UNITED STATES SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

Commission file number 000-22853

GulfMark Offshore, Inc.

Registrant’s telephone number, including area code: (713) 963-9522
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:

Common Stock, $0.01 Par Value
(Title of class)

     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 filing requirements for the past 90 days. Yes þ

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

     Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes þ

     The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2004, the last business day of the registrant’s most recently completed second fiscal quarter was $223,673,326 calculated by reference to the closing price of $15.78 for the registrant’s common stock on the NASDAQ National Market on that date.

     Number of shares of common stock outstanding as of March 24, 2005: 20,114,744.

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.

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TABLE OF CONTENTS

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PART I

ITEMS 1. and 2. Business and Properties

GENERAL BUSINESS

     GulfMark Offshore, Inc. is a Delaware corporation that provides offshore marine services primarily to companies involved in offshore exploration and production of oil and natural gas. Our vessels transport materials, supplies and personnel to offshore facilities, and position drilling structures. The majority of our operations are conducted in the North Sea, with the balance in offshore Southeast Asia and Brazil. Periodically, we will contract vessels into other regions to meet our customers’ requirements.

     GulfMark Offshore, Inc. operates 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 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 Operation – Segment Results” included in Part II, Item 7. and Note 9 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 special reports, proxy statements and other information with the SEC. Our SEC filings are available 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: 450 Fifth Street, N.W., 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. 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 position drilling structures. Offshore marine service providers are employed by oil and 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 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 India, Australia, 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 our fleet of 54 offshore supply vessels in the following regions: 34 in the North Sea, ten in Southeast Asia, five in Brazil, two in India, one in West Africa, and two vessels mobilizing to Mexico.

     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 not followed previous patterns of greater expenditures when commodity prices are high and lower expenditures during lower pricing periods. 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 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. These same design characteristics make the North Sea capable vessels unsuitable for certain underdeveloped areas where draft restrictions and, to a lesser degree, higher operating costs restrict migration out of the market. The effect of these restrictions on vessel movement is to segment various regions into separate markets.

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Size of Vessel Fleet

     The size of our fleet has changed from 56 vessels on December 31, 2003 to 54 vessels on March 31, 2005. One newbuild vessel, the Austral Abrolhos, was delivered in September 2004, as a part of our new construction program. Additionally, in December 2004 we acquired the Highland Citadel, a 2003 built 755L platform supply vessel, which we previously managed. The new vessel construction program was concluded in March 2005 with the delivery of two vessels that are mobilizing to Mexico under long-term charters. During 2004, we sold three of our older Southeast Asia-based vessels, one vessel in the North Sea, and we returned the last of our bareboat chartered vessels to its owner. Also, during 2004, our managed vessel fleet was reduced by one vessel bringing the total managed vessels to seven as of March 31, 2005. The following table summarizes the fleet changes since December 31, 2003:

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 neither precise nor rigid, and it is not unusual for a vessel to fit into more than one of the categories. These functional classifications are:

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Platform Supply 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 service in construction support.

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Anchor Handling, Towing and Supply Vessels, or AHTS, are used to set anchors for drilling rigs and tow mobile drilling rigs and equipment from one location to another. In addition, these vessels typically can be used in limited 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, SmAHTS, while AHTSs in excess of 10,000 BHP are referred to as large AHTSs, or LgAHTSs. The most powerful North Sea Class AHTSs have up to 25,000 BHP. All our AHTSs can also function as PSVs.

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Construction Support Vessels are vessels such as pipe-laying barges 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. Our North Sea fleet has the distinction of being one of the only significant concentration of pipe carrier capable vessels outside of Scandinavian control.

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Standby Rescue Vessels, or Stby, perform a safety patrol function for an area and are required for all manned locations in the United Kingdom sector of the North Sea. 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 and shelter and, in some cases, also function as supply vessels.

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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 supply 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.

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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.

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Some of our owned vessels frequently provide specialty functions, and two managed vessels are currently chartered for 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 gas companies and state-owned oil and gas companies), in large part because of the significant financial commitment required in this market. Recently, however, there have been a number of independent operators who have begun to develop fields in the North Sea or who have made significant acquisitions from the major oil companies with plans to further develop these properties. 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 such as the Gulf of Mexico. 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.

     This market can be broadly divided into three areas: exploration, production platform support and field development or construction. Support of the more volatile exploration segment of the market represents the primary demand for AHTSs. While supply vessels 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. However, since AHTSs are capable of performing in a supply role, with the reduction in exploration and production activities starting in 2002 in the North Sea, many AHTSs have been available to compete in the supply vessel market and thus contributed to lower day rates in 2003 and through the third quarter of 2004.

     Our North Sea-based fleet is oriented toward supply vessels which work in the more stable segments of production platform support and field development or construction, and includes 30 owned (21 PSVs, four AHTSs, and five SpV vessels) and seven managed PSVs. 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 the North Sea vessel count and related statistics, unless deployed to one of our other regions under long-term contracts.

     The North Sea market was generally a very stable market from the early-1990’s through late in 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 newbuild vessels delivered into the market in 2002 – 2004 which resulted in the lowest utilization in the region in the last decade during the period 2003-2004. While the number of high capacity vessels in this market has remained fairly constant over the last ten years at approximately two hundred, there have been over three hundred vessels of the same design capacity delivered which 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 was also a transformation in the customer base in the region that began in 2003 and continued throughout 2004 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 was evidenced in the North Sea, particularly in the Norwegian sector, which specifically related to the opening of the Barent Sea to exploration activities by the Norwegian government. In addition, several large projects including the Orman Lange, Snovhit and Alvheim Field developments resulted in the oil and gas companies that contracted the drilling rigs to tender for vessel services in support for these rigs. Late in the third quarter

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of 2004, utilization and day rates for vessels in the region began to improve with some consistency throughout the balance of 2004.

     This region typically has weaker periods in the winter months of December – February; however, with a few exceptions, utilization and day rates have remained strong throughout these months. Visibility with regard to vessel demand over the balance of 2005 and into 2006 is directly related to drilling and development activities in the region as well as construction work required in support of these activities and demands outside of the region which will draw vessels to other international markets. Geopolitical events, the demand for oil and 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, we anticipate a consistent market throughout the balance of 2005 and into the first half of 2006.

