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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

[X]	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
	SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2000
	OR
[   ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
	SECURITIES EXCHANGE ACT OF 1934

GulfMark Offshore, Inc.
(Exact name of Registrant as specified in its charter)

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 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.

      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 [X]    No [   ]

      Aggregate market value of the voting stock held by nonaffiliates of the Registrant based upon the price at which the stock was sold as of March 5, 2001: $93,562,681.

      Number of shares of common stock outstanding as of March 5, 2001: 8,185,968.

DOCUMENTS INCORPORATED BY REFERENCE

The information called for by Part III Items 10,11,12 and 13 will be included in a proxy statement to be filed
pursuant to Regulation 14A, and is incorporated herein by reference.
Exhibit Index Located on Page 40.

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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 drilling materials, supplies and personnel to offshore facilities, as well as move and position drilling structures. The majority of our operations are conducted in the North Sea, with the balance in offshore Southeast Asia, Brazil and West Africa. Periodically, we will charter vessels into other regions to meet our customer’s requirements.

      Our principal executive offices are located at 4400 Post Oak Parkway, Suite 1170, Houston, Texas 77027-3414, and our telephone number at that address is (713) 963-9522.

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 (“Offshore Marine Services”). This industry employs various types of vessels, referred to broadly as offshore support vessels, that are used to transport materials, supplies, equipment and personnel. Offshore Marine Service providers are employed by oil 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 Gulf of Mexico, the North Sea, offshore Southeast Asia, offshore West Africa and offshore Brazil are each major markets that employ a significant number of vessels. Vessel usage is also significant in other international areas, including India, Australia, the Persian Gulf and the Mediterranean Sea. The industry is relatively fragmented, with more than 20 major participants and numerous small regional competitors. Historically, few of these competitors have participated in all five of these major markets. We operate our fleet of 47 offshore supply vessels in four of the five major markets: 28 in the North Sea, 12 in Southeast Asia, 5 in Brazil and 2 in West Africa.

      During 2000, we committed to the construction of nine new vessels at a total cost of $185 million. Delivery of these vessels is scheduled to begin in the third quarter of 2001 and will continue through the end of 2003. We expect to enter into charters for these vessels as their delivery dates approach. Additionally, in March 2001 we signed an agreement to purchase the Stirling Fyne (to be renamed the Highland Patriot) for approximately $6.9 million. We expect that the acquisition will close in early April 2001. We have already secured a term charter for this vessel.

      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 impacted by trends in oil and natural gas prices. Oil and natural gas prices are affected by a host of geopolitical and economic forces, including the fundamental principles of supply and demand. Each of the major geographic offshore oil and gas production regions have 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 vessels between regions. This is most notably the case in the North Sea, where vessel design requirements dictated by the harsh operating environment restrict migration of vessels into that market and, to a lesser degree, high operating costs restrict migration out of the market. The effect of these restrictions on vessel migration is to segment various regions into separate markets.

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 in more than one of the categories. These functional classifications are: (i) platform supply vessel, (ii) anchor handling, towing and supply vessel, (iii) construction support vessel, (iv) standby rescue vessel, (v) crewboat, (vi) specialty vessel and (vii) utility vessel.

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•		Platform Supply Vessels (“PSVs”) serve drilling and production facilities and support offshore construction and maintenance work. They are differentiated from other offshore support vessels by their cargo handling capabilities, particularly their large capacity and versatility. PSVs utilize space on deck and below deck and are used to transport supplies such as fuel, water, drilling fluids, equipment and provisions. PSVs range in size from 150’ to 200’. Large PSVs (“LgPSVs”) range up to 275’ 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. We operate 21 LgPSVs (14 of which are owned by us) that function primarily in this classification but are also capable of service in construction support. 19 of the PSVs in the North Sea operate exclusively in this function and 10 SmAHTS vessels (as defined below) in Southeast Asia often support production operations as PSVs.
•		Anchor Handling, Towing and Supply Vessels (“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 (“BHP”) are referred to as small AHTS vessels (“SmAHTS”), while AHTS vessels in excess of 10,000 BHP are referred to as large AHTS vessels (“LgAHTS”). The most powerful North Sea Class AHTS vessels have up to 25,000 BHP. We own one and operate three additional LgAHTS vessels in the North Sea, bareboat charter one operated in Brazil, operate one managed LgAHTS in West Africa and own ten SmAHTSs in Southeast Asia. From time to time, all of our AHTS vessels function as PSVs.
•		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. Our 21 LgPSVs (14 of which are owned by us) fit the definition of pipe carriers. Our North Sea fleet has the distinction of being the only significant concentration of pipe carrier capable vessels outside of Scandinavian control.
•		Standby Rescue Vessels (“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. We own two vessels of this type and manage two specialty vessels that operate in this capacity in the North Sea.
•		Crewboats (“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 165’ in length and can be longer with greater cargo carrying capacities. They are used primarily to transport cargo on a time-sensitive basis. We own one of these vessels currently operating in Southeast Asia.
•		Specialty Vessels (“SpV”) generally have special features to meet the requirements of specific jobs. The special features 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 FPSOs, diving operations, remotely operated vehicles (“ROVs”), survey operations and seismic data gathering, as well as oil recovery, oil spill response and well stimulation. Three of our owned vessels frequently provide specialty functions, and five 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 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 are typically large and well-capitalized entities (such as major oil companies and state-owned oil companies), in large part because of the significant financial commitment required in this market. Projects in the region 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. Consequently, vessel demand in the North Sea has generally been steadier 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

