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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2003

Commission File Number: 0-28316

Trico Marine Services, Inc.

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code: (985) 851-3833

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 per share

Preferred Stock Purchase Rights

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  ¨

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 this Form 10-K or any amendment to this Form 10-K.  ¨

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2.)    Yes  x    No  ¨

The aggregate market value of the voting stock held by non-affiliates of the Registrant at June 30, 2003 based on the closing price on NASDAQ National Market on that date was $109,744,438.

The number of shares of the Registrant’s common stock, $0.01 par value per share, outstanding at February 27, 2004 was 36,935,537.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement, to be filed electronically no later than 120 days after the end of the fiscal year, are incorporated by reference in Part III.

Table of Contents

TRICO MARINE SERVICES, INC.

ANNUAL REPORT ON FORM 10-K FOR

THE YEAR ENDED DECEMBER 31, 2003

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PART I

Items 1 and 2.    Business and Properties

General

Trico Marine Services, Inc. and its subsidiaries (“the Company”, “Trico”, or collectively “we”) are a leading provider of marine support vessels to the oil and gas industry, primarily in the U.S. Gulf of Mexico, the North Sea and Latin America. The services provided by our diversified fleet include the transportation of drilling materials, supplies and crews to drilling rigs and other offshore facilities; towing drilling rigs and equipment from one location to another; and support for the construction, installation and maintenance of offshore facilities. Using our larger and more sophisticated vessels, we also provide support for deepwater ROVs (remotely operated vehicles) and well stimulation and maintenance services. We have a total fleet of 84 vessels, including 48 supply vessels, 13 large capacity platform supply vessels, six large anchor handling, towing and supply vessels, 11 crew boats (including three crew boats we are leasing under ten-year operating leases), and six line-handling vessels.

Demand for our services is primarily affected by expenditures for oil and gas exploration, development and production in the markets in which we operate. We experienced increases in our vessel day rates and utilization from late 1999 through the first half of 2001. This increase was primarily due to increased drilling activity and a reduction in the number of vessels in our markets, which was partially caused by the stacking or retirement of older vessels by some of our competitors and us. In the third quarter of 2001, we began to experience decreases in day rates and lower utilization for our Gulf fleet due to decreased offshore drilling activity in the Gulf. In 2002, we experienced decreased day rates and utilization for both our Gulf fleet and our North Sea class vessels. In 2003, drilling activity in the regions in which the Company operates experienced continued softness, which has adversely affected both the day rates and utilization of our fleet.

Typically, marine support vessels are priced to the customer on the basis of a daily rate, or “day rate,” regardless of whether a charter contract is for several days or several years. The average day rate of a vessel, or class of vessel, is calculated by dividing its revenues by the total number of days such vessel was under contract during a given period. A vessel’s utilization is the number of days in a period the vessel is under contract as a percentage of the total number of days in such period. Vessel demand is most directly impacted by offshore drilling activity. Vessel day rates and utilization are impacted by general vessel demand and various factors including vessel size, capacity, horsepower, age and whether a vessel has equipment such as sophisticated positioning and fire-fighting systems.

Our business was incorporated as a Delaware corporation in 1993. Our principal executive offices are located at 250 North American Court, Houma, Louisiana 70363. Our website address is www.tricomarine.com where all of our public filings are available, free of charge, through website linkage to the Securities and Exchange Commission. The information contained on this website is not part of this annual report.

The Industry

Marine support vessels are used primarily to transport equipment, supplies, and personnel to drilling rigs, to support the construction and operation of offshore oil and gas production platforms, as work platforms for offshore construction and platform maintenance and for towing services for drilling rigs and equipment. The principal types of vessels that we operate can be summarized as follows:

Supply Boats.    Supply boats are generally at least 165 feet in length and were constructed primarily for operations on the outer continental shelf of the Gulf to serve drilling and production facilities and support offshore construction and maintenance work. Supply boats are differentiated from other types of vessels by cargo flexibility and capacity. In addition to transporting deck cargo, such as pipe or drummed materials, supply boats transport liquid mud, potable and drilling water, diesel fuel, dry bulk cement and dry bulk mud.

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Platform Supply Vessels.    Platform supply vessels, also known as PSVs, were constructed primarily for international and deepwater operations. PSVs serve drilling and production facilities and support offshore construction and maintenance work. They are differentiated from other offshore support vessels by their larger deck space and cargo handling capabilities. Utilizing space on and below deck, they are used to transport supplies such as fuel, water, drilling fluids, equipment and provisions. PSVs range in size from 165 feet to more than 300 feet and are particularly suited for supporting large concentrations of offshore production locations because of their large deck space and below deck capacities.

Anchor Handling, Towing and Supply Vessels.    Anchor handling, towing and supply vessels, also known as AHTSs, are used to set anchors for drilling rigs and tow mobile drilling rigs and equipment from one location to another. In addition, these vessels can be used in limited supply roles when they are not performing anchor handling and towing services. They are characterized by large horsepower (generally averaging approximately 12,000-15,600 horsepower), shorter after decks and special equipment such as towing winches.

Crew Boats.    Crew boats are generally at least 100 feet in length and are used primarily for the transportation of personnel and light cargo, including food and supplies, to and among drilling rigs, production platforms and other offshore installations. Crew boats are constructed from aluminum. As a result, they generally require less maintenance and have a longer useful life without refurbishment than steel-hulled supply boats. The majority of our crew boats range from 120 to 155 feet in length.

Line Handling Boats.    Line handling boats are generally outfitted with special equipment to assist tankers while they are loading from single buoy mooring systems. These vessels support oil off-loading operations from production facilities to tankers and transport supplies and materials to and between deepwater platforms.

Market Areas

We operate primarily in the Gulf of Mexico (“the Gulf”), the North Sea, and offshore Brazil. Financial data, including revenues, expenses, and assets by market area/operating segment, are detailed in Note 17 of our consolidated financial statements. Our primary market areas are summarized below.

Gulf of Mexico.    Our vessels support exploration and development activities in the Gulf as well as existing oil and gas production platforms from both offshore U.S. and offshore Mexico. Demand for our supply boats is primarily impacted by the level and type of offshore oil and gas drilling activity. Drilling activity is influenced by a number of factors, including oil and gas prices and offshore drilling budgets of oil and gas companies. The level of exploration and development is typically tracked by the number of rigs in the market area (“rig count”). The rig count is ultimately the driving force behind the vessel day rates and utilization for any given period.

As of February 27, 2004, we had 43 supply boats and 10 crew boats in the Gulf, including four vessels operating offshore of Mexico.

North Sea.    The North Sea market area consists of offshore Norway, Denmark, the Netherlands, Germany, Great Britain and Ireland, and the area west of the Shetland Islands. Historically, it has been the most demanding of all offshore areas due to harsh weather, erratic sea conditions, significant water depth and long sailing distances. Exploration and production operators in the North Sea 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 area. In comparison to the Gulf, projects in the region tend to be fewer in number, but larger in scope, with longer planning horizons and more long-term contracts. Consequently, vessel demand in the North Sea is generally slower to react to changes in energy prices and less susceptible to abrupt swings than vessel demand in other regions. Activity in the North Sea generally is at its highest level during the months from April to September and at its lowest level during November to February.

As of February 27, 2004, we had 13 PSVs and six AHTSs in the North Sea.

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Brazil.    The primary customer in the Brazilian market is Petrobras, the Brazilian national oil company. Since 1999, Brazil has permitted foreign oil companies to participate in offshore oil and gas drilling and production. Offshore exploration and production activity in Brazil is concentrated in the deep water Campos Basin, located 60 to 100 miles from the Brazilian coast. A number of fields in the Campos Basin are being produced using floating production facilities. In addition, exploration activity has expanded south to the Santos Basin approximately 100 miles southeast of the city of Rio de Janeiro and to the northeastern and northern continental shelves.

As of February 27, 2004, we had six line-handling vessels, our Small Water Area Twin Hull (SWATH) crew boat and one supply boat operating offshore Brazil. Seven of our vessels operating offshore Brazil are under charters with Petrobras.