     The demand for existing vessels outside of the North Sea and the expanded role for deepwater projects in worldwide locations have continued to lead to migrations of vessels to other operating areas. As 2002 was coming to a close, we mobilized three vessels from the North Sea to other operating areas. The Highland Legend went to Southeast Asia, the Highland Piper went to Brazil and the newly delivered Highland Bugler went to India. In 2003, the North Crusader mobilized to Brazil as a front-runner for the Brazilian vessel under construction and the Highland Drummer mobilized to India along with a managed vessel. In 2004 we mobilized the Highland Warrior to Brazil on a four-year contract and the North Stream on a two year contract. The Highland Patriot went to Southeast Asia where we gained higher utilization. We also brought the Highland Bugler and the Highland Piper back to the North Sea after completion of contracts in India and Brazil respectively. Late in 2004 and after the delivery of the Austral Abrolhos in Brazil the North Crusader left the region and initially went to West Africa where it is working on a short term exploration project. All of these vessel movements have been undertaken to take advantage of contract opportunities or to place the vessels where there were improved opportunities for contracts. It is our intent to continue to seek opportunities for term work at attractive rates outside of the North Sea while preserving our capability to take advantage of market potential in the North Sea region.

The Southeast Asia Market

     We define the Southeast Asia market 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. We believe that a number of exploration and production projects planned or underway could increase the future demand for offshore marine services in the Southeast Asia market.

     The Southeast Asia market differs country by country, but the 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 ten vessels deployed in this market.

     Vessels in this market are typically smaller than those operating in areas such as the North Sea. Yet, 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 Asian fleet. Demand for larger, newer and higher specification vessels is developing 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 the Highland Legend from the North Sea to this market in late 2002 and the Highland Patriot in early 2004 to meet the changing market in the region, as both of these vessels are larger than the typical vessels of the region. We sold three vessels serving in our Southeast Asia fleet, the Seawhip and the Seawitch in July 2004, and the Sea Conquest in September 2004.

     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, West Africa or the Gulf of Mexico could relocate to Southeast Asia. Not all vessels currently located in those regions would be able to operate in Southeast Asia. Furthermore, transferring a vessel from the Gulf of Mexico to this region would involve a significant cash and opportunity cost. During 2003, and the first half of 2004 when this market was stronger than other markets, movement of vessels into the Southeast Asia became more of a factor in the supply/demand equation. However, in the latter stages of 2004 the continuing strength in West Africa and the Middle East resulted in vessels leaving the area for those locations.

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     Indonesia is the only member of OPEC in the region. Oil and natural gas exploration activity in Indonesia has historically focused on oil exploration. Several large projects have now been identified that would exploit gas reserves as well as convert gas into liquefied natural gas for shipment to other areas of the world where gas demand is anticipated to continue to grow. Indonesian-based operations utilize the largest number of service vessels in the region. Demand in Indonesia has seen a number of peaks and valleys during the past decade, but over the last several years, has remained relatively constant with utilization levels remaining relatively high and day rates steady. We currently have one vessel operating in Indonesia for a major oil and natural gas company.

The Americas Market

     We define the Americas market as offshore North, Central and South America. Historically, our activity in the Americas has been in Brazil; however, we currently have two vessels in transit to Mexico to fulfill a contract with Pemex.

     Similar to the North Sea, the Brazilian market requires highly sophisticated vessels due to the harsh operating environment. We have experienced success in meeting the market requirements through owned, managed and bareboat chartered vessels and will look to our existing and newbuild fleet to meet the expanding demand for vessels in this important market.

     Over the last several years, the Brazilian government has opened up the petroleum industry to private investment. 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 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 which 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, with the recent success resulting in the contract awards for the North Stream, the Highland Warrior and the Austral Abrolhos.

     Currently, we operate five vessels in this region, including the Brazilian newbuild Austral Abrolhos, which was delivered in September 2004 and is contracted through October 2009 to Enterprise Oil do Brasil Ltda., a subsidiary of the Royal Dutch/Shell Group, in support of its Brazilian program in the Campos Basin. The Seapower has been operating in Brazil since 1995 under a contract with Petrobras, which runs into October 2005. The Highland Scout has been contracted to Petrobras since January 2000 and is contracted into April 2007. The Highland Warrior and the North Stream were mobilized to the region during 2004 and are contracted through August 2008 and June 2006, respectively. The North Crusader, which had been used as a front-runner for the Austral Abrolhos, mobilized to West Africa, and the Highland Piper completed its contract with Petrobras and mobilized back to the North Sea.

     We have contracted the two new build vessels, Coloso and Titan, under five-year primary-term contracts to Pemex in the Gulf of Mexico. This represents our first entry into the Gulf of Mexico market with Pemex and is anticipated to create additional opportunities in the Gulf of Mexico in the future as Pemex increases the size and capability of the vessel fleet required to support their drilling operations. The vessels are scheduled to arrive in Mexico from the shipyard in Singapore and begin their contracts late in the second quarter of 2005.

Other Markets

     We have contracted our vessels outside of our operating segment regions principally on short-term charters in places such as West Africa and the Mediterranean region. We currently have a managed vessel in addition to one of our owned vessels working in support of drilling operations in India and one of our owned vessels operating in the Congo. 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.

New Vessel Construction Program

     During 2000, we committed to the construction of nine new North Sea class vessels with a Norwegian shipbuilder. This shipyard previously constructed several of our other newbuilds including the UT 755 design PSVs. The newbuild program included six PSVs and three AHTSs with all vessels designed to be multi-functional in that they are capable of supporting underwater ROV operations as well as traditional offshore support operations. All of the vessels were built to Rolls Royce/Ulstein specifications and included two UT 745 PSV, four UT 755 PSV and three UT 722L

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AHTSs. All of these vessels were delivered on time and within budget.

     Additionally, we contracted with the Norwegian shipyard’s Brazilian affiliate for the construction of a SpV for an estimated cost of $24 million. This vessel, the Austral Abrolhos, was delivered in September 2004. In December of 2003, we entered into a contract to build two 6,000 horsepower AHTSs pursuant to a contract with our joint venture partner in Mexico for Pemex. These two vessels, that cost approximately $22.0 million, were delivered in March 2005. As of the end of 2004, we had spent $226.0 million under the new vessel construction program, including $88.2 million in 2003 and $23.5 million in 2004. The following table outlines the cost and contracted delivery schedule of the program:

Delivered Vessels

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Our Fleet

     Our existing fleet as of March 31, 2005 is 54 vessels including the two vessels transitioning to Mexico. Of these vessels, 47 are owned by us (see table below) and seven are under management for other owners.

     The table above does not include seven managed vessels.