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demand for AHTS vessels. While supply vessels also support the exploration segment, they additionally support the production and field construction segments, which generally are not affected by frequent short-term swings in demand. However, since AHTS vessels are capable of performing in a supply role, the availability of AHTS vessels during prolonged periods of weakness in the exploration segment, as was experienced during 1999 and the first half of 2000, can put downward pressure on PSV demand.

      Our North Sea fleet is oriented toward supply vessels which work in the more stable segments of production platform support and field development or construction, and includes 18 owned and bareboat chartered vessels (14 PSV’s, 2 AHTS, and 2 SpV) and 10 managed vessels (3 PSV’s, 2 AHTS vessels and 5 SpVs). Onshore bases in Aberdeen, Scotland and Liverpool, England support these vessels.

      During the period of 1995-1998, the North Sea market experienced consistently high vessel utilization rates and increasing day rates. Increased drilling rig requirements during 1995 and 1996 led to a shortage of high specification drilling rigs. A number of long-term drilling contracts were signed during that period and, as demand increased in other regions, orders for new drilling rigs were placed. Accelerated activity in construction and development projects added to the demand for supply vessel services and by 1997 vessel demand was very strong. The positive market dynamics continued into the first quarter of 1998. A drop in oil prices in the latter half of 1998 and into the first quarter of 1999 resulted in significant reductions in spending plans for 1999 and caused demand for vessel services in 1999 to fall well below that experienced in 1997 and 1998. A number of the large integrated oil companies were merged and the consolidation process in the industry had an adverse near-term effect on the market for support vessel services. This slowdown in demand occurred in a period when a number of vessels entered the marketplace well ahead of the drilling rigs they were built to support. Most of these vessels were ordered in 1997 and 1998 in response to increased construction in the drilling industry and were delivered by the end of 1999. The vessel deliveries aggravated an oversupply condition caused by the reduction in development activity but was mitigated somewhat by vessels utilized in fiber optic cable installation and maintenance activity. In the second quarter of 2000, in response to higher commodity pricing and some increase in drilling activity, this market began to improve. This was at first evidenced by increased utilization rates for offshore support vessels and was followed by an improvement in day rates. The steady recovery continued throughout the balance of the year, with demand outside of the North Sea accelerating price recovery as deepwater locations in international locations competed for the available vessels. These factors allowed day rates and utilization to escalate to levels similar to those experienced during the high point of 1998. At the end of 2000 and into the first quarter of 2001, rates continued to improve and tended to be above those experienced in the previous peak period of 1998.

      The supply of vessels to the region has been a function of new build vessels delivered to the market and the migration of vessels to other markets, either permanently or for temporary assignments. The demand for existing vessels outside of the North Sea and the expanded role for deepwater projects in worldwide locations left the North Sea fleet largely in balance through the end of 1998. As oil and gas activity levels declined after the precipitous oil price drop in 1998-1999 and a number of new build vessels entered the market in advance of new deepwater drilling rigs which had been delayed, an excess of supply resulted and caused day rates and utilization to fall. The excess supply began to be absorbed in 2000 as vessels moved out of the North Sea in support of drilling rigs in other deepwater markets and as activity levels improved in the region. Throughout the second half of 2000, many companies committed to a number of new build vessels with deliveries scheduled from 2001 through 2003. These new build vessels are generally designed to meet the expanding worldwide demand for deepwater support vessels.

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

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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.

      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. In the middle part of the 1990s there was pressure (most notably from Malaysia) to upgrade offshore vessel capabilities by establishing limits on the age of vessels working in certain countries’ territorial waters and encouraging construction of new vessels designed particularly to operate in this region. Demand for new vessels is developing in the region where deepwater projects occur or where oil and gas companies employ larger fleets of vessels. This trend toward newer vessels is less likely to be a factor in vessel selection during a period of reduced expenditures, as was experienced in part of 1999 and during much of 2000.

      Changes in supply and demand dynamics have led at times, most recently during 1999, 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 Southeast Asia would involve a significant cash and opportunity cost. Historically there has been some movement between these operating areas, but vessel movements have not been a major factor in the Southeast Asia vessel market.

      Indonesia is the only member of the Organization of Petroleum Exporting Countries (“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. 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. In 1992, demand softened as exploration activities were reduced while some of the major oil companies renegotiated their production royalty and tax structures with local authorities. This reversed somewhat in 1993 and 1994, as some agreements were reached. However, in 1995, the oil companies pressed for further modifications to their production royalty and tax structures and reduced their exploration budgets, resulting in lower-than-expected activity in 1995 and only marginal improvement in 1996 and 1997. The market improved in early 1998 as part of a general improvement throughout Southeast Asia but turned lower in 1999 as a result of an overall worldwide slowdown in exploration and development expenditures. During 2000, as markets in other regions rebounded, this market lagged behind with several brief upturns only to be followed by contractions back to the previously reduced levels. At the end of the fourth quarter and continuing into the first quarter of 2001, activity levels have improved and both day rates and utilization have been consistently higher than at any time in the last two years.

      In the first quarter of 2000, we secured a two-year contract for one of the newbuild vessels completed in 1999 to work for a major oil company in Indonesia. This development was important because it marked a shift from the historical demand of the commodity type vessels which have dominated this market in the past to newer, more technologically advanced service vessels. The efficiency of this vessel compared to other vessels commonly found in the region is the major factor leading to the acceptance of this vessel, despite its higher day rate.

The Brazilian Market

      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 new build fleet to meet the expanding demand for vessels in this important market.

      Over the last two 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, which will explore the offshore blocks awarded in the lease sales. This has created a demand for deepwater AHTS and PSV vessels in support of the drilling and exploration activities that has been met primarily from mobilization of vessels from other regions. As this activity increases throughout 2001-2002 to meet the commitments of the oil companies to the Brazilian government, there will be a growing demand for offshore support vessels.

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Additional bid rounds have been announced by the Brazilian government, which could generate additional drilling activity and vessel demand.

      The Seapower has been operating in Brazil since 1995 under a contract, which runs into October 2001 with Petróleo Brasiliero S.A. (“Petrobras”), the Brazilian national oil company. The Leopard Bay, an AHTS built by Sanko Steamship Co. Ltd., (“Sanko”) and bareboat chartered by us for three years, began a three-year contract with Petrobras in November 1998. We exercised our option to extend the bareboat charter for this vessel for an additional year during 2000. We contracted a third vessel, the Highland Scout, to Petrobras in January 2000 for an initial period of six months which was extended several times during the year. At the close of 2000, we executed a new contract for one year for this vessel at a day rate higher than the initial contract with Petrobras. In the first quarter of 2001, we mobilized two of our managed PSVs, the Torm Kestrel and Waveny Castle, to Brazil to work for BP in support of their drilling program offshore Belem, Brazil.

The West African Market

      During January 2000, we mobilized a bareboat chartered vessel from the North Sea market to Equatorial Guinea under a two-year contract with a major international oil company. This marked our entry into this market and was viewed as an important step for us in meeting the growing demand for deepwater capable vessels in the emerging West African Offshore Marine Services market. Subsequent to the end of 2000, we mobilized one of our managed AHTSs to West Africa in support of a construction/cable installation program. With the notable exploration successes, which have been publicized by both major oil companies and independents operating in the area, we believe that the market in this region has one of the highest potentials for attracting North Sea capable vessels. The heightened level of offshore expenditures has created an increase in the demand for vessels to support drilling operations in this region, as evidenced by the increase in vessel contracts awarded in 1999-2000. We believe that further demand will be created for both AHTSs and PSVs as expenditures to further delineate and exploit the deepwater discoveries are initiated by the international oil companies. We will look to our current fleet of vessels in addition to our new build vessels to meet the requirements of this market.

New Vessel Construction Program

      In response to the improving worldwide market conditions, during the second half of 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 new builds including the UT 755 design PSVs. The program includes six PSVs and three AHTS with all vessels designed to be multi-functional in that they will be capable of supporting underwater remotely operated vehicle (“ROV”) operations as well as traditional offshore support operations. All of the vessels are being built to Rolls Royce/Ulstein specifications and include two UT 745 and four UT 755 PSVs plus three UT 722 AHTS vessels. The timing of this construction program was chosen based on the increased demand for deepwater and ultra-deepwater capable vessels. One PSV is due to be delivered at the first part of the third quarter 2001, with four vessels each in 2002 and 2003. The delivery dates are expected to precede the termination dates of the four current bareboat chartered vessels. The total estimated cost of the program is approximately $185 million. The construction cost for the vessels is based on a fixed price contract denominated in Norwegian Kroner. Many of the same construction supervisors utilized in the Company’s successful construction program during 1996 —1999 have been mobilized to manage the new program. Additionally, we have systematically entered into forward contracts to foreign exchange risk. The following table outlines the cost and expected delivery schedule of the program:

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Our Fleet

      Our existing fleet as of March 5, 2001 includes 47 vessels. Of the 47 vessels, 30 are owned by us, four are bareboat chartered from other owners and 13 are under management for other owners. Additionally, we have committed to the construction of nine new vessels in Norway. In March 2001, we purchased a 1982 built PSV which is expected to close in April 2001. The following table summarizes information with respect to each of these vessels:

(a)		Legend:	LgPSV – Large platform supply vessel PSV – Platform supply vessel AHTS – Anchor handling, towing and supply vessel SmAHTS – Small anchor handling, towing and supply vessel Crew – Crewboat SpV – Specialty vessel, including towing and oil spill response
(b)		Brake horsepower.
(c)		Deadweight tons.
(d)		Vessel currently under construction in Norwegian shipyard.
(e)		Operated pursuant to 50/50 joint venture agreement with Torm U.K. Limited.

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Customers, Contract Terms and Competition

      Our principal customers are major integrated oil companies and large independent oil and natural gas exploration, production companies working in international markets, and foreign government owned or controlled oil companies, as well as companies that provide logistic, construction and other services to such oil companies and foreign government organizations. During 2000, under multiple contracts in the ordinary course of business, two customers each accounted for more than 10% of total consolidated revenues: Aberdeen Services Company (“ASCO”) at 18.2% and Petrobras at 11.2%. ASCO is a logistics coordinator primarily serving major international oil companies. The contracts are industry standard time charters involving several of our vessels for periods ranging from a few days or months to more than a year. The contracts are generally not cancelable except for unsatisfactory performance by the vessel. The loss of a major customer could have a material adverse effect on our financial condition and results of operations until a replacement is obtained.

      Contract or charter durations vary from single-day to multi-year in length, based upon many different factors that vary by market. Historically, term charters in the Offshore Marine Services industry have generally extended from six months to one year in length. 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 the majority of the market. Term charters in Southeast Asia are currently somewhat less common than in the North Sea and generally are two years or shorter in length. In the developing Brazil and West Africa markets, term charters are relatively common due to the harsh operating conditions, the scarcity of quality equipment and the distance to larger markets. In addition, charters for vessels in support of floating production, storage and offloading (“FPSO”) are typically “life of field” or “full production horizon charters”. Because of frequent renewals, the stated duration of charters may have little correlation with the length of time the vessel is actually contracted to a particular customer.

      Bareboat charters are contracts for vessels, generally for a term in excess of one year, whereby the owner transfers all market exposure for the vessel to the charterer in exchange for an arranged fee. The charterer has the right to market the vessel without direction from the owner. In addition to bareboat charter fees paid to the owner, the charterer is responsible for providing the crew and all operating costs for the vessel. No depreciation expense is borne by the charterer. Bareboat chartered vessels in comparison to identical owned vessels with the same day rate generate the same revenue but less operating income since bareboat charter expense is generally higher than depreciation expense and less operating cash flow since bareboat charter expense is a cash cost.

      Managed vessels add to the market presence of the manager but provided 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 range from $5,000 to $10,000 per month per vessel.

      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 matching its operating expenses. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations —Currency Fluctuations and Inflation.”

      We compete with approximately 15-20 companies in the North Sea market and numerous small and large competitors in the Southeast Asia market principally on the basis of suitability of equipment, price and service. Also, in certain foreign countries, preferences are given to vessels owned by local companies. We have attempted to mitigate some of the impact of such preferences through affiliations with local companies. Some of our competitors have significantly greater financial resources than we do.

Fleet Availability

      A significant portion of our available fleet is committed under contracts of various terms. This represents a major improvement over the prior year at the same time and is indicative of the improving market conditions. The following table outlines the percentage of our days in 2001 and 2002 under contract as of March 5, 2001:

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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, 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 recently made the regulations of the International Safety Management (“ISM”) Code mandatory. The ISM Code provides an international standard for the safe management and operation of ships and for pollution prevention. The regulations under the ISM Code further require that we satisfy certain crew and vessel certifications prior to July 1, 2002. We are not a party to any pending litigation or similar proceeding, and we are not aware of any threatened litigation or proceeding which, if adversely determined, would have a material adverse effect on our financial condition or results of operations. However, the risks of incurring substantial compliance costs, liabilities and penalties for 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 environmental, health and safety 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:

	•		adverse weather conditions;
	•		mechanical failure;
	•		navigation errors;
	•		collision; and
	•		oil and hazardous substance spills.

      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.

      We maintain insurance coverage against the casualty and liability risks listed above. We believe our insurance is adequate, and we have never experienced a loss in excess of policy limits. However, we may not be able to renew or maintain our existing insurance coverage at commercially reasonable rates or at all. Additionally, there is no assurance that our insurance coverage 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:

	•		legal and governmental regulatory requirements;
	•		difficulties and costs of staffing and managing international operations;
	•		language and cultural differences;
	•		potential vessel seizure or nationalization of assets;
	•		import-export quotas or other trade barriers;
	•		difficulties in collecting accounts receivable and longer collection periods;
	•		political and economic instability;
	•		imposition of currency exchange controls; and
	•		potentially adverse tax consequences.

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      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 conclusion. If our assumptions are incorrect, or if the relevant countries change or modify such laws or the current interpretation of such laws, we may suffer adverse 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

      Our fleet operations are subject to seasonal factors. Operations in the North Sea are generally at their highest level during the months from April to August and at their lowest levels during November to February. 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.

Employees

      At December 31, 2000, we had 259 employees located in the United States, the United Kingdom, Norway, Southeast Asia and Brazil. Through its contract with a crewing agency, we participate in collective bargaining arrangements with 621 employees working on our North Sea vessels under agreements covering one-to-two year periods. We have no other collective bargaining agreements. Relations with our employees are considered satisfactory. To date, our operations have not been interrupted by strikes or work stoppages.

Properties

      Our principal executive offices are located in Houston, Texas, while operations are headquartered in Lafayette, Louisiana. For local support, we have offices and warehouse facilities in Singapore and Aberdeen, Scotland. All facilities except one owned facility in Aberdeen, Scotland are under lease. Our operations generally do not require highly specialized facilities, and suitable facilities are generally available on a lease basis as required.

      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 at the SEC’s website at http://www.sec.gov. 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.

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 relating to the Offshore Marine Services operations. Additionally, we may be subject to claims for indemnification by Weatherford International, Inc. (“Weatherford”) under our indemnity obligations described below. 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 will 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.

Distribution Agreement Indemnities

      We were formed as a spin-off from our predecessor and began separate trading on May 1, 1997. The assets remaining with the predecessor included a domestic erosion control business known as “Ercon” and an investment in

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the common stock of Weatherford. In effecting the spin-off, we agreed to indemnify Weatherford and certain of its affiliates against:

	•		liabilities for all past and future claims and litigation against Weatherford stemming from the predecessor’s or our offshore marine services operations;
	•		liabilities for claims and litigation against Weatherford or its current or past subsidiaries and affiliates, including Ercon, arising out of acts or omissions prior to May 1, 1997; and
	•		any tax liabilities in the event the spin-off and related transactions are determined to be taxable.

      We have established an accrual on our financial statements and maintain insurance coverage, which we believe is adequate, to cover any contingent liabilities that may arise under the indemnity. However, there is no assurance that the accrual is adequate. Any future successor of GulfMark would be required to assume these indemnity obligations, which may have the effect of delaying, deferring or preventing a change of control.

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

NONE

PART II

ITEM 5.   Market for Registrant’s Common Equity and Related Stockholder Matters

      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, 2001 (through March 5, 2001), the range of low and high sales prices was $25.00 and $35.00, respectively. On March 5, 2001, the closing sale price of our common stock as reported by the NASDAQ National Market was $31.56 per share. As of March 5, 2001, there were 871 shareholders of record.

      We have not declared or paid dividends during the past five years. Pursuant to the terms of the indenture under which the 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.

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ITEM 6.   Selected Consolidated Financial Data

      The Consolidated Financial Statements included herein, as well as the financial data presented in the table following, present the net assets and results of operations of Ercon and the common stock of Weatherford owned by our predecessor as discontinued operations for all periods presented. 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.”

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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.”

General

      Our operations are affected primarily by day rates, fleet utilization and the number and type of vessels in our fleet. These factors are driven by trends within the oil and natural gas exploration and production industry, which generally affect the demand for vessels, as well as by trends impacting the broader economy and capital markets, which generally affect the supply of vessels. While offshore support vessels service existing oil and natural gas production platforms and exploration and development activities, incremental demand depends primarily upon drilling activity, which, in turn, is related to both short-term and long-term trends in oil and natural gas prices. As a result, trends in oil and natural gas prices may significantly affect fleet utilization and day rates. There were significant declines in oil and gas prices during 1998 followed by equally significant increases subsequent to the first quarter of 2000. Although commodity prices have rebounded from the levels of 1998-1999, they have remained somewhat volatile, albeit at a higher average level than at any sustained time over the past decade. The volatility of prices will continue to be a factor in the planning for future oil and gas exploration and development expenditures and the consequent demand for our vessels.

      An additional factor affecting operating earnings is the mix of vessels owned versus bareboat chartered by us. Owned and bareboat chartered vessels generate operating revenues and may incur expenses at similar rates. However, chartered vessels also incur bareboat charter hire expense instead of depreciation expense. Depreciation expense is generally less than bareboat charter expense.

      In addition, we provide management services to other vessel owners for a fee. Only the management fee charged by us is included in our operating revenues. The day rates for these vessels are excluded for purposes of calculating fleet rates per day worked and utilization in all years.

      Our operating costs are primarily a function of fleet size 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 affect only that portion of our direct operating costs that is incurred when the vessels are active. 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 these variable costs, we incur fixed charges related to the depreciation of our fleet and costs for routine drydock inspections and maintenance and repairs designed to ensure compliance with applicable regulations and to maintain 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 and marine inspection amortization charges. Costs incurred for drydock inspection and regulatory compliance are capitalized and amortized over the period between such drydockings, typically two to three years.

      Under applicable maritime regulations, vessels must be drydocked twice in a five-year period for inspection and certification. Should we undertake a large number of drydockings in a particular fiscal period, comparative results may be affected. For the year ended December 31, 2000, we completed the drydocking of 11 vessels at an aggregate cost of $2.4 million, versus 10 vessels at an aggregate cost of $2.6 million in 1999 and 6 vessels drydocked at an aggregate cost of $1.3 million in 1998.

      Over the last several years, we have been actively expanding our fleet through the construction of new vessels, acquisition of existing equipment from the resale market and by bareboat chartering vessels owned by others. In the third quarter of 2000, four vessels which are bareboat chartered and two vessels managed by us and owned by Sanko Steamship Co. Ltd. were sold to one of our competitors. The terms of the sale preserve our extension options under the bareboat charters, which, in turn, allow us to meet the terms and conditions of our contracts with our customers. Additionally, option extensions provided in the bareboat charters allow us to have full control of the vessels until replacement vessels under our new build program are delivered. We contracted with a Norwegian shipbuilder for the construction of nine North Sea class vessels for a total of approximately $185 million to be delivered over the period

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2001-2003. These vessels include six PSVs and three AHTS vessels. Projected cash outflows for this newbuild program including the payments made during 2000 are as follows:

Results of Operations

Comparison of the Fiscal Years Ended December 31, 2000 and December 31, 1999.

      Our results for 2000 reflect increased activity as energy commodities have shown consistently strong pricing. During the first half of 2000, we were unwilling to fix our fleet on long-term contracts based on our belief that there would be a recovery in the market during the second half of the year. Exploration and development expenditures began to show the effects of the recovery in commodity prices during the second quarter of 2000. Accordingly, we began fixing our vessels on term work and as such, the utilization levels were at near capacity in the North Sea fleet and Brazil for the last two quarters of 2000. Likewise, Southeast Asia began to show improvements in utilization as the year 2000 progressed, which should further cause the day rates in the region to climb. Recent fixtures of vessels in that region have demonstrated that a recovery in that market is following the other major markets.

      We recognized net income of $7.9 million in 2000 compared to $1.9 million in 1999. Revenues increased to $77.7 million and operating income increased to $18.0 million in 2000, compared to $72.3 million and $12.5 million in 1999, respectively. The increase in revenue was attributable to the 1999 expansion of the fleet with the full year effect of the Highland Guide, Highland Scout and Highland Pioneer as well as the significant improvement in utilization. These increases more than offset the impact of the sale of the 1982-built PSV, the Highland Fortress, in July 2000 and the slight decrease in average day rate. Operating expenses remained virtually unchanged in part due to our cost control measures and the weaker exchange rates in both the U.K. and Norway. Net interest expense reflected an increase of $1.2 million due to a decrease in interest income of $0.3 million coupled with a reduction in the amount of interest capitalized of $0.9 million. The 2000 period also reflected a pre-tax gain of $3.7 million primarily reflecting the gain on sale of the Highland Fortress. The following table summarizes day rates, utilization and average vessels owned or chartered for the comparable periods:

(a)		Includes all owned or bareboat chartered vessels, except the joint venture bareboat chartered vessel. Managed vessels are not included.
(b)		Rates per day worked is defined as total charter revenues divided by number of days worked. Utilization rate is defined as the total number of days worked divided by the total number of days of availability in the period.

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(c)		Revenues for vessels in our North Sea fleet are primarily earned in British pounds (£) and have been converted to U.S. dollars at the average exchange rate ($/£) for the periods indicated. The average exchange rates for the years ended December 31, 2000, and 1999 were £ = $1.52 and £ = $1.62, respectively.
(d)		Adjusted for vessel additions and dispositions occurring during each period.

Comparison of the Fiscal Years Ended December 31, 1999 and December 31, 1998.

      The year 1999 continued to be affected by the volatility of oil and gas prices as oil prices, in particular, began to recover in the first several months of the year, fell back in March 1999 and then exhibited a prolonged increase through the end of the year. Exploration and development expenditures, however, did not recover as consolidation within the industry and a concern over the sustainability of higher pricing caused companies to delay or cancel both construction and exploration programs. We had a relatively strong level of contract cover for the fleet at the beginning of the 1999, which resulted in utilization and day rates at levels providing net income during the first three quarters. It became evident, however, that as the vessels completed their contracts, the market had deteriorated thus resulting in lower day rates and utilization for the fourth quarter of 1999, which caused us to report a loss for this period.

      We continued to increase the size of our fleet during 1999 and added three owned vessels and one bareboat chartered vessel during the year. The Highland Guide and Highland Scout, newbuild vessels completed during the third quarter of the year, were able to secure a two-year contract in Southeast Asia and an eight-month contract in Brazil, respectively. The Highland Pioneer was acquired in December 1999 and immediately started a five-year contract in the Liverpool Bay area of the U.K. for an international oil company. The Torm Heron, a newbuild vessel built for Sanko Steamship Co. Ltd. (“Sanko”) that we operated under a joint venture agreement with Torm, entered the fleet in May 1999 and operated in the North Sea spot market throughout 1999.

      We recognized net income of $1.9 million in 1999 compared to net income of $20.8 million in 1998. Revenues decreased $13.9 million and operating income decreased $22.5 million from 1998 to 1999. The decrease in revenue was directly attributable to the lower average day rate and decreased utilization experienced in our major markets during 1999 compared to 1998. Partially offsetting the effects of these lower day rates and utilization were increased revenues derived from the full year impact of vessels added throughout 1998 and the Brovig acquisition. Operating expenses increased $7.1 million compared to 1998 primarily due to the full year effect of bareboat charter expense associated with the three bareboat chartered vessels and the increased costs of operating the expanded fleet. Depreciation expense increased $1.1 million as a result of the full year impact of the increased fleet size. The following summarizes dayrates, utilization and average vessels owned or chartered for our fleet of vessels:

(a)		Includes all owned or bareboat chartered vessels, except the joint venture bareboat chartered vessel. Managed vessels are not included.
(b)		Rates per day worked is defined as total charter revenues divided by number of days worked. Utilization rate is defined as the total number of days worked divided by the total number of days of availability in the period.
(c)		Revenues for vessels in our North Sea fleet are primarily earned in British pounds (£) and have been converted to U.S. dollars at the average exchange rate ($/£) for the periods indicated. The average exchange rates for the years ended December 31, 1999, and 1998 were £ = $1.62, and £ = $1.66, respectively.
(e)		Adjusted for vessel additions and dispositions occurring during each period.

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      We recognized $10.4 million of other expense in 1999 compared to $8.4 million of other expense in 1998, excluding a $2.9 million pre-tax gain on the sale of a joint venture interest included in 1998. The increase in other expense was due to higher interest expense of $2.0 million reflecting interest on the Senior Notes for the full year and an increased loss in all other expenses due principally to losses sustained in an unconsolidated subsidiary in 1999. Partially offsetting was an increase in interest income of $0.7 million reflecting higher overall cash balances.

Liquidity and Capital Resources

      Our ongoing liquidity requirements arise primarily from 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. Historically, bank financing and internally generated funds have provided funding for these activities. We are currently in the process of constructing nine new vessels in Norway. In April 2001 we anticipate closing the purchase of a 1982-built PSV, the Highland Patriot, for approximately $6.9 million. We are in discussions with the banking group to extend the $75 million credit facility (the “Credit Facility”) beyond its current expiration at the end of the second quarter of 2003. Estimated cash flow from operations, cash balances on hand and the extended $75 million credit facility should be adequate to meet the requirements of the new build program and normal capital expenditures for drydocking and enhancements to our existing fleet. There can be no assurance that we will be successful in extending the current facility or obtaining replacement financing at rates commercially acceptable to us.

      Our current debt structure includes $130 million of senior unsecured notes (the “Notes”). We pay interest semi-annually each June 1 and December 1 at the annual coupon rate of 8.75%. The Notes do not require payments of principal prior to their maturity on June 1, 2008, but we are required to make offers to purchase the Notes upon the occurrence of certain events, such as asset sales or a change in control of the Company. The Notes are not redeemable at the option of the Company prior to June 1, 2001.

      The Notes are general unsecured obligations and rank equally in right of payment with all existing and future unsecured senior indebtedness, which may include unsecured borrowings under the Credit Facility described more fully below, and senior to all future subordinated indebtedness. The Notes will be 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 Notes may be jointly and severally guaranteed on a senior unsecured basis by one or more of our subsidiaries.

      The indenture under which the Notes are issued imposes operating and financial restrictions on us. These restrictions affect, and in many cases limit or prohibit, among other things, our ability to incur additional indebtedness, make capital expenditures, create liens, sell assets and make dividend or other payments.

      The Credit Facility is with three banks and has two tranches. Tranche 1 is unsecured and is available for general corporate purposes. The maximum commitment amount is limited to $30 million. Interest on outstanding balances under Tranche 1 accrues at LIBOR plus a margin ranging from 1.0% to 1.375% depending on our ratio of funded debt to total capitalization (“Leverage Ratio”).

      Tranche 2 is available to finance the acquisition of (i) up to 50% of the acquisition costs of shares in another company (a “Share Acquisition”) or (ii) up to 65% of the purchase price or cost of a vessel (a “Vessel Acquisition”). Drawings under Tranche 2 will be secured, in the case of a Share Acquisition, by the capital stock of the acquired company or, in the case of a Vessel Acquisition, (i) by a first priority mortgage, (ii) by an assignment of earnings and insurance and (iii) by an assignment of charters over one year. The maximum committed amount is $45 million. The interest on outstanding balances under Tranche 2 is LIBOR plus 0.80% to 1.25% depending on our Leverage Ratio. Both tranches begin to reduce by 12.5% beginning on September 8, 2001, and shall be fully reduced by June 8, 2003.

      The Credit Facility also requires us not to exceed a maximum Leverage Ratio and to maintain a specified interest coverage ratio and a minimum net worth. We are currently in compliance with all of the covenants of this agreement.

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There can be no assurance that we will meet the covenants in future periods as compliance is dependent on the results of operations, nor can there be any assurance that waivers will be granted under the agreement.

      As of December 31, 2000, we had cash on hand of $34.7 million. Cash flows from operations for the year ended December 31, 2000, were $14.3 million compared to $16.4 million in the previous year. The decrease in operating cash flow was attributable to the increase in accounts receivable balances late in the year with the improvements in revenue in the fourth quarter.

      Cash flows used for investing activities for the years ended December 31, 2000 and 1999 were $6.2 million and $19.7 million, respectively. Our capital expenditures in 2000 included $12.3 million related to vessel and other fixed assets. These expenditures were partially offset by the proceeds from the sale of fixed assets totaling $8.5 million, primarily the sale of the Highland Fortress. Capital expenditure in the year ended December 31, 1999 included $17.1 million for progress payments on the Highland Guide and the Highland Scout and for the purchase the Highland Pioneer. The number of vessels required to be drydocked also impacts investing activities as vessels must be drydocked every two to three years to meet regulatory requirements. In 2000, there were 11 vessels drydocked at an aggregate cost of $2.4 million compared to ten vessels drydocked in 1999 at an aggregate cost of $2.6 million.

      Substantially all of our tax provision is for deferred taxes. The net operating loss available in the United Kingdom is primarily the result of accelerated depreciation allowances under United Kingdom tax law.

      We believe that our current reserves of cash and short-term investments, cash flows from operations and access to various credit arrangements 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.

Currency Fluctuations and Inflation

      Substantially all of our operations are conducted overseas; therefore we are exposed to currency fluctuations and exchange rate risks. Contracts for vessels in the North Sea fleet are primarily denominated in British pounds as are substantially all of the operating costs. The North Sea fleet generated $57.6 million in revenues and $15.1 million in operating income for the year ended December 31, 2000. In 2000, the British pound/U.S. dollar exchange rate ranged from a high of £ = U.S. $1.66 to a low of £ = U.S. $1.40 with an average of £ = U.S. $1.52 for the year. As of March 5, 2001, the exchange rate was £ = U.S.$1.46.

      With the issuance of the Notes in June 1998, our debt is primarily denominated in U.S. dollars, while a substantial portion of our revenue continues to be 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:

	(i)		the cost of using such instruments in relation to the risks of currency fluctuations,
	(ii)		the propensity for adjustments in British pounds denominated vessel day rates over time to compensate for changes in the purchasing power of British pounds as measured in U.S. dollars,
	(iii)		the Company’s strong cash position substantially held in U.S. dollars,
	(iv)		the level of dollar denominated borrowings available to the Company and
	(v)		the conditions in the Company’s dollar generating regional markets.

      One or more of these factors may change and the Company, in response, 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. At December 31, 2000, we had several contracts to hedge specific obligations to make payments in Norwegian Kroner related to our current construction program. Based on the exchange rate on February 23, 2001, the unrealized gain from the hedge contracts totaled approximately $1.1 million. Upon delivery of the vessels, any exchange rate benefit (loss) would be reflected in the net purchase price of the vessels.

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      Reflected in the accompanying balance sheet at December 31, 2000, is a $22.4 million cumulative translation adjustment primarily relating to the lower British pounds and Norwegian Kroner exchange rate as of December 31, 2000 in comparison to the exchange rate when we invested capital in our subsidiaries. Changes in the cumulative translation adjustment are non-cash items that are primarily attributable to investments in vessels and dollar denominated inter-company loans.

      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.

Accounting Pronouncements

      In June 1998, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” This statement requires the recognition of derivative instruments as assets and liabilities, based on their fair value, and specifies certain methods for the recognition of related gains and losses. In June 2000, the FASB issued SFAS No. 138, which amends and clarifies certain guidance in SFAS No. 133. We have implemented the appropriate systems and processes to adopt these statements effective January 1, 2001. The statements provide for the recognition of a cumulative adjustment for an accounting change, as of the date of adoption. The cumulative effect of adoption of these new accounting standards will not have a significant impact on our results of operations.

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 services and future capital expenditures. Such statements are subject to certain risks, uncertainties and assumptions, including, without limitation, 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, assumptions concerning competition and risks of currency fluctuations and other matters. 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

      Our financial instruments that are potentially sensitive to changes in interest rates include the Notes, which are due June 1, 2008. They have a stated interest rate of 8.75% and an effective interest rate of 8.8%. At December 31, 2000, the fair value of these notes, based on quoted market prices, was approximately $121.9 million, as compared to a carrying amount of $129.7 million.

Exchange Rate Sensitivity

      Other than trade accounts receivable and trade accounts payable, we do not currently have financial instruments that are sensitive to foreign currency exchange rates. Other information required under Item 7A has been provided in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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ITEM 8.   Consolidated Financial Statements and Supplementary Data

REPORT OF INDEPENDENT AUDITORS

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

      We have audited the accompanying consolidated balance sheets of GulfMark Offshore, Inc., and subsidiaries as of December 31, 2000, and the related consolidated statements of income, stockholders’ equity, comprehensive income, and cash flows for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

      In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of GulfMark Offshore, Inc. and subsidiaries as of December 31, 2000, and the consolidated results of their operations and their cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States.

Ernst & Young LLP

Houston, Texas
February 23, 2001

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To GulfMark Offshore, Inc.:

      We have audited the accompanying consolidated balance sheets of GulfMark Offshore, Inc., a Delaware corporation and subsidiaries as of December 31, 1999, and the related consolidated statements of income, stockholders’ equity, comprehensive income, and cash flows for each of the two years in the period ended December 31, 1999. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

      In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of GulfMark Offshore, Inc. and subsidiaries as of December 31, 1999, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States.

Arthur Andersen LLP

Houston, Texas
March 8, 2000

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GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

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

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GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME