008

3.3	Certificate of Amendment of Certificate of Incorporation, dated May 24, 2002	Exhibit 4.3 to our Registration Statement on Form S-3, Registration No. 333-153459 filed on September 12, 2008

3.4	Bylaws, dated December 5, 1996	Exhibit 3.3 to our Registration Statement on Form S-4, Registration No. 333-24141 filed on March 28, 1997

3.5	Amendment No. 1 to Bylaws	Exhibit 3.1 to our Form 8-K/A filed on September 17, 2007

4.1	See Exhibit Nos. 3.1, 3.2 and 3.3 for provisions of the Certificate of Incorporation and Exhibits 3.4 and 3.5 for provisions of the Bylaws defining the rights of the holders of Common Stock	Exhibit 3.1 filed herewith, Exhibits 4.2 and 4.3 to our Registration Statement on Form S-3, Registration No. 333-153459 filed on September 12, 2008, Exhibit 3.3 to our Registration Statement on Form S-4, Registration No. 333-24141 filed on March 28, 1997, and Exhibit 3.1 to our Form 8-K/A filed on September 17, 2007


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

4.2	Specimen Certificate for GulfMark Offshore, Inc. Common Stock, $0.01 par value	Exhibit 4.2 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997


4.3	Indenture, dated as of July 21, 2004, among GulfMark Offshore, Inc., as Issuer, 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

4.4	Registration Rights Agreement, dated July 21, 2004, among GulfMark Offshore, Inc. and the initial purchasers	Exhibit 4.5 to our quarterly report on Form 10-Q for the quarter ended September 30, 2004

4.5	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

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	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

10.11	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

10.12	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


		Filed Herewith or
		Incorporated by Reference
		from the
Exhibits	Description	Following Documents
10.13 `	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

10.14	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

10.15	Executive Nonqualified Excess Plan GM Offshore, Inc. Plan Document*	Exhibit 10.23 to our annual report on Form 10-K for the year ended December 31, 2001

10.16	Form of the Executive Nonqualified Excess Plan GM Offshore, Inc. Initial Salary Deferred Agreement*	Exhibit 10.24 to our annual report on Form 10-K for the year ended December 31, 2001

10.17	Employment Agreement effective December 31, 2006, made by and between GM Offshore, Inc. and Bruce A. Streeter*	Exhibit 10.1 to our current report on Form 8-K filed on January 30, 2007

10.18	Employment Agreement effective December 31, 2006, made by and between GM Offshore, Inc. and Edward A. Guthrie, Jr.*	Exhibit 10.2 to our current report on Form 8-K filed on January 30, 2007

10.19	Employment Agreement effective December 31, 2006, made by and between GM Offshore, Inc. and John E. Leech*	Exhibit 10.3 to our current report on Form 8-K filed on January 30, 2007

10.20	$85 Million Secured Reducing Revolving Loan and Letter of Credit Facility Agreement between GulfMark Offshore, Inc. and DnB NOR Bank ASA and others dated June 1, 2006	Exhibit 10.28 to our current report on Form 8-K filed on June 9, 2006


10.21	$60 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

10.22	$30 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

10.23	Charter Party dated July 31, 2002 between Enterprise Oil do Brasil Limitada and Gulf Marine [Serviços Maritimos] do Brasil Limitada	Exhibit 10.30 to our annual report on Form 10-K/A for the year ended December 31, 2004

10.24	General Form Contract between Keppel Singmarine Pte. Ltd. and GulfMark Offshore, Inc.	Exhibit 10.27 to our annual report on Form 10-K for the year ended December 31, 2005

