Edgar Filing: GULFMARK OFFSHORE INC

k10.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

R ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THESECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2007

£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THESECURITIES EXCHANGE ACT OF 1934

Commission file number 000-22853

GulfMark Offshore, Inc.

(Exact name of Registrant as specified in its charter)

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

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

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

Common Stock, $0.01 Par Value New York Stock Exchange

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

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x 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 x

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 x No o

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer" and "large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check One):

Large accelerated filer x Accelerated filer o Non-accelerated filer o

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2007, the last business day of the registrant’s most recently completed second fiscal quarter was $930,800,982 calculated by reference to the closing price of $51.22 for the registrant’s common stock on the NASDAQ Global Select Market on that date.

Number of shares of common stock outstanding as of February 28, 2008: 23,046,544

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 64

TABLE OF CONTENTS

		Page

PART I
Items 1 and 2.	Business and Properties	3
	General Business	3
	The Company	3
Item 1A.	Risk Factors	12
Item 1B.	Unresolved Staff Comments	16
Item 3.	Legal Proceedings	16
Item 4.	Submission of Matters to a Vote of Security Holders	16
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	16
Item 6.	Selected Consolidated Financial Data	18
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	33
Item 8.	Consolidated Financial Statements and Supplementary Data	34
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	59
Item 9A.	Controls and Procedures	59
Item 9B.	Other Information	59
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	60
Item 11.	Executive Compensation	60
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	60
Item 13.	Certain Relationships and Related Transactions, and Director Independence	60
Item 14.	Principal Accounting Fees and Services	60
PART IV
Item 15.	Exhibits and Financial Statement Schedules	60

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 11 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, 2007 includes as exhibits all required Sarbanes-Oxley Act Section 302 certifications by our CEO and CFO regarding the quality of our public disclosure. Each year, our CEO must certify to the New York Stock Exchange (NYSE) that he is not aware of any violation of NYSE corporation governance listing standards by us. As we have only been listed on the NYSE since July 2007, our CEO will certify as to fiscal year 2007 during fiscal year 2008 when due. 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 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 62 offshore support vessels in the following regions: 35 vessels in the North Sea, 13 vessels offshore Southeast Asia, four vessels offshore Brazil, two vessels in the Mediterranean Sea, three vessels offshore India, three vessels in the Gulf of Mexico and two offshore Africa. Our vessels in the Mediterranean Sea, offshore India, offshore West/South Africa and one of our vessels in the Gulf of Mexico are based in our North Sea segment.

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, upstream expenditures by oil and gas exploration and

development companies have been volatile throughout the first part of this decade. Beginning in the second half of 2004 and throughout 2007, oil and natural gas companies increased their exploration and development activities, after a period of reduced levels that started during 2002 and continued to mid-2004. 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 and vessel suitability 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.

Size of Vessel Fleet

The size of our fleet has increased by one to 62 vessels since December 31, 2006 with significant changes that occurred during the period as part of our fleet upgrade and modernization initiative. We added five new build program vessels to the fleet, thus, enhancing our capability to service customers in more demanding environments around the world. Over the same period we sold four of our older, smaller vessels, whose age averaged over 26 years, to buyers generally outside our normal market.

Vessel Additions Since December 31, 2006
Vessel	Region	Type	Year Built	Length (feet)	BHP	DWT	Month Delivered
Highland Prestige	N. Sea	LgPSV	2007	284	10,000	4,850	Apr 2007
North Promise	N. Sea	LgPSV	2007	284	10,000	4,850	Sep 2007
Sea Supporter	SEA	AHTS	2007	225	7,954	2,360	Oct 2007
Sea Cheyenne	SEA	AHTS	2007	250	10,700	2,700	Oct 2007
Sea Apache	SEA	AHTS	2008	250	10,700	2,700	Jan 2008

Vessels Sold Since December 31, 2006
Vessel	Region	Type	Year Built	Length (feet)	BHP	DWT	Month Sold
North Prince	N. Sea	LgPSV	1978	259	6,000	2,717	Jan 2007
Sem Courageous	SEA	SmAHTS	1981	191	3,900	1,200	Jun 2007
Sea Explorer	SEA	SmAHTS	1981	192	5,750	1,500	Sep 2007
Sea Endeavor	SEA	SmAHTS	1981	191	3,900	1,000	Oct 2007

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, 2006:

	Owned Vessels			Managed Vessels		Total Fleet
December 31, 2006		48			12		60
New Build Program		4			--		4
Vessel Additions		--			2		2
Vessel Sales		(4	)		--		(4	)
Out of Service		(1	)		--		(1	)
December 31, 2007		47			14		61
New Build Program		1			--		1
February 28, 2008		48			14		62

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:

•

Platform Support Vessels, or 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 or 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.

•

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

•

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.

•

Standby Rescue Vessels, or 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.

•

Crewboats, or Crew, 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 this category are also called fast support vessels, or FSVs. They are used primarily to transport cargo on a time-sensitive basis. We do not currently operate any vessels in this category.

•

Specialty Vessels, or SpVs, generally have special features to meet the requirements of specific jobs. The special features can include large deck spaces, high electrical generating capacities, slow controlled speed and varied propulsion thruster configurations, extra berthing facilities and long-range capabilities. These vessels are primarily used to support floating production storing and offloading, or FPSOs; diving operations; remotely operated vehicles, or 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.

•	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 North Sea Market

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 away from the larger companies. 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. During 2006 and 2007, due to a large number of drilling rig moves taking place in the North Sea, spot market (short-term contracts) rates for AHTSs reached record levels.

The North Sea market can be broadly divided into three areas: exploration, production platform support and field development or construction, including subsea services. The more volatile exploration area of the market represents the primary demand for AHTSs. While OSVs support the exploration segment, they also support the production and field construction segments, which generally are not affected by the volatility in demand for the AHTSs.

Our North Sea-based fleet, consisting of 43 vessels, is oriented toward support vessels which work in the more stable segments of production platform support and field development or construction, and includes 29 owned (22 PSVs, four AHTSs, and three SpV vessels) and 14 managed vessels. Onshore bases in Aberdeen, Scotland; Liverpool, England and Sandnes, Norway support these vessels. Vessels that are based in the North Sea but operate temporarily out of the region are included in our North Sea vessel count and related statistics, unless deployed to one of our other operating segments under long-term contracts.

The North Sea market was generally a very stable market from the early 1990’s through late 2001 with minor periods of disruption caused by fluctuating expenditures for oil and natural gas exploration and development, primarily by the major oil companies that dominated this market. In late 2000, commodity prices and increased drilling activity resulted in improved vessel utilization and day rates through 2001 and into the first part of 2002. Subsequent to the terrorist attacks on September 11, 2001, both oil and natural gas prices remained significantly higher; however, despite these higher commodity price levels, exploration and development activity in the region did not increase accordingly. At the same time, there was an increase in the number of new build vessels delivered into the market in 2002 through 2004, coupled with a reduction in demand for vessel services which resulted in the 2003-2004 period having the lowest utilization and day rates in the region in the last decade. While the number of high capacity vessels in this market remained fairly constant over the last ten years at approximately two hundred, over four hundred vessels of reasonably similar design capacity have gone into service in other international markets or displaced older equipment in the North Sea. These displaced vessels have subsequently mobilized to other international markets, either permanently or for temporary assignments.

There has also been 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. This was in part caused by legislative initiatives in the U.K. which made these properties attractive to the independents. The independent companies typically had shorter horizons with regard to exploration and development activities than the major oil and natural gas companies, which in turn resulted in a decline in the availability of long-term contracts for vessel services at economically attractive day rates. The consequence of this transformation and curtailment of activities by the major companies was an increase in the number of vessels available in the spot market, which in turn depressed both utilization of vessels and day rates. In the second quarter of 2004, an increase in long-term drilling rig contracts occurred in the North Sea, particularly in the Norwegian sector, which specifically related to the opening of the Barents Sea to exploration activities by the Norwegian government. In addition, several large projects, including the Orman Lange, Snovhit and Alvheim Field developments, resulted in oil and natural gas companies contracting drilling rigs to tender for vessel services in support for these rigs. Late in the third quarter of 2004, utilization and day rates for vessels in the region began to improve with some consistency for the remainder of 2004.

Starting in 2005 and continuing throughout 2007, there were significant improvements in industry fundamentals as the major oil and natural gas companies expanded their capital expenditures in the North Sea and exploration activities became more extensive and longer in duration. This has been evidenced by drilling rig commitments extending well into the future, with some contracts into and beyond 2010. This, coupled with spending by the independents, created strong demand for vessels, which resulted in some of the highest day rates we have seen in our history.

Even though the North Sea region typically has weaker periods in the winter months of December through February, utilization and day rates, with some exceptions, are expected to remain strong throughout the current period. Forward 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 which 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 in the near term; however, based on current conditions and the available information regarding future drilling plans for the region, a healthy market could continue throughout 2008. In order to continue to meet the demand for high specification vessels, we constructed two new generation LgPSVs in Norway in 2007. The Highland Prestige delivered in April 2007 and the North Promise delivered in September 2007.

The Southeast Asia Market

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 in this market and the technical requirements for vessels. As a result of a number of exploration and production projects underway or planned, the Southeast Asia market is experiencing an increase in the demand for offshore marine services.

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. We currently have 13 vessels deployed in this market.

Vessels in this market are typically 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 moderate weather conditions prevail, have historically made up the bulk of the Southeast Asia fleet. 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 four years we also sold seven of our older vessels serving Southeast Asia. In an effort to leverage this changing market, in October 2005, we took delivery of a new vessel constructed in China, the Sea Intrepid. In 2006 we took delivery of two additional new build vessels, the Sea Guardian and Sea Sovereign. In October 2007, we took delivery of the Sea Supporter and Sea Cheyenne, and in January 2008 the Sea Apache was delivered. 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 2007 we initiated, and are now in the final stages of implementing, a strategic reorganization of our Southeast Asia operations which is designed to maximize the benefits to the Company under the various tax laws in the jurisdictions in which we operate.

Changes in supply and demand dynamics have led, at times, to an excess number of vessels in markets such as the Gulf of Mexico. 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 are demanding newer, higher specification vessels. Furthermore, transferring a vessel from elsewhere in the world to this region would involve significant cash and opportunity costs. Still, offshore exploration drilling has increased in this area and is expected to continue for several years. Currently, we are in the midst of the six new generation AHTS new build vessel program with potential use in the region and have purchased, as previously mentioned, three additional new AHTS vessels, the Sea Intrepid, Sea Guardian and Sea Sovereign, which are currently working in the area. Additionally, we exercised a right of first refusal granted under the Sea Sovereign purchase contract for an additional vessel, the Sea Supporter, which delivered in October 2007. Overall, demand in the area continues to remain strong.

The Americas Market

We define the Americas market as offshore North, Central and South America. Our Americas based fleet currently includes six vessels. Historically, our activity in the Americas has been in Brazil; however, since 2005, we have had two AHTS vessels offshore Mexico on five-year primary-term contracts with Pemex. Similar to the North Sea, the Brazilian market requires highly sophisticated vessels due to the harsh operating environment. We have been successful in meeting the market requirements through owned, managed and bareboat chartered vessels and will look to our existing and new build fleet to meet the expanding demand for vessels in this market.

The Brazilian government has opened up the petroleum industry to private investment, and the early bid rounds resulted in extensive commitments by major international oil companies and consortiums of independents, many of whom have explored and to some extent will continue to explore the offshore blocks awarded in the lease sales. This has created a demand for deepwater AHTSs, to some extent, and PSVs in support of the drilling and exploration activities that has been met primarily from mobilization of vessels

from other regions. In addition, Petrobras, the Brazilian national oil company, continues to expand operations. This expansion has created, and could continue to create, additional demand for offshore support vessels. We have been active in bidding on additional work with both Petrobras and the consortiums.

Currently, we operate four vessels in Brazil, including the Brazilian built vessel Austral Abrolhos, which was delivered in September 2004. We have three PSV’s that have operated in the region under contracts of varying lengths, the earliest of which began in 1990. We have two additional vessels, for which we have signed multi-year contracts, beginning in the first and third quarters of 2008. One of these vessels will transition from the North Sea while the other vessel will come from the group of vessels being constructed in Southeast Asia.

We have two vessels under five-year primary-term contracts to Pemex in the Gulf of Mexico. These vessels, part of our new build construction program, arrived in Mexico from the shipyard in Singapore and began their contracts in May 2005. This represents our first entry into the Mexican market which could create additional future opportunities in the Gulf of Mexico when and if Pemex increases the size and capability of the vessel fleet required to support its drilling operations.

Other Markets

We have contracted our vessels outside of our operating segment regions principally on short-term charters in places such as offshore Africa and the Mediterranean region. We currently have three of our owned vessels supporting operations offshore India, two owned vessels operating in the Mediterranean region, and one owned and one managed vessel operating offshore West Africa. 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 often managed through offices in the North Sea region.

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. 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. However, operations in any market may be affected by 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.

New Vessel Construction and Acquisition Program

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 offshore 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, which incorporates Dynamic Positioning 2 (DP-2) certification and Fire Fighting Class 1 (FiFi-1). They have a 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. The first of these vessels, the Sea Cheyenne, delivered in October 2007 and began operations in Southeast Asia on a term contract. The delivery of the final vessel in this group is scheduled for the fourth quarter of 2008. 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. These vessels are currently under contract in Southeast Asia. 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 and went to work on a term contract in Southeast Asia.

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 and is also working on a term contract in the North Sea region. 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 $84 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 new build vessels is $130 million. The first of these vessels is scheduled to be delivered in the fourth quarter of 2009 and the last of the five is scheduled to be delivered in the third quarter of 2010.

When applicable, we will enter into forward currency contracts to minimize our foreign currency exchange risk related to the construction of new vessels. To this end on September 30, 2005, we entered into a forward contract related to the construction of the Highland Prestige. This forward contract was designated as a fair value hedge and was highly effective as the terms of the contract were the same as the purchase commitment. During the term of the hedge, the consolidated balance sheet reflected the change in fair value of the foreign currency contract and the offsetting purchase commitment. 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 and was reflected as a reduction to the overall construction cost of the vessel.

Additionally during August 2007, we entered into a series of forward currency contracts relative to future milestone payments for the six Keppel vessels under construction and the two Aker Yards vessels. As of December 31, 2007, the positive foreign currency change on the forward contracts was $6.7 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.

Historically, our strategy has been 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. In June 2007, we sold the 1981 built Sem Courageous, which was based in Southeast Asia and recognized a gain of $0.9 million on proceeds of $2.5 million. Additionally, in September 2007, we completed the sale of the Sea Explorer, a Southeast Asia based vessel, for a sales price of $5.1 million, generating a gain of $4.5 million. During the third quarter of 2007, we entered into an agreement to sell the Sea Endeavor, another Southeast Asia based vessel, for $2.5 million. The sale was completed in October 2007 and recognized in our fourth quarter 2007 financial results. We believe the timing of these sales fit well with our Southeast Asia new build delivery schedule. During the second quarter of 2007, we signed a memorandum of agreement for the sale of the Sem Valiant, an older Southeast Asia based vessel, for $2.5 million. Delivery of the vessel is to be agreed upon with the buyer.

Interest is capitalized in connection with the construction of the vessels. During 2007 and 2006, $6.2 million and $2.4 million, respectively, was capitalized in connection with the construction of vessels.

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

Vessel	Scheduled Delivery Date	Type	Length (feet)	Deadweight tons	Estimated Cost (in millions)
North Sea Based:
Aker 726	Q4 2009	PSV	284	4,850	$45.4
Aker 727	Q2 2010	PSV	284	4,850	$45.4
Southeast Asia Based:
Sea Kiowa	Q1 2008	AHTS	250	2,700	$24.9
Sea Cherokee	Q3 2008	AHTS	250	2,700	$24.5
Sea Choctow	Q3 2008	AHTS	250	2,700	$24.3
Sea Comanche	Q4 2008	AHTS	250	2,700	$24.4
Other:
Bender 1	Q4 2009	PSV	245	3,000	$25.5
Bender 2	Q2 2010	PSV	245	3,000	$25.5
Bender 3	Q3 2010	PSV	245	3,000	$25.5
Remontowa 20	Q2 2010	AHTS	230	2,150	$26.9
Remontowa 21	Q3 2010	AHTS	230	2,150	$26.9

Our Fleet

As of February 28, 2008, we operate a fleet of 62 vessels. Of these vessels, 48 are owned by us (see table below) and 14 are under management for other owners.

		Type			Length		BHP		DWT
Fleet	Vessel	(a)	Flag	Built	(feet)		(b)		(c)
NORTH SEA BASED	Highland Bugler	LgPSV	UK	2002		221		5,450		3,115
	Highland Champion	LgPSV	UK	1979		265		4,800		3,910
	Highland Citadel	LgPSV	UK	2003		236		5,450		3,200
	Highland Eagle	LgPSV	UK	2003		236		5,450		3,200
	Highland Fortress	LgPSV	UK	2001		236		5,450		3,200
	Highland Monarch	LgPSV	UK	2003		221		5,450		3,115
	Highland Navigator	LgPSV	Panama	2002		275		9,600		4,250
	Highland Pioneer	LgPSV	UK	1983		224		5,400		2,500
	Highland Piper	LgPSV	Panama	1996		221		5,450		3,115
	Highland Prestige	LgPSV	UK	2007		284		10,000		4,850
	Highland Pride	LgPSV	UK	1992		265		6,600		3,080
	Highland Rover	LgPSV	Panama	1998		236		5,450		3,200
	Highland Star	LgPSV	UK	1991		265		6,600		3,075
	North Challenger	LgPSV	Norway	1997		221		5,450		3,115
	North Fortune	LgPSV	Norway	1983		264		6,120		3,366
	North Mariner	LgPSV	Norway	2002		275		9,600		4,400
	North Promise	LgPSV	Norway	2007		284		10,000		4,850
	North Stream	LgPSV	Norway	1998		276		9,600		4,585
	North Traveller	LgPSV	Norway	1998		221		5,450		3,115
	North Truck	LgPSV	Norway	1983		265		6,120		3,370
	North Vanguard	LgPSV	Norway	1990		265		6,600		4,000
	Highland Trader (e)	LgPSV	UK	1996		221		5,450		3,115
	Highland Courage	AHTS	UK	2002		260		16,320		2,750
	Highland Valour	AHTS	UK	2003		260		16,320		2,750
	Highland Endurance	AHTS	UK	2003		260		16,320		2,750
	North Crusader	AHTS	Panama	1984		236		12,000		2,064
	Clwyd Supporter	SpV	UK	1984		266		10,700		1,350
	Highland Spirit	SpV	UK	1998		202		6,000		1,800
	Highland Sprite	SpV	UK	1986		194		3,590		1,442

SOUTHEAST ASIA BASED	Highland Guide	LgPSV	Panama	1999		218		4,640		2,800
	Highland Legend	PSV	Panama	1986		194		3,600		1,442
	Highland Drummer	LgPSV	Panama	1997		221		5,450		3,115
	Sea Apache	AHTS	Panama	2008		250		10,700		2,700
	Sea Cheyenne	AHTS	Panama	2007		250		10,700		2,700
	Sea Diligent	SmAHTS	Panama	1981		192		4,610		1,219
	Sea Eagle	SmAHTS	Panama	1976		185		3,850		1,215
	Sea Guardian	SmAHTS	Panama	2006		191		5,150		1,500
	Sea Intrepid	SmAHTS	Panama	2005		191		5,150		1,500
	Sea Searcher	SmAHTS	Panama	1976		185		3,850		1,215
	Sea Sovereign	SmAHTS	Panama	2006		230		5,500		1,800
	Sea Supporter	AHTS	Panama	2007		225		7,954		2,360
	Sem Valiant	Sm AHTS	Malaysia	1981		191		3,900		1,220

AMERICAS BASED	Austral Abrolhos (d)	AHTS	Brazil	2004		215		7,100		2,000
	Highland Scout	LgPSV	Panama	1999		218		4,640		2,800
	Highland Warrior	LgPSV	Panama	1981		265		5,300		4,049
	Seapower	SpV	Panama	1974		222		7,040		1,205
	Coloso	AHTS	Mexico	2005		199		5,916		1,674
	Titan	AHTS	Mexico	2005		199		5,916		1,674

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

The table above does not include 14 managed vessels.

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. The contracts are industry standard time charters for periods ranging from a few days or months to more than five years. While certain contracts do contain cancellation provisions, the contracts are generally not cancelable 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. In 2005, BP accounted for 11.0% of our total consolidated revenue. No single customer accounted for 10% or more of our total consolidated revenue for 2007.

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, 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”. 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. As of February 28, 2008 we have no third party bareboat chartered vessels in our fleet.

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

Substantially all of our charters are fixed in British Pounds, or GBP; Norwegian Kroner, or NOK; Euros; U.S. Dollars, or US$; or Brazilian Reais. We attempt to reduce currency risk by matching each vessel’s contract revenue to the currency in which its operating expenses are incurred. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Currency Fluctuations and Inflation.”

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 are given to vessels owned by local companies. We have attempted to mitigate some of the impact of such preferences through affiliations with local companies. Some of our competitors have significantly greater financial resources than we do.

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, 2007 and February 22, 2008:

	As of February 22 , 2008						As of February 23, 2007
	2008 Vessel Days			2009 Vessel Days			2007 Vessel Days			2008 Vessel Days
North Sea-Based Fleet		85.6	%		44.9	%		76.9	%		49.3	%
Southeast Asia-Based Fleet		69.9	%		50.0	%		39.8	%		8.5	%
Americas-Based Fleet		91.1	%		84.5	%		100.0	%		78.7	%
Overall Fleet		82.6	%		52.7	%		69.8	%		41.9	%

These commitments provide us with a forward view of vessel earnings before interest, taxes, depreciation and amortization, or EBITDA, in the respective periods based on the contract rates that are in effect on each of the contracts comprising the forward days

less the estimated costs of operating the vessels in each geographical area. The increase in the percentage of contracted days at February 22, 2008, as compared to February 23, 2007, for the current year is a result of securing a number of charters in the Southeast Asia region on terms longer than historical averages, and our strategy of optimizing the fleet availability in the North Sea to both take advantage of spot market opportunities and attractive term charters.

Environmental and Government 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 and operation of vessels. We believe that we are in material compliance with all applicable 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. Compliance with environmental, health and safety laws and regulations increases our cost of doing business. Additionally, environmental, health and safety laws change frequently. Therefore, we are unable to predict the future costs or other future impact of these laws on our operations. There is no assurance that we can avoid significant costs, liabilities and penalties imposed as a result of governmental regulation in the future.

Employees

At December 31, 2007, we had 1,300 employees located in the United States, the United Kingdom, Norway, Southeast Asia, Brazil and other areas depending on vessel location. Through our contract with a crewing agency, we participate in the negotiation of collective bargaining agreements for 1,012 contract crew members who are members of two North Sea unions, under evergreen employment agreements, and a Mexican union. 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; Liverpool, England; Sandnes, Norway; Macae, Brazil and Paraiso, Mexico. All facilities, except one owned facility in Aberdeen, Scotland, 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;

·	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. Currently, there is a period of high prices for oil and natural gas, and oil and gas companies have increased their exploration and development activities. The price of oil and natural gas is high compared to historical levels. The activity increase that began in the second half of 2004 has continued through 2007 after reduced levels of activity were experienced in 2002-2004. A decline in the worldwide demand for oil and natural gas or prolonged low oil or natural gas prices in the future, 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. 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 type operated by us for use in the North Sea and elsewhere has significantly increased. The addition of new capacity 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 reduce our business opportunities and increase our costs.

·	oil spills and other matters of environmental protection;

·	worker health, safety and training;

·	construction and operation of vessels; and

·	vessel and port security.

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 environmental, health, safety and vessel and port security laws increases our costs of doing business. Additionally, environmental, health, safety and vessel and port security laws change frequently. Therefore, we are unable to predict the future costs or other future impact of 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.

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, their 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 2008-2009, and have negotiated terms for renewal in 2009-2010 for our primary coverage. We can provide no assurance, however, that our insurance coverage will be available beyond the renewal periods, and be adequate to cover future claims that may arise.

Substantially all our revenue is derived from our international operations and those operations are subject to government regulation and operating risks.

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

·	foreign currency exchange fluctuations or imposition of currency exchange controls;

·	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; and

·	imposition of currency exchange controls.

In the past, these conditions or events have not materially affected our operations. However, we cannot predict whether any such conditions or events might develop in the future. Also, our subsidiary structure and our operations are in part based on certain assumptions about currency exchange requirements and capital repatriation laws. While we believe our assumptions are correct, there can be no assurance that authorities will reach the same conclusion. 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 financial consequences, including the reduction of cash flow available to meet required debt service and other obligations. Any of these factors could materially adversely affect our international operations and, consequently, our business, operating results and financial condition.

Changes in tax legislation in countries in which we operate could result in higher tax expense or a higher effective tax rate on our worldwide earnings.

Our worldwide operations are mostly conducted through our various subsidiaries. Accordingly, we are subject to income taxes in the United States and foreign jurisdictions. Any material changes in tax law, 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. Additionally, our tax returns are subject to examination and review by the tax authorities in the jurisdictions in which we operate. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Policies and Estimates-Income Taxes.”

Our international operations 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. 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, but we do not speculate in foreign currencies. Because we conduct a large portion of our operations in foreign currencies, any increase in the value of the U.S. Dollar in relation to the value of applicable foreign currencies could potentially adversely affect our operating revenue when translated into U.S. Dollars.

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

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

·	shortages of equipment;

·	unforeseen engineering problems;

·	work stoppages;

·	weather interference;

·	unanticipated cost increases; and

·	shortages of materials or skilled labor.

Significant cost overruns or delays in connection with our repair projects would adversely affect our financial condition and results of operations. Significant delays could also result in penalties under, or the termination of, most of the long-term contracts under which we plan to operate our vessels.

Our current operations and future growth may require significant additional capital, and our indebtedness could restrict our ability to fund our capital requirements.

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. We cannot provide assurance that we will have sufficient resources to maintain our fleet either by extending the economic life of existing vessels through major refurbishment or by acquiring new or used vessels.

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.

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 andIssuer Purchases of Equity Securities

In July 2007, we listed our common stock on the New York Stock Exchange (NYSE). Our common stock is traded on the NYSE Market under the symbol “GLF”. Prior to July 2007, our stock traded on the NASDAQ Global Stock Market under the symbol “GMRK”. The following table sets forth the range of high and low sales prices for our common stock for the periods indicated, as reported:

	2007				2006
	High		Low		High		Low
Quarter ended March 31,	$	44.64	$	31.80	$	34.07	$	25.54
Quarter ended June 30,	$	54.65	$	43.51	$	29.45	$	23.15
Quarter ended September 30,	$	56.94	$	40.00	$	32.95	$	24.95
Quarter ended December 31,	$	53.13	$	40.92	$	40.90	$	30.31

For the period from January 1, 2008 through February 27, 2008, the range of low and high sales prices of our common stock was $40.41 to $52.50, respectively. On February 27, 2008, the closing sale price of our common stock as reported by the NYSE Market was $52.50 per share. At February 28, 2008, there were 541 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 4 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 7 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., Core Laboratories N.V., Diamond Offshore Drilling Inc., Dresser-Rand Group Inc., ENSCO International Inc., Exterran Holdings Inc., FMC Technologies Inc., Global Industries Ltd., Grant Prideco Inc., Grey Wolf Inc., 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 Inc., Unit Corp., W-H Energy Services Inc., 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, 2002.

Comparison of Cumulative Total Return

	2002		2003		2004		2005		2006		2007
GulfMark Offshore, Inc.		100		95		151		201		254		317
Dow Jones Total Market Index		100		131		147		156		180		191
Dow Jones Oilfield Equipment and Services Index		100		115		155		236		267		388

ITEM 6. Selected Consolidated Financial Data

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

	Year Ended December 31,
	2007			2006			2005			2004			2003
	(Dollars in thousands, except per share amounts)
Operating Data:
Revenue	$	306,026		$	250,921		$	204,042		$	139,312		$	129,900
Direct operating expenses		108,386			91,874			82,803			71,239			69,836
Drydock expense (a)		12,606			9,049			9,192			8,966			—
Bareboat charter expense		—			—			3,864			1,410			6,505
General and administrative expenses		32,311			24,504			19,572			15,666			10,801
Depreciation and amortization		30,623			28,470			28,875			26,137			28,031
Gain on sale of assets		(12,169	)		(10,237	)		—			(2,282	)		(16	)
Operating income		134,269			107,261			59,736			18,176			14,743
Interest expense		(7,923	)		(15,648	)		(19,017	)		(17,243	)		(12,988	)
Interest income		3,147			1,263			569			276			238
Debt refinancing costs		—			—			—			(6,524	)		—
Other income (expense), net		(298	)		(95	)		484			1,517			(1,267	)
Income tax (provision) benefit (a)		(30,220	)		(3,052	)		(3,382	)		6,476			(192	)
Income before cumulative effect of change in accounting principle	$	98,975		$	89,729		$	38,390		$	2,678		$	534
Cumulative effect on prior years of change in accounting principle – net of $773 related tax effect (b)		—			—			—			(7,309	)		—
Net income (loss)	$	98,975		$	89,729		$	38,390		$	(4,631	)	$	534
Amounts per common share (basic):
Income before cumulative effect of change in accounting principle	$	4.41		$	4.40		$	1.92		$	0.13		$	0.03
Cumulative effect on prior years of change in accounting principle		—			—			—		$	(0.36	)		—
Net income (loss)	$	4.41		$	4.40		$	1.92		$	(0.23	)	$	0.03
Weighted average common shares (basic)		22,435			20,377			20,031			19,938			19,919
Amounts per common share (diluted):
Income before cumulative effect of change in accounting principle	$	4.29		$	4.28		$	1.86		$	0.13		$	0.03
Cumulative effect on prior years of change in accounting principle		—			—			—		$	(0.36	)		—
Net income (loss)	$	4.29		$	4.28		$	1.86		$	(0.23	)	$	0.03
Weighted average common shares (diluted) (c)		23,059			20,975			20,666			19,938			20,272
Statement of CashFlows Data:
Cash provided by operating activities	$	128,577		$	104,869		$	64,913		$	25,561		$	20,150
Cash used in investing activities		(175,383	)		(28,300	)		(43,343	)		(40,404	)		(91,575	)
Cash provided by (used in) financing activities		373			(20,679	)		(15,674	)		23,005			68,646
Effect of exchange rate changes on cash		3,793			2,679			765			1,031			1,707
Other Data:
Adjusted EBITDA (d)	$	164,892		$	135,731		$	88,611		$	44,313		$	42,774
Cash dividends per share		—			—			—			—			—
Total vessels in fleet (e)		61			60			59			52			53
Average number of owned or chartered vessels (f)		46.8			48.5			47.2			45.6			46.8

	As of December 31,
	2007		2006		2005		2004		2003
	(In thousands)
Balance Sheet Data:
Cash and cash equivalents	$	40,119	$	82,759	$	24,190	$	17,529	$	8,336
Vessels and equipment including construction in progress, net		754,000		571,989		510,446		538,978		485,502
Total assets		934,012		750,829		613,915		632,718		575,501
Long-term debt (g)		159,558		159,490		247,685		258,022		236,589
Total stockholders’ equity		676,091		541,428		320,096		316,157		292,128

(a)	See Note 5 to our “Consolidated Financial Statements – Income Taxes”.

(b)

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, we recorded a non-cash cumulative effect charge of $7.3 million, net of tax ($0.36 per basic and diluted common share). See Note 1 to our “Consolidated Financial Statements” included in Part II, Item 8.

(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,
	2007			2006			2005			2004			2003
	(In thousands)
Net income (loss)	$	98,975		$	89,729		$	38,390		$	(4,631	)	$	534
Interest expense		7,923			15,648			19,017			17,243			12,988
Interest income		(3,147	)		(1,263	)		(569	)		(276	)		(238	)
Income tax (benefit) provision		30,220			3,052			3,382			(6,476	)		192
Depreciation and amortization		30,623			28,470			28,875			26,137			28,031
EBITDA		164,594			135,636			89,095			31,997			41,507
Adjustments:
Cumulative effect of change in accounting principle		—			—			—			7,309			—
Debt refinancing costs		—			—			—			6,524			—
Other *		298			95			(484	)		(1,517	)		1,267
Adjusted EBITDA	$	164,892		$	135,731		$	88,611		$	44,313		$	42,774

* 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 Resultsof 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 in international markets 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 technologicallyadvanced 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. Additionally, 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. We also have sold certain older, smaller vessels that will not continue to meet our long term strategy. 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 forour 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 international markets: We have elected to conduct our current operations mainly in the North Sea, offshore Southeast Asia and offshore Americas markets because we believe there are higher barriers to entry, lower volatility of day rates and greater potential for increasing day rates in these markets than in other markets. Furthermore, 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 by our recent additions to our North Sea fleet. In addition, we have 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. The majority of our operations are based in the North Sea with 35 vessels operating from the area. We also have 13 vessels operating offshore Southeast Asia, four vessels offshore Brazil, two in the Mediterranean Sea, three vessels offshore India, two vessels offshore Africa and three vessels in the Gulf of Mexico. Our fleet has grown in both size and capability, from an original 11 vessels in 1990 to our present number of 62 vessels, through strategic acquisitions and new construction of technologically advanced vessels, partially offset by dispositions of certain older, less profitable vessels. At February 28, 2008, our fleet includes 48 owned vessels and 14 managed vessels.

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

From time to time, we bareboat charter vessels with revenue and operating expenses reported in the same income and expense categories as our owned vessels. The chartered vessels, however, incur bareboat charter fees instead of depreciation expense. Bareboat 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 costs are wages paid to vessel crews, maintenance and repairs, and marine insurance. Generally, fluctuations in vessel utilization have little effect on direct operating costs in the short term. 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, maintenance and repairs designed to ensure compliance with applicable regulations and maintaining certifications for our vessels with various international classification societies. The aggregate 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 the availability allowed by our customers have influenced, and will continue to 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 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 collectibility of our receivables and to establish appropriate allowances for bad debt. This policy states that a reserve for bad debt may 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, 2007 and 2006, respectively, we provided an allowance for doubtful accounts of $0.1 million and $0.4 million. Additional allowances for doubtful accounts may be necessary as a result of our ongoing assessment of our customers’ ability to pay. 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 and Goodwill

Our long-lived tangible assets consist primarily of vessels and construction-in-progress. Our goodwill primarily relates to the 1998 acquisition of Brovig Supply AS and the 2001 acquisition of Sea Truck Holding AS. The determination of impairment of all long-lived assets, including goodwill, 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 2007 and 2006, we performed our impairment test 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

A significant portion of our earnings originate in the North Sea, a region in which certain jurisdictions including the United Kingdom and Norway provide alternative taxing structures created specifically for qualified shipping companies, referred to as “tonnage tax” regimes. The tonnage tax regimes provide for a tax based on the net tonnage weight of a qualified vessel, resulting in significantly lower taxes than those that would apply if we were not a qualified shipping company in those jurisdictions.

During the fourth quarter of 2007, the Norwegian taxing authority enacted tonnage tax legislation as part of their 2008 budgetary process 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 that is similar to other EU tonnage tax systems. 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. Companies that participated in the repealed Norwegian tonnage tax system are now required to pay the tax on the accumulated untaxed shipping profits as of December 31, 2006. Two-thirds of the liability is payable in equal installments over ten years, while the remaining one-third of the tax liability can be met through qualified environmental expenditures on Norwegian flagged vessels. Any remaining portion of the environmental part of the liability at the end of ten years would be payable at that time. As of December 31, 2007, our total USD equivalent of the NOK liability for the repealed Norwegian tonnage tax was $25.3 million. This amount was recorded in our tax provision as current income tax expense. The first annual cash payment of $1.7 million due in 2008 is classified on our balance sheet as current income taxes payable and the $23.6 million remainder is classified on our balance sheet as other income taxes payable – long term. Of this amount, $15.2 million is payable over nine years and $8.4 million is the one-third environmental portion of the total liability, which we expect will be fully expended within

the ten year period. Any such qualified environmental expenditures will reduce the $8.4 million tax liability and be recorded as a credit to our tax provision for the period in which the expenditures are incurred. Our Norwegian ship owning subsidiary plans to elect to enter into the new tonnage tax regime which will be based on the tonnage of our Norwegian flagged vessels and result in minimal Norwegian tax provisions/payments related to our operations from January 1, 2007 forward.

Except for the impact recorded in our 2007 tax provision for the repeal of the Norway tonnage tax law as described above, substantially all of our tax provision is for taxes unrelated to our United Kingdom and Norway tonnage tax qualified shipping activities. Should our operational structure change or should the laws that created the tonnage tax regimes change, excluding the 2007 effect of the repeal of the Norway tonnage tax law through 2006 as described above, we could be required to provide for taxes at rates much higher than 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. As with the effect of the 2007 Norway changes, any such increase could cause volatility in the comparison 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.

Beginning January 1, 2005, the majority of our foreign shipping income was no longer subject to tax in the United States of America. In 2005, we reviewed our global operating structure and executed a world-wide restructuring to maximize potential growth and cash flow and create a more favorable tax efficient corporate structure for the expansion of our business. In addition, in 2007 we initiated, and are now in the final stages of implementing, a strategic reorganization of our Southeast Asia operations which should result in our realization of measurable tax benefits in 2008 and beyond.

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 newly enacted tax rates are as follows: 16.5% for 2008, 17% for 2009 and 17.5% for 2010 and beyond. This new tax will affect our operations in Mexico, the results of which includes the effect of the tax beginning in the first quarter of 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 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 Note 1 “Nature of Operations and Summary of Significant Accounting Policies – Income Taxes” and Note 5 “Income Taxes” to our “Consolidated Financial Statements” included in Part II, Item 8.

Commitments and Contingencies

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. There currently is no provision within the plan to refund excess contributions, which, if were to occur in the 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, 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 market 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 this year and two additions in Southeast Asia last year 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,
	(Dollars in thousands)
	2007			2006			Increase (Decrease)
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 the year 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 relates largely to the sale of our four older vessels: the North Prince and the Sem Courageous sold in the first half of the year, and the Sea Explorer and the Sea Endeavor sold in the second half of the year.

Interest expense decreased $7.7 million as we paid off our revolving credit facility, coupled with higher capitalized interest recorded in the year. 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 the year.

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.

Comparison of the Fiscal Years Ended December 31, 2006 and December 31, 2005

Our revenue increased from $204.0 million in 2005 to $250.9 million in 2006, or 23%, mainly as a result of continued increased activity in both the North Sea and Southeast Asia regions, and additions to the fleet, with two new build vessels delivered during 2006 and the full year effect of three new build vessels delivered during 2005, offset in part by the sale of two vessels in the last half of the year. For the year ended December 31, 2006, net income was $89.7 million, or $4.28 per diluted share, compared to $38.4 million, or $1.86 per diluted share in 2005.

Continued strength in the North Sea market accounted for the majority of the year over year increase in both day rates and utilization. Similarly, our Southeast Asia region, with the addition of three technically advanced vessels in the last two years, showed a significant increase in day rates as well as utilization. Our Americas region experienced an increase in utilization; with the full year effect of two new builds added in 2005. This increase was offset partially by a decrease in day rates in the region resulting from the return of the North Stream back to the North Sea, 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. We continue to experience strong demand for our vessels in all our regions, and could see this trend continuing into the 2007-2008 period.

Our North Sea and Southeast Asia regions experienced significant increases in revenue year over year, while our Americas region revenue remained stable. The overall improvement in revenue resulted mainly from a $37.2 million increase in day rates mainly attributable to improved market conditions and stronger exploration and development activities, an increase in capacity of $2.1 million mainly due to vessel additions, a $5.8 million increase in utilization, and $1.8 million attributable to the strengthening of the GBP and NOK against the US$.

	Year Ended December 31,
	(Dollars in thousands)
	2006			2005			Increase (Decrease)
Average Rates Per Day Worked (a) (b):
North Sea-Based Fleet (c)	$	19,164		$	15,530		$	3,634
Southeast Asia-Based Fleet		7,062			5,849			1,213
Americas-Based Fleet		11,014			11,518			(504	)
Overall Utilization (a) (b):
North Sea-Based Fleet (c)		94.9	%		91.9	%		3.0	%
Southeast Asia-Based Fleet		92.3	%		91.6	%		0.7	%
Americas-Based Fleet		96.0	%		95.6	%		0.4	%
Average Owned or Chartered Vessels (a) (d):
North Sea-Based Fleet		30.4			30.8			(0.4	)
Southeast Asia-Based Fleet		11.7			10.2			1.5
Americas-Based Fleet		6.4			6.2			0.2
Total		48.5			47.2			1.3

(a)	Includes all owned or bareboat chartered vessels. Managed vessels are not included.

(b)	Average rates per day worked is defined as total charter revenue divided by number of days worked. Overall utilization rate is defined as the total number of days worked divided by the total number of days of availability in the period.

(c)

	Year Ended December 31,
	2006		2005
$1 US=GBP		0.543		0.549
$1 US=NOK		6.406		6.439
$1 US=Euro		0.796		0.806

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

Direct operating expenses increased $9.1 million in 2006 when compared to 2005. This increase was due mainly to vessel additions throughout the year coupled with salary and travel costs related to more vessels operating in locations that are distant from

our regional offices. Additional direct costs were related to stronger foreign currencies when compared to the reporting currency, amounting to $0.7 million. Drydock expense decreased by $0.1 million, and bareboat charter expense decreased $3.9 million as the bareboat charter agreement entered in 2005 ended. General and administrative expenses increased $4.9 million in 2006, largely related to higher salary, bonus and employee benefits. Depreciation expense decreased by $0.4 million from 2005 to 2006 due mainly to older vessels being fully depreciated during the year, partially offset by fleet additions. The gain on sale of assets relates largely to the sale of two older vessels, the Highland Patriot, sold during the third quarter for a gain of approximately $6.6 million, and the Sentinel, sold during the fourth quarter for a gain of approximately $3.6 million.

Interest expense decreased $3.4 million as we paid off our revolving credit facility, coupled with higher capitalized interest recorded in the year. The increase in interest income of $0.7 million relates to the interest earned on higher cash balances throughout the year resulting from higher sales and our stock offering in December 2006. Additionally, the other expense of $0.1 million was mainly related to foreign currency movements throughout the year.

Income tax expense remained fairly constant, at $3.1 million for 2006, compared to $3.4 million for 2005. The 2006 effective tax rate of 3.3% was mostly the result of activities that were not UK and Norway tonnage tax qualified shipping operations. For 2005, the effective tax rate was 8.1%. 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. Substantially all of our revenue is derived from and all of our long-lived assets located in foreign jurisdictions.

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, as 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 detailed discussions follow.

Operating Income by Operating Segment

	Year Ended December 31,
	2007			2006			2005
	(In thousands)
North Sea	$	110,679		$	100,909		$	55,897
Southeast Asia		35,858			14,998			10,007
Americas		5,136			4,100			4,421
Total reportable segment operating income		151,673			120,007			70,325
Other		(17,404	)		(12,746	)		(10,589	)
Total reportable segment and other operating income	$	134,269		$	107,261		$	59,736

North Sea Region:

	Year Ended December 31,
	2007			2006			2005
	(In thousands)
Revenue	$	241,664		$	199,368		$	160,276
Direct operating expenses		100,716			80,519			75,226
Drydock expense		10,369			6,446			7,069
Depreciation and amortization expense		24,914			21,731			22,084
Gain on sale of assets		(5,014	)		(10,237	)		—
Operating income	$	110,679		$	100,909		$	55,897

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.

Comparison of Fiscal Year Ended December 31, 2006 and December 31, 2005

Revenue for 2006 increased $39.1 million compared to 2005, an increase of 24%. This increase was primarily driven by higher day rates, from $15,530 in 2005 to $19,164 in 2006, largely due to the continued improvement in exploration and development activities, a strong spot market, and increases in foreign currency exchange rates between the GBP and NOK against the U.S. Dollar. Capacity increased by $1.0 million due to the mobilization into the region of the North Stream, a vessel that had been working in Brazil, partially offset by the return of a bareboat chartered vessel to its owner and the sale of the Sentinel during the fourth quarter of 2006. Utilization increased by $5.2 million, from 92.5% in 2005 to 94.9% in 2006, also due to the general market strength in the region. Operating expenses increased by $5.3 million from 2005 to 2006, primarily due to the vessel addition described above, to higher salaries and travel costs related to vessels operating in distant areas and higher vessel utilization.

Southeast Asia Region:

	Year Ended December 31,
	2007			2006		2005
	(In thousands)
Revenue	$	41,257		$	27,385	$	19,570
Direct operating expenses		8,064			8,058		5,982
Drydock expense		1,832			1,775		960
Depreciation and amortization expense		2,657			2,554		2,621
Gain on sale of assets		(7,154	)		—		—
Operating income	$	35,858		$	14,998	$	10,007

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.

Comparison of Fiscal Year Ended December 31, 2006 and December 31, 2005

Revenue increased by $7.8 million or 40% year over year. This improvement can be attributed primarily to increased capacity of $5.2 million, as two vessels, the Sea Guardian and Sea Sovereign were delivered during 2006, and the full-year effect of the Sea Intrepid delivered in 2005, offset somewhat by the sale of the Highland Patriot in the third quarter of 2006. Day rates increased from $5,849 in 2005 to $7,062 in 2006, contributing to an increase of $1.9 million, largely due to higher demand for our technologically advanced vessels. Utilization increased by $0.7 million, from 91.6% in 2005 to 92.3% in 2006. Operating expenses increased by $2.1 million due mainly to the increase in the number of vessels in the region as described above. Depreciation expense decreased by $0.1 million, due to an increase in the number of fully depreciated vessels.

Americas Region:

	Year Ended December 31,
	2007		2006		2005
	(In thousands)
Revenue	$	23,105	$	24,168	$	24,196
Direct operating expenses		14,651		15,361		14,648
Drydock expense		405		828		1,166
Depreciation and amortization expense		2,913		3,879		3,961
Operating income	$	5,136	$	4,100	$	4,421

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.

Comparison of Fiscal Year Ended December 31, 2006 and December 31, 2005

Revenue of $24.2 million for 2006 remained constant from 2005. The increase in utilization was offset by a decrease in both capacity and day rates. The decrease in capacity was the result of the mobilization of the North Stream out of the region, partially offset by the full-year impact of the two Mexican vessels added in 2005. Operating expenses increased by $0.7 million resulting mainly from the increased size of the fleet in the area. Depreciation expense decreased by $0.1 million, as the North Stream was removed from the region.

Liquidity and Capital Resources

Our ongoing liquidity requirements are generally associated with our need to service debt, fund working capital, acquire or improve equipment and make other investments. Since inception, we have been 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, and we expect to fund the $98.6 million in new build commitments for 2008 and other capital expenditures from such sources. Internally generated funds are directly related to fleet activity and vessel day rates, which are ultimately determined by the supply and demand for crude oil and natural gas.

We anticipate that cash on hand and future cash flow from operations for the twelve months ending December 31, 2008, will be adequate to repay our debts due and payable during such period, to make normal recurring capital additions and improvements, and to meet working capital requirements. We believe that our current cash and cash flows from operations will provide sufficient resources to finance our operating requirements. However, our ability to fund working capital, capital expenditures and debt service in excess of cash on hand will be dependent upon the success of our operations. During 2006 we refinanced our revolving debt as discussed below.

In December 2006, we raised approximately $76.8 million through an offering of 2,000,000 shares of common stock. These proceeds were used to repay the outstanding portion of the credit facility and for corporate working capital needs. We plan to also use remaining proceeds to partly fund, as needed, future progress payments for the delivery of vessels in our new build program.

Long-Term Debt

On June 8, 2006, we closed on a $175 million Secured Reducing Revolving Loan Facility with a group of financial institutions headed by Den Norske Bank, or DnB. The multi-currency facility was structured as follows: $85 million allocated to GulfMark Offshore, Inc., our parent company, $60 million allocated to Gulf Offshore N.S. Limited, a U.K. wholly owned subsidiary, and $30 million allocated to GulfMark Rederi AS, a Norwegian wholly owned subsidiary. The facility replaced all our existing bank debt, including the $100 million Multi-currency Bank Credit Facility, $50 million Senior Secured Revolving Credit Facility and notes secured by two vessel mortgages. Approximately $80.9 million was refinanced under the facility. The facility matures in 2013 and the maximum availability begins to reduce in increments of $15.2 million every six months beginning after 66 months (in late 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 and a negative pledge over other vessels. The interest rate ranges from LIBOR plus a margin of 0.7% to 0.9% depending on

our EBITDA coverage ratio. During December 2007, we repaid all outstanding balances under the facility. From time to time, we may borrow funds to meet certain construction milestones in our new build program. We borrowed and repaid $20.0 million in the fourth quarter of 2007 for such purposes, and have borrowed an additional $12.0 million in the first quarter of 2008, which we anticipate repaying in the same quarter.

As part of the plan to reorganize our Southeast Asia operations and subsequent ownership of vessels in the region, we are in the process of reallocating $60 million of the $85 million previously assigned to GulfMark Offshore, Inc. The result will be $60 million allocated to Gulf Marine Far East Pte Ltd., a wholly owned Singapore subsidiary, and $25 million allocated to GulfMark Offshore, Inc. This redesignation aligns the credit facility with our post-reorganization vessel ownership, including existing vessel construction contracts, in our Southeast Asia region. This action has been approved by the bank group, and documentation is expected to be complete during the first quarter of 2008.

On July 2, 2004, we commenced a tender offer to purchase all of our outstanding $130 million aggregate principal amount of 8.75% senior notes due 2008 for cash in an amount up to 103.29% of the principal amount thereof, plus accrued and unpaid interest. In connection with the tender offer, we also solicited and received the consent of the holders of our 8.75% senior notes to amend the indenture governing the 8.75% senior notes to eliminate substantially all of the restrictive covenants contained in the indenture. We used the net proceeds of the debt offering discussed below to purchase the 8.75% senior notes, to repay a portion of indebtedness outstanding under our Multi-currency Bank Credit Facility, which has since been replaced as discussed above, and for general corporate purposes.

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:

•	At any time before July 15, 2007, we may redeem up to 35% of the 7.75% senior notes with net cash proceeds of certain equity offerings, as long as at least 65% of the aggregate principal amount of the 7.75% senior notes issued pursuant to the indenture remains outstanding after the redemption.

•	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 imposed operating and financial restrictions on us. These restrictions affect, and in many cases limited or prohibited, among other things, our ability to incur additional indebtedness, make capital expenditures, create liens, sell assets and make cash dividends or other payments. We were in compliance with all indenture covenants at December 31, 2007.

Current Year Cash Flow

At December 31, 2007, we had cash on hand of $40.1 million. Cash provided by operating activities for the year ended December 31, 2007 was $128.6 million compared to $104.9 million in the previous year. The increase was primarily attributable to higher operating income reflecting strong North Sea and Southeast Asia markets and new vessel additions.

Cash used in investing activities for the years ended December 31, 2007 and 2006 was $175.4 million and $28.3 million, respectively. In 2007 and 2006, we sold assets, for approximately $15.8 million and $19.2 million, respectively. The proceeds from these sales decreased the reported cash used in investing activities. Before this decrease, cash used in investing activities increased by $143.7 million from 2006 to 2007, mainly due to increased expenditures relating to purchases of vessels and equipment in 2007.

In 2007, we provided $0.4 million in financing activities, compared to using $20.7 million in 2006. In 2007, we repaid all debt that was borrowed and received proceeds from the exercise of stock options of $0.9 million. During 2006, we received proceeds from issuance of stock of approximately $77.1 million, largely related to our December 2006 stock issuance, and we borrowed $80.8 million and repaid $179.3 million in debt. Additionally, during 2006 we received proceeds from the exercise of stock options in the amount of $0.7 million.

The 2007 Norway tonnage tax legislative changes resulted in required annual tax cash payments approximately $1.7 million, U.S. Dollar equivalent NOK liability, for ten years beginning in 2008. Otherwise, the tonnage tax regimes in both the U.K. and Norway reduce the cash required for taxes in each of these regions, which are both in the North Sea Market. Our tax provision can therefore fluctuate greatly depending on the mix of income from low tax jurisdictions of the U.K. and Norway versus income outside of these areas.

Debt and Other Contractual Obligations

The following table summarizes our contractual obligations at December 31, 2007 and the effect these obligations are expected to have on liquidity and cash flows in future periods (in millions):

	2008		2009		2010		2011		2012		Thereafter
Repayment of Long-Term Debt, Excluding Debt Discount of $0.6 million	$	—	$	—	$	—	$	—	$	—	$	160.0
Purchase Obligations for New Build Program		98.7		84.3		57.3		—		—		—
Non-Cancelable Operating Leases		0.8		0.7		0.6		0.5		0.4		1.5
Long Term Income Taxes Payable		1.7		1.7		1.7		1.7		1.7		16.8
Other		0.6		0.6		0.6		0.6		0.6		1.7
Total	$	101.8	$	87.3	$	60.2	$	2.8	$	2.7	$	180.0

Due to the uncertainty with respect to the timing of future cash payments, if any, associated with our unrecognized tax benefits at December 31, 2007, we are unable to make reasonably reliable estimates of the period of cash settlements with the respective taxing authority. Therefore, $9.1 million of unrecognized tax benefits have been excluded from the contractual obligations table above. Included above as Long Term Taxes Payable is our liability for income taxes resulting from the repeal of the Norway tonnage tax law for the years 1996 – 2006 which is payable over ten years beginning in 2008. Refer to Note 5 “Income Taxes” in our “Notes to Consolidated Financial Statement” included in Part II, Item 8.

Other Commitments

We execute letters of credit, performance bonds and other guarantees in the normal course of business that ensure our performance or payments to third parties. The aggregate notional value of these instruments was $1.0 million and $0.7 million at December 31, 2007 and 2006, 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 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 10 “Related Party Transactions” in our “Notes to Consolidated Financial Statements” included in Part II, Item 8.

Currency Fluctuations and Inflation

Substantially all 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 79% of our total consolidated revenue for the year ended December 31, 2007. In 2007, the exchange rates of GBP, NOK and Euros against the US$ ranged as follows:

	High	Low	Year Average	As of February 27, 2008
$1 US=GBP	0.521	0.473	0.500	0.508
$1 US=NOK	6.496	5.241	5.844	5.308
$1 US=Euro	0.771	0.668	0.730	0.673

Our outstanding debt of $159.6 million 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 in our interest not 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, 2007, is a $128.3 million accumulated other comprehensive income primarily relating to the higher exchange rate at December 31, 2007 in comparison to the exchange rate when we invested capital in these markets. Accumulated other comprehensive income was $93.5 million at December 31, 2006. 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 weakening in the U.S. Dollar compared to the functional currencies of our major operating subsidiaries, particularly in the U.K. and Norway. To date, general inflationary trends have not had a material effect on our operating revenue or expenses. One of the major consumables for the fleet is diesel fuel, the price of which has escalated significantly over the last year. However, fuel usually is provided by our customers, and as a result escalating fuel prices have not and in all probability will not adversely affect our operating cost structure.

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, delay or cost overruns on construction projects, ongoing capital expenditure requirements, uncertainties surrounding environmental and government regulation, 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

Interest Rate Sensitivity

At December 31, 2007, we had financial instruments that are potentially sensitive to changes in interest rates including our 7.75% senior notes, which are due July 15, 2014. Our senior notes have a stated interest rate of 7.75% and an effective interest rate of 7.8%. At December 3, 2007, the fair value of these notes, based on quoted market prices, was approximately $161.2 million, as compared to a carrying amount of $159.6 million.

Exchange Rate Sensitivity

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.

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, 2007 and 2006, 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, 2007. 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, 2007 and 2006, and the consolidated results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2007, 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, 2007, 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 28, 2008 expressed an unqualified opinion.

UHY LLP

Houston, Texas

February 28, 2008

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, 2007, 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, 2007, 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 28, 2008 expressed an unqualified opinion.

UHY LLP

Houston, Texas

February 28, 2008

GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31,
	2007			2006
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	40,119		$	82,759
Trade accounts receivable, net of allowance for doubtful accounts of $149 in 2007 and $436 in 2006		87,243			54,235
Other accounts receivable		3,399			3,376
Prepaid expenses and other current assets		3,273			2,742
Total current assets		134,034			143,112
Vessels and equipment at cost, net of accumulated depreciation of $218,342 in 2007 and $192,065 in 2006		641,333			524,676
Construction in progress		112,667			47,313
Goodwill		34,264			29,883
Fair value hedge		6,740			501
Deferred costs and other assets		4,974			5,344
Total assets	$	934,012		$	750,829

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	—		$	794
Accounts payable		21,409			16,516
Income taxes payable		2,516			3,806
Accrued personnel costs		17,872			9,527
Accrued interest expense		5,793			5,711
Accrued professional fees		982			1,059
Other accrued liabilities		1,906			751
Total current liabilities		50,478			38,164
Long-term debt		159,558			159,490
Long-term income taxes:
Deferred tax liabilities		2,731			7,277
Income tax liabilities – FIN 48		9,060			—
Other income taxes payable		23,602			—
Fair value hedge		6,740			501
Other liabilities		5,752			3,969
Stockholders’ equity:
Preferred stock, no par value; 2,000 shares authorized; no shares issued		—			—
Common stock, $0.01 par value; 30,000 shares authorized; 22,983 and 22,680 shares issued and outstanding, respectively		227			225
Additional paid-in capital		211,004			204,986
Retained earnings		336,846			242,733
Accumulated other comprehensive income		128,308			93,484
Treasury stock, at cost		(4,200	)		(3,012	)
Deferred compensation expense		3,906			3,012
Total stockholders’ equity		676,091			541,428
Total liabilities and stockholders’ equity	$	934,012		$	750,829

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,
	2007			2006			2005
	(In thousands, except per share amounts)
Revenue	$	306,026		$	250,921		$	204,042
Costs and expenses:
Direct operating expenses		108,386			91,874			82,803
Drydock expense		12,606			9,049			9,192
Bareboat charter expenses		—			—			3,864
General and administrative expenses		32,311			24,504			19,572
Depreciation		30,623			28,470			28,875
Gain on sale of assets		(12,169	)		(10,237	)		—
Total costs and expenses		171,757			143,660			144,306
Operating income		134,269			107,261			59,736
Other income (expense):
Interest expense		(7,923	)		(15,648	)		(19,017	)
Interest income		3,147			1,263			569
Foreign currency gain (loss) and other		(298	)		(95	)		484
Total other expense		(5,074	)		(14,480	)		(17,964	)
Income from continuing operations		129,195			92,781			41,772
Income tax provision		(30,220	)		(3,052	)		(3,382	)
Net income	$	98,975		$	89,729		$	38,390
Earnings per share:
Basic	$	4.41		$	4.40		$	1.92
Diluted	$	4.29		$	4.28		$	1.86
Weighted average shares outstanding:
Basic		22,435			20,377			20,031
Diluted		23,059			20,975			20,666

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, 2007, 2006 and 2005

	Common Stock at 0.01 Par Value		Additional Paid-In Capital		Retained Earnings			Accumulated Other Comprehen-sive Income			Treasury Stock						Deferred Compen- sation Expense		Total Stockholders’ Equity
											Shares			Share Value
	(In thousands)
Balance at December 31, 2004	$	201	$	122,105	$	114,614		$	79,237			(91	)	$	(1,344	)	$	1,344	$	316,157
Net loss		—		—		38,390			—			—			—			—		38,390
Issuance of common stock		—		282		—			—			—			—			—		282
Exercise of stock options		1		2,118		—			—			—			—			—		2,119
Tax benefit of options exercised		—		672		—			—			—			—			—		672
Deferred compensation plan		—		—		—			—			(25	)		(673	)		673		—
Translation adjustment		—		—		—			(37,524	)		—			—			—		(37,524	)
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

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, 2007, 2006 and 2005

	Year Ended December 31,
	2007		2006		2005
	(In thousands)
Net income	$	98,975	$	89,729	$	38,390
Comprehensive income:
Foreign currency gain (loss)		34,824		51,771		(37,524	)
Total comprehensive income	$	133,799	$	141,500	$	866

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,
	2007			2006			2005
	(In thousands)
Cash flows from operating activities:
Net income	$	98,975		$	89,729		$	38,390
Adjustments to reconcile net income from operations to net cash provided by operations
Depreciation		30,623			28,470			28,875
Amortization of deferred financing costs		704			903			1,083
Amortization of stock-based compensation		4,215			1,969			729
Provision for doubtful accounts receivable, net of write offs		(287	)		410			67
Deferred income tax provision (benefit)		454			(2,397	)		1,040
Gain on sale of assets		(12,169	)		(10,237	)		—
Disposition of assets		—			—			9
Foreign currency transaction loss		1,273			1,277			1,266
Change in operating assets and liabilities —
Accounts receivable		(30,013	)		(11,068	)		(7,976	)
Prepaids and other		(349	)		1,159			(499	)
Accounts payable		3,686			(85	)		1,920
Other accrued liabilities and other		7,863			4,739			9
Norwegian income taxes payables		23,602			—			—
Net cash provided by operating activities		128,577			104,869			64,913
Cash flows from investing activities:
Purchases of vessels and equipment		(191,158	)		(47,466	)		(43,343	)
Proceeds from disposition of equipment		15,775			19,166			—
Net cash used in investing activities		(175,383	)		(28,300	)		(43,343	)
Cash flows from financing activities:
Proceeds from debt, net of direct financing costs		20,257			80,794			12,280
Repayments of debt		(21,104	)		(179,265	)		(29,749	)
Proceeds from exercise of stock options		852			663			1,513
Proceeds from issuance of stock		368			77,129			282
Net cash provided by (used in) financing activities		373			(20,679	)		(15,674	)
Effect of exchange rate changes on cash		3,793			2,679			765
Net increase (decrease) in cash and cash equivalents		(42,640	)		58,569			6,661
Cash and cash equivalents at beginning of year		82,759			24,190			17,529
Cash and cash equivalents at end of year	$	40,119		$	82,759		$	24,190
Supplemental cash flow information:
Interest paid, net of interest capitalized	$	6,597		$	15,120		$	16,412
Income taxes paid, net	$	4,695		$	1,853		$	2,824

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 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 which 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 such vessels and equipment. 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 2007, 2006, and 2005, interest of $6.2 million, $2.4 million, and $0.8 million was capitalized, respectively. 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 2007, 2006 and 2005, are $14.0 million, $11.8 million, and $9.6 million, respectively, of costs for maintenance and repairs.

Goodwill

Goodwill primarily relates to the 1998 acquisition of Brovig Supply AS and the 2001 acquisition of Sea Truck Holding 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.

Fair Value of Financial Instruments

As of December 31, 2007, our financial instruments consist primarily of long-term debt and a 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. 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, 2007, the consolidated balance sheet has “Fair value hedge” on both the assets and liabilities sections reflecting the change in the fair value of the foreign currency contracts and purchase commitments.

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. In contrast, 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 collectibility 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, 2007, 2006 and 2005, we reported net foreign currency gains (losses) in the amount of $(2.0) million, $(1.7) million and $0.1 million, respectively.

Concentration of Credit Risk

We extend credit to various companies in the energy industry that may be affected by changes in economic or other external conditions. Our policy is to manage our exposure to credit risk through credit approvals and limits. Our trade accounts receivable are aged based on contractual payment terms and an allowance for doubtful accounts is established in accordance with our written corporate policy. The age of the trade accounts receivable, customer collection history and management’s judgment as to the customer’s ability to pay are considered in determining whether an allowance is necessary. Historically, write-offs for doubtful accounts have been insignificant. In 2005, however, 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.

In 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 and BP accounted for 11.0% in 2005. No other single customer accounted for 10% or more of total consolidated revenue for 2006 and 2005.

Stock-Based Compensation

In October 1995, the Financial Accounting Standards Board issued SFAS No. 123, “Accounting for Stock-Based Compensation”. SFAS No. 123 establishes financial accounting and reporting standards for stock-based employee compensation. The pronouncement defined a fair value-based method of accounting for an employee stock option or similar equity instrument. SFAS No. 123 also allowed an entity to continue to measure compensation cost for those instruments using the intrinsic value-based method of accounting prescribed by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB No. 25”). We elected to follow APB No. 25 and its related interpretations in accounting for employee stock options because the valuation models prescribed for use by SFAS No. 123 to determine the fair value of options were not developed for use in valuing employee stock options and did not consider factors such as vesting periods or other selling limitations.

In December 2004, the FASB issued SFAS No. 123R “Share Based Payment”, which replaced SFAS No. 123 and superceded APB No. 25. SFAS No. 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values beginning with the first interim or annual period after December 31, 2005. The pro forma disclosures previously permitted under SFAS No. 123 are no longer an alternative to financial statement recognition. Under SFAS No. 123R, we must determine the appropriate fair value model to be used for valuing share-based payments, the amortization method for compensation cost and the transition method to be used at the date of adoption. The transition methods include modified prospective and retroactive adoption options. Under the modified retroactive option, prior periods may be restated either as of the beginning of the year of adoption or for all periods presented. The prospective method requires that compensation expense be recorded for all unvested awards at the beginning of the first quarter of adoption of SFAS No. 123R, while the retroactive methods would record compensation expense for all unvested awards beginning in the first period restated.

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

For purposes of pro forma disclosure, the estimated fair value of the options is amortized to expense over the options’ vesting period. Set forth below is a summary of our net income and earnings per share as reported and pro forma as if the fair value-based method of accounting defined in SFAS No. 123 had been applied. The pro forma information is not meant to be representative of the effects on reported net income for future years.

	2005
	(in thousands, except for per share amounts)
Net income, as reported	$	38,390
Employee stock-based compensation included in net income (loss), net of income taxes		481
Pro forma stock-based employee compensation expenses determined under fair value- based method, net of related tax effects		(553	)
Pro forma net income	$	38,318
Earnings per share:
Basic, as reported	$	1.92
Basic pro forma	$	1.91
Earnings per share:
Diluted, as reported	$	1.86
Diluted pro forma	$	1.85

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. For the year ended December 31, 2005, options to purchase 563,000 shares at prices ranging from $16.27 to $21.25 were excluded from the calculation, as the results would be anti-dilutive. The detail of the earnings per share calculations for continuing operations for the years ended December 31, 2007, 2006 and 2005 is as follows (in thousands, except per share amounts):

	Year ended December 31, 2007
	Net Income		Weighted Average Shares		Per Share 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 Income		Weighted Average Shares		Per Share 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

	Year ended December 31, 2005
	Net Income		Weighted Average Shares		Per Share Amount
Loss per share, basic	$	38,390		20,031	$	1.92
Dilutive effect of common stock options		—		635
Loss per share, diluted	$	38,390		20,666	$	1.86

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 2007, 2006 or 2005.

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 September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value, and expands disclosure requirements regarding fair value measurement. Where applicable, this statement simplifies and codifies fair value related guidance previously issued within U.S. GAAP. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We are currently reviewing SFAS No. 157 to determine if its adoption will have a material effect on our results of operations or financial position.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”). SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We are currently reviewing SFAS No. 159 to determine if its adoption will have a material impact on our results of operations or financial position.

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 November 2007, the SEC issued Staff Accounting Bulletin No. 109, “Written Loan Commitments Recorded at Fair Value through Earnings” (“SAB No. 109”). SAB No. 109 expressed the views of the staff regarding written loan commitments that are accounted for at fair value through earnings under generally accepted accounting principles. The staff expects registrants to apply these views on a prospective basis to derivative loan commitments issued or modified in fiscal quarters beginning after December 15, 2007. We have evaluated SAB No. 109 and have determined that it will not have an impact on our results of operations or financial position.

In December 2007, the SEC issued Staff Accounting Bulletin No. 110, “Share-Based Payments” (SAB No. 110). SAB No. 110 expresses the views of the staff regarding the use of a simplified method in developing an estimate of expected term of share options, and will continue to accept under certain circumstances, the use of the simplified method beyond December 31, 2007. We have evaluated SAB No. 110 and have determined that it will not have an impact on our results of operations or financial position.

(2) 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. In 2005, we took delivery of three new build vessels, the Coloso, Titan, and Sea Intrepid. During 2006, we took delivery of two new construction vessels, the Sea Guardian and the Sea Sovereign. In 2007 and early 2008, we added another five new build vessels to our fleet.

In 2007, we made progress payments related to our ongoing new build vessel program. Also during 2007, we committed to build two new PSVs, similar to the design of the North Promise and HighlandPrestige but with a double hull and environmental enhancements. The delivery of these vessels are scheduled to occur in late 2009 and the first half of 2010. Additionally, in the third quarter 2007, we entered into agreements with two shipyards to construct five additional vessels, three PSVs and two AHTS vessels. These vessels are scheduled to be delivered between the fourth quarter of 2009 and the third quarter of 2010. In total, we spent approximately $175.7 million related to new vessel construction in 2007.

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

Vessel	Scheduled Delivery Date	Type	Length (feet)	Deadweight tons	Estimated Cost (in millions)
North Sea Based:
Aker 726	Q4 2009	PSV	284	4,850	$45.4
Aker 727	Q2 2010	PSV	284	4,850	$45.4
Southeast Asia Based:
Sea Kiowa	Q1 2008	AHTS	250	2,700	$24.9
Sea Cherokee	Q3 2008	AHTS	250	2,700	$24.5
Sea Choctow	Q3 2008	AHTS	250	2,700	$24.3
Sea Comanche	Q4 2008	AHTS	250	2,700	$24.4
Other:
Bender 1	Q4 2009	PSV	245	3,000	$25.5
Bender 2	Q2 2010	PSV	245	3,000	$25.5
Bender 3	Q3 2010	PSV	245	3,000	$25.5
Remontowa 20	Q2 2010	AHTS	230	2,150	$26.9
Remontowa 21	Q3 2010	AHTS	230	2,150	$26.9

Our strategy has always 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. Additionally, during 2007 we sold the North Sea based North Prince and Southeast Asia based Sem Courageous, Sea Explorer and Sea Endeavor. All of these vessels were sold for gains. We feel the sale of these older vessels coincides well with the scheduled deliveries of our new builds and fits our long-term strategy of selling older vessels when attractive opportunities arise.

(3) GOODWILL

The following is a rollforward of our goodwill (in thousands):

	2007		2006		2005
Balance, January 1,	$	29,883	$	27,628	$	30,218
Adjustment related to prior-period acquisition costs		—		—		430
Impact of foreign currency translation and adjustments		4,381		2,255		(3,020	)
Balance, December 31,	$	34,264	$	29,883	$	27,628

(4) LONG-TERM DEBT

Our long-term debt at December 31, 2007 and 2006, consisted of the following:

	2007			2006
	(In thousands)
7.75% Senior Notes due 2014, interest payable semi-annually	$	160,000		$	160,000
Debt owed on partnership interest related to the new build vessels		—			794
		160,000			160,794
Less: Current maturities of long-term debt		—			(794	)
Debt discount, net		(442	)		(510	)
	$	159,558		$	159,490

The following is a summary of scheduled debt maturities by year (in thousands):

2008	$	—
2009		—
2010		—
2011		—
2012		—
Thereafter		160,000
Total	$	160,000

Senior Notes

•	At any time before July 15, 2007, we could redeem up to 35% of the 7.75% senior notes with net cash proceeds of certain equity offerings, as long as at least 65% of the aggregate principal amount of the 7.75% senior notes issued pursuant to the indenture remains outstanding after the redemption.

•	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, 2007, 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 7.8%. At December 3, 2007, the fair value of these notes, based on quoted market prices, was approximately $161.2 million, as compared to a carrying amount of $159.6 million.

Bank Credit Facilities

secured by two vessel mortgages. Approximately $80.9 million was refinanced under the facility. The facility will mature in 2013 and the maximum availability begins to reduce in increments of $15.2 million every six months beginning after 66 months (in late 2011), with a final reduction of $129.5 million in June 2013. Security for the facility is provided by first priority mortgage on ten North Sea vessels and six Southeast Asia vessels and a negative pledge over six other vessels. The interest rate ranges from LIBOR plus a margin of 0.7% to 0.9% depending on our EBITDA coverage ratio. As of December 2007, there was no outstanding balance under the facility.

Other Debt

In 2006, we also 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.

(5) INCOME TAXES

A significant portion of our earnings originate in the North Sea, a region in which certain jurisdictions, including the United Kingdom and Norway, provide alternative taxing structures created specifically for qualified shipping companies, referred to as “tonnage tax” regimes. The tonnage tax regimes provide for a tax based on the net tonnage weight of a qualified vessel resulting in significantly lower taxes than those that would apply if we were not a qualified shipping company in those jurisdictions.

During the fourth quarter of 2007, the Norwegian taxing authority enacted tonnage tax legislation as part of their 2008 budgetary process and 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 which is similar to other EU tonnage tax systems. 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. Companies that participated in the repealed Norwegian tonnage tax system are now required to pay the tax on accumulated untaxed shipping profits as of December 31, 2006. Two-thirds of the liability is payable in equal installments over ten years, while the remaining one-third of the tax liability can be met through qualified environmental expenditures on Norwegian flagged vessels. Any remaining portion of the environmental part of the liability at the end of ten years would be payable at that time. As of December 31, 2007, our total USD equivalent of the NOK liability for the repealed Norwegian tonnage tax was $25.3 million. This amount was recorded in our tax provision as current income tax expense. The first annual cash payment of $1.7 million due in 2008 is classified on our balance sheet as current income taxes payable and the $23.6 million remainder is classified on our balance sheet as other income taxes payable – long term. Of this amount, $15.2 million is payable over nine years and $8.4 million is the one-third environmental portion of the total liability, which we expect will be fully expended within the ten year period. Any such qualified environmental expenditures will reduce the $8.4 million tax liability and be recorded as a credit to our tax provision for the period in which the expenditures are incurred. Our Norwegian ship owning subsidiary plans to elect to enter into the new tonnage tax regime which will be based on the tonnage of our Norwegian flagged vessels and result in minimal Norwegian tax provisions/payments related to our operations from January 1, 2007 forward.

Except for the impact recorded in our 2007 tax provision for the repeal of the Norway tonnage tax law through 2006 as described above, substantially all of our tax provision is for taxes unrelated to the United Kingdom and Norway tonnage tax qualified shipping activities. Should our operational structure change or should the laws that created the tonnage tax regimes change, excluding the 2007 effect of the repeal of the Norway tonnage tax law through 2006 as described above, 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. As with the effect of the 2007 Norway changes, any such increase could cause volatility in the comparisons of our effective tax rate from period to period.

Effective January 1, 2008, Mexico has 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. This newly enacted tax rates are as follows: 16.5% for 2008, 17% for 2009 and 17.5% for 2010 and beyond. The results of our operations in Mexico will include the effect of the tax beginning in the first quarter of 2008. Additionally, in light of this new legislation we have 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 resulting in the establishment of net valuation allowance as described below.

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

	Year Ended December 31,
	2007			2006			2005
U.S.	$	(9,748	)	$	(10,583	)	$	(10,204	)
Foreign		138,943			103,364			51,976
	$	129,195		$	92,781		$	41,772

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

	2007										2006								2005
	Current		Deferred			FIN 48		Total			Current		Deferred			Total			Current		Deferred			Total
U.S.	$	53	$	(3,955	)	$	—	$	(3,902	)	$	—	$	(6,309	)	$	(6,309	)	$	44	$	(550	)	$	(506	)
Foreign		29,814		3,565			743		34,122			5,449		3,912			9,361			2,298		1,590			3,888
	$	29,867	$	(390	)	$	743	$	30,220		$	5,449	$	(2,397	)	$	3,052		$	2,342	$	1,040		$	3,382

Included in the $29,814 current foreign income taxes in the above table is $23.6 million for the change in the Norway tax law of which $8.4 million is the tax liability that can be reduced by qualified environmental expenditures through the year 2016 and $15.2 million is payable over nine years beginning in 2009.

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

	2007			2006			2005
U.S. federal statutory income tax rate		34.0	%		34.0	%		34.0	%
Effect of foreign operations		(10.2	)		(30.0	)		(27.0	)
Valuation allowance		0.4			0.7			2.0
Other		(0.8	)		(1.4	)		(0.9	)
		23.4	%		3.3	%		8.1	%

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, 2007 and 2006 are as follows:

	December 31,
	2007			2006
	(In thousands)
Deferred tax assets
Accruals currently not deductible for tax purposes	$	3,762		$	2,615
Net operating loss carryforwards		18,727			16,052
Foreign and other tax credit carryforwards		4,364			3,676
	$	26,853		$	22,343
Less valuation allowance		(9,092	)		(4,901	)
Net deferred tax assets	$	17,761		$	17,442

Deferred tax liabilities
Depreciation	$	(16,714	)	$	(14,274	)
Foreign income not currently recognizable		(2,655	)		(6,367	)
Other		(1,124	)		(4,078	)
Total deferred tax liabilities	$	(20,493	)	$	(24,719	)
Net deferred tax liability	$	(2,731	)	$	(7,277	)

As of December 31, 2007 and 2006, the total net deferred tax liability of $2.73 million and $7.3 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, 2007 and 2006 was an increase of $4.2 million and $1.4, respectively. As of December 31, 2007, we had net operating loss carryforwards, or NOLs, for income tax purposes totaling $31.6 million in the U.S., $6.7 million in Brazil, $8.1 million in Norway, and $12.3 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 $2.3 million valuation allowance has been established for these NOLs. In addition, it is more likely than not that the Norway NOLs will not be utilized and a full valuation allowance has been established for such NOLs. Except for the amounts related to Brazilian temporary differences, it is also more likely than not that the Brazilian NOLs will not be utilized and a $1.6 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 $430.1 million at December 31, 2007.

Beginning January 1, 2005, the majority of our foreign shipping income was no longer subject to tax in the United States. Accordingly, in 2005 we reviewed our global operating structure and executed a worldwide restructuring to maximize potential growth and cash flow, as well as create a more favorable tax efficient corporate structure for the expansion of our business.

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:

	2007
	(in thousands)

Unrecognized tax benefits balance at January 1, 2007	$	8,883
Gross increases for tax positions taken in prior years		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, 2007	$	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 do not expect that any of our unrecognized tax benefits as of December 31, 2007 will be settled within twelve months. As of December 31, 2007 we are under tax examination, or may be subject to examination in the U. S. for years after 1998 and in five major foreign tax jurisdictions with open years for one after 1995, one after 1996, one after 2000, one after 2003 and one after the year 2004.

We accrue interest and penalties related to unrecognized tax benefits in our provision for income taxes. At December 31, 2007, we had accrued interest and penalties related to unrecognized tax benefits of $5.8 million. The amount of interest and penalties recognized in our tax provision for the year ended December 31, 2007 was $1.9 million.

(6) COMMITMENTS AND CONTINGENCIES

At December 31, 2007, 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, 2007, 2006 and 2005 was $904, $673, and $579 thousand, respectively. Future minimum rental commitments under these leases are as follows (in thousands):

2008	$	848
2009		711
2010		625
2011		477
2012		424
Thereafter		1,474
Total	$	4,559

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 2004. The option is subject to a notification period and agreement between the parties as to the purchase price based on certain factors. An amendment to the charter in 2007 has resulted in a further extension of the option until late 2010.

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.

(7)

EQUITY INCENTIVE PLANS

Stock Options and Stock Option Plans

The terms of our 2005 Non-Employee Director Plan, or Director Plan, provides that each non-employee director will receive a grant of stock awards annually. 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, 2007, 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.

	2007					2006					2005
	Shares			Weighted Average Exercise Price		Shares			Weighted Average Exercise Price		Shares			Weighted Average Exercise Price
		904,150		$	13.63		1,083,470		$	11.98		1,233,626		$	11.69
Granted		—			—		—			—		—			—
Forfeitures		—			—		—			—		—			—
Exercised		(114,500	)		8.78		(179,320	)		3.70		(150,156	)		9.57
Outstanding at end of year		789,650		$	14.33		904,150		$	13.63		1,083,470		$	11.98
Exercisable shares and weighted average exercise price				$	14.33		904,150		$	13.63		1,083,470		$	11.98
Shares available for future grants at December 31, 2007:
1993 Non-Employee Director Stock Option Plan		360,000					360,000					360,000
1997 Incentive Equity Plan		1,218,914					190,100					287,550
2005 Non-Employee Director Share Incentive Plan		99,000					120,100					136,800

The following table summarizes information about stock options outstanding at December 31, 2007:

		Outstanding					Exercisable
Range of Exercise Prices		Shares		Weighted Average Exercise Price		Weighted Average Remaining Life	Shares		Weighted Average Exercise Price
$	6.58 to $10.06		244,000	$	7.26	1.56 years		244,000	$	7.26
$	13.10 to $17.44		443,650	$	16.60	3.14 years		443,650	$	16.60
$	19.37 to $21.25		102,000	$	21.21	4.37 years		102,000	$	21.21
			789,650	$	14.31			789,650	$	14.31

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 and APB No. 25, 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, 2007, there were 309,352 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, 2007, a total of $1.7 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.

(8) 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 $90,000, $24,000 and $27,000 for the years ended December 31, 2007, 2006 and 2005, respectively.

Multi-employer Pension Obligation

Norwegian Pension Plan

The Norwegian pension plan includes approximately 15 office employees and 290 seamen and is a defined benefit, multiple-employer plan, insured with Nordea Liv. Benefits 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 measurement date is used for the actuarial

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

	2007			2006
Change in Benefit Obligation
Benefit obligation at beginning of the period	$	5,545		$	3,479
Benefit periodic cost		683			386
Interest cost		284			251
Benefits paid		(298	)		(234	)
Actuarial gain/loss		(327	)		1,377
Translation adjustment		820			286
Benefit obligation at year end	$	6,707		$	5,545

	2007			2006
Change in Plan Assets
Fair value of plan assets at beginning of the period	$	3,326		$	2,390
Actual return on plan assets		208			164
Contributions		835			665
Benefits paid		(112	)		(91	)
Administrative fee		(41	)		(35	)
Actuarial gain/loss		(605	)		36
Translation adjustment		492			197
Fair value of plan assets at end of year	$	4,103		$	3,326

	2007			2006

Funded status	$	2,603		$	2,218
Social security		400			345
Unrecognized net actuarial gain and other prepaid benefit cost		—			—
Net obligation including social security	$	3,003		$	2,563

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

	2007			2006

Deferred costs and other assets	$	233		$	228
Other liabilities		3,237			2,791

	2007			2006
Components of Net Period Benefit Cost
Service cost	$	684		$	386
Interest cost		284			251
Return on plan assets		(208	)		(164	)
Administrative fee		41			35
National Insurance (social security) contribution		127			104
Recognized net actuarial loss		299			1,491
Net periodic benefit cost	$	1,227		$	2,103

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	2007			2006
Discount rate		4.7	%		5	%
Return on plan assets		5.75	%		6	%
Rate of compensation increase		4.5	%		4.75	%

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:

	2007			2006
Equity securities		20.7	%		18	%
Debt securities		55.7	%		61	%
Property		17.9	%		16	%
Other		5.7	%		5	%
All asset categories		100	%		100	%

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

The projected benefit obligation and the fair value of plan assets for the Norwegian pension plan were approximately $6.7 million and $4.1 million, respectively for December 31, 2007, and $5.5 million and $3.3 million, respectively for December 31, 2006. We expect to contribute approximately $0.9 million to the Norwegian pension plan in 2008. No plan assets are expected to be returned to us in 2008.

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

Year ended December 31,
2008	$	289
2009		299
2010		310
2011		322
2012		322
Total	$	1,542

(9) 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 2007, 9,948 shares were issued through the ESPP, generating approximately $0.3 million in proceeds. The provisions of the ESPP are described above in Note 7 in more detail.

A total of 160,102 and 97,450 restricted shares of our stock were granted to certain officers and key employees in 2007 and 2006, respectively, pursuant to our 1997 Incentive Equity Plan described above in Note 7, with an aggregate market value of $6.3 million and $2.7 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.

(10) RELATED PARTY TRANSACTIONS

Lehman Brothers, Inc., or Lehman, an affiliate of Lehman Brothers Holdings, Inc., a significant shareholder, has provided certain investment banking, commercial banking and financial advisory services to us and our affiliates, for which it has received customary fees and commissions. Lehman received approximately $2.2 million in fees in 2005 in connection with the tender offer purchase of our 8.75% senior notes and subsequent issuance of our 7.75% senior notes. Two of our board members are officers of Lehman.

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.

(11) 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 Sea			Southeast Asia			Americas		Other			Total
Year Ended December 31, 2007
Revenue	$	241,664		$	41,257		$	23,105	$	—		$	306,026
Direct operating expenses		100,716			8,064			14,651		17,266			140,697
Drydock expense		10,369			1,832			405		—			12,606
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		80,519			8,058			15,361		12,440			116,378
Drydock expense		6,446			1,775			828		—			9,049
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

Year Ended December 31, 2005
Revenue	$	160,276		$	19,570		$	24,196	$	—		$	204,042
Direct operating expenses		75,226			5,982			14,648		10,380			106,236
Drydock expense		7,069			960			1,166		—			9,195
Depreciation and amortization		22,084			2,621			3,961		209			28,875
Gain on sale of assets		—			—			—		—			—
Operating income (loss)	$	55,897		$	10,007		$	4,421	$	(10,589	)	$	59,736

Total assets	$	424,890		$	39,349		$	96,445	$	53,231		$	613,915
Long-lived assets(a)(b)	$	390,121		$	32,427		$	92,340	$	28,956		$	543,844
Capital expenditures	$	4,026		$	9,751		$	6,556	$	23,009		$	43,343

(a)	Goodwill is included in the North Sea 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. We had no revenue or long-lived assets attributable to the United States, our country of domicile.

(12) UNAUDITED QUARTERLY FINANCIAL DATA

Summarized quarterly financial data for the two years ended December 31, 2007 and 2006 are as follows:

	Quarter
	First		Second		Third		Fourth
	(In thousands, except per share amounts)
2007
Revenue	$	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

2006
Revenues	$	47,675	$	58,433	$	75,831	$	68,982
Operating income		10,173		18,777		44,355		33,956
Net income		6,263		13,034		39,852		30,580
Per share (basic)		0.31		0.64		1.96		1.47
Per share (diluted)		0.30		0.63		1.91		1.42

ITEM 9. Changes in and Disagreements With Accountants on Accounting andFinancial 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, 2007, 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, 2007. 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, 2007, 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 andRelated 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 and Financial Statement Schedules

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

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

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

(3) Exhibits

Exhibits	Description	Incorporated by Reference from the Following Documents

3.1	Certificate of Incorporation, dated December 4, 1996	Exhibit 3.1 to our quarterly report on Form 10-Q for the quarter ended September 30, 2002

3.2	Certificate of Amendment of Certificate of Incorporation, dated March 6, 1997	Exhibit 3.2 to our quarterly report on Form 10-Q for the quarter ended September 30, 2002

3.3	Certificate of Amendment of Certificate of Incorporation, dated May 24, 2002	Exhibit 3.3 to our quarterly report on Form 10-Q for the quarter ended September 30, 2002

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	Exhibits 3.1, 3.2 and 3.3 to our quarterly report on Form 10-Q for the quarter ended September 30, 2002, 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 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

	10.1	GulfMark International, Inc. 1987 Stock Option Plan, as amended*	Exhibit 10.1 to our Registration Statement on Form S-4, Registration No. 333-24141 filed on March 28, 1997

	10.2	Amendment to the GulfMark International, Inc. 1987 Stock Option Plan, as amended*	Exhibit 10.2 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 (GulfMark International, Inc. 1987 Stock Option Plan, as amended)*	Exhibit 10.3 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997

	10.4	Form of Incentive Stock Option Agreement (1987 Stock Option Plan, as amended)*	Exhibit 10.6 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 Incentive Stock Option Agreement (1987 Stock Option Plan, as amended)*	Exhibit 10.5 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997

	10.6	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

	10.7	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

	10.8	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

	10.9	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

	10.10	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

10.11		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

10.12		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

10.13		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

10.14		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


10.15	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

10.16	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

10.17	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

10.18	Amendment No. 1 to the GulfMark Offshore, Inc. 2005 Non-Employee Director Share Incentive Plan*	Exhibit 4.8.2 to our Registration Statement on Form S-8, Registration No. 333-143258 filed on May 25, 2007

10.19	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

10.20	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

10.21	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

10.22	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

10.23	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

10.24	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

10.25	$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

10.26	$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

10.27	$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

10.28	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

10.29	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
	* Denotes compensatory arrangements.
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 28, 2008

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

/s/ Bruce A. Streeter	Chief Executive Officer, President and Director	February 28, 2008
Bruce A. Streeter	(Principal Executive Officer)

/s/ Edward A. Guthrie	Executive Vice President, Finance	February 28, 2008
Edward A. Guthrie	(Principal Financial Officer)

/s/ Carla S. Mashinski	Vice President, Accounting	February 28, 2008
Carla S. Mashinski	(Principal Accounting Officer)

/s/ David J. Butters	Director	February 28, 2008
David J. Butters

/s/ Peter I. Bijur	Director	February 28, 2008
Peter I. Bijur

/s/ Marshall A. Crowe	Director	February 28, 2008
Marshall A. Crowe

/s/ Louis S. Gimbel, 3rd	Director	February 28, 2008
Louis S. Gimbel 3rd

/s/ Sheldon S. Gordon	Director	February 28, 2008
Sheldon S. Gordon

/s/ Robert B. Millard	Director	February 28, 2008
Robert B. Millard

/s/ Robert T. O’Connell	Director	February 28, 2008
Robert T. O’Connell

/s/ Rex C. Ross	Director	February 28, 2008
Rex C. Ross

Exhibits		Description	Incorporated by Reference from the Following Documents

3.1		Certificate of Incorporation, dated December 4, 1996	Exhibit 3.1 to our quarterly report on Form 10-Q for the quarter ended September 30, 2002

3.2		Certificate of Amendment of Certificate of Incorporation, dated March 6, 1997	Exhibit 3.2 to our quarterly report on Form 10-Q for the quarter ended September 30, 2002

3.3		Certificate of Amendment of Certificate of Incorporation, dated May 24, 2002	Exhibit 3.3 to our quarterly report on Form 10-Q for the quarter ended September 30, 2002

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	Exhibits 3.1, 3.2 and 3.3 to our quarterly report on Form 10-Q for the quarter ended September 30, 2002, 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 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

	10.1	GulfMark International, Inc. 1987 Stock Option Plan, as amended*	Exhibit 10.1 to our Registration Statement on Form S-4, Registration No. 333-24141 filed on March 28, 1997

	10.2	Amendment to the GulfMark International, Inc. 1987 Stock Option Plan, as amended*	Exhibit 10.2 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 (GulfMark International, Inc. 1987 Stock Option Plan, as amended)*	Exhibit 10.3 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997

	10.4	Form of Incentive Stock Option Agreement (1987 Stock Option Plan, as amended)*	Exhibit 10.6 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 Incentive Stock Option Agreement (1987 Stock Option Plan, as amended)*	Exhibit 10.5 to our Registration Statement on Form S-1, Registration No. 333-31139 filed on July 11, 1997

	10.6	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

	10.7	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


	10.8	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

	10.9	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

	10.10	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

10.11		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

10.12		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

10.13		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

10.14		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

10.15		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

10.16		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

10.17		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

10.18		Amendment No. 1 to the GulfMark Offshore, Inc. 2005 Non-Employee Director Share Incentive Plan*	Exhibit 4.8.2 to our Registration Statement on Form S-8, Registration No. 333-143258 filed on May 25, 2007

10.19		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

10.20		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

10.21		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

10.22		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

10.23		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


10.24	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

10.25	$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

10.26	$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

10.27	$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

10.28	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

10.29	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
	* Denotes compensatory arrangements.
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