Other Areas.    The Company also has developing operations in West Africa, for which operations are based in Nigeria.

Our Fleet

Existing Fleet.    The following table sets forth information regarding the vessels operated by us as of February 27, 2004:

As of February 27, 2004, the average age of our vessels was 16 years. We believe that our upgrade and refurbishment program, completed in the first half of 1999, has significantly extended the service life of most of our Gulf supply boats.

Vessel Maintenance.    We incur routine dry-dock inspection, maintenance and repair costs under U.S. Coast Guard Regulations and to maintain American Bureau of Shipping or DetNorske Veritas certification for our vessels. In addition to complying with these requirements, we also have our own comprehensive vessel maintenance program that we believe helps us to continue to provide our customers with well maintained, reliable vessels. We incurred approximately $10.8 million, $9.5 million, and $11.3 million in dry-docking and marine inspection costs in the years ended December 31, 2003, 2002, and 2001, respectively.

Operations Bases

We support our operations in the Gulf from a 62.5 acre docking, maintenance and office facility in Houma, Louisiana located on the Intracoastal Waterway that provides direct access to the Gulf. We also lease a 3,600 square foot office in Houston, Texas. Our North Sea operations are supported from an owned office in Fosnaväg, Norway and leased offices in Kristiansand, Norway and Aberdeen, Scotland. Our Brazilian operations are supported from a maintenance and administrative facility in Macae, Brazil and a sales and administrative office in Rio de Janeiro. The Company also has sales and operational offices in Port Harcourt, Nigeria and Cuidad Del Carmen, Mexico.

Customers and Charter Terms

We have entered into master service agreements with substantially all of the major and independent oil companies operating in the Gulf. Most of our charters in the Gulf are short-term contracts (60 to 90 days) or spot

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contracts (less than 30 days) and are cancelable upon short notice. Because of frequent renewals, the stated duration of charters frequently has little relationship to the actual time vessels are chartered to a particular customer.

Our principal customers in the North Sea are major integrated oil companies and large independent oil and gas companies as well as foreign government owned or controlled companies that provide logistic, construction and other services to such oil companies and foreign government organizations. The charters with these customers are industry standard time charters. Current charters in the North Sea include periods ranging from spot contracts of just a few days or months to long-term contracts of several years.

Charters are obtained through competitive bidding or, with certain customers, through negotiation. The percentage of revenues attributable to an individual customer varies from time to time, depending on the level of exploration and development activities undertaken by a particular customer, the availability and suitability of our vessels for the customer’s projects, and other factors, many of which are beyond our control. For the years ended 2001 and 2002, approximately 16% and 13%, respectively, of our total revenues were received from ExxonMobil Corporation or its subsidiaries on a worldwide basis. No individual customer represented more than 10% of consolidated revenues during 2003.

Competition

Our business is highly competitive. Competition in the marine support services industry primarily involves factors such as price, service and reputation of vessel operators and crews, and availability and quality of vessels of the type and size needed by the customer. Although a few of our competitors are larger and many have greater financial resources and international experience than us, we believe that our operating capabilities and reputation enable us to compete with other fleets in the market areas in which we operate.

Regulation

Our operations are significantly affected by federal, state and local regulations, as well as certain international conventions, private industry organizations and laws and regulations in jurisdictions where our vessels operate and are registered. These regulations govern worker health and safety and the manning, construction and operation of vessels. For example, we are subject to the jurisdiction of the U.S. Coast Guard, the National Transportation Safety Board, the U.S. Customs Service and the Maritime Administration of the U.S. Department of Transportation, as well as private industry organizations such as the American Bureau of Shipping and DetNorske Veritas. The latter two organizations establish safety criteria and are authorized to investigate vessel accidents and recommend improved safety standards. In addition, we are subject to regulation in other areas in which we operate.

The U.S. Coast Guard regulates and enforces various aspects of marine offshore vessel operations, such as classification, certification, routes, dry-docking intervals, manning requirements, tonnage requirements and restrictions, hull and shafting requirements and vessel documentation. U.S. Coast Guard regulations require that each of our vessels be dry-docked for inspection at least twice within a five-year period. We believe we are in compliance in all material respects with all U.S. Coast Guard regulations.

Under U.S. law, the privilege of transporting merchandise or passengers in domestic waters extends only to vessels that are owned by U.S. citizens and are built in and registered under the laws of the United States. Under the citizenship provisions of the Merchant Marine Act of 1920 and the Shipping Act of 1916, the Company could not engage in U.S. coastwise trade if more than 25% of the Company’s outstanding stock was owned by non-U.S. citizens. If we should fail to comply with this requirement, during the period of such noncompliance we would not be permitted to continue operating our vessels in coastwise trade.

Our operations are also subject to a variety of federal and state statutes and regulations regarding the discharge of materials into the environment or otherwise relating to environmental protection. Included among

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these statutes are the Clean Water Act, the Resource Conservation and Recovery Act (“RCRA”), the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the Outer Continental Shelf Lands Act (“OCSLA”) and the Oil Pollution Act of 1990 (“OPA”).

The Clean Water Act imposes strict controls on the discharge of pollutants into the navigable waters of the U.S., and imposes potential liability for the costs of remediating releases of petroleum and other substances. The Clean Water Act provides for civil, criminal and administrative penalties for any unauthorized discharge of oil and other hazardous substances in reportable quantities and imposes substantial potential liability for the costs of removal and remediation. Many states have laws that are analogous to the Clean Water Act and also require remediation of accidental releases of pollutants in reportable quantities. Our vessels routinely transport diesel fuel to offshore rigs and platforms, and also carry diesel fuel for their own use. Our supply boats transport bulk chemical materials used in drilling activities, and also transport liquid mud which contains oil and oil by-products. All offshore companies operating in the U.S. are required to have vessel response plans to deal with potential oil spills.

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

CERCLA contains provisions dealing with remediation of releases of hazardous substances into the environment and imposes strict, joint and several liability for the costs of remediating environmental contamination upon owners and operators of contaminated sites where the release occurred and those companies who transport, dispose of or who arrange for disposal of hazardous substances released at the sites. Although we handle hazardous substances in the ordinary course of business, we are not aware of any hazardous substance contamination for which we may be liable.

OCSLA provides the federal government with broad discretion in regulating the leasing and development of submerged outer continental shelf lands for oil and gas production. If the government were to exercise its authority under OCSLA to restrict the availability of offshore oil and gas leases, this could reduce demand for our Gulf vessels and adversely affect utilization and day rates.

OPA contains provisions specifying responsibility for removal costs and damages resulting from discharges of oil into navigable waters or onto the adjoining shorelines. Among other requirements, OPA requires owners and operators of vessels over 300 gross tons to provide the U.S. Coast Guard with evidence of financial responsibility to cover the costs of cleaning up oil spills from such vessels. We have provided satisfactory evidence of financial responsibility to the U.S. Coast Guard for all of our Gulf vessels over 300 tons.

We believe we are in compliance in all material respects with all applicable environmental laws and regulations. Our vessels operating in foreign market areas are subject to regulatory controls concerning environmental protection similar to those in force in the Gulf. We believe that compliance with any existing environmental requirements will not materially affect our operations or competitive position.

Insurance

The operation of our vessels is subject to various risks representing threats to the safety of our crews, and to the safety of our vessels and cargo. We maintain insurance coverage against risks such as catastrophic marine disaster, adverse weather conditions, mechanical failure, collision and navigation errors, which management considers to be customary in the industry. We believe that our insurance coverage is adequate and we have not experienced a loss in excess of our policy limits. However, there can be no assurance that we will be able to maintain adequate insurance at rates which we consider commercially reasonable, nor can there be any assurance that such coverage will be adequate to cover all claims that may arise. Insurance rates have been subject to wide fluctuation and have led to increases in costs and higher deductibles and retention amounts in recent years.

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Employees

As of February 27, 2004, we had 983 employees worldwide, including 853 operating personnel and 130 corporate, administrative and management personnel. We believe our relationship with our employees is satisfactory. To date, strikes, work stoppages, boycotts, or slowdowns have not interrupted our operations.

Our U.S. employees have not chosen to be represented by a labor union and are not covered by a collective bargaining agreement. We, together with other providers of marine support vessels, have in the past been targeted by maritime labor unions in an effort to organize our Gulf employees. If our Gulf employees were to become union represented, we believe that our flexibility in dealing with changing circumstances in our industry, or in our own operations, could be limited and our business operations could be adversely affected.

Our Norwegian seamen are covered by three union contracts with three separate Norwegian unions. Our United Kingdom seamen are covered by two union contracts with two separate unions. We believe our relationships with our employees in Norway and the United Kingdom are satisfactory.

Our seamen in Brazil, Nigeria and Trinidad are covered by separate collective bargaining agreements. We believe our relationships with our employees in these areas are satisfactory.

Cautionary Statements

Certain statements made in this Annual Report that are not historical facts are “forward-looking statements.” Such forward-looking statements may include statements that relate to:

Also, you can generally identify forward-looking statements by such terminology as “may,” “will,” “expect,” “believe,” “anticipate,” “project,” “estimate” or similar expressions. We caution you that such statements are only predictions and not guarantees of future performance or events. In evaluating these statements, you should consider various risk factors, including but not limited to the risks listed below. These risk factors may affect the accuracy of the forward-looking statements and the projections on which the statements are based.

All phases of our operations are subject to a number of uncertainties, risks and other influences, many of which are beyond our control. Any one of such influences, or a combination, could materially affect the results of our operations and the accuracy of forward-looking statements made by us. Some important factors that could cause actual results to differ materially from the anticipated results or other expectations expressed in our forward-looking statements include the following:

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Many of these factors are beyond our ability to control or predict. We caution investors not to place undue reliance on forward-looking statements. We disclaim any intent or obligation to update the forward-looking statements contained in this Annual Report, whether as a result of receiving new information, the occurrence of future events or otherwise, other than as required by law.

In addition to the other information in this Annual Report, the following factors should be considered carefully.

Our debt has been recently downgraded and could be downgraded again by one or both of the rating agencies

On July 25, 2003, Moody’s Investors Service (“Moody’s”) downgraded our long-term senior implied rating to B3 from B1 and lowered our senior unsecured notes’ rating to Caa1 from C2. On January 27, 2004, Moody’s downgraded our long-term senior implied rating to Caa1 from B3 and lowered our senior unsecured notes’ rating to Caa2 from Caa1. On November 24, 2003, Standard & Poor’s Ratings Services (“S&P”), a division of The McGraw-Hill Companies, Inc., downgraded our senior unsecured notes to CCC from CCC+ and placed that credit rating on creditwatch with negative implications. In addition, S&P lowered our corporate rating to B- from B on the same date. On March 11, 2004, S&P downgraded the senior unsecured notes from CCC to CCC- and the corporate rating from B- to CCC+. This downgrade requires the Company to post an additional letter of credit of approximately $1.7 million under the Company’s master bareboat charter agreement. Because of these downgrades, and the potential of one or both rating agencies continuing to downgrade our debt, it is likely that we will have difficulty obtaining financing and our cost of obtaining additional financing or refinancing existing debt may be increased significantly.

Our substantial indebtedness could adversely affect our financial health.

We now have a significant amount of indebtedness. As of December 31, 2003, we had total indebtedness of approximately $380.2 million. Our high level of debt could have important consequences to you, including the following:

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We are highly dependent on external sources of financing and improved cash flow to meet our obligations and reduce our indebtedness in the future.

In the short-term, we expect a substantial portion of our liquidity to be provided by cash provided by operations, our unrestricted cash, and our NOK Credit Facility. As of February 27, 2004, we had unrestricted cash of $37.6 million and NOK 320 million of borrowing capacity under our NOK Credit Facility. However, we are restricted to NOK 202 million of availability as a result of financial covenants under such facility. With the completion of the 2004 Term Loan (described in more detail in Item 7, Liquidity and Capital Resources), the Company believes that cash provided by operations and current unrestricted cash and available credit under its NOK credit facility will be sufficient to fund our debt service requirements, working capital and vessel maintenance expenditures until at least December 31, 2004, barring any unforeseen circumstances. If current activity levels continue in the Gulf of Mexico and the North Sea, it would require us to depend more heavily on our NOK Credit Facility.

In the longer term, our ability to pay debt service and other contractual obligations will depend on improving our future performance and cash flow generation, which in turn will be affected by prevailing economic and industry conditions and financial, business and other factors, many of which are beyond our control. If we have difficulty providing for debt service or other contractual obligations in the future, we will be forced to take actions such as reducing or delaying capital expenditures, reducing costs, selling assets, refinancing or restructuring our debt or other obligations and seeking additional equity capital, or any combination of the above. We may not be able to take any of these actions on satisfactory terms, or at all.

We have had two consecutive years of operating losses and will incur additional operating losses for the foreseeable future.

We reported operating losses of $135.5 million and $12.1 million for the years ended December 31, 2003 and 2002, respectively. As of December 31, 2003, we had an accumulated deficit of approximately $214.8 million. We expect to continue to incur losses for the foreseeable future. We had negative cash flows from operations in 2003. Insufficient cash flows may adversely affect our ability to fund capital expenditures and pay debt service and other contractual obligations. To become profitable, we must depend on increases to the current levels of oil and gas production and exploration, primarily in the Gulf of Mexico.

Market volatility and low levels of exploration and development activity affect demand for our services.

Demand for our services depends heavily on activity in offshore oil and gas exploration, development and production. The level of exploration and development is typically tracked by the number of offshore rigs in each market area (“offshore rig count”) in which the Company operates. The offshore rig count is ultimately the driving force behind the day rates and utilization in any given period. A reduction in the offshore rig count and day rates could be delayed or prolonged if the Company enters into a long-term contract. This is particularly relevant to the North Sea market, where contracts tend to be longer in nature. The continuation of low levels of activity in the Gulf and other areas in which we operate may adversely affect the demand for our marine support services, and may reduce our revenues and negatively impact our cash flows. If market conditions were to continue to decline in market areas in which the Company operates, it could require the Company to evaluate the recoverability of its long-lived assets.

Charter rates for marine support vessels in our market areas also depend on the supply of vessels. Excess vessel capacity in the offshore support vessel industry is primarily the result of either construction of new vessels

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or the mobilization of existing vessels into fully saturated markets. In recent years, the Company has been subject to both new vessel construction, particularly in the Gulf and the North Sea, as well as vessels mobilizing into regions in which it operates, which has increased the competition in those areas. Additional excess capacity coupled with prolonged periods of low levels of production and exploration could further reduce our day rates and utilization levels.

We operate in a highly competitive industry.

Our business is highly competitive. Certain of our competitors have significantly greater financial resources than us and more experience operating in international areas. Competition in the marine support services industry primarily involves factors such as:

Operating hazards may increase our operating costs; our insurance coverage is limited.

Marine support vessels are subject to operating risks such as catastrophic marine disaster, adverse weather conditions, mechanical failure, collisions, oil and hazardous substance spills and navigation errors. The occurrence of any of these events may result in damage to or loss of our vessels and our vessels’ tow or cargo or other property and in injury to passengers and personnel. Such occurrences may also result in a significant increase in operating costs or liability to third parties. We maintain insurance coverage against certain of these risks, which our management considers to be customary in the industry. We cannot assure you, however, that we can renew our existing insurance coverage at commercially reasonable rates or that such coverage will be adequate to cover future claims that may arise. In addition, the recent terrorist attacks that occurred in the U.S., as well as other factors, have caused significant increases in the cost of our insurance coverage. More restrictive coverage could adversely impact our operating results.

Compliance with governmental regulations may impose additional costs.

We must comply with federal, state and local regulations, as well as certain international conventions, private industry organizations and agencies, and laws and regulations in jurisdictions in which our vessels operate and are registered. These regulations govern worker health and safety and the manning, construction and operation of vessels. These organizations establish safety criteria and are authorized to investigate vessel accidents and recommend approved safety standards. If we fail to comply with the requirements of any of these laws or the rules or regulations of these agencies and organizations, we could be subject to substantial fines, penalties or other restrictions.

Our operations also are subject to federal, state and local laws and regulations that control the discharge of pollutants into the environment and that otherwise relate to environmental protection. While our insurance policies provide coverage for accidental occurrence of seepage and pollution or clean up and containment of the foregoing, pollution and similar environmental risks generally are not fully insurable. We may incur substantial costs in complying with such laws and regulations, and noncompliance can subject us to substantial liabilities. The laws and regulations applicable to us and our operations may change. If we violate any such laws or regulations, this could result in significant liability to us. In addition, any amendment to such laws or regulations that mandates more stringent compliance standards would likely cause an increase in our vessel operating expenses.

The Coast Guard adopted a major new vessel and marine facility security rule in October 2003 that will impact all providers of marine transportation services in the United States. Provisions of international treaty have put in place major vessel and marine facility security regulatory regimes that impact all providers of marine transportation services worldwide. By July 1, 2004, the Company must have approved security plans in place on

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all our vessels, both domestic and international. These plans require additional crew training and flag state approval surveys. Trico has submitted security plans for all of its affected vessels and expects to meet the July deadline. In addition, certain electronic equipment has been mandated for vessels operating internationally, and as a result, Trico will be adding such equipment to the majority of its fleet during 2004.

Our marine operations are seasonal and depend, in part, on weather conditions.

In the Gulf, we have historically enjoyed our highest utilization rates during the second and third quarters, as mild weather provides favorable conditions for offshore exploration, development and construction. Adverse weather conditions during the winter months generally curtail offshore development operations. Activity in the North Sea is also subject to delays during periods of adverse weather. Accordingly, the results of any one quarter are not necessarily indicative of annual results or continuing trends.

Age of fleet.

The average age of our vessels is approximately 16 years. Expenditures required for the repair, certification and maintenance of a vessel typically increase with vessel age. These expenditures may increase to a level at which they are no longer economically justifiable. We cannot assure you that we will be able to maintain our fleet by extending the economic life of existing vessels through major refurbishment or by acquiring new or used vessels. Also, as the age of a vessel increases, it becomes less marketable, particularly in periods with low utilization such as 2002 and 2003.

Currency fluctuations could adversely affect our results of operations.

Due to the size of our international operations, a significant percentage of our business is conducted in currencies other than the U.S. Dollar. We are primarily exposed to fluctuations in the foreign currency exchange rates of the Norwegian Kroner (NOK), the British Pound and the Brazilian Real. Changes in the value of these currencies relative to the U.S. Dollar could result in translation adjustments reflected as comprehensive income or losses on our balance sheet. In addition, translation gains and losses could contribute to fluctuations in our results of operations. Due to the fluctuation of these currencies, primarily the NOK, we incurred a favorable accumulated foreign currency translation adjustment of $10.6 million in 2003 and $71.5 million in 2002. The Company experienced unfavorable accumulated foreign currency translation adjustments of $1.0 million for the year ended December 31, 2001. We incurred foreign exchange losses of $0.9 million, $1.4 million, and $1.0 million for 2003, 2002, and 2001, respectively. Future fluctuations in these and other foreign currencies may result in additional foreign exchange gains or losses, and could have a significant impact on our financial position.

Operating internationally poses uncertain hazards.

Our international operations are subject to a number of risks inherent to any business operating in foreign countries. These risks include, among others:

We cannot predict the nature and the likelihood of any such events. However, if such an event should occur, it could have a material adverse effect on our financial condition and results of operations.

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We depend on key personnel.

We depend on the continued services of our executive officers and other key management personnel, the loss of any of whom could result in inefficiencies in our operations, lost business opportunities or the loss of one or more customers.

A terrorist attack could have a material adverse effect on our business.

The potential for future terrorist attacks, the national and international response to terrorist attacks, and other acts of war or hostility have created many economic and political uncertainties, which could adversely affect our business for the short or long-term in ways that cannot presently be predicted.

Item 3.    Legal Proceedings

We are involved in various legal and other proceedings that are incidental to the conduct of our business. Legal proceedings include, among other things, suits filed by employees and other individuals under the Merchant Marine Act of 1920 (“the Jones Act”), and other personal injury type suits. We do not believe that any of these proceedings, if adversely determined, would have a material adverse effect on our financial condition, results of operations or cash flows.

Item 4.    Submission of Matters To a Vote Of Security Holders

None.

Item 4A.    Executive Officers of the Registrant

The name, age and offices held by each of the executive officers of the Company as of February 27, 2004, are as follows:

Ronald O. Palmer has been a director since October 1993 and Chairman of the Board since May 1997. Mr. Palmer also served as Executive Vice President from February 1995 to May 1997. Mr. Palmer joined Mr. Fairley in founding our predecessor company in 1980 and served as Vice President, Treasurer and Chief Financial Officer until February 1995.

Thomas E. Fairley, who co-founded our predecessor company with Mr. Palmer in 1980, has been President and Chief Executive Officer and a director since October 1993. From October 1993 to May 1997, Mr. Fairley also served as our Chairman of the Board. Mr. Fairley is also a director of Gulf Island Fabrication, Inc., a leading marine fabricator.

Trevor Turbidy has served as Vice President and Chief Financial Officer since August 2003. From November 2000 until May 2002, Mr. Turbidy served as a Director in the Investment Banking Department of Credit Suisse First Boston. From 1991 until November 2000, Mr. Turbidy held various positions leading up to being a Director in the Investment Banking Department of Donaldson, Lufkin & Jenrette.

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Kenneth W. Bourgeois has served as one of our Vice Presidents since October 1993. Mr. Bourgeois served as our Controller from October 1993 to June 2002, and also served as the Controller of our predecessor company from December 1981 to October 1993. Mr. Bourgeois is a Certified Public Accountant.

Michael D. Cain has served as our Vice President, Marketing since February 1993. From 1986 to 1993, Mr. Cain served as Marketing Manager for our predecessor company.

Charles E. Tizzard has served as our Vice President, Administration since June 1997. From October 1994 to June 1997, Mr. Tizzard served as Manager of Administration and Planning.

Charles M. Hardy has served as our Vice President of Operations since July 2000. From May 1996 to July 2000, Mr. Hardy served as President of Offshore Towing, Inc. From 1993 to 1996, Mr. Hardy was employed by Tidewater Marine, Inc. as Vice President—Towing Division.

D. Michael Wallace has served as our Vice President, International Business Development since November 2002. From January 2000 to November 2002, Mr. Wallace was Vice President of Marine Logistics with ASCO US LLC. From December 1996 to December 1999, Mr. Wallace was General Manager for Tidewater Marine, Inc. in Venezuela.

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PART II

Item 5.    Market for Registrant’s Common Stock and Related Stockholder Matters

Our common stock is listed for quotation on the NASDAQ National Market under the symbol “TMAR.” At February 27, 2004 we had 82 holders of record of our common stock.

The following table sets forth the range of high and low closing sales prices of our common stock as reported by the NASDAQ National Market for the periods indicated.

We have not paid any cash dividends on our common stock during the past two years and have no plans to pay dividends. In addition, our debt agreements contain a restricted payment test which currently prohibits us from paying dividends on our common stock.

Equity Compensation Plan Information

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Item 6.    Selected Financial Data

The selected financial data presented below for the five fiscal years ended December 31, 2003 is derived from our audited consolidated financial statements. You should read this information in conjunction with the discussion under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements.

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

General

We are a leading provider of marine support vessels to the oil and gas industry, primarily in the U.S. Gulf of Mexico, the North Sea, and Latin America. We have a total fleet of 84 vessels, including 48 supply vessels, 13 large capacity platform supply vessels, six large anchor handling, towing and supply vessels, 11 crew boats and six line-handling vessels. Three of the crew boats are being leased under ten-year operating leases.

Our results of operations are affected primarily by the day rates we receive and our fleet utilization. Demand for our vessels is primarily impacted by the level of offshore oil and gas drilling activity, which historically has been primarily influenced by oil and gas prices and drilling budgets of oil and gas companies. Our day rates and utilization rates are also affected by the size, configuration, age and capabilities of our fleet. In the case of supply boats and PSVs, their deck space and liquid mud and dry bulk cement capacity are important attributes. In certain markets and for certain customers, horsepower and dynamic positioning systems are also important requirements. For crew boats, size and speed are important factors. Our day rates and utilization are also affected by the supply of other vessels available in a given market area with similar configurations and capabilities.

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, increases or decreases in vessel utilization only affect 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.

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In addition to these variable costs, we incur fixed charges related to the depreciation of our fleet and costs for the routine dry-dock inspection, maintenance and repair designed to ensure compliance with U.S. Coast Guard regulations and to maintain required certifications for our vessels. Maintenance and repair expense and marine inspection amortization charges are generally determined by the aggregate number of dry-dockings and other repairs undertaken in a given period. Costs incurred for dry-dock inspection and regulatory compliance are capitalized and amortized over the period between such dry-dockings, typically two to five years.

Overview

During 2003, the Company experienced disappointing results from operations primarily due to low levels of drilling activity in the key markets in which it operates. These low levels of drilling activity, combined with the increase of competition to our market areas, led to reductions in day rates and utilization of our fleet in most market areas. As a result of reduced revenues and disappointing operating results in 2003 and in the recent past, the Company completed steps to enhance liquidity. During 2003, the Company sold a large North Sea vessel and a Brazilian vessel under construction, which generated approximately $52.5 million of cash. Additionally, the Company entered into a new term loan in February 2004, which added flexibility and increased available liquidity.

The Company had goodwill related to the 1997 acquisition of its North Sea reporting segment. Statement of Financial Accounting Standards (“SFAS”) No. 142, “Goodwill and Other Intangible Assets,” requires an annual assessment of goodwill for impairment, which the Company elected to conduct during the second quarter of its fiscal year. During the second quarter ended June 30, 2002, the Company conducted its initial assessment for goodwill impairment as required under SFAS No. 142. That assessment used a projection of discounted cash flows, comparable industry financial ratios and other data. The Company determined at that time that there was no impairment of goodwill based on the operating results to date, and, as discussed in previous filings, management’s expectations that market conditions for the North Sea would remain stable through 2002, and then improve in 2003. However, operating results in the North Sea began to experience a decline during the early part of fiscal 2003. Upon the completion of the Company’s annual goodwill analysis in the second quarter ended June 30, 2003, the Company recorded a goodwill impairment charge of approximately $28.6 million. This charge reflected the devaluation in the North Sea reporting unit’s fair value compared to the book value, and was estimated based on the projected future discounted cash flows of the reporting unit, in light of current market conditions and our expectations at the time, which we believed would remain stable or improve in the latter half of 2003. After continued deterioration in market conditions in the North Sea during the third and fourth quarters of 2003, the Company determined that an additional interim test of impairment was necessary as of December 31, 2003. While annual average day rates and number of vessels in the North Sea had remained relatively steady for the past three years and the utilization had declined marginally, our expectation of the low level of activity in the North Sea is believed to continue rather than return to 2001 levels in the near term. As a result of performing this test, we recorded an additional charge of $84.4 million in the fourth quarter of 2003 which represents the remainder of the goodwill associated with the North Sea reporting unit.

Looking forward, we will continue to explore ways to enhance the Company’s liquidity and leverage structure. Although the overall U.S. economy is improving in general, we are very cautious about 2004 operating results, and believe the exploration and production activity in our market areas could remain somewhat depressed. If market conditions in any market in which the Company operates were to continue to deteriorate, it could require the Company to examine the recoverability of its long-lived assets in that market. See further discussion in “Impairment of long-lived assets other than goodwill” in Critical Accounting Policies included in Item 7.

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Results of Operations

The table below sets forth by vessel class, the average day rates and utilization for our vessels and the average number of vessels we operated during the periods indicated.

Set forth below is the internal allocation of our charter revenues and charter revenues less direct vessel operating expenses among vessel classes for each of the periods indicated (dollars in thousands).

Comparison of the Year Ended December 31, 2003 to the Year Ended December 31, 2002

Our revenues in 2003 were $123.5 million compared to $133.9 million in 2002. The 8% decrease in revenues during the year was a result of lower average vessel day rates and utilizations, specifically in the Gulf class supply boats and the North Sea AHTS vessels.

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For the Gulf class supply vessels, day rates decreased 11% from $5,575 in 2002 to $4,954 in 2003. Utilization also decreased for these vessels from 53% in 2002 to 51% in 2003. The decrease in both day rates and utilization is a direct result of the continued low level of Gulf of Mexico drilling activity.

For our North Sea PSVs and AHTSs, day rates decreased 3% from $11,641 in 2002 to $11,295 in 2003. Utilization also decreased from 89% in 2002 to 82% in 2003. The decrease in both day rates and utilization were results of continued market pressure from competition and low levels of drilling activity.

In contrast, the Company’s crew boats and line handlers experienced increased day rates and utilization in 2003 compared to 2002. Day rates increased 9% from $2,654 in 2002 to $2,897 in 2003, while utilization increased from 67% in 2002 to 74% in 2003. These increases were partly due to the full year effect of several two-year contracts for line handlers entered into during the third quarter of 2002 at increased day rates.

Direct vessel operating expenses decreased 3% from $84.1 million in 2002 to $81.2 million in 2003. The decrease is primarily due to reductions in vessel maintenance and repairs and labor costs during 2003, offset partially by an increase in supplies. The reduction in labor and maintenance costs is a result of an increase in the Norwegian government’s reimbursement of such costs, and the sale of the large North Sea AHTS in 2003.

General and administrative expenses increased 3% from $15.1 million to $15.5 million when comparing 2003 to 2002. The increase in general and administrative expenses are related to increased insurance and professional fees, as well as increased costs associated with the new sales and operations offices in Mexico and Nigeria.

The Company’s depreciation and amortization expense increased $1.5 million or 5% from $31.9 million in 2002 to $33.4 million in 2003. Depreciation and amortization increased when comparing 2003 to 2002 due to the Company recording the first full year of depreciation for two vessels entering the North Sea fleet in 2002.

During 2003, the Company recorded a charge of $6.2 million in association with the sale of one of its larger North Sea vessels, and the sale of its investment in a construction project in Brazil. The expense is classified as a “Loss on assets held for sale” since the Company recorded the charge when the formal plan to sell the assets was committed to.

Also in 2003, the Company recorded two impairment charges to goodwill of $28.6 and $84.4 million during the second and fourth quarters of 2003, respectively. When performing its annual impairment test during the second quarter ended June 2003, the Company determined that an impairment was necessary for its goodwill balance related to the North Sea reporting unit and, to a lesser extent, Brazil. The June 2003 impairment was a result of the continued slowness in the North Sea market, which in turn, devalued the reporting unit. As a result, the Company recorded a charge of $28.6 million in the second quarter of 2003. After continued deterioration in market conditions in the North Sea during the third and fourth quarters of 2003, the Company determined that an additional interim test of impairment was necessary as of December 31, 2003. As a result of the December 2003 analysis, the Company determined that an additional impairment was warranted, and recorded an impairment on the remaining goodwill balance of approximately $84.4 million.

During 2003, the Company sold two crew boats and one supply vessel, which resulted in gains of $1.0 million in the aggregate.

Interest expense increased $1.7 million or 6% as a result of a higher average debt balance, and the full year of expense for the 8.875% senior notes, which were issued in May 2002 to replace the 8.5% senior notes.

The Company recorded a consolidated income tax benefit in 2003 of $2.9 million, which is primarily related to the Company’s Norwegian operations. The Company’s $14.6 million tax expense in 2002 is a result of the deferred tax valuation allowance booked in 2002. The Company has continued to book a full valuation allowance against its U.S. deferred tax assets during 2003.

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Comparison of the Year Ended December 31, 2002 to the Year Ended December 31, 2001

Our revenues in 2002 were $133.9 million, a decrease of 27%, compared to $182.6 million in 2001. The decrease was due primarily to a decrease in day rates and utilization for our Gulf class supply boats and crew boats. The decrease in utilization and day rates of our Gulf class fleet is attributable to decreased Gulf drilling activity.

Our average Gulf class supply boat day rates decreased 21% to $5,575 for 2002, compared to $7,043 for 2001. The average day rates for our fleet of crew boats and line handling vessels decreased 2% to $2,654, compared to $2,714 for 2001.

Utilization for our Gulf class supply boat fleet decreased to 53% in 2002 from 69% in 2001 due to the decrease in offshore drilling activity in the Gulf. Utilization for our crew boats and line handling vessels decreased to 67% in 2002, compared to 78% in 2001, due to the decrease in activity in the Gulf.

Average day rates for our North Sea vessels in 2002 decreased 2% to $11,641 compared to $11,884 for 2001. Vessel utilization was 89% for 2002, compared to 93% for 2001. Two large PSVs were added to our North Sea fleet during 2002.

During 2002, direct vessel operating expenses increased to $84.1 million, compared to $82.1 million for 2001. The direct vessel operating expenses increased as a result of higher North Sea labor costs, higher insurance costs and the addition of two new PSVs during 2002. The higher North Sea labor costs were primarily attributable to the addition of two new PSVs during 2002, required union related pay increases and the strengthening of the Norwegian Kroner against the dollar. The above rate increases were offset in part by reduced U.S. vessel labor and U.S. maintenance costs.

During the fourth quarter of 2002, we recorded a non-cash vessel book value write-down in the amount of $5.2 million. The write-down was taken against the book value of two special purpose towing vessels that have limited capabilities as conventional supply vessels.

Depreciation and amortization expense was $31.9 million in 2002, down from $32.9 million in 2001. Depreciation and amortization in 2001 included $2.6 million of amortization expense associated with goodwill. Pursuant to the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 142, “Goodwill and Other Intangible Assets”, no goodwill amortization expense was recorded in 2002. Amortization of marine inspection costs decreased to $10.2 million in 2002, from $13.4 million in 2001 due to a reduction in dry docking and marine inspection costs.

Our general and administrative expenses increased to $15.1 million in 2002, from $13.6 million for 2001, principally due to increases in insurance, professional fees and the strengthening of the Norwegian Kroner against the dollar. General and administrative expenses, as a percentage of revenues, increased in 2002 due primarily to the decrease in average day rates and utilization for our Gulf class supply boats and crew boats.

Interest expense increased to $28.4 million during 2002, compared to $26.2 million during 2001, due to additional borrowings associated with the construction of the two North Sea PSVs completed in 2002 and additional borrowings and interest costs associated with the refinancing of our senior notes.

We incurred an $11.0 million loss in 2002, which resulted from the early retirement of the Company’s previously issued 8 ¹/2% senior notes and the fourth quarter 2002 refinancing of our revolving credit facility.

Income tax expense in 2002 of $14.5 million is comprised of a $1.7 million income tax expense associated with our North Sea operations and a $12.8 million income tax expense associated with our third quarter of 2002 U.S. deferred tax valuation allowance made pursuant to the provisions under SFAS No. 109, “Accounting for Income Taxes.” In 2001, we had an income tax benefit of $3.3 million and an effective tax rate of 32%. The

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variance from our statutory rate is due to income that was contributed by our Norwegian operations for which taxes were provided at the Norwegian statutory rate of 28%.

Liquidity and Capital Resources

Our on-going capital requirements arise primarily from our need to service debt, maintain or improve equipment and provide working capital to support our operating activities.

Continued low levels of Gulf of Mexico drilling activity have negatively impacted Gulf class vessel utilization and day rates in 2003. North Sea operating results for 2003 also lagged behind the comparable 2002 period. During the third quarter of 2003, the Company completed phase one of its liquidity enhancement plan that was designed to address its near-term financial and liquidity needs. Phase one of the liquidity enhancement plan resulted in the Company entering into a loan agreement providing for a NOK 150 million ($22.5 million) term loan, receiving a $4.5 million federal tax refund as a result of net operating loss carryback claims, and selling a North Sea class vessel and the Brazilian AHTS project for a total of approximately $52.5 million.

Phase two of the Company’s liquidity enhancement plan included amending the Company’s U.S. bank credit facility in an effort to comply with its restrictive covenants, or refinancing the facility. In February 2004, the Company entered into a new $55 million senior secured term loan (the “2004 Term Loan”) which retired and replaced the existing Bank Credit Facility (See Note 7 to the Consolidated Financial Statements, included in Item 8). The 2004 Term Loan eliminates the financial maintenance covenants of the Bank Credit Facility, and is collateralized by 43 Gulf Coast class supply vessels.

In the short-term, we expect a substantial portion of our liquidity to be provided by cash provided by operations, our unrestricted cash, and our NOK Credit Facility. As of February 27, 2004, we had unrestricted cash of $37.6 million and NOK 320 million of borrowing capacity under our NOK Credit Facility. However, we are restricted to NOK 202 million of availability as a result of financial covenants under such facility. With the completion of the 2004 Term Loan, the Company believes that cash provided by operations and current unrestricted cash and availability under its NOK credit facility will be sufficient to fund our debt service requirements, working capital and vessel maintenance expenditures until at least December 31, 2004, barring any unforeseen circumstances. If current activity levels continue in the Gulf of Mexico and the North Sea, it would require us to depend more heavily on our NOK Credit Facility.

In the longer term, our ability to pay debt service and other contractual obligations will depend on improving our future performance and cash flow generation, which in turn will be affected by prevailing economic and industry conditions and financial, business and other factors, many of which are beyond our control. If we have difficulty paying debt service or other contractual obligations in the future, we will be forced to take actions such as reducing or delaying capital expenditures, reducing costs, selling assets, refinancing or restructuring our debt or other obligations and seeking additional equity capital. We may not be able to take any of these actions on satisfactory terms or at all.

As a result of the Company’s operating losses and continued negative market conditions during 2003, on July 25, 2003, Moody’s Investors Service (“Moody’s”) downgraded our long-term senior implied rating to B3 from B1 and lowered our senior unsecured notes’ rating to Caa1 from C2. On January 27, 2004, Moody’s downgraded our long-term senior implied rating to Caa1 from B3 and lowered our senior unsecured notes’ rating to Caa2 from Caa1. On November 24, 2003, Standard & Poor’s Ratings Services (“S&P”), a division of The McGraw-Hill Companies, Inc., downgraded our senior unsecured notes to CCC from CCC+ and placed that credit rating on creditwatch with negative implications. In addition, S&P lowered our corporate rating to B- from B on the same date. On March 11, 2004, S&P downgraded the senior unsecured notes from CCC to CCC- and the corporate rating from B- to CCC+. This downgrade requires the Company to post an additional letter of credit of approximately $1.7 million under the Company’s master bareboat charter agreement. Because of these downgrades, and the potential of one or both rating agencies continuing to downgrade our debt, it is likely that

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we will have difficulty obtaining financing and our cost of obtaining additional financing or refinancing existing debt may be increased significantly.

During 2003, $9.6 million in funds were used in operating activities compared to $7.9 million used in operating activities during 2002. Operating cash flows have remained negative, due primarily to the continued slowness of drilling activity in our market areas. Operating cash flows decreased by $1.7 million primarily due to reduced revenues compared to 2002, offset by a recovery of cash from a reduction of the accounts receivable balance during the year. In 2003, $31.5 million was provided by investing activities, compared with $63.6 million used in investing activities in 2002. The increase of funds in 2003 was the result of the sales of the Brazilian AHTS and a large Norwegian vessel for $52.5 million, accompanied by a $43.4 million reduction of property and equipment purchases during 2003 due to fewer vessel constructions. The sale of vessels and the reduction of new property purchases are a direct result of the Company’s liquidity enhancement plan enacted during 2003. From financing activities, the Company used $6.3 million in 2003 compared to cash provided by financing activities of $47.5 million in 2002. In 2003, the Company repaid current debt maturities as well as retiring a portion of the existing debt with new debt issuances.

The following table summarizes our contractual commitments, as of December 31, 2003, related to the principal amount of our debt (adjusted to reflect subsequent transactions), leases and other arrangements for the periods indicated below (in thousands).

As of December 31, 2003, the Company has approximately $380.2 million of debt outstanding with a weighted average interest rate of 7.2%. Of this amount, approximately $4.8 million is due in 2004. When adjusted to include the effects of the 2004 Term Loan entered into subsequent to December 31, 2003, the current maturities of long term debt increase to $5.2 million and the total debt balance increases to $406.0 million, as reflected in the table above.

The Company’s long term debt is comprised of a combination of senior unsecured notes, credit facilities, and senior secured notes, subject to restrictive covenants. The indenture governing the 8 ⁷/8% Senior Notes contains covenants that, among other things, prevent us from incurring additional debt, paying dividends or making other distributions, unless our ratio of cash flow to interest expense on a rolling twelve month basis is at least 2.0 to 1. Currently we do not meet this ratio and, therefore, are limited under the indenture to incurring at any one time and having outstanding, up to $150.0 million of secured debt after the date of issuance of the notes. In addition, our NOK credit facility contains covenants that require our North Sea reporting unit to maintain certain financial ratios and limit its ability to create liens, or merge or consolidate with other entities.

Approximately 22% of the Company’s total debt is payable in NOK, while 78% is payable in U.S. Dollars (USD). At December 31, 2003, the Company had approximately $265.2 million (or 70%) of fixed rate debt and approximately $115.0 million (or 30%) of variable rate debt. The Company’s fixed interest rates range from 6.08% to 8.875%. The Company’s variable rate debts are indexed based on LIBOR (London Interbank Offered Rate) and NIBOR (Norwegian Interbank Offered Rate), some of which are subject to floors.

The Company has entered into operating leases, primarily as a result of sale-leaseback type transactions. The leases are classified as operating leases due to their relative short duration (10 years) as compared to the expected life of the vessel.

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The Company has issued stand-by letters of credit totaling $6.3 million as of December 31, 2003.

At December 31, 2003, the Company does not have any planned capital expenditures other than approximately $10.5 million to fund the dry docking of vessels and related repairs to be incurred during 2004.

Subsequent to December 31, 2003, the Company entered into a $55 million term loan, the proceeds of which were used primarily to retire its U.S. Credit Facility. As a result of the refinancing, at February 27, 2003, we had approximately $45.7 million in cash, of which $37.6 million was unrestricted. In addition to cash on hand, the Company has NOK 320 million ($45.4 million) of available borrowing capacity under our NOK Credit Facility. The NOK credit facility availability reduces by NOK 40 million every March and September. However, we are restricted to NOK 202 million ($28.7 million) of availability as a result of financial covenants under such facility. In an effort to repatriate funds from Norway to the U.S. in a tax-efficient manner, the Company is undertaking a reduction of its paid-in capital in Trico Supply AS. Upon completion of this reduction, the Company will be able to repatriate NOK 200 million ($28.4 million) for working capital and other corporate purposes. The Company believes that the reduction of its paid-in capital process will be completed by June 30, 2004.

We cannot make any assurances, however, that the factors beyond our control affecting demand for our vessels will not impact our ability to generate sufficient cash flow from operations, or obtain borrowings under our credit facilities, in an amount sufficient to enable us to pay our indebtedness and fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness on or before maturity. We cannot assure you that we will be able to refinance any of our indebtedness, including existing and subsequent facilities, on commercially reasonable terms or at all.

Critical Accounting Policies

Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. On an on-going basis, we evaluate our estimates, including those related to bad debts, fixed assets, deferred expenses, inventories, goodwill, income taxes, pension liabilities, contingencies and litigation. We base our estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.

We consider certain accounting policies to be critical policies due to the significant judgement, estimation processes and uncertainty involved for each in the preparation of our consolidated financial statements. We believe the following represent our critical accounting policies.

Impairment of long-lived assets other than goodwill.    In accordance with the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long Lived Assets,” we review long-lived assets for impairment when events or changes in circumstances indicate that the carrying amount of any such asset may not be recoverable. We record impairment losses on long-lived assets used in operations when the net discounted cash flows estimated to be generated by those assets are less than the carrying amount of those items. Our cash flow estimates are based upon historical results adjusted to reflect our best estimate of future market rates, utilization, operating performance and other factors. Our estimates of cash flows may differ from actual cash flows due to changes in economic conditions or changes in an asset’s operating performance, among other things. If the undiscounted value of the cash flows is less than the carrying value, we recognize an impairment loss, measured as the amount by which the carrying value exceeds the net discounted cash flow. No impairments were determined as a result of the 2003 FAS No. 144 analysis. During the year ended December 31, 2002, we recognized $5.2 million of fixed asset impairments. While we believe that our estimates of future cash flows are reasonable, different assumptions regarding future market rates, utilization and operating performance could materially affect our evaluations. If market conditions were to decline in any markets in which the Company operates, it could require the Company to evaluate the recoverability of its long-lived assets in that market.

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Impairment of goodwill.    At the beginning of 2003, the Company’s goodwill balance of $110.6 million related primarily to the 1997 acquisition of our North Sea operations, which is considered a reporting unit pursuant to the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets.” The Company tests for the possible impairment of goodwill at the reporting unit level in accordance with the requirements of SFAS No. 142. In assessing reporting unit fair value, we must make assumptions regarding estimated future cash flows and other factors used to determine fair value. If these estimates or their related assumptions adversely change in the future, we may be required to record material impairment charges for these assets. Annually or when market conditions necessitate interim analysis, the Company calculates reporting unit fair value based on estimated cash flows, comparable industry financial ratios and other analysis. The reporting unit fair value is compared to carrying value to determine whether the goodwill is impaired. The Company performed its annual impairment analysis as of June 30, 2003 and determined that a goodwill impairment did exist. Therefore, the Company recorded a charge of approximately $28.6 million during the second quarter of 2003. After continued deterioration in market conditions in the North Sea during the third and fourth quarters of 2003, the Company determined that an additional interim test of impairment was necessary as of December 31, 2003. As a result of the December 2003 analysis, the Company determined that an additional impairment was warranted, and recorded an impairment on the remaining goodwill balance of approximately $84.4 million.

Deferred Tax Valuation Allowance.    Income taxes are determined in accordance with SFAS No. 109, “Accounting for Income Taxes,” which requires recognition of deferred income tax liabilities and assets for the expected future tax consequences of events that have been included in the consolidated financial statements or tax returns. Under this method, deferred income tax liabilities and assets are determined based on the difference between the financial statement and tax bases of liabilities and assets using enacted tax rates in effect for the year in which the differences are expected to reverse. SFAS 109 also provides for the recognition of deferred tax assets if it is more likely than not that the assets will be realized in future years. A valuation allowance of $22.7 million was established in the third quarter of 2002 associated with the U.S. deferred tax asset. The Company has continued to book a full valuation allowance against all U.S. net operating losses since the establishment of the allowance in 2002.

Deferred marine inspection costs.    We record the cost of major scheduled drydocking inspection costs for our vessels as deferred charges. We amortize these deferred charges over the expected periods of benefit, typically ranging from two to five years. See “New Accounting Standards” below for more discussion on proposed accounting changes for deferred marine inspection costs.

New Accounting Standards

In January 2003, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 46 (“FIN 46”), “Consolidation of Variable Interest Entities.” FIN 46 clarifies the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements,” to 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. The FASB subsequently revised FIN 46 with FIN 46R. FIN 46 and FIN 46R apply immediately to variable interest entities created after January 31, 2003, and to variable interest entities in which an enterprise obtains an interest after that date. The statements apply in the first fiscal year or interim period ending after March 15, 2004, to variable interest entities in which an enterprise holds a variable interest that it acquired before February 1, 2003. The Company believes that the adoption of the provisions of FIN 46 will have no impact upon its financial position or results of operations.

In June 2001, the Accounting Standards Executive Committee of the AICPA, (“AcSEC”), issued an exposure draft of a proposed Statement of Position (“SOP”), “Accounting for Certain Costs and Activities Related to Property, Plant, and Equipment.” This SOP provides guidance on accounting for certain costs and activities relating to property, plant, and equipment (“PP&E”). For purposes of this SOP, a project stage or timeline framework is used and PP&E assets are accounted for at a component level. Costs incurred for PP&E are classified into four stages: preliminary, preacquisition, acquisition-or-construction and in-service. The SOP requires, among other things, that preliminary, preacquisition and acquisition-or-construction stage costs, except for payments to obtain an

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option to acquire PP&E, should be charged to expense as incurred. Costs related to PP&E that are incurred during the in-service stage, including costs of normal, recurring, or periodic repairs and maintenance activities, should be charged to expense as incurred unless the costs are incurred for acquisition of additional PP&E or components of PP&E or the replacement of existing PP&E or components of PP&E. Costs of planned major maintenance activities would be charged to expense, except for acquisitions or replacements of components that are capitalizable under the in-service stage guidance of this SOP. In September 2003, the AcSEC approved the SOP for issuance to the FASB for final clearance, which is expected in the second quarter of 2004. If the proposed SOP is adopted in its current form, the Company will have to expense its currently capitalized deferred marine inspection costs, which totaled approximately $20.8 million at December 31, 2003. This write-off would be accounted for as a cumulative effect of a change in accounting principle as of the beginning of the year of adoption. This SOP, if approved, is scheduled to become effective for fiscal periods beginning after December 15, 2004. Further evaluation is required by the Company to fully quantify the impact of this proposed pronouncement, if adopted.

In December 2003, the FASB issued a revised version of SFAS No. 132. This revised statement adds to the annual disclosures about pensions and other postretirement benefits that were required by the original statement issued in 1997. The revised statement also requires certain interim disclosures. Both the original and the revised statements address disclosure only and do not address accounting, measurement or recognition for benefit obligations. With certain limited exceptions, the added annual disclosures were effective as of December 31, 2003 for the Company and are included in Note 13 of the Consolidated Financial Statements in Item 8. The Company is required to present the interim disclosures beginning with its quarter ending March 31, 2004.

Item 7A.    Quantitative and Qualitative Disclosures About Market Risk

Our market risk exposures primarily include interest rate and exchange rate fluctuations on derivative and financial instruments as detailed below. Our market risk sensitive instruments are classified as “other than trading.” The following sections address the significant market risks associated with our financial activities during 2003. The Company’s exposure to market risk as discussed below includes “forward-looking statements” and represents estimates of possible changes in fair values, future earnings or cash flows that would occur assuming hypothetical future movements in foreign currency exchange rates or interest rates. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated, based upon actual fluctuations in foreign currency exchange rates, interest rates and the timing of transactions.

Interest Rate Sensitivity

We have entered into a number of variable and fixed rate debt obligations, denominated in both the U.S. Dollar and the Norwegian Kroner (Norwegian debt payable in Norwegian Kroner), as detailed in Note 7 to our consolidated financial statements in Item 8. These instruments are subject to interest rate risk.

As of December 31, 2003 and 2002, we had $115.0 and $116.6 million, respectively, in variable rate debt. As of December 31, 2003 and 2002, the carrying value of our long-term variable rate debt, including accrued interest, was approximately $115.6 and $117.5 million, respectively, which included our U.S. and Norwegian bank credit facilities. The fair value of this debt approximates the carrying value because the interest rates are based on floating rates identified by reference to market rates. A hypothetical 1% increase in the applicable interest rates as of December 31, 2003 and 2002 would increase annual interest expense by approximately $1.15 and $1.17 million, respectively.

As of December 31, 2003, the carrying value of our long-term fixed rate debt, including accrued interest, was $268.2 million, which included our 8.875% senior notes ($251.0 million), 6.08% MARAD bonds ($3.8 million), and 6.11% MARAD bonds ($13.4 million). As of December 31, 2002, the carrying value of our long-term fixed rate debt, including accrued interest, was $270.6 million. The fair value of our long-term fixed rate debt as of December 31, 2003 and 2002 was approximately $198.6 million and $255.2 million, respectively. Fair value was determined using discounted future cash flows based on quoted market prices, where available, on our

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current incremental borrowing rates for similar types of borrowing arrangements as of the balance sheet dates. A hypothetical 1% increase in the applicable interest rates would decrease the fair value of our long-term fixed rate debt as of December 31, 2003 and 2002 by approximately $15.3 million and $17.9 million, respectively. The hypothetical fair values are based on the same assumptions utilized in computing fair values.

Foreign Currency Exchange Rate Sensitivity

The Company has substantial operations located outside the United States (principally the North Sea and Brazil) for which the functional currency is not the U.S. Dollar. As a result, the reported amount of the Company’s assets and liabilities related to its non-U.S. operations and, therefore, the Company’s consolidated financial statements, will fluctuate based upon changes in currency exchange rates.

We manage foreign currency risk by attempting to contract as much foreign revenue as possible in U.S. Dollars. To the extent that our foreign subsidiaries revenues are denominated in U.S. Dollars, changes in foreign currency exchange rates impact our earnings. This is somewhat mitigated by the amount of foreign subsidiary expenses that are also denominated in U.S. Dollars. In order to further mitigate this risk, we may utilize foreign currency forward contracts to better match the currency of our revenues and associated costs. We do not use foreign currency forward contracts for trading or speculative purposes. The counterparties to these contracts are major financial institutions, which minimizes counterparty credit risk.

During 2003, in conjunction with the sale of the Company’s large North Sea vessel described in Note 3 of the consolidated financial statements in Item 8, the Company entered into a series of foreign currency forward contracts with notional amounts of $24.0 million to fix the currency exchange rates between Norwegian Kroner and U.S. Dollars. As a result of the hedge, the Company recorded a net transaction gain during 2003 of $0.6 million, which is included in other income (loss) in the consolidated statement of operations. There were no foreign exchange contracts outstanding as of December 31, 2003.

In accordance with SFAS No. 52, “Foreign Currency Translation,” all assets and liabilities of the Company’s foreign subsidiaries are translated into U.S. Dollars at the exchange rate in effect at the end of the period, and revenues and expenses are translated at average exchange rates prevailing during the period. The resulting translation adjustments are reflected in a separate component of stockholders’ equity. We recorded $10.6 million and $71.5 million adjustments to our other comprehensive income account for the years ended December 31, 2003 and 2002 as a result of the net increase in the value of the NOK and other currencies against the U.S. dollar. In 2001, we recorded a $(1.0) million adjustment to other comprehensive income as a result of the net decrease in the value of foreign currencies against the U.S. dollar.

As described above, at December 31, 2003, 2002, and 2001, the Company had the equivalent of $84.6 million, $94.1 million, and $35.3 million, respectively, of outstanding NOK-denominated indebtedness, including accrued interest. The potential increase in the U.S. Dollar equivalent of the principal amount outstanding resulting from a hypothetical 10% adverse change in exchange rates at such date would be approximately $9.3 million, $10.5 million, and $3.9 million at December 31, 2003, 2002, and 2001, respectively.

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Item 8.    Financial Statements and Supplementary Data

Index to Consolidated Financial Statements

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REPORT OF INDEPENDENT AUDITORS

To the Board of Directors and

Stockholders of Trico Marine Services, Inc.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, stockholders’ equity and cash flows present fairly, in all material respects, the financial position of Trico Marine Services, Inc. and Subsidiaries (the “Company”) as of December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. 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 of these statements in accordance with auditing standards generally accepted in the United States of America, which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 5 to the consolidated financial statements, the Company changed the manner in which it accounts for goodwill and other intangible assets as of January 1, 2002.

/s/ PricewaterhouseCoopers LLP

New Orleans, Louisiana

March 11, 2004

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TRICO MARINE SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

as of December 31, 2003 and 2002

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

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TRICO MARINE SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

for the years ended December 31, 2003, 2002 and 2001

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

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TRICO MARINE SERVICES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

for the years ended December 31, 2003, 2002 and 2001