10.25	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

10.26	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

10.27	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


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

10.28	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

10.29	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

10.30	Senior Secured Credit Facility Agreement among Rigdon Marine Corporation and DVB Bank NV, as Underwriter, Arranger, Agent, Security Trustee, Swap Bank and Book Manager, and the lenders that are parties thereto, dated December 28, 2005	Exhibit 10.11 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.31	Amendment No. 1 to Senior Secured Credit Facility Agreement among Rigdon Marine Corporation, DVB Bank NV, as Underwriter, Arranger, Agent, Security Trustee, Swap Bank and Book Manager, and the lenders that are parties thereto, dated February 28, 2006	Exhibit 10.12 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.32	Amendment No. 2 to Senior Secured Credit Facility Agreement among Rigdon Marine Corporation, DVB Bank NV, as Underwriter, Arranger, Agent, Security Trustee, Swap Bank and Book Manager, DVB Bank AG, as Swap Bank, and the lenders that are parties thereto, dated May 9, 2007	Exhibit 10.13 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.33	Amendment No. 3 to Senior Secured Credit Facility Agreement among Rigdon Marine Corporation, DVB Bank NV, as Underwriter, Arranger, Book Manager, Facility Agent and Security Trustee, DVB Bank AG, as Swap Bank, and the lenders that are parties thereto, dated July 1, 2008	Exhibit 10.14 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.34	Guaranty given by GulfMark Offshore, Inc. in favor of DVB Bank NV pursuant to Senior Secured Credit Facility Agreement, dated July 1, 2008	Exhibit 10.15 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.35	First Preferred Fleet Mortgage by Rigdon Marine Corporation in favor of DVB Bank NV dated as of December 28, 2005	Exhibit 10.16 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.36	Amendment No. 1 to First Preferred Fleet Mortgage dated July 1, 2008	Exhibit 10.17 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.37	Subordination Agreement between DVB Bank NV, as Agent for Senior Lenders, DVB Bank NV, as Agent for the Junior Lenders, and Rigdon Marine Corporation, as Borrower, dated July 1, 2008	Exhibit 10.18 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.38	Assignment, Assumption, Amendment and Restatement of Loan Agreement Providing for a US $85,000,000 Subordinated Secured Credit Facility between Bourbon Capital U.S.A., Inc., as Assignor, Rigdon Marine Corporation, as Borrower, DVB Bank NV, as Facility Agent and Security Trustee, and the lenders that are parties thereto, dated July 1, 2008	Exhibit 10.19 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008


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

10.39	Guaranty given by GulfMark Offshore, Inc. in favor of DVB Bank NV, pursuant to Assignment, Assumption, Amendment and Restatement of Loan Agreement, dated July 1, 2008	Exhibit 10.20 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.40	Second Preferred Fleet Mortgage by Rigdon Marine Corporation in favor of Bourbon Capital U.S.A., Inc. dated December 28, 2005, as supplemented by Supplement Nos. 1, 2, 3, 4, 5, 6 and 7, dated August 20, 2007, October 22, 2007, November 30, 2007, December 18, 2007, February 26, 2008, February 29, 2008 and June 27, 2008, respectively	Exhibit 10.21 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.41	Assignment of Second Preferred Fleet Mortgage between Bourbon Capital U.S.A., Inc., as Assignor, and DVB Bank NV, as Assignee, dated July 1, 2008	Exhibit 10.22 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.42	Amendment to Second Preferred Fleet Mortgage by Rigdon Marine Corporation in favor of DVB Bank NV, as Security Trustee, dated July 1, 2008	Exhibit 10.23 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.43	US $25,000,000 Secured Reducing Revolving Loan and Letter of Credit Facility Agreement between GulfMark Offshore, Inc. and DnB NOR Bank ASA, dated June 1, 2006, as Amended and Restated by a First Supplemental Agreement dated June 5, 2008	Exhibit 10.24 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.44	First Supplemental Agreement to Loan Agreement dated June 1, 2006 between GulfMark Offshore, Inc. and DnB NOR Bank ASA, dated June 5, 2008	Exhibit 10.25 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.45	US $60,000,000 Secured Reducing Revolving Loan Facility Agreement between GulfMark Far East PTE. LTD. and DnB NOR Bank ASA, dated June 5, 2008	Exhibit 10.26 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

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 E.A. Guthrie	Filed herewith

32.1	Section 906 Certification furnished for B.A. Streeter	Filed herewith

32.2	Section 906 Certification furnished for E.A. Guthrie	Filed herewith

SIGNATURES

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


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

Date: February 27, 2009

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


/s/ Bruce A. Streeter Bruce A. Streeter	Chief Executive Officer, President and Director (Principal Executive Officer)	February 27, 2009

/s/ Edward A. Guthrie Edward A. Guthrie	Executive Vice President, Finance (Principal Financial Officer)	February 27, 2009

/s/ Samuel R. Rubio Samuel R. Rubio	Vice President, Controller and Chief Accounting Officer (Principal Accounting Officer)	February 27, 2009

/s/ David J. Butters David J. Butters	Director	February 27, 2009

/s/ Peter I. Bijur Peter I. Bijur	Director	February 27, 2009

/s/ Marshall A. Crowe Marshall A. Crowe	Director	February 27, 2009

/s/ Louis S. Gimbel, 3rd Louis S. Gimbel 3rd	Director	February 27, 2009

/s/ Sheldon S. Gordon Sheldon S. Gordon	Director	February 27, 2009

/s/ Robert B. Millard Robert B. Millard	Director	February 27, 2009

/s/ Robert T. O’Connell Robert T. O’Connell	Director	February 27, 2009

/s/ Larry T. Rigdon Larry T. Rigdon	Director	February 27, 2009

/s/ Rex C. Ross Rex C. Ross	Director	February 27, 2009

INDEX TO EXHIBITS


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

3.1	Certificate of Incorporation, dated December 4, 1996	Filed herewith

3.2	Certificate of Amendment of Certificate of Incorporation, dated March 6, 1997	Exhibit 4.2 to our Registration Statement on Form S-3, Registration No. 333-153459 filed on September 12, 2008

3.3	Certificate of Amendment of Certificate of Incorporation, dated May 24, 2002	Exhibit 4.3 to our Registration Statement on Form S-3, Registration No. 333-153459 filed on September 12, 2008

3.4	Bylaws, dated December 5, 1996	Exhibit 3.3 to our Registration Statement on Form S-4, Registration No. 333-24141 filed on March 28, 1997

3.5	Amendment No. 1 to Bylaws	Exhibit 3.1 to our Form 8-K/A filed on September 17, 2007

4.1	See Exhibit Nos. 3.1, 3.2 and 3.3 for provisions of the Certificate of Incorporation and Exhibits 3.4 and 3.5 for provisions of the Bylaws defining the rights of the holders of Common Stock	Exhibit 3.1 filed herewith, Exhibits 4.2 and 4.3 to our Registration Statement on Form S-3, Registration No. 333-153459 filed on September 12, 2008, Exhibit 3.3 to our Registration Statement on Form S-4, Registration No. 333-24141 filed on March 28, 1997, and Exhibit 3.1 to our Form 8-K/A filed on September 17, 2007

4.2	Specimen Certificate for GulfMark Offshore, Inc. Common Stock, $0.01 par value	Exhibit 4.2 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997

4.3	Indenture, dated as of July 21, 2004, among GulfMark Offshore, Inc., as Issuer, 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

4.4	Registration Rights Agreement, dated July 21, 2004, among GulfMark Offshore, Inc. and the initial purchasers	Exhibit 4.5 to our quarterly report on Form 10-Q for the quarter ended September 30, 2004

4.5	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	Exhibit 10.12 to our Registration Statement on Form


		Filed Herewith or
		Incorporated by Reference
		from the
Exhibits	Description	Following Documents
	1993 Non-Employee Director Stock Option Plan)*	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	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

10.11	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

10.12	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

10.13	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

10.14	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

10.15	Executive Nonqualified Excess Plan GM Offshore, Inc. Plan Document*	Exhibit 10.23 to our annual report on Form 10-K for the year ended December 31, 2001

10.16	Form of the Executive Nonqualified Excess Plan GM Offshore, Inc. Initial Salary Deferred Agreement*	Exhibit 10.24 to our annual report on Form 10-K for the year ended December 31, 2001

10.17	Employment Agreement effective December 31, 2006, made by and between GM Offshore, Inc. and Bruce A. Streeter*	Exhibit 10.1 to our current report on Form 8-K filed on January 30, 2007

10.18	Employment Agreement effective December 31, 2006, made by and between GM Offshore, Inc. and Edward A. Guthrie, Jr.*	Exhibit 10.2 to our current report on Form 8-K filed on January 30, 2007

10.19	Employment Agreement effective December 31, 2006, made by and between GM Offshore, Inc. and John E. Leech*	Exhibit 10.3 to our current report on Form 8-K filed on January 30, 2007

10.20	$85 Million Secured Reducing Revolving Loan and Letter of Credit Facility Agreement between GulfMark Offshore, Inc. and DnB NOR Bank ASA and others dated June 1, 2006	Exhibit 10.28 to our current report on Form 8-K filed on June 9, 2006

10.21	$60 Million Secured Reducing Revolving Loan Facility	Exhibit 10.29 to our current report on Form 8-K filed


		Filed Herewith or
		Incorporated by Reference
		from the
Exhibits	Description	Following Documents
	Agreement between Gulf Offshore N.S. Limited and DnB NOR Bank ASA and others dated June 1, 2006	on June 9, 2006

10.22	$30 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

10.23	Charter Party dated July 31, 2002 between Enterprise Oil do Brasil Limitada and Gulf Marine [Serviços Maritimos] do Brasil Limitada	Exhibit 10.30 to our annual report on Form 10-K/A for the year ended December 31, 2004

10.24	General Form Contract between Keppel Singmarine Pte. Ltd. and GulfMark Offshore, Inc.	Exhibit 10.27 to our annual report on Form 10-K for the year ended December 31, 2005

10.25	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

10.26	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

10.27	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

10.28	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

10.29	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

10.30	Senior Secured Credit Facility Agreement among Rigdon Marine Corporation and DVB Bank NV, as Underwriter, Arranger, Agent, Security Trustee, Swap Bank and Book Manager, and the lenders that are parties thereto, dated December 28, 2005	Exhibit 10.11 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.31	Amendment No. 1 to Senior Secured Credit Facility Agreement among Rigdon Marine Corporation, DVB Bank NV, as Underwriter, Arranger, Agent, Security Trustee, Swap Bank and Book Manager, and the lenders that are parties thereto, dated February 28, 2006	Exhibit 10.12 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.32	Amendment No. 2 to Senior Secured Credit Facility Agreement among Rigdon Marine Corporation, DVB Bank NV, as Underwriter, Arranger, Agent, Security Trustee, Swap Bank and Book Manager, DVB Bank AG, as Swap Bank, and the lenders that are parties thereto, dated May 9, 2007	Exhibit 10.13 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.33	Amendment No. 3 to Senior Secured Credit Facility Agreement among Rigdon Marine Corporation, DVB Bank	Exhibit 10.14 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008


		Filed Herewith or
		Incorporated by Reference
		from the
Exhibits	Description	Following Documents
	NV, as Underwriter, Arranger, Book Manager, Facility Agent and Security Trustee, DVB Bank AG, as Swap Bank, and the lenders that are parties thereto, dated July 1, 2008

10.34	Guaranty given by GulfMark Offshore, Inc. in favor of DVB Bank NV pursuant to Senior Secured Credit Facility Agreement, dated July 1, 2008	Exhibit 10.15 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.35	First Preferred Fleet Mortgage by Rigdon Marine Corporation in favor of DVB Bank NV dated as of December 28, 2005	Exhibit 10.16 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.36	Amendment No. 1 to First Preferred Fleet Mortgage dated July 1, 2008	Exhibit 10.17 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.37	Subordination Agreement between DVB Bank NV, as Agent for Senior Lenders, DVB Bank NV, as Agent for the Junior Lenders, and Rigdon Marine Corporation, as Borrower, dated July 1, 2008	Exhibit 10.18 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.38	Assignment, Assumption, Amendment and Restatement of Loan Agreement Providing for a US $85,000,000 Subordinated Secured Credit Facility between Bourbon Capital U.S.A., Inc., as Assignor, Rigdon Marine Corporation, as Borrower, DVB Bank NV, as Facility Agent and Security Trustee, and the lenders that are parties thereto, dated July 1, 2008	Exhibit 10.19 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.39	Guaranty given by GulfMark Offshore, Inc. in favor of DVB Bank NV, pursuant to Assignment, Assumption, Amendment and Restatement of Loan Agreement, dated July 1, 2008	Exhibit 10.20 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.40	Second Preferred Fleet Mortgage by Rigdon Marine Corporation in favor of Bourbon Capital U.S.A., Inc. dated December 28, 2005, as supplemented by Supplement Nos. 1, 2, 3, 4, 5, 6 and 7, dated August 20, 2007, October 22, 2007, November 30, 2007, December 18, 2007, February 26, 2008, February 29, 2008 and June 27, 2008, respectively	Exhibit 10.21 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.41	Assignment of Second Preferred Fleet Mortgage between Bourbon Capital U.S.A., Inc., as Assignor, and DVB Bank NV, as Assignee, dated July 1, 2008	Exhibit 10.22 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.42	Amendment to Second Preferred Fleet Mortgage by Rigdon Marine Corporation in favor of DVB Bank NV, as Security Trustee, dated July 1, 2008	Exhibit 10.23 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.43	US $25,000,000 Secured Reducing Revolving Loan and Letter of Credit Facility Agreement between GulfMark Offshore, Inc. and DnB NOR Bank ASA, dated June 1, 2006, as Amended and Restated by a First Supplemental Agreement dated June 5, 2008	Exhibit 10.24 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.44	First Supplemental Agreement to Loan Agreement dated June 1, 2006 between GulfMark Offshore, Inc. and DnB NOR Bank ASA, dated June 5, 2008	Exhibit 10.25 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008

10.45	US $60,000,000 Secured Reducing Revolving Loan Facility Agreement between GulfMark Far East PTE. LTD. and DnB NOR Bank ASA, dated June 5, 2008	Exhibit 10.26 to our quarterly report on Form 10-Q for the quarter ended June 30, 2008


		Filed Herewith or
		Incorporated by Reference
		from the
Exhibits	Description	Following Documents
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 E.A. Guthrie	Filed herewith

32.1	Section 906 Certification furnished for B.A. Streeter	Filed herewith

32.2	Section 906 Certification furnished for E.A. Guthrie	Filed herewith