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Customers, Contract Terms and Competition

     Our principal customers are major integrated oil and gas companies and large independent oil and natural gas exploration and production companies working in international markets, and foreign government-owned or controlled oil and gas companies, as well as companies that provide logistic, construction and other services to such oil and 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 a year. While certain contracts do contain cancellation provisions, the contracts are generally not cancelable except for unsatisfactory performance by the vessel. During 2004, under multiple contracts in the ordinary course of business, one customer, Petrobras, accounted for 10.3% of total consolidated revenues. No other single customer accounted for 10% or more of our total consolidated revenues for 2004.

     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 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, multi-year charters have been more common, and we believe that term charters constitute a significant portion of that market. Term charters in Southeast Asia are currently somewhat less common than in the North Sea and generally less than two years in length. In addition, charters for vessels in support of floating production are typically “life of field” or “full production horizon charters”. Because 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.

     In the past we have bareboat chartered vessels. Bareboat charters are contracts for vessels, generally for a term in excess of one year, whereby the owner transfers all market exposure for the vessel to the charterer in exchange for an arranged fee. The charterer has the right to market the vessel without direction from the owner. Currently however, we have no 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. Depending on the level of service provided by the manager, fees for services are generally less than $10,000 per month per vessel. Currently, we have seven vessels under management.

     Substantially all of our charters are fixed in British pounds, Norwegian kroner and U.S. dollars. 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 10-15 companies in the North Sea market and numerous small and large competitors in the Southeast Asia and Americas markets 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.

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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 March 1, 2004 and March 1, 2005:

     These commitments provide us with a forward view of vessel income 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 March 1, 2005, as compared to March 1, 2004, for the current year and one year forward, is primarily a reflection of increased drilling and exploration activity in late 2004 and continuing into 2005, which resulted in higher demand for support vessels. This increase in demand resulted in more long-term (greater than one year) contracts at day rates we deem to be acceptable.

Environmental and Government Regulation

     We must comply with extensive government regulation in the form of international conventions, federal and state 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, recently 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 recently 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.

Operational Risks and Insurance

     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. Third parties may have significant claims against us for damages due to personal injury, death, property damage, pollution and loss of business.

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     We maintain customary insurance coverage for casualty and liability risks. We have renewed our primary insurance program for the insurance year 2005-2006. We believe our insurance is adequate, and we have never experienced a loss in excess of policy limits. There is no assurance that our insurance coverage will be available, or affordable in the future, and if available, whether it will be adequate to cover future claims that may arise.

Foreign Operations

     During the past five years, we derived substantially all of our revenues 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 governmental regulatory requirements;
	•	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;
	•	potentially adverse tax consequences;
	•	difficulties and costs of staffing and managing international operations; and
	•	language and cultural differences.

     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, we organized our subsidiary structure and our operations in part based on certain assumptions about various foreign and domestic tax laws, currency exchange requirements and capital repatriation laws. While we believe our assumptions are correct, there can be no assurance that taxing or other authorities will reach the same conclusions. If our assumptions are incorrect, or if the relevant countries change or modify such laws or the current interpretation of such laws, we may suffer adverse tax and financial consequences, including the reduction of cash flow available to meet required debt service and other obligations. Any of these factors could materially adversely affect our international operations and, consequently, our business, operating results and financial condition.

Seasonality of Business

     The operations of our fleet are subject to seasonal factors. Operations in the North Sea are generally at their highest levels during the months from April to August and at their lowest levels during November to February. During the last quarter of 2004 and the first several months of 2005, this typical pattern has not been evident as the demand for vessels in the region has been higher than in previous years during this period. Vessels operating in 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 actual monsoon season for a specific Southeast Asian location is about two months. In addition, operations in any market may be affected by unusually long or short construction seasons due to, among other things, abnormal weather conditions.

Internal Controls

     As a result of Section 404 of the Sarbanes-Oxley Act (“Sarbanes-Oxley”) and the rules issued thereunder by the SEC and the Public Company Accounting Oversight Board (“PCAOB”), we are required to include a report on our internal controls over financial reporting with our annual report on Form 10-K beginning with this Form 10-K for the year ending December 31, 2004. Our report must include an assessment by management on the effectiveness of our internal controls as well as a report from our independent registered public accounting firm attesting to management’s assessment. Further, our report is required to include a disclosure of any “material weakness” in our internal controls over financial reporting we have identified.

     During the review of the third quarter results, our independent registered public accounting firm identified internal control deficiencies related to the complexity of our multinational operations. These deficiencies were considered by our independent registered public accounting firm to be material weaknesses, which, if not corrected, could result in a material misstatement of our annual or interim financial results. Our independent registered public accounting firm concluded that we needed to evaluate our resources, processes and controls to implement improvements in our internal controls surrounding our financial statement close process. That conclusion was based on several adjustments that were made in the course of their quarterly review that, in their view, should have been identified and resolved by us as part of the financial statement close process.

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The adjustments made in the third quarter 2004 involved:

	•	our foreign tax provision in Norway,
	•	the allowance for bad debts, and
	•	accrued liabilities related to indirect labor costs in the North Sea.

     Our independent registered public accounting firm notified us that, in connection with these material weaknesses, we needed to implement certain improvements to our financial statement close, specifically the evaluation of the related resources, processes and controls. In response to this notification, we have taken steps to improve our financial close process and have evaluated the related resources, processes and controls as follows:

	•	Foreign Tax Provision. We have engaged an outside tax advisor separate from our registered independent public accounting firm to assist us with the tax considerations resulting from our multinational operations. We have subscribed to an online accounting research tool, which will be utilized to research complex accounting issues. A part-time Assistant Controller has been replaced with a full-time employee. With these steps we believe that we now should have sufficient resources and controls for our foreign tax provision close process and believe that the foreign tax provision control deficiency should have been resolved.
	•	Allowance for Bad Debts. We have developed a written corporate policy regarding the allowance for doubtful accounts receivable for significantly aged receivables that the Audit Committee has approved and that we have implemented as of December 31, 2004. This more formalized policy ensures there is a critical review of our aged accounts receivable to evaluate the collectibility of our receivables and establish appropriate allowances for bad debts. The newly adopted policy formalizes a previous practice of reviewing each account receivable that is six months old or more to determine whether, under the facts and circumstances, an allowance for bad debts should be established. In addition, the new policy, unlike previous practice, mandates that a reserve for bad debts must 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. Our previous practice did not require that a reserve for bad debt be established if an account receivable was outstanding one year or more unless management believed it was appropriate under the facts and circumstances. Because our exposure to foreign government-owned and controlled oil companies, as well as companies that provide logistics, construction or other services to oil and gas companies, may result in longer payment terms, management intends to continue to meet with customers that have significant aged receivables to assess the recovery of all receivables. We have implemented this policy and believe the allowance for bad debt control deficiency has been resolved.
	•	Indirect Labor Costs. The material weakness occurred as a result of a lack of processes in place to reconcile accruals against our actual indirect labor costs. We have revised our processes to include a reconciliation of our accruals to actual indirect labor costs incurred at the end of each reporting period. These accruals will be reviewed and reconciled on an on-going basis. We now believe the indirect labor cost control deficiency has been resolved.

     We estimate that the remedial steps outlined above will cost us approximately $100,000 in out-of-pocket costs, excluding reallocation of internal resources. For information on disclosure controls, and internal controls over financial reporting, see Item 9A "Controls and Procedures."

Employees

     At December 31, 2004, we had 1,085 employees located in the United States, the United Kingdom, Norway, Southeast Asia, India and Brazil. Through our contract with a crewing agency, we participate in the negotiation of collective bargaining agreements for 871 contract crew members who are members of two United Kingdom unions under evergreen employment agreements with wages negotiated annually in June. 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 these collective bargaining agreements. Relations with our employees are considered satisfactory. To date, our operations have not been interrupted by strikes or work stoppages.

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Properties

     Our principal executive offices are located in Houston, Texas. For local support, we have offices and warehouse facilities in: Singapore; Aberdeen, Scotland; Liverpool, England; Sandnes, Norway; and Macae, Brazil. 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 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 the outcome of these legal actions, if any, would not have a material adverse effect upon our consolidated financial position and results of our operations. We cannot predict whether any such claims may be made in the future.

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

NONE

PART II

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

     Our common stock is traded on the NASDAQ National 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:

     For the quarter ended March 31, 2005 (through March 15, 2005), the range of low and high sales prices was $19.55 to $28.34, respectively. On March 15, 2005, the closing sale price of our common stock as reported by the NASDAQ National Market was $23.65 per share. As of March 15, 2005, there were 597 shareholders 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 hereinafter defined) 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.

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 Item 8 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, included in Item 7.

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

     (i) Includes foreign currency transaction adjustments.

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

     This information should be read in conjunction with our Consolidated Financial Statements, including the notes thereto, contained herein. See also “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 technologically advanced fleet: Our fleet size, location and profile allow us to provide a full range of services to our customers from platform supply work to specialized floating, production, storage and offloading, or “FPSO”, support, including anchor handling and remotely operated vehicle, or ROV, operations. We regularly upgrade our fleet to improve capability, reliability and customer satisfaction. We also seek to take advantage of attractive opportunities to acquire or build new vessels to expand our fleet. We took delivery of nine newbuild vessels between 2001 and 2003, and one in 2004, acquired a vessel in December 2004 and have two newbuild vessels that delivered in the first quarter of 2005. We believe our relatively young fleet allows for less downtime, resulting in more dependable operations for both our customers and us. Our relatively young fleet requires less maintenance and refurbishment work during required drydockings than older fleets, which allows us to minimize downtime and maintenance capital expenditures.

Enhancing fleet utilization through development of specialty applications for our vessels: We operate some of the most technologically advanced vessels available. Our highly efficient, multiple-use vessels provide our customers maximum flexibility and are constructed with design elements such as dynamic positioning, firefighting, moon pools, and ROV handling and oil spill response capabilities. In addition, we design and equip newbuild vessels specifically to customer needs. In March, 2005, we took delivery of two vessels that were built to customer specifications for long-term contracts.

Focusing on attractive international markets: We have elected to conduct our current operations in the North Sea and offshore Southeast Asia and Americas markets because we believe there are higher barriers to entry, lower volatility of day rates and greater potential for increasing day rates in those 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 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 ones as they develop economically and become more profitable.

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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 pools. 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 pooling arrangements where vessels of similar specifications enter into a marketing alliance. 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 34 vessels operating from the area. We also have ten vessels operating in Southeast Asia, five vessels in Brazil, two vessels in India and two vessels mobilizing to Mexico. Our fleet has grown in both size and capability, from an original 11 vessels in 1990 to our present number of 54 vessels, through strategic acquisitions and new construction of technologically advanced vessels, partially offset by dispositions of certain older, less profitable vessels. As of March 31, 2005, our fleet includes 47 owned vessels and seven 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.

     In recent years the North Sea market has been characterized by delivery of new higher capacity and specification vessels, which have generally left the region or replaced older vessels that transferred to other oil service markets. During this same time frame, despite consistently high commodity prices in the oil and gas industry, exploration and production activities by oil and gas companies have not increased according to historical precedent. These two factors have led to lower utilization in the North Sea market over the last two years than had been experienced in the last decade and applied downward pressure to day rates. The first six months of 2004 were consistent with the lower utilization and day rates obtained during the previous two years. Improvements in industry day rates, and more particularly in utilization, during the third and fourth quarters indicate improving conditions. We believe that this market is poised for recovery as new drilling programs and associated construction projects in both the Norwegian and U.K. sectors of the North Sea begin in the latter part of 2004 and in 2005. Until such time as contracts for vessels are tendered, however, it is difficult to predict when this recovery will take place. The other two major markets in which we currently operate, Southeast Asia and Brazil, have been exemplified by consistent demand and relatively stable day rates. In addition to the one vessel we transferred to the region from the North Sea early in 2004, there have been several vessel operators that have repositioned equipment into Southeast Asia, which may tend to heighten competition in the region in the future. In October 2004, we mobilized the frontrunner for our newly delivered Brazilian vessel, the Austral Abrolhos, to the North Sea, as well. We anticipate the Brazil and Southeast Asia markets will continue to develop in the near term.

     From time to time, we bareboat charter vessels with revenues 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 have no bareboat chartered vessels at the present time.

     We also provide management services to other vessel owners for a fee. We do not include charter revenues and vessel expenses of these vessels in our operating results. However, management fees are included in operating revenues. 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 and utilization levels. 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 revenues 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.

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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.

Change in Accounting Principle

     Effective January 1, 2004, we began expensing the costs associated with the periodic requirements of the various classification societies, which requires each vessel to be placed in drydock twice in a five-year period. Generally, drydock costs include refurbishment of structural components as well as major overhauls of operating equipment, and is subject to scrutiny by the relevant classification society. Previously, costs incurred in connection with drydockings were capitalized and amortized over 30 months, which approximated the period between required drydockings.

     The industry’s accounting practices have historically allowed three methods to account for these expenditures: (1) defer and amortize, (2) accrue in advance, and (3) expense as incurred. There are no authoritative criteria for determining a preferable method of accounting for drydock expenditures. However, we have determined that expensing these costs as incurred is the method predominantly used in our industry peer group and at this time would be a more rational basis for recognizing major maintenance expenditures in our financial statements. Therefore, we believe that the change is to an acceptable alternative method, which is preferable based on our particular circumstances under accounting principles generally accepted in the United States, and we are adopting the method of expensing drydock costs in the period incurred effective in 2004.

     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), in the consolidated statement of operations for 2004. The effect of the change in accounting principle in 2004 also decreased income before the cumulative effect of change in accounting principle by approximately $1.9 million by reversing the current drydock amortization expense of $7.1 million and recognizing the expense for current drydock expenditures of $9.0 million. The following table illustrates the pro forma effects of retroactive application of this change in accounting principle on net income and earnings per share if we had expensed drydock costs in prior years.

Valuation Allowances

     Our valuation allowances relate primarily to the allowance for doubtful accounts receivable and the allowance against deferred tax assets arising from foreign tax credit carryforwards. 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 companies 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

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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 on a case-by-case basis as conditions warrant. We make critical estimates for the allowance for doubtful accounts based on the age of the receivable, collection history from the particular customer and management’s judgment of the ability of the customer to pay. Historically, we have collected appreciably all of our accounts receivable balances with the exception of approximately $0.2 million, which was deemed uncollectible and was written off during the past six years. At December 31, 2004, we provided an allowance for doubtful accounts of $0.9 million. Additional allowances for doubtful accounts may be necessary as a result of our ongoing assessment of our customers’ ability to pay. Because 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.

     In the fourth quarter of 2004, our Audit Committee adopted a management recommendation regarding the allowance for doubtful accounts receivable for significantly aged receivables. See “Business—Internal Controls.”

     Due to the passage of the American Jobs Creation Act (“Jobs Act”) on October 22, 2004, the foreign tax credit carryforwards of $1.5 million that would have expired in 2004 will now 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 have considered estimated future taxable income in the relevant tax jurisdictions to utilize the credits 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. Historically, we have not made significant adjustments to our valuation allowance.

Deferred Costs

     Since inception, we have capitalized the costs associated with the periodic requirements of the various classification societies, which requires the 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. Historically, these costs have been amortized over an estimated 30-month period. As discussed in the “Change in Accounting Principle” section above, we have changed our accounting for these costs. Effective January 1, 2004, we began expensing these costs as incurred. A charge of $7.3 million, net of tax ($0.37 per basic and diluted common share), reflecting the cumulative effect of this accounting change has been recorded at January 1, 2004.

     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. In the third quarter of 2004, a charge of $6.5 million was recognized relating to the retirement of our 8.75% senior notes. Those costs included $4.4 million from the payment of tender offer premiums and $2.1 million from the write-off of unamortized debt issuance costs and unamortized debt discount.

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 ASA and the June 2001 acquisition of Sea Truck (UK) Ltd. The determination of impairment of all long-lived assets, including goodwill, is conducted when indicators of impairment are present and at least annually on December 31 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 revenues and

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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.

     At December 31, 2004, 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 attrition, 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 change; 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 such as the United Kingdom and Norway provide for an alternative taxing structure created specifically for qualified shipping companies, referred to as the “tonnage tax” regime. The tonnage tax regime provides for tax at rates significantly lower than would apply if we were not a qualified shipping company. Substantially all of our tax provision is for deferred taxes in regions outside of the United Kingdom and Norway. The tonnage tax regime in the North Sea reduces the cash required for taxes in that region. In other regions, accelerated depreciation has minimized our cash requirements for income taxes. Should our organizational structure change or should the laws that created the tonnage tax regime or that allow for accelerated depreciation change, we would be required to provide for taxes at rates much higher than currently reflected in our financial statements. Additionally, if our pre-tax earnings in a higher tax jurisdiction increase, there could be a significant increase in our average tax rate. That increase could cause volatility in the comparison of our tax rate from period to period.

     Our United Kingdom tax return for the year 2001 was reviewed by Inland Revenue, the U.K. tax authority. As a result of this review, an amended year 2001 tax return has been filed and accepted by Inland Revenue as of December 27, 2004. The 2002 and 2003 returns have been amended consistent with the accepted methodology used in preparing the amended 2001 return. Since the U.K. subsidiary is under the self assessment system, and years 2002 and 2003 are within the prescribed period, the revised returns for 2002 and 2003 should be accepted as filed in December 2004 with respect to the issues reviewed by Inland Revenue. Based on the above, the previously provided deferred tax liability of $4.9 million, was reduced in the 2004 financial statements to the amount of tax payable of $0.3 million for the period 2001 through 2003.

     On October 22, 2004, President Bush signed the Jobs Act, which among other items, provides reform related to foreign shipping income. This new tax legislation should favorably impact us beginning January 1, 2005, as the majority of our foreign shipping income will not be subject to tax in the United States. The full extent of the positive impact on earnings as it relates to our organizational structure is not yet clear; however, we and our outside tax consultants are evaluating the ultimate impact of this new tax legislation.

Commitments and Contingencies

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

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Consolidated Results of Operations

Comparison of the Fiscal Years Ended December 31, 2004 and December 31, 2003.

     Our revenues increased from $129.9 million in 2003 to $139.3 million in 2004, largely as a result of the increase in North Sea activity late in the year, the full year effect of 2003 newbuild deliveries and the addition of two vessels during the second half of 2004. For the year ended December 31, 2004, income was $2.7 million, or $0.13 per diluted share before the cumulative effect of change in accounting principle of $7.3 million, or $0.36 per diluted share. Including the cumulative effect of the change in accounting principle, our net loss for 2004 was $4.6 million, or $0.23 per diluted share. For the year ended December 31, 2003, net income was $0.5 million, or $0.03 per diluted share.

     The weakness in exploration and development activities in the North Sea that started in 2002 began showing signs of recovery beginning late in the third quarter of 2004, with increasing day rates and utilization evident. Additionally, we experienced an increase in capacity resulting from the full year effect of the four newly built vessels delivered in 2003 and the addition of two additional vessels to our fleet in 2004, one in September and the other in December. Day rates improved during the year with the increases in the foreign currency exchange rate between the British pound and Norwegian kroner against the U.S. dollar being part of the improvement in rates.

     Revenue increased in all our regions except Southeast Asia, where the sale of three vessels during the year and slightly lower utilization resulted in a decrease of $0.4 million in revenue. In the Americas, revenue levels and average rate increased because of the change in our equipment mix. Overall, we experienced an increase in capacity of $4.2 million, mainly due to the factors listed above as well as one additional operating day in 2004. Day rates showed an increase of $8.2 million mainly attributable to stronger British pound and Norwegian kroner against the weak U.S. dollar, as day rates are generally denominated in international currencies. The decrease in revenues attributed to lower utilization was $2.9 million, resulting mainly from the weakness in the North Sea early in the year and the large number of vessels that were working on the spot market as a result.

     Direct operating expenses increased $1.4 million in 2004 over 2003. This increase was due to higher costs resulting from stronger currencies in the operating regions compared to the reporting currency and change in our equipment mix. Bareboat charter expense decreased $5.1 million to $1.4 million as we returned the last bareboat chartered vessel to its owner during 2004. We currently have no bareboat chartered vessels in our fleet. General and administrative expenses increased $4.9 million in 2004, as the implementation of Sarbanes-Oxley resulted in higher professional fees and higher salary-related expenses. Also, an increase in the allowance for doubtful accounts of $0.9 million contributed to this increase. Drydock expense of $9.0 million in 2004 relates to the change in accounting principle described above and in Note 1 to the Consolidated Financial Statements. Depreciation and amortization expense decreased by $1.9 million from 2004 to 2003 mainly due to the reclassification of drydock expense resulting from the change in accounting principle.

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Interest expense increased $4.3 million due mainly to the higher outstanding balance and a higher weighted average interest rate on our line of credit, resulting from the conversion of the line of credit from U.S. dollars to British pounds at the end of 2003. During 2004, we also incurred an expense of $6.5 million related to the redemption of our $130 million 8.75% senior notes. The gain on sale of assets of $2.3 million primarily reflects the sale of three of our oldest Southeast Asia based vessels, the Seawhip, the Seawitch and the Sea Conquest. Additionally, we reported income in the other category of $1.5 million, compared to $1.3 million expense in 2003, resulting from favorable foreign currency movements on intercompany accounts anticipated to be settled.

     The income tax benefit of $6.5 million for 2004 reflects the reversal of previously provided deferred tax liabilities for our North Sea operations, as our United Kingdom subsidiary underwent an Inland Revenue review relating to tonnage tax. Substantially all of our tax provision is for deferred taxes, and can fluctuate significantly based on the mix of vessels working in the higher tax jurisdictions.

Comparison of the Fiscal Years Ended December 31, 2003 and December 31, 2002.

     Because of the weakness experienced in our major market of the North Sea and despite the increase in the number of owned vessels in the year, our revenues decreased from $133.9 million in 2002 to $129.9 million in 2003. For the year ended December 31, 2003, we reported net income of $0.5 million, $0.03 per diluted share compared to $24.0 million, or $1.22 per diluted share in the prior year.

     The weakness in exploration and development activities in 2003, and the increased number of vessels which we had in the spot market where both day rates and utilization were well below historical levels, caused us to continue the strategy we implemented in 2002 whereby we did not generally elect to charter our vessels on long-term contracts at the prevailing rates. The result of this strategy was that our average utilization for the North Sea decreased when compared to the prior year and caused the overall utilization for the year to decrease slightly from the prior year. Utilization and day rates in the other two regions, namely the Americas and Southeast Asia, remained fairly consistent in 2003 when compared to 2002.

     The decrease in revenue therefore was entirely attributable to lower day rates and utilization in the North Sea which resulted in a $19.0 million decrease. Partially offsetting this decrease was the full year impact of vessels added to the fleet from the newbuild program in 2002 and the addition of the four new vessels in 2003. These additions to capacity, reduced by the return of three bareboat chartered vessels in 2003, contributed an additional $15.3 million more in revenue than in the prior year. During 2003, day rates, which are generally denominated in international currencies, were significantly lower in the North Sea, but due to the weakness of the U.S. dollar, the currency effect partially offset the lower day rates. In the table below, the North Sea day rate is a reflection of all vessels which are categorized in the North Sea and therefore the averages reflect all factors including day rates, utilization, currency effects and the increase in owned vessels. The following table summarizes average day rates, overall utilization and average vessels owned or chartered for the comparable periods:

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     Direct operating expenses increased $11.8 million in 2003. This increase was due to the increased number of vessels in the fleet as well as higher costs due to stronger currencies in the operating regions compared to the reporting currency. Bareboat charter expense decreased $2.8 million as a direct result of the return of three bareboat chartered vessels during 2003. General and administrative expenses increased $0.8 million in 2003. Half of the increase was due to higher exchange rates with the balance due to the expanded fleet size. Depreciation expense also increased in 2003 by $6.6 million when compared to 2002 as a result of the fleet increases and the currency effect. Interest expense (net of interest income) reflected an increase of $1.8 million due to a higher level of borrowings required to support the newbuild vessel program and lower interest income reflecting reduced cash balances available for investment. Additionally, we reported an unfavorable variance in the other category related to the weakening of the Norwegian kroner versus the British pound the denominated debt in our Norwegian subsidiary.

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. In prior years, we reported all operations in a single segment. In 2004, our segment reporting was changed to conform to the manner in which our chief operating decision maker reviews, and we manage, our business.

     Management evaluates segment performance primarily based on operating income. Cash and cash equivalents 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. Each operating segment’s operating income is summarized in the following table, and detailed discussions follow.

Operating Income by Operating Segment

North Sea Region:

Comparison of Fiscal Year Ended December 31, 2004 and December 31, 2003

     Revenues for 2004 increased $7.1 million, compared to 2003. The increase was primarily driven by increased capacity of $3.2 million due to a full year effect of newly built vessels delivered in 2003 partially offset by vessels mobilized out of the region and increased day rates of $8.7 million principally due to increases in foreign currency exchange rates between the British pound and Norwegian kroner against the U.S. dollar, offset by utilization decrease of $4.8 million due to the weaknesses in the market. Operating expenses and depreciation and amortization expense increased in total by $2.0 million from 2003 to 2004 primarily due to stronger currencies in the operating region compared to the U.S. dollar. Depreciation and amortization expense also decreased due to the reversal of drydock amortization and recording drydock expenses as incurred in 2004, which are now recorded in operating expenses.

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Comparison of Fiscal Year Ended December 31, 2003 and December 31, 2002

     Revenues from 2002 to 2003 decreased by $10.5 million. The decrease was primarily due to lower day rates of $1.9 million and utilization of $18.1 million, partially offset by the addition of new vessels in 2003 for a $9.5 million increase in capacity. The day rates, denominated in local currencies, were significantly lower in the North Sea, but due to the weakening of the U.S. dollar, the currency difference largely offset the lower day rate comparing 2002 to 2003. Operating expenses and depreciation and amortization expense increased by $7.7 million and $4.6 million, respectively, due primarily to the increased numbers of vessels in 2003 resulting from the delivery of vessels in the newbuild program.

Southeast Asia Region:

Comparison of Fiscal Year Ended December 31, 2004 and December 31, 2003

     Revenues for 2004 decreased by $0.4 million compared to 2003 due primarily to lower day rates of $0.6 million. Additionally, we experienced lower utilization of $0.2 million due to the sale of three vessels in 2004, partially offsetting this increase was higher capacity of $0.4 million resulting from mobilization of a vessel from another location. Operating expenses increased by $2.4 million largely due to the mobilization of a vessel from another region. Depreciation and amortization expense decreased due to the reversal of drydock amortization and recording drydock expense in 2004.

Comparison of Fiscal Year Ended December 31, 2003 and December 31, 2002

     Revenues from 2002 to 2003 increased by $1.7 million. The increase is principally due to increased capacity with a full year effect of Highland Legend in 2003. The full year effect of the mobilization of this vessel into the region also caused an aggregate increase in operating expenses and depreciation and amortization expense of $1.1 million.

Americas Region:

Comparison of Fiscal Year Ended December 31, 2004 and December 31, 2003

     Revenues for 2004 increased by $2.7 million, compared to 2003 due to increased capacity, day rate and utilization with the mobilization of the North Stream and the Highland Warrior into the region, and the delivery of the Austral Abrolhos to the Brazil market in 2004 offset by the mobilization of the Highland Piper to the North Sea during 2004 and the full year effect of the return of a bareboat chartered vessel to its owner during 2003. Operating expenses and depreciation and amortization expense increased in total by $1.5 million due to the net addition of vessels.

Comparison of Fiscal Year Ended December 31, 2003 and December 31, 2002

     Revenues increased by $4.8 million from 2002 to 2003 primarily due to increased capacity resulting from the mobilization of a vessel from the North Sea into the region and by increased day rates. Operating expenses and depreciation and amortization expense increased as well due to the increase in the number of vessels in the market.

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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.

     We anticipate that the cash on hand and cash flow from operations, for the twelve months ending December 31, 2005, will be adequate to repay our debts due during such period to make normal recurring capital additions and improvements and to meet working capital requirements. We believe that our current cash and short-term investments 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. To the extent that existing sources are insufficient to meet those cash requirements we would seek other debt or equity financing, however, we can give no assurances that such debt or equity financing would be available on acceptable terms.

Long-Term Debt

     The Multi-currency Bank Credit Facility, which we entered into with a syndicate of five banks, is presently secured by eight of our vessels. The maximum commitment amount was originally $100 million. During the third quarter of 2004, the facility began its $4 million quarterly reduction phase, which will continue until the fourth quarter of 2007. A final payment of $44 million will be due in March 2008. At December 31, 2004, the Multi-currency Bank Credit Facility had a balance of $92 million, which was the maximum available after the quarterly reductions for 2004. Interest on outstanding balances accrues at LIBOR plus a margin ranging from 1.2% to 1.5% depending on our ratio of funded debt to total capitalization, or Leverage Ratio. At December 31, 2004, all outstanding borrowings under the Multi-currency Bank Credit Facility were denominated in British pounds in order to match the currency associated with the revenue stream for the collateral vessels. As of December 31, 2004, the weighted average interest rate on the outstanding borrowings under the Credit Facility was 6.1%. The Multi-currency Bank Credit Facility requires us not to exceed a maximum Leverage Ratio and to maintain a specified interest coverage ratio and a minimum net worth. We were in compliance with all Multi-currency Bank Credit Facility covenants at December 31, 2004.

     On December 23, 2004, we entered into a new senior secured acquisition credit facility providing for a $50 million revolving credit facility which is secured by eight vessels. This credit facility has a final maturity date of the earlier of January 31, 2008 or three calendar years from the first drawdown date. At December 31, 2004, we had $8 million outstanding under this credit facility. On January 24, 2005, we entered into a supplemental agreement to amend the new acquisition credit facility to clarify the covenants relating to the amounts of insurance on the eight vessels. On March 24, 2005, we entered into a supplemental agreement to amend the definition of “Material Adverse Effect” and to clarify the definition of “Consolidated EBIT”.

     In order to allow us to enter into the new acquisition credit facility, we requested an amendment to the negative pledge covenant under Multi-currency Bank Credit Facility and an amendment to one of the financial covenants to the Multi-currency Bank Credit Facility, which reduced the EBITDA to Interest coverage ratio for the period September 30, 2004, through September 30, 2005. Both amendments to the Multi-currency Bank Credit Facility were approved on November 17, 2004, but became effective December 23, 2004. On March 22, 2005, we entered into a supplemental agreement to clarify the covenants relating tot he amounts of insurance on the eight vessels. On March 24, 2005, we entered into a supplemental agreement to amend the definition of “Material Adverse Effect” and to clarify the definitions of “Consolidated EBIT”, “Consolidated Interest Expense” and “Consolidated EBITDA” and the financial covenant ratio of Consolidated EBITDA to Consolidated Interest Expense for quarters ending March 31, 2004 and June 30, 2004.

     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 the Multi-currency Bank Credit Facility, 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 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 plus accrued interest.

     The 7.75% senior notes are general unsecured obligations and ranked 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 jointly and severally guaranteed on a senior unsecured basis by one or more of our subsidiaries.

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     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 dividends or other payments. We were in compliance with all indenture covenants at December 31, 2004.

     We also have a credit facility relating to a 2002 acquisition consisting of three tranches, each secured by certain vessels. We had $18.2 million outstanding on this debt as of December 31, 2004. This debt amortizes in various quarterly amounts until maturity in 2008.

Current Year Cash Flow

     As of December 31, 2004, we had cash on hand of $17.5 million. Cash provided by operating activities for the year ended December 31, 2004, was $25.1 million compared to $19.0 million in the previous year. The increase was primarily attributable to higher operating income reflecting a strengthening of the North Sea market at the end of 2004.

     Cash used in investing activities for the years ended December 31, 2004 and 2003 was $40.4 million and $91.6 million, respectively. The decrease is attributable to fewer purchases of vessels and other fixed assets in 2004 than in 2003.

     Substantially all of our tax provision is for deferred taxes. The tonnage tax regimes in both the U.K. and Norway reduce the cash required for taxes in each of these regions. 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. We provide for taxes at U.S. statutory rates on income from vessels based on subpart F regulations of the Internal Revenue Code. Accelerated depreciation has minimized the cash requirements for income taxes.

Debt and Other Contractual Obligations

     The following table summarizes our contractual obligations at December 31, 2004 and the effect these obligations are expected to have on liquidity and cash flows in future periods (in millions).

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 $14.5 million at December 31, 2004. All of these instruments have an expiration date within one 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.

Currency Fluctuations and Inflation

     In areas where currency risks are potentially high, we normally accept only a small percentage of charter hire in local currency. The remainder is paid in U.S. dollars. Substantially all of our operations are international; therefore we are exposed to currency fluctuations and exchange rate risks. Charters for vessels in the North Sea fleet are primarily denominated in British pounds with a portion denominated in Norwegian kroner. 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 74% of our total consolidated revenue for the year ended December 31, 2004. In 2004, the British pound/U.S. dollar exchange rate ranged from a high of £ = U.S. $1.94 to a low of £ = U.S. $1.76 with an average of £ = U.S. $1.83 for the year. As of March 1, 2005, the exchange rate was £ = U.S. $1.92.

     Our outstanding debt of $277.5 million includes $168.0 million denominated in U.S. dollars with the balance denominated in British pounds. A substantial portion of our revenue is generated in British pounds. 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 British pound-denominated vessel day rates over time to compensate for changes in the purchasing power of British pounds as measured in U.S. dollars;

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	•	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.

     Reflected in the accompanying balance sheet at December 31, 2004, is an $79.2 million cumulative translation adjustment primarily relating to the higher British pound and Norwegian kroner exchange rate as of December 31, 2004 in comparison to the exchange rate when we invested capital in these markets. Changes in the cumulative translation adjustment are non-cash items that are primarily attributable to investments in vessels and U.S. dollar-based capitalization between the parent company and its foreign subsidiaries. The current year change reflects the significant weakness in the U.S. dollar compared to the functional currencies of our major operating subsidiaries, particularly in the U.K. and Norway.

     To date, general inflationary trends have not had a material effect on our operating revenues or expenses. One of the major consumables for the fleet is diesel fuel, the price of which has escalated significantly over the last year. Except for one contract, which has a cost flow-through provision, fuel is provided by our customers; therefore, escalating fuel prices have not and will not adversely affect our operating cost structure.

Transactions with Related Parties

     For information regarding transactions with related parties, see Note 8 to our Consolidated Financial Statements included in Part II, Item 8.

New Accounting Pronouncements

     The following new accounting standards were issued, but have not yet been adopted by GulfMark as of December 31, 2004: SFAS No. 123 (Revised 2004), “Share-Based Payment” (“SFAS No. 123R”); FASB Staff Position FSP FAS 109-2, “Accounting and Disclosure Guidance for the Foreign Repatriation Provision within the American Jobs Creation Act of 2004” (“FSP FAS 109-2); and FASB Interpretation No. 46, “Consolidation of Variable Interest Entities (“FIN 46”).

     In December of 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123R, which replaces SFAS No. 123 and supercedes Accounting Principles Board Opinion (“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 June 15, 2005. The pro forma disclosures previously permitted under SFAS No. 123 no longer will be 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 prospective and retroactive adoption options. Under the 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. The impact on earnings per share (“EPS”) for 2004, 2003 and 2002 of SFAS No. 123 is discussed in Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies.” We continue to assess the transition provisions and have not yet determined the transition method to be used or if any changes will be made to the valuation method used for share-based compensation awards issued to employees in future periods. The impact in periods subsequent to adopting SFAS 123R will be dependent upon the nature of any equity-based compensation awards issued to employees, but we do not anticipate our adoption of SFAS No. 123R on July 1, 2005 to have any material impact on our consolidated results of operations, cash flows or financial position.

     In December 2004, the FASB Staff issued FSP FAS 109-2. Management is currently evaluating the impact of the Jobs Act and has not yet determined what impact, if any, implementation of FSP FAS 109-2 will have on our consolidated financial statements.

     In January 2003, the FASB issued FIN 46. FIN 46 clarifies the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements”, for certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 requires that variable interest entities (“VIEs”), as defined, should be consolidated by the primary beneficiary, which is defined as the entity that is expected to absorb the majority of the expected losses, receive the majority of the gains, or both. FIN 46 requires that companies disclose certain information about a VIE created prior to February 1, 2003 if it is reasonably possible that the enterprise will be required to consolidate that entity. The application of FIN 46 is required in the first interim period ending after December 15, 2003 for entities created prior to February 1, 2003, and immediately for any VIEs created subsequent to January 31, 2003.

     In November 2004, we further evaluated the application of FIN 46 and have determined that our rabbi trust is a VIE. The rabbi trust is a deferred compensation arrangement allowing amounts earned by certain employees to be invested in the stock of the Company or other assets. Our determination that our rabbi trust was a VIE had no impact on our financial position or results of operations because we already reflect the rabbi trust in our consolidated financial statements.

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Forward-Looking Statements

     This Form 10-K, particularly the sections entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business,” contains 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, 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 the sections entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, “Business” and elsewhere in this Form 10-K.

ITEM 7A. Quantitative and Qualitative Disclosures about Market Risk

Interest Rate Sensitivity

     At December 31, 2004, 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. They have a stated interest rate of 7.75% and an effective interest rate of 7.8%. At December 31, 2004, the fair value of these notes, based on quoted market prices, was approximately $169.6 million, as compared to a carrying amount of $159.4 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 Item 7A has been provided in “Management’s Discussion and Analysis of Financial Condition and Results of Operations”. Other than trade accounts receivable and trade accounts payable, we do not currently have financial instruments that are sensitive to foreign currency exchange rates.

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ITEM 8. Consolidated Financial Statements and Supplementary Data

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

     We have audited the accompanying consolidated balance sheets of GulfMark Offshore, Inc. and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of operations, stockholders’ equity, comprehensive income, and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

     In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of GulfMark Offshore, Inc. and subsidiaries at December 31, 2004 and 2003, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles.

     As discussed in Note 1 to the consolidated financial statements, in 2004 the Company changed its method of accounting for drydock expenditures.

ERNST & YOUNG LLP

Houston, Texas
March 31, 2005

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GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

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

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GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS