HORNBECK OFFSHORE SERVICES INC /LA - 10-K Annual Report

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

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

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

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 ¨ No x

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 the Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. Yes ¨ No ¨ NOT APPLICABLE.

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

The aggregate market value of common stock, par value $.01 per share, held by non-affiliates of the Registrant is not ascertainable as such stock is privately held and there is no public market for such stock. The total number of shares of the Registrant’s common stock, par value $.01 per share, outstanding as of March 5, 2004 was 14,527,814 (after giving effect to a 1-for-2.5 reverse stock split effective on such date)

Hornbeck Offshore Services, Inc. was incorporated under the laws of the State of Delaware in 1997. In this annual report on Form 10-K, “company,” “we,” “us” and “our” refers to Hornbeck Offshore Services, Inc. and its subsidiaries, except as otherwise indicated. References in this annual report on Form 10-K to “OSVs” mean offshore supply vessels; to “deepwater” mean offshore areas, generally 1,000’ to 5,000’ in depth, and ultra-deepwater areas, generally more than 5,000’ in depth; to “deep well” mean a well drilled to a true vertical depth of 15,000’ or greater; and to “new generation,” when referring to OSVs, mean modern, deepwater-capable vessels subject to the regulations promulgated under the International Convention on Tonnage Measurement of Ships, 1969, which was adopted by the United States and made effective for all U.S.-flagged vessels in 1992.

We are a leading provider of technologically advanced, new generation OSVs serving the offshore oil and gas industry, primarily in the U.S. Gulf of Mexico and in select international markets. The focus of our OSV business is on complex exploration and production activities, which include deepwater, deep well and other logistically demanding projects. We are also a leading transporter of petroleum products through our tug and tank barge segment serving the energy industry, primarily in the northeastern United States and Puerto Rico.

In the mid-1990s, oil and gas producers began seeking large hydrocarbon reserves at deeper well depths using new, specialized drilling and production equipment. We recognized that the existing fleet of conventional 180’ OSVs operating in the U.S. Gulf of Mexico was not designed to support these more complex projects or to operate in the challenging environments in which they were conducted. Therefore, in 1997, we began a program to construct new generation OSVs based upon the proprietary designs of our in-house team of naval architects. Since that time, we have constructed 17 new generation OSVs using these proprietary designs, and expanded our fleet with the acquisitions of a total of six additional new generation OSVs. Our fleet of 23 OSVs is among the youngest fleets in the industry with an average age of approximately three years.

Our OSVs were purposefully designed with the flexibility to meet the diverse needs of our clients in all stages of their exploration and production activities. As a result, all of our OSVs have enhanced capabilities that allow them to more effectively support premium drilling equipment required for deep drilling and related specialty services. In contrast to conventional 180’ OSVs, our vessels have dynamic positioning capability, as well as greater storage and off-loading capacity. We are capable of providing OSV services to our customers anywhere in the world and we are actively pursuing additional contracts in select international markets.

Historically, demand for our OSV services has been primarily driven by the drilling of deep wells, whether in the deepwater or on the U.S. Continental Shelf, and other complex exploration and production projects that require specialized drilling and production equipment. In addition, our new generation OSVs are increasingly in demand by our customers for conventional drilling projects. Customers on such projects are willing to pay more than the prevailing dayrates for conventional 180’ OSVs because of the ability of our OSVs to reduce overall offshore logistics costs for the customer through the vessels’ greater capacities and operating efficiencies.

According to the Minerals Management Service, or MMS, in 2002 the deepwater region accounted for 68% of total U.S. Gulf of Mexico oil production and 38% of total U.S. Gulf of Mexico natural gas production, up substantially from 4% and 1%, respectively, in 1990. In addition, the MMS estimates that deep reservoirs on the Continental Shelf may hold up to 55 tcf of undiscovered natural gas. This potential reserve base compares favorably to the current total of approximately 26 tcf of proven natural gas reserves in the entire U.S. Gulf of Mexico. Our new generation OSVs are also well suited for drilling in logistically demanding projects and frontier areas, where support infrastructure is severely limited.

Our tug and tank barge fleet consists of 12 ocean-going tugs, 16 ocean-going tank barges and one coastwise tanker. We believe our tug and tank barge business complements our OSV business by providing additional revenue and geographic diversification, while allowing us to offer another line of services to integrated oil and gas companies. Demand for our tug and tank barge services is primarily driven by the level of refined petroleum product consumption in the northeastern United States and Puerto Rico, our core operating markets. The Energy Information Administration, or EIA, projects that refined petroleum product consumption in the East Coast region of the United States will increase by an average of 1.7% per year from 2002 to 2010. Demand for refined petroleum products is primarily driven by population growth, the strength of the U.S. economy, seasonal weather patterns, oil prices and competition from alternate energy sources.

OSVs primarily serve exploratory and developmental drilling rigs and production facilities and support offshore construction and subsea maintenance activities. OSVs differ from other types of marine vessels in their cargo carrying flexibility and capacity. In addition to transporting deck cargo, such as pipe or drummed material and equipment, OSVs also transport liquid mud, potable and drilling water, diesel fuel, dry bulk cement and personnel between shore bases and offshore rigs and facilities. In general, demand for OSVs, as evidenced by dayrates and utilization rates, is primarily related to offshore oil and natural gas exploration, development and production activity, which in turn is influenced by a number of factors, including oil and natural gas prices and the drilling budgets of offshore exploration and production companies.

OSVs operate worldwide, but are generally concentrated in relatively few offshore regions with high levels of exploration and development activity such as the Gulf of Mexico, the North Sea, Southeast Asia, West Africa, Brazil and the Middle East. While there is some vessel migration between regions, key factors such as mobilization costs, vessel suitability and government statutes prohibiting foreign-flagged vessels from operating in certain waters generally limit such migration.

The U.S. Gulf of Mexico is a critical oil and natural gas supply basin for the United States, accounting for 30% and 25%, respectively, of total U.S. oil and natural gas production in 2002. Offshore oil and natural gas drilling and production in the U.S. Gulf of Mexico occurs on the Continental Shelf and in the deepwater. Drilling activity on the Continental Shelf has historically been limited to shallow wells, or wells with true vertical depths of less than 15,000’. More recently, however, operators have begun to increasingly focus exploratory efforts on deep wells and natural gas reserves located below 15,000’. These deep prospects are largely undeveloped, but are believed to contain significant reserves.

While the shallow waters of the Continental Shelf have been actively explored for decades, relatively few deep wells have been drilled historically due to the high cost associated with these wells. The dry hole cost of a typical Continental Shelf well drilled from 8,000’ to 12,000’ generally ranges from $4 million to $8 million, while the dry hole cost for a deep well drilled in a similar location but to 15,000’ or more can range from $10 million to $25 million. The higher costs associated with the drilling of deep wells can be attributed to, among other things, the need for specialized, high-end drilling rigs and related equipment, greater volumes of downhole materials such as liquid mud, tubular products and cement, and longer drilling times.

Despite the higher costs associated with deep well Continental Shelf drilling, operators, especially those in search of natural gas, have continued to demonstrate interest. This interest is driven by, among other things, the potential for the discovery of significant natural gas reserves. The MMS estimates that there may be up to 55 tcf of undiscovered, conventionally recoverable, deep well natural gas on the Continental Shelf. Moreover, the abundance of existing platforms, production facilities and pipelines on the Continental Shelf allow new deep gas to flow quickly to market. In addition, MMS data indicates that higher natural gas production rates can be expected from wells drilled on the Continental Shelf below 16,000’. Furthermore, the MMS royalty relief programs enacted in 2001, and expanded in August 2003 and again in January 2004, have stimulated interest by reducing the development costs of these deep wells. The combination of these factors partly compensates for the higher drilling costs of deep wells on the Continental Shelf and can allow operators to commercially produce discovered reserves in this market. While drilling on the Continental Shelf has declined, gas production data from 2000 to 2003 provided by IHS Energy, an energy research company, suggests an

increasing focus on deep wells on the Continental Shelf. From 2000 to 2003, gas production from deep wells as a percentage of total wells on the Continental Shelf increased from 22% to 30%.

Recent discoveries of large hydrocarbon reserves in deepwater fields in the Gulf of Mexico and at deeper well depths on the Continental Shelf have resulted in increased developmental and exploratory drilling activities in these areas. The deepwater region of the U.S. Gulf of Mexico is an increasingly important source of oil and natural gas production with many unexplored areas of potential oil and natural gas reserves. According to the 2004 Deepwater and Ultra Deepwater Report of Infield Systems Limited, an international energy research firm, the U.S. Gulf of Mexico had 58 deepwater projects developed between 1999 and 2003, and an additional 79 deepwater projects have been identified for development between 2004 and 2008.

Because oil and natural gas exploration, development and production costs in the shallow well Continental Shelf market are generally lower than those in the deepwater or deep well environments, shallow well drilling activity on the Continental Shelf is typically more sensitive to fluctuations in commodity prices, particularly the price of natural gas. Accordingly, actual or anticipated decreases in oil and natural gas prices generally result in reduced offshore drilling activity and correspondingly lower demand for the conventional 180’ OSVs serving the shallow well Continental Shelf market. This causes a corresponding decline in OSV dayrates and utilization rates in that market. In contrast, the relatively larger capital commitments and longer lead times and investment horizons associated with deepwater, particularly ultra-deepwater, and deep well developments make it less likely that an operator will abandon such projects in response to a short-term decline in oil or natural gas prices. Dayrates and utilization rates for new generation OSVs that serve the deepwater and deep well markets are, therefore, generally less sensitive to short-term commodity price fluctuations and tend to be more stable than dayrates and utilization rates for OSVs serving the shallow well Continental Shelf market.

According to our analysis of the industry and data compiled from various industry sources, including the U.S. Coast Guard, we estimate that the U.S.-flagged OSV fleet currently totals 353 vessels, substantially all of which are located in the Gulf of Mexico. Of this total, 246, or 70% are conventional 180’ OSVs that primarily operate on the Continental Shelf. The remaining 107 vessels are new generation OSVs that primarily operate in the deepwater Gulf of Mexico. However, during soft market conditions in the deepwater, these modern vessels have increasingly migrated at premium dayrates to conventional drilling environments, such as the U.S. Continental Shelf, Mexico and Trinidad & Tobago. Of the conventional OSV fleet, a significant number are currently cold-stacked. Vessels that are cold-stacked have generally been removed from active service by the operator due to lack of demand. In contrast, we believe there are currently no new generation OSVs cold-stacked.

Complex exploration and production projects require specialized equipment and higher volumes of supplies to meet the more difficult operating environment associated with such offshore developments. In order to better serve these projects and meet customer demands, new generation OSVs, including our entire OSV fleet, are designed with larger capacities, including greater liquid mud and dry bulk cement capacities, as well as larger areas of open deck space than conventional 180’ OSVs. These features are essential to the effective servicing of deepwater drilling projects, which are often distant from shore-based support infrastructure, because they allow a vessel to make fewer trips to supply the liquid mud, drilling water, dry bulk cement and other needs of the customer. In addition, OSVs operating in deepwater environments generally require dynamic positioning, or anchorless station-keeping capability, primarily because customers’ safety procedures preclude OSVs from tying up to deepwater installations, and to enable continued operation in adverse weather conditions. We believe that conventional 180’ OSVs, substantially all of which lack dynamic positioning capability and sufficient on-deck or below-deck cargo capacity, are not capable of operating effectively or economically in the deepwater market. In addition, certain ports have draft or other logistical impediments, which limit the pool of new generation vessels capable of servicing such ports. Our proprietary vessels were designed to work under these shallow draft and logistically demanding conditions.

As a result of recent deepwater and deep well drilling activity, utilization rates for new generation OSVs in the U.S. Gulf of Mexico have averaged approximately 95% over the last two years while the average utilization rate for the conventional 180’ OSV fleet over the same period has been approximately 73%. Additional utilization for new generation OSVs has come from increasing demand for these vessels in support of conventional shelf drilling projects. Moreover, during the same two-year period, average dayrates for new generation OSVs were generally more than double the average dayrates

of conventional 180’ OSVs. Given the recent and expected deepwater and deep well activity, we believe that the supply of new generation OSVs, including vessels currently available and vessels being constructed under announced construction plans, is more than sufficient to meet the current and near term demand for such vessels. Long-term projections of deepwater and deep well activity, however, indicate a potential shortage of new generation OSVs. Furthermore, although U.S.-flagged vessels operating in overseas locations may be remobilized to the U.S. Gulf of Mexico, historically such remobilization has been limited.

We currently own and operate a fleet of 23 new generation OSVs. Our in-house engineering team, using our proprietary designs, built 17 of our OSVs expressly to meet the demands of deepwater regions and other complex drilling projects. Our in-house engineering team possesses significant vessel operating experience. Drawing from this experience, we work closely with potential charterers to design vessels specifically to meet their anticipated needs. This is particularly the case when the charterer will operate a project that could have a duration of more than 20 years and require expenditures exceeding $1 billion. All of our vessels have up to three times the dry bulk capacity and deck space, two to ten times the liquid mud capacity and two to four times the deck tonnage compared to conventional 180’ OSVs. The advanced cargo handling systems of our 17 proprietary OSVs allow for dry bulk and liquid cargos to be loaded and unloaded three times faster than conventional 180’ OSVs, while the solid state controls of their engines typically result in a 20% greater fuel efficiency than vessels powered by conventional engines. In addition, our larger classes of proprietary OSV designs, designated by us as our 240 ED and 265 classes, were designed, in part, to supply the substantially greater liquid mud volume and other cargo capacity required for ultra-deepwater drilling. We believe that the customers’ recognition of the superior capabilities of our proprietary OSVs has contributed to our ability to achieve higher dayrates and utilization rates and increased overall operating cost efficiencies than our competitors.

All of our new generation OSVs are equipped with dynamic positioning systems and controllable pitch thrusters, which allow our vessels to maintain position within minimal variance, and state-of-the-art safety, emergency power, fire alarm and fire suppression systems and systems monitoring equipment. The unique hull design and integrated rudder and thruster system of our 17 proprietary OSVs provide for a more maneuverable vessel. These proprietary vessels also have double-bottomed and double-sided hulls that minimize environmental impact in the event of vessel collisions or groundings, solid state controls that minimize visible soot and polluting gases and zero discharge sewage and waste systems that minimize the impact on marine environments. In addition, these 17 vessels are either fully SOLAS (Safety of Life at Sea) certified or SOLAS ready. SOLAS is the international convention that regulates the technical characteristics of vessels for purposes of ensuring international standards of safety for vessels engaged in commerce between international ports. These features allow us to market our proprietary OSVs for service in international waters.

Our technologically advanced, new generation OSVs are also capable of providing specialty services in support of certain of our customers, including well stimulation, remotely operated vehicles, or ROVs, used in oilfield subsea construction and maintenance, underwater inspections, marine seismic operations, and certain non-energy applications such as fiber optics cable installation, military work and containerized cargo transportation. Compared to conventional 180’ OSVs, our OSVs have more dead weight capacity, deck space, and berthing accommodations, improved maneuverability and greater fuel efficiency. We believe these characteristics strengthen demand for our OSVs in specialty situations. Two of our vessels, the HOS Innovator and the HOS Dominator, currently provide ROV subsea construction and maintenance support for a large oilfield service company under contracts that each have an initial term of three years. The BJ Blue Ray provides deepwater well stimulation support services for another large oilfield service company under a contract with a five-year initial term. This vessel was the first U.S.-flagged well stimulation vessel to receive the American Bureau of Shipping WS and DPS2 class notations. We believe the BJ Blue Ray is one of the most technologically sophisticated well stimulation vessels in the world.

On June 26, 2003, we completed the acquisition of five 220’ new generation OSVs from Candy Marine Investment Corporation, an affiliate of Candy Fleet Corporation, or Candy Fleet. Following the completion in July 2003 of a private placement of our common stock and satisfaction of certain other conditions, on August 6, 2003 we acquired an additional 220’ new generation OSV from Candy Fleet. These six vessels complement our existing OSV fleet and have allowed us to expand our service offerings to clients, particularly those drilling wells on the Continental Shelf.

The following table provides information, as of March 1, 2004, regarding our existing fleet of OSVs.

We have designed and constructed five distinct classes of proprietary OSVs and added a sixth class, through the acquisitions of six OSVs from Candy Fleet, to meet the diverse needs of the offshore oil and gas industry. The following table provides a comparison of certain specifications and capabilities of our new generation OSVs to conventional 180’ OSVs.

Introduction. The domestic tank barge industry provides marine transportation of crude oil, petroleum products and petrochemicals by tug and tank barge, and is a critical link in the U.S. petroleum distribution chain. Petroleum products are transported in the northeastern United States through a vast network of terminals, tankers and pipelines. We believe, based upon our analysis of the industry, that in the northeastern United States approximately 430 million barrels of petroleum products are transported annually by tank barges. Additionally, the EIA estimates that in Puerto Rico, our other core area of operation, approximately 70 million barrels of petroleum products are transported annually.

Demand for tug and tank barge services in the northeastern United States is primarily driven by population growth, the strength of the U.S. economy, seasonal weather patterns, oil prices and competition from alternate energy sources. According to the EIA, demand for petroleum products in the northeastern United States is expected to increase approximately 1.7% annually through 2010, which we believe will generate steadily increasing demand for the tank barge industry.

The largest single tank barge market in the northeastern United States is New York Harbor. Imported petroleum products are primarily delivered to New York Harbor as it has the capacity to receive products in cargo lots of 50,000 tons or more per tanker. By contrast, draft limitations in most New England ports and drawbridge limitations in Boston and Portland, Maine limit the average cargo carrying capacity of direct imports into many of the largest New England ports to about 30,000 tons per tanker. As a result, ships importing directly into New England must frequently discharge in multiple ports or terminals or transfer cargos to tank barges. As existing single-hulled tankers are retired due to age or as mandated under the Oil Pollution Act of 1990, or OPA 90, they are typically replaced by larger tankers. These larger-sized tankers are being built to facilitate the importation of crude oil and petroleum products into the United States. The volume of imported crude oil and petroleum products is expected to grow at a compound annual rate of 2.4% through 2025, according to the EIA. As larger petroleum tankers are being built, we believe that direct delivery into New York Harbor will

generate increased tank barge demand for lightering services and further shipment to New England, the Hudson River and Long Island.

Oil Pollution Act of 1990. OPA 90 mandates that all single-hulled tank vessels operating in U.S. waters be removed from service according to a time schedule. Data provided by a U.S. Coast Guard report dated September 2001 indicates that 5.5 million barrels of single-hulled tank barge capacity would need to be retired by 2005 and an additional 3.5 million barrels by 2010, as mandated by OPA 90. According to the report, this represented on a cumulative basis as of each such retirement date, 22% and 36%, respectively, of the total 24.9 million barrel single- and double-hulled tank barge capacity that existed in 2001. The following chart illustrates the capacity of tank vessels that must be removed from service from 2000 through 2014. We believe that, absent a substantial increase in the number of double-hulled vessels constructed in the industry, this reduction in capacity, assuming steady demand, may favorably impact dayrates and utilization of the remaining tank barges, including our own.

Based on data contained in the United States Coast Guard Report to Congress on the Progress to Replace Single Hull Tank

Additionally, OPA 90 requires that owners or operators of tankers operating in U.S. waters submit vessel spill response plans to the U.S. Coast Guard for approval and operate according to the plans upon approval. Our vessel response plans have been approved by the U.S. Coast Guard, and all of our crew members have been trained to comply with these guidelines. For further discussion of OPA 90 see “—Environmental and Other Governmental Regulation” below.

We provide marine transportation, distribution and logistics services in the northeastern United States, Puerto Rico and the U.S. Gulf of Mexico with our fleet of 12 ocean-going tugs and 16 ocean-going tank barges. We provide our services to major oil companies, refineries and oil traders. Generally, a tug and tank barge work together as a “tow” to transport refined or bunker grade petroleum products. Our tank barges carry petroleum products that are typically characterized as either “clean” or “dirty.” Clean products are primarily gasoline, home heating oil, diesel fuel and jet fuel. Dirty products are mainly crude oils, residual crudes and feedstocks, heavy fuel oils and asphalts. Our tugs and tank barges serve the northeastern U.S. coast, primarily New York Harbor, by transporting both clean and dirty petroleum products to and from refineries and distribution terminals.

Our tugs and tank barges also transport both clean and dirty petroleum products from refineries and distribution terminals in Puerto Rico to the Puerto Rico Electric Power Authority and to utilities located on other Caribbean islands. In

addition, we provide ship lightering, bunkering and docking services in these markets and are well positioned to provide such services to the increasing number of new tankers that are too large to make direct deliveries to distribution terminals and refineries.

On May 31, 2001, we acquired nine ocean-going tugs and nine ocean-going tank barges from the Spentonbush/Red Star Group, composed of certain affiliates of Amerada Hess, as well as the business related to these tugs and tank barges, greatly expanding our capacity in the northeastern United States and increasing our market share of the coastwise trade on the U.S. upper east coast. As part of the acquisition, Amerada Hess entered into a long-term contract of affreightment with us pursuant to which Amerada Hess has committed to use us as its exclusive marine logistics provider and transporter of liquid petroleum products by tank barge in the northeastern United States. Under this contract, Amerada Hess has committed to ship a minimum of 45 million barrels annually for an initial period from June 1, 2001 through March 31, 2006 with options to renew for subsequent periods by mutual agreement. Also under the contract, we have the opportunity, on a reasonable commercial efforts basis, to coordinate the marine logistics for Amerada Hess in the southeastern United States, subject to Amerada Hess’s right to cancel within 30 days after December 31 of each year of the contract. The contract of affreightment will provide us with a significant source of revenues over the life of the contract. Our contract of affreightment allows Amerada Hess to reduce its minimum annual cargo volume commitment subject to significant adjustment penalties. Because the tank barge market in the northeastern United States is currently operating at or near capacity, we believe that we would be able to replace through other customers any volumes that Amerada Hess does not transport as contemplated by the contract.

One of our tank barges is double-hulled and is not subject to OPA 90 retirement dates. Ten of our 15 single-hulled tank barges are not required under OPA 90 to be retired or double-hulled until 2015. Of our remaining five single-hulled tank barges, three are required to be retired or modified before 2005 and two in 2009. In recognition of their upcoming retirements, we have recently commenced construction of two double-hulled, ocean-going tank barges that are expected to be delivered in December 2004 and we are evaluating plans for the construction or retrofit of a third tank barge. Our coastwise tanker is not subject to OPA 90 retirement dates. Based on the remaining lives of the majority of our tank barge fleet under OPA 90, we believe we are well positioned to obtain additional customers in the northeastern United States, as a large portion of currently available capacity in that market is required to be removed from service or be substantially reconstructed by 2005.

The following tables provide information, as of March 1, 2004, regarding the tugs, tank barges and the coastwise tanker we own and the two double-hulled tank barges currently under construction.

Technologically Advanced Fleet of New Generation OSVs. Our technologically advanced, new generation OSVs were designed with the specifications necessary for operations in complex and challenging drilling environments, including deepwater, deep well and other logistically demanding projects. Our new generation OSVs have significantly more capacity and operate more efficiently than conventional 180’ OSVs. While operators are especially concerned with a vessel’s ability to avoid collisions with multi-million dollar drilling rigs or production platforms during adverse weather conditions, they are hesitant to stop operations under such conditions due to the high daily cost of halting such complex operations. Our proprietary vessels incorporate sophisticated technologies and are designed specifically to operate safely in complex exploration and production environments. These technologies include dynamic positioning, roll reduction systems and controllable pitch thrusters, which allow our vessels to maintain position with minimal variance, and our unique cargo handling systems, which permit high volume transfer rates of liquid mud and dry bulk. We believe that we earn higher average dayrates and maintain higher utilization rates than our competitors due to the superior capabilities of our OSVs, our six-year track record of safe and reliable performance and the collaborative efforts of our in-house design team in providing marine engineering solutions to our customers.

Young OSV Fleet with Lower Cost of Ownership. We believe that we operate the youngest fleet of U.S.-flagged OSVs. While the average age of the conventional 180’ U.S.-flagged OSV fleet is approximately 24 years, the average age of our OSV fleet is approximately three years. Newer vessels generally experience less downtime and require significantly less maintenance and scheduled drydocking costs compared to older vessels. The average intermediate drydocking for

recertification for one of our OSVs generally lasts five to ten days in the shipyard and costs approximately $0.3 million. In contrast, the typical drydocking for recertification of a conventional 180’ OSV may last up to 90 days in the shipyard and can cost as much as $1.5 million. We believe that our operation of new, technologically advanced OSVs gives us a competitive advantage in obtaining long-term contracts for our vessels and in attracting and retaining crews. Since we accepted delivery of our first OSV in November 1998, the average utilization rate for our OSVs has been approximately 94%. According to ODS-Petrodata, the U.S. Gulf of Mexico industry average was approximately 73% over the same time period, based on vessels available for service. We expect that our newer, larger, faster and more cost-efficient vessels will remain in high demand as deepwater and other complex and challenging exploration, development and production activities continue to increase globally.

Commitment to Safety and Quality. As part of our commitment to safety and quality, we have voluntarily pursued and received certifications that are not generally held by other companies in our industry. We have formerly maintained certifications to the requirements of the International Standards Organization, or ISO, Standards 9002 and 14000 for quality and environmental management, respectively, with respect to the eight tugs and nine tank barges acquired from the Spentonbush/Red Star Group. We are one of the few OSV companies operating in the U.S. Gulf of Mexico that is approved under the U.S. Coast Guard’s Streamlined Inspection Program in which we and the Coast Guard cooperate to develop training, inspection and compliance processes, with our personnel conducting periodic examinations of vessel systems to the requirements of the vessels’ Coast Guard certifications, and taking corrective actions where necessary. Both of our principal office locations in Covington, Louisiana and Brooklyn, New York, as well as the majority of our vessels, including all of our OSVs and our tugs and tank barges acquired from the Spentonbush/Red Star Group, are also certified under the International Safety Management Code, or ISM Code, developed by the International Maritime Organization to provide internationally recognized standards for the safe management and operation of ships and for pollution prevention. We are currently combining the ISO and ISM certification of our fleetwide operations to standards of the American Bureau of Shipping’s Safety, Quality and Environmental Certification, or ABS SQE, which integrates the elements of these certifications into a single program. Quality, Safety and Environmental Certificates are an increasingly important consideration for both our OSV and tank barge customers due to the environmental and regulatory sensitivity associated with offshore drilling and production activity and waterborne transportation of petroleum products, respectively. We believe that customers recognize our commitment to safety and that our strong reputation and performance history provide us with a competitive advantage.

Leading Market Presence in Core Target Markets. Our 23 OSVs comprise the second largest fleet of technologically advanced, new generation OSVs qualified for work in the U.S. Gulf of Mexico. Currently, 19 of our 23 OSVs operate in that area. We also operate one of the largest fleets of tugs and tank barges for the transportation of petroleum products in Puerto Rico and believe that we are the fourth largest tank barge transporter of petroleum products in New York Harbor. We believe that having scale in our selected markets benefits our customers and provides us with operating efficiencies.

Successful Track Record of Vessel Construction and Acquisitions. Our management has significant naval architecture, marine engineering and shipyard experience. We believe we are unique in the manner in which we design our own vessels and work closely with our contracted shipyards in their construction. We typically source and supply many of the manufactured components (owner-furnished equipment), comprising a large portion of the aggregate cost of a vessel, directly from vendors rather than through the shipyard. In addition to substantial cost savings, we believe our approach enables us to better control the construction process, resulting in a higher quality vessel and an enhanced level of service from these vendors during the applicable warranty periods. We believe that our history of designing and constructing 17 new generation OSVs on time and on budget provides us with a competitive advantage in obtaining contracts for our vessels prior to their actual delivery. Our company has designed its operations and management systems in contemplation of additional growth through new vessel construction and acquisitions. To date, we have successfully completed and integrated four acquisitions involving 13 ocean-going tugs and 13 ocean-going tank barges, one acquisition of a coastwise tanker and two acquisitions involving six 220’ new generation OSVs.

Favorable OPA 90 Fleet Status. Data provided by a U.S. Coast Guard report dated September 2001 indicates that 5.5 million barrels of single-hulled tank barge capacity would need to be retired by 2005 and an additional 3.5 million barrels by 2010, as mandated by OPA 90. According to the report, this represented on a cumulative basis as of each such retirement date, 22% and 36%, respectively, of the total 24.9 million barrel single- and double-hulled tank barge capacity that existed in 2001. Because 10 of our 15 single-hulled tank barges are not required to be replaced or retrofitted with double hulls until 2015, we believe we have a competitive advantage over operators who have a higher percentage of single-hulled tank barges that must be retired or modified to add double hulls before 2010.

Experienced Management Team with Proven Track Record. Our executive management team has an average of 20 years of domestic and international marine transportation industry-related experience. We believe that our team has successfully demonstrated its ability to grow our fleet through new construction and strategic acquisitions and to secure profitable contracts for our vessels in both favorable and unfavorable market conditions. Moreover, our in-house engineering team has significant operating experience that enables us to more effectively design and manage our new vessel construction program, adapt our vessels for specialized purposes, oversee and manage the drydocking process and provide custom marine engineering solutions to our customers. We believe this will continue to result in a lower overall cost of ownership over the life of our vessels compared to our competitors, as well as a competitive advantage in securing contracts for our OSVs as the benefits of our proprietary designs and in-house engineering capabilities are recognized by our customers.

Apply Existing and Develop New Technologies to Meet our Customers’ Vessel Needs. Our new generation OSVs are designed to meet the higher capacity and performance needs of our clients’ increasingly more complex drilling and production programs. In addition, our proprietary double-hulled tank barges currently under construction are designed to maximize transit speed, improve cargo through-put rates and enhance crew safety features. Our new generation OSVs are equipped with sophisticated propulsion and cargo handling systems, dynamic positioning capabilities and have larger capacities than conventional 180’ OSVs. We are committed to applying existing and developing new technologies to maintain a technologically advanced fleet that will enable us to continue to provide a high level of customer service and meet the developing needs of our customers for OSVs and ocean-going tugs and tank barges, as well as other types of vessels that complement our two business segments. Improvements in exploration and production technologies have enabled operators to pursue larger scale, more complex drilling programs in remote locations and under more challenging operating conditions. We believe that the trend toward increasingly more complex projects will increase the demand for our technologically advanced fleet of new generation OSVs. Oil and natural gas exploration and development activity in these regions has increased recently as a result of several factors, including world-class exploration potential, improvements in exploration and production technologies for deepwater projects, and slowing or declining production from onshore and shallow water fields. We believe that deepwater regions worldwide and deep well drilling on the Continental Shelf will continue to be active areas for exploration and development in the foreseeable future, and that demand for our OSVs, which are uniquely equipped to serve the current and planned drilling programs in these markets, will continue to be strong.

Expand Fleet Through Newbuilds and Strategic Acquisitions. We plan to expand our fleet through construction of new vessels, including construction of new generation OSVs and double-hulled tank barges as market conditions warrant, retrofitting of certain vessels and through strategic acquisitions. Market demand for vessels, including demand for new generation OSVs in domestic and international markets, will be the main determinant of the level and timing of construction of additional vessels. We believe that acquisition opportunities are likely to arise as consolidation continues in our two industry segments. We intend to use our expertise and experience to evaluate and execute strategic acquisitions where the opportunity exists to expand our service offerings in our core markets and create or enhance long-term client relationships. To date, we have completed seven acquisitions involving 33 vessels and have constructed 17 proprietary vessels, with two more expected for delivery in December 2004.

Pursue Optimal Mix of Long-Term and Short-Term Contracts. We seek to balance our portfolio of customer contracts by entering into both long-term and short-term charters. Long-term charters, which contribute to higher utilization rates, provide us with more predictable cash flow. Most of our long-term charters contain annual dayrate escalation provisions. Short-term charters provide the opportunity to benefit from increasing dayrates in favorable market cycles. Currently, seven of our 23 OSVs operate under long-term charters, the initial terms of which range from one to five years. Our contract of affreightment with Amerada Hess for the services of tugs and tank barges in the northeastern United States has an initial term of June 1, 2001 through March 31, 2006. Our other tug and tank barge contracts typically have been renewed annually over the last several years.

Build Upon Existing Customer Relationships. We intend to build upon existing customer relationships by expanding the services we offer to those customers with diversified marine transportation needs. Many integrated oil and gas companies require OSVs to support their exploration and production activities and ocean-going tugs and tank barges to support their refining, trading and retail distribution activities. Moreover, many of our customers that conduct operations internationally have expressed interest in chartering our OSVs in such markets. For example, we are operating three OSVs in Trinidad &

Tobago for a customer with whom we have a long-standing relationship in the U.S. Gulf of Mexico. Currently, four of our new generation OSVs are chartered for use in international markets. Our management team has significant international experience and will continue to evaluate such opportunities.

Optimize Tug and Tank Barge Operations. Due to OPA 90 phase-out requirements of single-hulled barges, the total barrel-carrying capacity of existing tank vessels transporting petroleum products domestically is projected to decline from its current level without a commensurate increase in newbuildings and retrofittings. In addition, the energy industry is increasingly outsourcing its marine transportation requirements and focusing on safety and reliability as a key determinant in awarding new business. We believe that these trends will improve the balance of supply and demand, and result in improved tank barge utilization and dayrates.

Major oil companies, large independent oil and gas exploration, development and production companies and large oil service companies constitute the majority of our customers for our OSV services, while refining, marketing and trading companies constitute the majority of our customers for our tug and tank barge services. The percentage of revenues attributable to a customer in any particular year depends on the level of oil and natural gas exploration, development and production activities undertaken or refined petroleum products or crude oil transported by a particular customer, the availability and suitability of our vessels for the customer’s projects or products and other factors, many of which are beyond our control. For the year ended December 31, 2003, Amerada Hess Corporation accounted for more than 10% of our total revenues. Under the terms of our contract of affreightment with Amerada Hess, we are required to meet certain performance criteria and, if we fail to meet such criteria, Amerada Hess would be entitled to terminate the contract. Our contract of affreightment provides for minimum annual cargo volumes to be transported and allows Amerada Hess to reduce its minimum commitment, subject to significant adjustment penalties. Because the tank barge market in the northeastern United States is currently operating at or near capacity, we believe that we would be able to replace through other customers any volumes that Amerada Hess does not transport as contemplated by the contract. For a discussion of significant customers in prior periods, see note 14 of the notes to our consolidated financial statements.

We enter into a variety of contract arrangements with our customers, including spot and time charters, contracts of affreightment and consecutive voyage contracts. Our contracts are obtained through competitive bidding or, with established customers, through negotiation.

Currently, seven of our 23 OSVs operate under long-term charters. Most of the contracts for our OSVs contain early termination options in favor of the customer; however some have substantial early termination penalties designed to discourage the customers from exercising such options. Similarly, 12 of our 16 tank barges provide services under long-term contracts with initial terms of one year or longer. Since we commenced operations, our OSVs have performed services for approximately 64 different customers, and our tugs and tank barges have performed services for approximately 252 different customers. Because of the variety and number of customers historically using the services of our fleet, and the approximate balance between supply and demand in both the OSV and tug and tank barge markets, we believe that the loss of any one customer would not have a material adverse effect on our business.

Because we have established a reputation for on-time delivery and reliability, charterers have contacted us in certain circumstances to construct vessels to meet their needs. In such circumstances, we have generally contracted these specially designed vessels for three to five years, with renewal options, before construction is completed. Although we will design vessels to meet the specific needs of a charterer, we ensure in our design that customization does not preclude efficient operation of these vessels for other customers, for other purposes or in other situations.

We operate in a highly competitive industry. Competition in the OSV and ocean-going tug and tank barge segments of the marine transportation industry primarily involves factors such as:

The terms of the Jones Act restrict the ability of vessels that are not built in the United States, registered under the laws of the United States and owned and managed by U.S. citizens to compete in the coastwise trade in the United States and Puerto Rico. See “—Environmental and Other Governmental Regulation” for a more detailed discussion of the Jones Act.

We do not anticipate significant competition in the near term from pipelines as an alternative method of petroleum product delivery in the northeastern United States or Puerto Rico. No pipelines are currently under construction that could provide significant competition to tank barges in the northeastern United States or Puerto Rico, nor are any new pipelines likely to be built in the near future due to cost constraints and logistical and environmental requirements.

We believe that approximately 84% of the new generation OSVs currently operating in the U.S. Gulf of Mexico are owned by privately-held companies. We believe we operate the second largest fleet of new generation OSVs in the U.S. Gulf of Mexico. In contrast, approximately 75% of the conventional 180’ OSVs operating on the Continental Shelf of the U.S. Gulf of Mexico are owned by publicly-traded companies. We operate one of the largest tank barge fleets in Puerto Rico and we believe that we are the fourth largest transporter by tank barge of petroleum products in New York Harbor. Most of our competitors in the tug and tank barge industry are privately held.

Although some of our principal competitors are larger and have greater financial resources and, with respect to OSVs, extensive international operations, we believe that our operating capabilities and reputation enable us to compete effectively with other fleets in the market areas in which we operate. In particular, we believe that the relatively young age and advanced features of our OSVs provide us with a competitive advantage. The ages of our OSVs range from one month to 76 months, while the average age of the industry’s conventional 180’ U.S.-flagged OSV fleet is approximately 24 years. Retirement of older vessels has already commenced and we believe that many more of these older vessels will be retired in the next few years. The young age of our fleet, together with the advanced capabilities of our vessels, position us to take advantage of the expanding deepwater, deep well and other logistically demanding exploration and production projects in the U.S. Gulf of Mexico and around the world. In addition, our new generation OSVs are also increasingly in demand by our customers for conventional drilling projects because of the ability of our OSVs to reduce overall offshore logistics costs for the customer through the vessels’ greater capacities and operating efficiencies.

Our operations are significantly affected by a variety of federal, state, local and international laws and regulations governing worker health and safety and the manning, construction and operation of vessels. Certain U.S. governmental agencies, including 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, have jurisdiction over our operations. In addition, private industry organizations such as the American Bureau of Shipping oversee aspects of our business. The Coast Guard and the National Transportation Safety Board establish safety criteria and are authorized to investigate vessel accidents and recommend improved safety standards.

The U.S. Coast Guard regulates and enforces various aspects of marine offshore vessel operations. Among these are classification, certification, routes, drydocking intervals, manning requirements, tonnage requirements and restrictions, hull and shafting requirements and vessel documentation. Coast Guard regulations require that each of our vessels be drydocked for inspection at least twice within a five-year period.

Under Section 27 of the Merchant Marine Act of 1920, also known as the Jones Act, the privilege of transporting merchandise or passengers for hire in the coastwise trade in U.S. domestic waters is restricted to only those vessels that are owned and managed by U.S. citizens and are built in and registered under the laws of the United States. A corporation is not considered a U.S. citizen unless, among other things:

We meet all of the foregoing requirements. If we should fail to comply with these requirements, our vessels would lose their eligibility to engage in coastwise trade within U.S. domestic waters. To facilitate compliance, our certificate of incorporation:

Recently, the Jones Act restrictions have been challenged by interests seeking to facilitate foreign competition for coastwise trade. Historically, their efforts have been defeated by large margins when considered by the U.S. Congress. Industry associations and participants have actively responded to the latest challenges involving the nature, extent and availability of lease-finance alternatives permitted by a 1996 amendment of the Jones Act. Certain foreign interests have attempted to utilize those provisions to operate or propose operation in the U.S. coastwise trade. On February 4, 2004, the United States Coast Guard published a final rule further restricting the lease-finance provisions to prevent their misuse. In the final rule, the Coast Guard noted that Congress’s intent in adopting the 1996 amendment was to broaden the sources of capital for owners of U.S. vessels engaged in coastwise trade by creating new lease-finance options and not to undermine the basic principle of U.S. maritime law that vessels operated in domestic trades must be operated and controlled by U.S. citizens. The final rule grandfathers indefinitely any vessel that received a coastwise endorsement before February 4, 2004 or any vessel built under a construction contract entered into before that date in reliance on a letter ruling from the Coast Guard dated prior to that date. In addition to the final rule, the Coast Guard and the Maritime Administration, on February 4, 2004, published a joint notice of proposed rulemaking that included provisions addressing certain charter-back restrictions intended to further prevent misuse of the lease-finance provisions. Also, the Coast Guard is proposing to limit the grandfathering provisions of the Coast Guard’s final rule to three years instead of having them be indefinite. There can be no assurance that the proposed rulemaking will be adopted as proposed or that, even if adopted with favorable provisions, further efforts to interpret the Jones Act, including these rules, in a manner designed to circumvent the historical protections afforded to U.S. coastwise trade will not continue. Should foreign competition be permitted to enter the U.S. coastwise market, it could have an adverse effect on the U.S. OSV industry and on us.

Our operations are also subject to a variety of federal, state, local and international laws and regulations regarding the discharge of materials into the environment or otherwise relating to environmental protection. The requirements of these laws and regulations have become more complex and stringent in recent years and may, in certain circumstances, impose strict liability, rendering a company liable for environmental damages and remediation costs without regard to negligence or fault on the part of such party. Aside from possible liability for damages and costs including natural resource damages associated with releases of hazardous materials including oil into the environment, such laws and regulations may expose us to liability for the conditions caused by others or even acts of ours that were in compliance with all applicable laws and regulations at the time such acts were performed. Failure to comply with applicable laws and

regulations may result in the imposition of administrative, civil and criminal penalties, revocation of permits, issuance of corrective action orders and suspension or termination of our operations. Moreover, it is possible that changes in the environmental laws, regulations or enforcement policies that impose additional or more restrictive requirements or claims for damages to persons, property, natural resources or the environment could result in substantial costs and liabilities to us. We believe that we are in substantial compliance with currently applicable environmental laws and regulations.

OPA 90 and regulations promulgated pursuant thereto impose a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills. A “responsible party” includes the owner or operator of an onshore facility, pipeline or vessel or the lessee or permittee of the area in which an offshore facility is located. OPA 90 assigns liability to each responsible party for oil removal costs and a variety of public and private damages. Under OPA 90, “tank vessels” of over 3,000 gross tons that carry oil or other hazardous materials in bulk as cargo, a term which includes our tank barges, are subject to liability limits of the greater of $1,200 per gross ton or $10 million. For any vessels, other than “tank vessels,” that are subject to OPA 90, the liability limits are the greater of $500,000 or $600 per gross ton. A party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, the liability limits likewise do not apply. Moreover, OPA 90 imposes on responsible parties the need for proof of financial responsibility to cover at least some costs in a potential spill. We have provided satisfactory evidence of financial responsibility to the U.S. Coast Guard for all of our vessels over 300 tons.

OPA 90 also imposes ongoing requirements on a responsible party, including preparedness and prevention of oil spills, preparation of an oil spill response plan and proof of financial responsibility (to cover at least some costs in a potential spill) for vessels in excess of 300 gross tons. We have engaged the National Response Corporation to serve as our independent contractor for purposes of providing stand-by oil spill response services in all geographical areas of our fleet operations. In addition, our Oil Spill Response Plan has been approved by the U.S. Coast Guard.

OPA 90 requires that all newly-built tank vessels used in the transport of petroleum products be built with double hulls and provides for a phase-out period for existing single hull vessels. Modifying existing vessels to provide for double hulls will be required of all tank barges and tankers in the industry by the year 2015. We are in a favorable position concerning this provision because a significant number of vessels in our fleet of tank barges measure less than 5,000 gross tons. Vessels of such tonnage may continue to operate without double hulls through the year 2015. Under existing legal requirements, therefore, we will be required to modify or replace only five of our tank barges before 2015. Although we are not aware of anything that would lead us to believe this current schedule will change, it remains possible that a change in the law affecting the requirement for double hulls or other aspects of our operations may occur that would require us to modify or replace our existing tank barge fleet earlier than currently anticipated.

The Clean Water Act imposes strict controls on the discharge of pollutants into the navigable waters of the United States. The Clean Water Act also provides for civil, criminal and administrative penalties for any unauthorized discharge of oil or other hazardous substances in reportable quantities and imposes substantial liability for the costs of removal and remediation of an unauthorized discharge. Many states have laws that are analogous to the Clean Water Act and also require remediation of accidental releases of petroleum in reportable quantities. Our OSVs routinely transport diesel fuel to offshore rigs and platforms and also carry diesel fuel for their own use. Our OSVs also transport bulk chemical materials used in drilling activities and liquid mud, which contain oil and oil by-products. In addition, our tank barges are specifically engaged to transport a variety of petroleum products. We maintain vessel response plans as required by the Clean Water Act to address potential oil and fuel spills.

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

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

LEEVAC Marine, Inc., a predecessor entity to one of our current subsidiaries, was notified in March 1996 regarding the possibility of remediating on a voluntary basis certain waste pits at the SBA Shipyards site in Jennings, Louisiana. This site is not identified as a federal Superfund site. Subsequent to this initial notice, in December 2000, LEEVAC Marine was one of approximately 14 companies that formed a limited liability company, SSIC Remediation, LLC, to address this matter. LEEVAC Marine accrued a $100,000 liability at the time of our formation to cover this expense. Our subsidiary’s current percentage of liability for cleanup efforts within the SSIC Remediation group at this site is estimated at approximately 2.64%, and, to date, it has contributed approximately $34,000 towards this cleanup effort and an additional $17,000 to pay certain costs discussed below, thereby reducing the accrued liability with respect to this matter to $44,600. The $34,000 contribution represents our subsidiary’s current share of a $1.9 million voluntary cleanup plan submitted to the limited liability company’s members by an independent contractor who has agreed to clean up the site in a manner that will meet both state and federal standards. In June 1997, Cari Investment Company, the former parent of LEEVAC Marine, Inc., agreed to indemnify us for certain matters, including those discussed in this paragraph. The indemnity would also be applicable to all liabilities, obligations, damages and expenses related to the SBA Shipyard matter in excess of $100,000. Christian G. Vaccari, who served as our Chairman and Chief Executive Officer until February 2002 and is serving as one of our directors, is a minority shareholder and President, Chief Executive Officer and Chairman of the Board of Cari Investment Company. In July 2002, our subsidiary entered into a contractual agreement whereby it paid an additional $17,000 to SSIC Remediation, LLC in order to limit its exposure to certain future costs incurred by the independent contractor at the site. This limitation on payment of future monies relates primarily to certain legal and administrative costs of SSIC Remediation, LLC and does not bar future payment of monies for potential Superfund cleanup costs or for costs associated with any suits brought by third parties. In late 2002, SSIC Remediation, LLC commenced interim phase remedial activities at the SBA Shipyards site pursuant to a December 9, 2002 “Order and Agreement” that it entered into with EPA. These remedial efforts are on-going at this site.

In addition to laws and regulations affecting us directly, our operations are also influenced by laws, regulations and policies which affect our customers’ drilling programs and the oil and natural gas industry as a whole.

The Outer Continental Shelf Lands Act gives the federal government broad discretion to regulate the release of offshore resources of oil and natural gas. Because our operations rely primarily on offshore oil and natural gas exploration, development and production, if the government were to exercise its authority under the Outer Continental Shelf Lands Act to restrict the availability of offshore oil and natural gas leases, such an action would have a material adverse effect on our financial condition and results of operations.

We currently have in place protection and indemnity insurance coverage that includes coverage for pollution incidents in navigable waters of the United States. Our OSVs have $5 million in primary insurance coverage for such offshore pollution incidents, with an additional $100 million in excess umbrella coverage. In addition, our tugs and tank barges have insurance coverage for oil spills with a coverage limit of $1 billion.

Our tugs and tank barges acquired from the Spentonbush/Red Star Group have formerly obtained certifications for environmental management according to the requirements of ISO Standard 14000. Both of our principal office locations in Covington, Louisiana and Brooklyn, New York, as well as the majority of our vessels, including all of our proprietary OSVs and our tugs and tank barges acquired from the Spentonbush/Red Star Group, are also certified to the standards of the ISM Code for the safe management and operation of ships and for pollution prevention. We are currently combining the ISO and ISM Code certification of our fleetwide operations to the standards of ABS SQE, which integrates the elements of these certifications into a single program. Additionally, our OSVs participate in the U.S. Coast Guard’s Streamlined Inspection Program (SIP), which ensures the overall readiness level of our vessel lifesaving and other critical safety and emergency systems. We believe that our voluntary attainment and maintenance of these certifications and participation in these programs provides evidence of our commitment to operate in a manner that minimizes any impact on the environment from our fleet operations.

The operation of our vessels is subject to various risks, such as catastrophic marine disaster, adverse weather conditions, mechanical failure, collision and navigation errors, all of which represent a threat to personnel safety and to our vessels and cargo. We maintain insurance coverage that we consider customary in the industry against certain of these risks, including, as discussed above, $1 billion in pollution insurance for the tug and tank barge fleet and $105 million of pollution coverage for the OSVs. We believe that our current level of insurance is adequate for our business and consistent with industry practice, and we have not experienced a loss in excess of our policy limits. We may not be able to obtain insurance coverage in the future to cover all risks inherent in our business, or insurance, if available, may be at rates that we do not consider to be commercially reasonable. In addition, as more single-hulled vessels are retired from active service, insurers may be less willing to insure and customers less willing to hire single-hulled vessels.

On December 31, 2003, we had 556 employees in the United States and Puerto Rico, including 468 operating personnel and 88 corporate, administrative and management personnel. None of our employees are represented by a union or employed pursuant to a collective bargaining agreement or similar arrangement. We have not experienced any strikes or work stoppages, and our management believes that we continue to enjoy good relations with our employees.

Our corporate headquarters are located in Covington, Louisiana. Our office lease covers 23,756 sq. ft. and has an initial term of five years, which commenced in September 2003, with two additional five-year renewal periods. We also hold a one-year lease on a 4,500-square-foot warehouse near our corporate headquarters to maintain spare parts inventory. For local support in Puerto Rico, we lease an office consisting of approximately 1,900 square feet. To support our operations in the northeastern United States, we lease office space and warehouse space in Brooklyn, New York, consisting of approximately 66,760 square feet. We also lease dock space, consisting of approximately 36,000 square feet, in Brooklyn, New York. We operate our tug and tank barge fleet from these New York facilities. The lease on our Brooklyn facilities expires in March 2006. We believe that our facilities, including waterfront locations used for vessel dockage and certain vessel repair work, provide an adequate base of operations for the foreseeable future. Information regarding our fleet is set forth above in “—Offshore Supply Vessels—Our OSV Business” and “—Tugs and Tank Barges—Our Tug and Tank Barge Business.”

Reverse Stock Split. On March 5, 2004, we effected a 1-for-2.5 reverse stock split of our common stock that caused the number of our outstanding shares to decrease from 36.3 million to 14.5 million. For all periods, the share amounts and per share data reflected throughout this annual report on Form 10-K have been adjusted to give effect to the reverse stock split.

Amendment to Revolving Credit Facility. On February 13, 2004, we amended and restated our revolving credit facility primarily to extend its maturity from December 31, 2004 to February 13, 2009 and to increase its nominal size from $60 million to $100 million. Our current borrowing base under the facility remains unchanged at $60 million. The maturity of this facility will automatically accelerate to March 31, 2008, if by that date we have not redeemed our senior notes or refinanced them with debt having a maturity later than July 31, 2009.

Delivery of 240 ED Class HOS Silverstar. On January 21, 2004, we took delivery of the HOS Silverstar, our fourth 240 ED class OSV, from the shipyard. After further vessel modifications, the HOS Silverstar was mobilized on March 3, 2004 and is scheduled to work in Trinidad & Tobago.

Double-Hulled Tank Barge Newbuild Program. In November 2003, we commenced our fourth new vessel construction program, the first such program for our tug and tank barge segment. We contracted with shipyards for the construction of two double-hulled tank barges and are currently evaluating our plans with respect to the construction or retrofit of a third tank barge. We expect to take delivery of the two tank barges currently under construction in December 2004. These two vessels are based on a proprietary design developed by our in-house engineering team. We also secured fixed-price options from one of the shipyards to construct up to three additional proprietary double-hulled tank barges for delivery

after 2004. The primary purpose of our tank barge newbuild and retrofit program is to address our need to replace three of our existing single-hulled tank barges that are required under OPA 90 to be retired from service prior to January 1, 2005. We expect to incur construction and retrofit costs of up to $42 million for the first three tank barges before allocation of construction period interest. We expect to fund these costs with current cash on hand, projected cash flow from operations and available borrowing capacity.

Demand for our OSV services is directly affected by the levels of offshore drilling activity. Budgets of many of our customers are based upon a calendar year, and demand for our services has historically been stronger in the third and fourth calendar quarters when allocated budgets are expended by our customers and weather conditions are more favorable for offshore activities. Many other factors, such as the expiration of drilling leases and the supply of and demand for oil and natural gas, may affect this general trend in any particular year. These factors have less impact on our OSV business due to our high level of contracted cash flow, which has resulted in high utilization.

Tank barge services are significantly affected by the strength of the U.S. economy, changes in weather patterns and population growth that affect the consumption of and the demand for refined petroleum products and crude oil. The tug and tank barge market, in general, is marked by steady demand over time, although such demand is seasonal and often dependent on weather conditions. Unseasonably mild winters result in significantly lower demand for heating oil in the northeastern United States, which is a significant market for our tank barge services. Conversely, the summer driving season can increase demand for automobile fuel and, accordingly, the demand for our services.

We are not currently a party to any material legal proceedings, although we may from time to time be subject to various legal proceedings and claims that arise in the ordinary course of business.

On October 9, 2003, we held a Special Meeting of Stockholders. At the meeting, the stockholders approved the Board of Director’s proposal to (i) effect a reverse stock split in connection with the Company’s proposed initial public offering, if necessary, by amending the Company’s Restated Certificate of Incorporation, as amended, and (ii) maintain the maximum number of shares that may be issued with respect to awards granted pursuant to the Company’s Incentive Compensation Plan following the above referenced reverse stock split at 3,500,000. As to each of the foregoing proposals, the number of shares cast for or against the proposal, as well as the number of abstentions, were as follows:

Proposal 1: Approval or disapproval to effect a reverse stock split in connection with the Company’s proposed initial public offering, if necessary, by amending the Company’s Restated Certificate of Incorporation, as amended.

Proposal 2: Approval of proposal to maintain the maximum number of shares that may be issued with respect to awards granted pursuant to the Company’s Incentive Compensation Plan following the anticipated reverse stock split at 3,500,000.

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

Our common stock is privately-held and is not listed for quotation or trading on any exchange, automated quotation system or over-the-counter market. On March 5, 2004, we had 99 holders of record of our common stock.

We have not previously paid or declared and we do not plan to declare or pay, any cash dividends on our common stock. We intend to retain all of the cash our business generates to meet our working capital requirements and fund future growth. In addition, our indenture and revolving credit facility include restrictions on our ability to pay cash dividends on our common stock.

During the year ended December 31, 2003, we issued the following shares of our common stock which were not registered under the Securities Act of 1933:

(a) In September 2003, we issued 1,000 shares of our common stock to a holder of options granted under our Incentive Compensation Plan upon the exercise of such options as reported in Item 2 of Form 10-Q filed November 12, 2003.

(b) The Company completed a $30.0 million private placement of 2,400,000 shares of common stock on July 3, 2003 as reported in Item 2 of Form 10-Q filed August 14, 2003.

(c) In June 2003, we issued 4,700 shares of our common stock to certain holders of options granted under our Incentive Compensation Plan upon the exercise of such options. The total amount of consideration we received for the issuance of these shares was approximately $31,138. The issuance of these shares of our common stock was exempt from registration under Rule 701 promulgated under the Securities Act of 1933.

Our selected historical consolidated financial information as of and for the periods ended December 31, 2003, 2002, 2001, 2000, and 1999 was derived from our audited historical consolidated financial statements prepared in accordance with generally accepted accounting principles, or GAAP. The data should be read in conjunction with and is qualified in its entirety by reference to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical consolidated financial statements and the notes to those statements included elsewhere in this annual report on Form 10-K.

In March 2003, the Securities and Exchange Commission, or Commission, adopted rules regulating the use of non-GAAP financial measures, such as EBITDA, in filings with the Commission, disclosures and press releases. These rules require non-GAAP financial measures to be presented with and reconciled to the most nearly comparable financial measure calculated and presented in accordance with GAAP.

EBITDA consists of earnings (net income) before interest expense, income tax expense, depreciation and amortization. This term, as we define it, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with accounting principles generally accepted in the United

States, or GAAP. EBITDA should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP.

We believe EBITDA is useful to an investor in evaluating our operating performance because:

The following table reconciles EBITDA with our net income (loss) for the following periods:

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

The following management’s discussion and analysis should be read in conjunction with our historical consolidated financial statements and their notes included elsewhere in this annual report on Form 10-K. This discussion contains forward-looking statements that reflect our current views with respect to future events and financial performance. Our actual results may differ materially from those anticipated in these forward-looking statements.

We own and operate a fleet of 23 technologically advanced, new generation OSVs. Currently, 19 of our OSVs are operating in the U.S. Gulf of Mexico, three of our OSVs are operating offshore Trinidad & Tobago and one is working offshore Mexico. We also operate 12 ocean-going tugs and 16 ocean-going tank barges in the northeastern United States, primarily New York Harbor, in Puerto Rico and in the U.S. Gulf of Mexico.

We charter our OSVs on a dayrate basis, under which the customer pays us a specified dollar amount for each day during the term of the contract, pursuant to either fixed time charters or spot market charters. A fixed time charter is a contract with a term of at least one year in which the charterer obtains the right to direct the movements and utilization of the vessel in exchange for payment of a specified dayrate, generally paid monthly, but the vessel owner retains operational control over the vessel. Typically, the owner fully equips the vessel and is responsible for normal operating expenses, repairs, wages and insurance, while the charterer is responsible for voyage expenses, such as fuel, port and stevedoring expenses. Spot market charters in the OSV industry are generally time charter contracts with either relatively short, indefinite terms or fixed terms of less than one year. Generally, the vessel owner absorbs crew, insurance and repair and maintenance costs in connection with the operation of OSVs pursuant to spot market charters, while customers absorb all other direct operating costs.

All of our OSVs operate under time charters, including seven that are chartered under long-term contracts with expiration dates ranging from July 2004 through November 2007. The long-term contracts for our OSVs are consistent with those used in the industry and are either fixed for a term of months or years or are tied to the duration of a long-term contract for a drilling rig for which the vessel provides services. These contracts generally contain, among others, provisions governing insurance, reciprocal indemnifications, performance requirements and, in certain instances, dayrate escalation terms and renewal options.

While OSVs service existing oil and gas production platforms as well as exploration and development activities, incremental OSV demand depends primarily upon the level of drilling activity, which can be influenced by a number of factors, including oil and natural gas prices and drilling budgets of exploration and production companies. As a result, utilization rates have historically been tied to oil and natural gas prices and drilling activity. However, the relatively large capital commitments, longer lead times and investment horizons associated with deepwater and deep well projects have diminished the significance of these factors. Soft market conditions for OSVs in the U.S. Gulf of Mexico persisted since the second half of 2002. We added six new generation OSVs to our fleet in mid-2003, three of which were cold-stacked by the seller at the time of acquisition. Despite market weakness, we were able to place in service all six of the acquired Candy Fleet vessels and to achieve a fleetwide OSV utilization of approximately 87% in the second half of 2003.

We have developed five different classes of proprietary, new generation OSVs to meet the diverse needs of our customers. The recent acquisition of six 220’ OSVs from Candy Fleet broadened the mix of equipment in our fleet, adding a sixth class of vessels well suited for deep shelf gas exploration and other complex shelf drilling applications. In addition, these new generation vessels are available to fill the increasing demand for modern equipment for conventional drilling on the Continental Shelf. Because the recently acquired vessels were 220 class OSVs, our complement of OSVs smaller in size than the 240 class increased from 33% to 50% of our fleet, resulting in a commensurate decrease in our fleetwide average dayrates beginning in mid-2003. However, we have achieved a comparable reduction in both our fleetwide average capital costs and our daily operating expense per vessel.

Our average dayrate was positively impacted during 2003 by the partial contribution from the first three of our four new 240 ED class OSVs. These vessels were delivered in March, June and September. Each of these three new vessels were delivered two weeks ahead of schedule. The delivery of the HOS Greystone in September 2003 marked the eighth consecutive quarter that we had placed a newly constructed OSV in service. The fourth vessel of this newbuild program,

the HOS Silverstar, was ready for early delivery in December; however, we elected to make various vessel enhancements that resulted in delivery of the vessel on January 21, 2004.

Although current U.S. Gulf of Mexico market conditions remain challenging, we believe certain events could have a favorable impact on the long-term market outlook. Deepwater properties continue to change ownership, and several of the new operators have publicly stated their intentions to develop these properties over the next several quarters. Additionally, certain operators have recently reaffirmed their commitments to continue developing large projects in the U.S. Gulf of Mexico. In response to U.S. Gulf of Mexico conditions, we elected to expand our operations within the western hemisphere in mid-2002. We currently have three vessels operating in Trinidad & Tobago and one in Mexico. We will continue to take advantage of our vessels’ capabilities to meet emerging market trends, both in the U.S. Gulf of Mexico and in select international markets.

Generally, we operate an ocean-going tug and tank barge together as a “tow” to transport petroleum products between U.S. ports and along the coast of Puerto Rico. We operate our tugs and tank barges under fixed time charters, spot market charters, contracts of affreightment and consecutive voyage contracts. Spot market charters in the tug and tank barge industry are generally single-voyage contracts of affreightment or time charter contracts with terms of less than one year. A consecutive voyage contract is a contract for the transportation of cargo for a specified number of voyages between designated ports over a fixed period of time under which we are paid based on the volume of products we deliver per voyage. Under consecutive voyage contracts, in addition to earning revenues for volumes delivered, we earn a standby hourly rate between charters. One of our tank barges was chartered to a third party under a bareboat charter from January 2000 until it was sold to the third party on January 28, 2003. A bareboat charter is a “net lease” in which the charterer takes full operational control over the vessel for a specified period of time for a specified daily rate that is generally paid monthly to the vessel owner. The bareboat charterer is solely responsible for the operation and management of the vessel and must provide its own crew and pay all operating and voyage expenses.

The primary demand drivers for our tug and tank barge services are population growth, the strength of the U.S. economy, changes in weather, oil prices and competition from alternate energy sources. The tug and tank barge market, in general, is marked by steady demand over time. Results for the first and fourth quarters of a given year are typically higher due to normal seasonal weather patterns that typically result in a drop-off of activity during the second and third quarters. We generally take advantage of this seasonality to prepare the tug and tank barge fleet for peak demand periods by performing our regulatory drydocking and maintenance programs during these off-peak periods. In addition, we continuously evaluate our customers’ needs and often elect to accelerate scheduled drydockings to take advantage of certain market opportunities. As expected, activity during the fourth quarter of 2003 was seasonally higher during the early stages of winter, with normal winter conditions extending into early 2004.

As the next major OPA 90 milestone approaches on January 1, 2005, customer demand for double-hulled equipment has led to increases in dayrates for this equipment, particularly for tank barges in black oil service. We are actively working to ensure that our fleet is well positioned to take advantage of these opportunities as they develop. In November 2003, we commenced a new double-hulled tank barge newbuild construction program to address our need to replace three single-hulled tank barges that are required under OPA 90 to be retired from service prior to January 1, 2005. Our recent newbuild program is based on a proprietary new design that we have developed to replace and expand our existing fleet of ocean-going tank barges. The design of these vessels is intended to maximize transit speed, improve cargo through-put rates and enhance crew safety features.

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. Because most of these expenses remain payable regardless of vessel utilization, our direct operating costs as a percentage of revenues may fluctuate considerably with changes in dayrates and utilization.

In addition to the operating costs described above, we incur fixed charges related to the depreciation of our fleet and costs for routine drydock inspections and maintenance and repairs necessary to ensure compliance with applicable regulations and to maintain certifications for our vessels with the U.S. Coast Guard and various classification societies. The aggregate number of drydockings and other repairs undertaken in a given period determines the level of maintenance and repair expenses and marine inspection amortization charges. We generally capitalize costs incurred for drydock inspection and regulatory compliance and amortize such costs over the period between such drydockings, typically 30 or 60 months.

Applicable maritime regulations require us to drydock our vessels twice in a five-year period for inspection and routine maintenance and repair. If we undertake a large number of drydockings in a particular fiscal period, comparative results may be affected.

Our consolidated financial statements included in this annual report on Form 10-K have been prepared in accordance with accounting principles generally accepted in the United States. In many cases, the accounting treatment of a particular transaction is specifically dictated by generally accepted accounting principles. In other circumstances, we are required to make estimates, judgments and assumptions that we believe are reasonable based upon available information. We base our estimates and judgments on historical experience and various other factors that we believe are reasonable based upon the information available. Actual results may differ from these estimates under different assumptions and conditions. We believe that of our significant accounting policies discussed in note 2 to our consolidated financial statements, the following may involve estimates that are inherently more subjective.

Purchase Accounting. Purchase accounting requires extensive use of estimates and judgments to allocate the cost of an acquired enterprise to the assets acquired and liabilities assumed. The cost of each acquired operation is allocated to the assets acquired and liabilities assumed based on their estimated fair values. These estimates are revised during an allocation period as necessary when, and if, information becomes available to further define and quantify the value of the assets acquired and liabilities assumed. For example, costs related to the recertification of acquired vessels that are drydocked within the allocation period immediately following the acquisition of such vessels are reflected as an adjustment to the value of the vessels acquired and the liabilities assumed related to the drydocking. The adjusted basis of the vessel is depreciated over the estimated useful lives of the vessel. The allocation period does not exceed one year from the date of the acquisition. To the extent additional information to refine the original allocation becomes available during the allocation period, the allocation of the purchase price is adjusted. For example, if an acquired vessel was subsequently disposed of within the allocation period, the sales price of the vessel would be used to adjust the original assigned value to the vessel at the date of acquisition such that no gain or loss would be recognized upon disposition during the allocation period. If information becomes available after the allocation period, those items are reflected in operating results.

Carrying Value of Vessels. We depreciate our tugs, tank barges, and OSVs over estimated useful lives of 14 to 25 years, three to 18 years and 25 years, respectively. The useful lives used for single-hulled tank barges is based on their classification under OPA 90, and for double-hulled tank barges it is 25 years. In assigning depreciable lives to these assets, we have considered the effects of both physical deterioration largely caused by wear and tear due to operating use and other economic and regulatory factors that could impact commercial viability. To date, our experience confirms that these policies are reasonable, although there may be events or changes in circumstances in the future that indicate the recoverability of the carrying amount of a vessel might not be possible. Examples of events or changes in circumstances that could indicate that the recoverability of a vessel’s carrying amount should be assessed might include a change in regulations such as OPA 90, a significant decrease in the market value of a vessel and current period operating or cash flow losses combined with a history of operating or cash flow losses or a projection or forecast that demonstrates continuing losses associated with a vessel. If events or changes in circumstances as set forth above indicate that a vessel’s carrying amount may not be recoverable, we would then be required to estimate the undiscounted future cash flows expected to result from the use of the vessel and its eventual disposition. If the sum of the expected future cash flows is less than the carrying amount of the vessel, we would be required to recognize an impairment loss.

Recertification Costs. Our tugs, tank barges and OSVs are required by regulation to be recertified after certain periods of time. These recertification costs are incurred while the vessel is in drydock where other routine repairs and maintenance are performed and, at times, major replacements and improvements are performed. We expense routine repairs and maintenance as they are incurred. Recertification costs can be accounted for in one of three ways: (1) defer and amortize, (2) accrue in advance, or (3) expense as incurred. Companies in our industry use either the defer and amortize or the expense as incurred accounting method. We defer and amortize recertification costs over the length of time in which the recertification is expected to last, which is generally 30 or 60 months. Major replacements and improvements, which extend the vessel’s economic useful life or functional operating capability, are capitalized and depreciated over the vessel’s remaining economic useful life. Inherent in this process are estimates we make regarding the specific cost incurred and the period that the incurred cost will benefit.

Revenue Recognition. We charter our OSVs to customers under time charters based on a daily rate of hire and recognize revenue as earned on a daily basis during the contract period of the specific vessel. Tugs and tank barges are contracted to customers primarily under contracts of affreightment, under which revenue is recognized based on the number of days incurred for the voyage as a percentage of total estimated days applied to total estimated revenues. Voyage related costs are expensed as incurred. Substantially all voyages under these contracts are less than 10 days in length. We also contract our tugs and tank barges under time charters based on a daily rate of hire. Revenue is recognized on such contracts as earned on a daily basis during the contract period of the specific vessel.

Allowance for Doubtful Accounts. Our customers are primarily major and independent, domestic and international, oil and oil service companies. Our customers are granted credit on a short-term basis and related credit risks are considered minimal. We usually do not require collateral. We provide an estimate for uncollectible accounts based primarily on management’s judgment. Management uses historical losses, current economic conditions and individual evaluations of each customer to make 26 adjustments to the allowance for doubtful accounts. Our historical losses have not been significant. However, because amounts due from individual customers can be significant, future adjustments to the allowance can be material if one or more individual customers balances are deemed uncollectible.

Income Taxes. We follow SFAS No. 109, “Accounting for Income Taxes.” SFAS 109 requires the use of the liability method of computing deferred income taxes. Under this method, deferred income taxes are provided for the temporary differences between the financial reporting basis and the tax basis of our assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The assessment of the realization of deferred tax assets, particularly those related to tax operating loss carryforwards, involves the use of management’s judgment to determine whether it is more likely than not that we will realize such tax benefits in the future.

The tables below set forth, by segment, the average dayrates and utilization rates for our vessels and the average number of vessels owned during the periods indicated. These OSVs and tugs and tank barges generate substantially all of our revenues and operating profit.

Summarized financial information concerning our reportable segments is shown below in the following table (dollars in thousands):

Revenues. Revenues were $110.8 million for 2003, compared to $92.6 million for 2002, an increase of $18.2 million or 19.7%. This increase in revenues is primarily the result of the year-over-year growth of our fleet. Our operating fleet grew from an average of 39 vessels during 2002 to an average of 45 vessels during 2003. The additional revenues generated by these six vessels accounted for $14.5 million of the increase in our revenues. We also experienced a $3.7 million increase in revenues from our 39 vessels that were in service during each of the years ended December 31, 2003 and 2002.

Revenues from our OSV segment increased to $62.4 million for 2003, compared to $46.4 million for 2002, an increase of $16.0 million or 34.5%. Our utilization rate was 88.6% for 2003, compared to 94.9% in 2002. The increase in revenues was primarily the result of the year-over-year increase in the size of our fleet. The decrease in utilization was due to having fewer OSVs on long-term contracts and an increased proportion of vessels operating in the spot market, which is more susceptible to market fluctuations. The soft OSV spot market that began in mid-2002 continued throughout 2003, and is continuing in 2004. Our OSV average dayrate was $10,940 for 2003, compared to $12,176 in 2002, a decrease of $1,236 or 10.2%. The decrease in average dayrates primarily reflects the addition of six 220 class OSVs, which typically experience lower dayrates, regardless of market conditions, than our 240 or 265 class vessels and continued dayrate weakness in the U.S. Gulf of Mexico. Our average dayrate for the fourth quarter of 2003 was $9,769, which we believe is more indicative of our expectations for early 2004 than our annual average dayrate of $10,940 for 2003. The fourth quarter of 2003 was the first quarter that reflected a full contribution of the operating results from all six of the new 220 class OSVs acquired in mid-2003, causing a shift in our OSV vessel mix.

Revenues from our tug and tank barge segment totaled $48.4 million for 2003 compared to $46.2 million for 2002, an increase of $2.2 million or 4.8%. The segment revenue increase was primarily due to the acquisition of one 80,000-barrel double-hulled tank barge on February 28, 2003. Our utilization rate decreased to 73.6% for 2003, compared to 78.1% for the same period of 2002 primarily due to more drydocking days occurring in 2003 and an increase in vessels operating under contracts of affreightment during the 2003 period. Our average dayrate increased $1,472, or 15.5%, to $10,971 for 2003 compared to $9,499 for 2002. The increased dayrates were primarily driven by higher average barge capacities and a bareboat charter contract that was replaced by a time charter contract, the latter of which commands a higher dayrate.

Operating Expenses. Our operating expenses, including depreciation and amortization, increased to $64.4 million for 2003, compared to $48.6 million for 2002, an increase of $15.8 million or 32.5%. The increase in operating expenses was primarily the result of having more vessels in service in 2003 compared to 2002.

Operating expenses for our OSV segment increased $12.0 million or 59.4% for 2003 to $32.2 million, compared to $20.2 million for 2002. This increase was primarily the result of five newly constructed, larger class OSVs being in service for substantially more days during 2003 compared to 2002, and the acquisition of six 220 class OSVs in mid-2003. Daily operating costs per vessel for 2003 decreased over 2002, primarily due to a change in the OSV fleet complement in the second half of 2003.

Operating expenses for our tug and tank barge segment were $32.2 million for 2003, compared to $29.4 million for 2002, an increase of $3.8 million or 13.4%. The operating expense increase was primarily due to the acquisition of the Energy 8001 in February 2003. Average daily operating expenses per vessel in the tug and tank barge segment remained fairly constant.

General and Administrative Expenses. Our general and administrative expenses were $10.7 million for 2003, compared to $9.7 million for 2002, an increase of $1.0 million or 10.3%. This increase primarily resulted from increased overhead relating to the costs associated with increased reporting obligations under federal securities laws incurred during 2003 but not in 2002 and the expansion of our fleet during 2003.

Interest Expense. Interest expense was $18.5 million in 2003, compared to $16.2 million in 2002, an increase of $2.3 million or 14.2%. The increase in interest expense resulted from lower capitalized interest in 2003 of $2.7 million related to the construction in progress of four vessels compared to $3.9 million related to the construction of eight vessels in progress during 2002. In addition, the net increase in interest expense was impacted by an average balance outstanding under our revolving credit facility during calendar 2003 of $20.0 million compared to 2002, when the facility was undrawn all year.

Interest Income. Interest income was $0.2 million in 2003 compared to $0.7 million in 2002, a decrease of $0.5 million or 71.4%. Average cash balances were $17.6 million and $37.7 million for the years ended December 31, 2003 and 2002, respectively, which substantially contributed to the decrease in interest income during the year ended December 31, 2003.

Income Tax Expense. Our effective tax rate was 38.0% for 2003 and 2002. Our income tax expense primarily consists of deferred taxes due to our federal tax net operating loss carryforwards of approximately $37.4 million as of December 31, 2003, that are available through 2018 to offset future taxable income. Our income tax rate is higher than the federal statutory rate due primarily to expected state and foreign tax liabilities and items not deductible for federal income tax purposes.

Revenues. Revenues were $92.6 million for 2002, compared to $68.8 million in 2001, an increase of $23.8 million or 34.6%. The increase in revenues was primarily the result of the year-over-year increase in the size of our fleet. Our operating fleet grew from an average of 28 vessels during 2001 to an average of 39 during 2002.

Revenues from our OSV segment increased to $46.4 million in 2002, compared to $33.6 million for 2001, an increase of $12.8 million or 38.1%. Our average OSV fleet size grew by 3.2 vessels during 2002 compared to 2001. The average utilization rate was 94.9% for 2002, compared to 99.1% for 2001. The 4.2% decrease in utilization for 2002 resulted from a reduced number of long-term contracts and an increased proportion of vessels operating in the spot market, which is more susceptible to market fluctuations. The spot OSV market was softer in 2002 and we experienced more drydocking days in 2002 than in 2001. Our OSV average dayrate was $12,176 for 2002, compared to $11,872 for 2001, an increase of $304 or 2.6%. The increase in average dayrates primarily reflected the addition of larger, newly constructed 240 and 265 class OSVs, which experience higher dayrates than our 200 class OSVs.

Revenues from our tug and tank barge segment totaled $46.2 million for 2002, compared to $35.2 million in 2001, an increase of $11.0 million or 31.3%. This increase in revenue was primarily due to the acquisition of nine tugs and nine tank barges on May 31, 2001, which increased average fleet capacity in barrels from 451,655 to 1,130,727. Revenues for 2002 included $2.9 million that was equal to the cost of in-chartering third party equipment paid by customers, compared to $1.4 million for 2001. Our utilization rate decreased 6.3% to 78.1% for 2002, compared to 84.4% for 2001, primarily due to a significant increase in vessels operating under contracts of affreightment during 2002, and the adverse impact of the warm winter season and weak economic conditions experienced in the northeastern United States since the third quarter

of 2001. More barrels moved under contracts of affreightment also contributed to our average dayrate increasing by $555 to $9,499 for 2002, compared to $8,944 for 2001.

Operating Expenses. Our operating expenses, including depreciation and amortization, increased to $48.6 million for 2002, compared to $32.8 million in 2001, an increase of $15.8 million or 48.2%. The increase in operating expenses was the result of an average of 10.7 more vessels in service during 2002 compared to 2001.

Operating expenses for our OSV segment increased $8.5 million, or 72.6%, in 2002 to $20.2 million, compared to $11.7 million in 2001. This increase was primarily the result of an average of 3.2 more new OSVs being in service during 2002 compared to 2001. Daily operating costs per vessel for 2002 increased slightly over 2001, primarily due to the higher costs of operating larger vessels, including increased manning requirements.

Operating expenses for our tug and tank barge segment was $28.4 million for 2002, compared to $21.1 million in 2001, an increase of $7.3 million or 34.6%. The increase in operating expenses was primarily the result of the addition of nine tugs and nine tank barges on May 31, 2001. Daily operating expenses per vessel in the tug and tank barge segment remained fairly constant.

As discussed in note 2 to the audited consolidated financial statements contained herein, we adopted SFAS 142 effective January 1, 2002 and, accordingly, we have ceased amortizing goodwill. Operating expenses for 2001 included goodwill amortization of $0.1 million.

General and Administrative Expenses. Our general and administrative expenses were $9.7 million for 2002, compared to $8.0 million in 2001, an increase of $1.7 million or 21.3%. This increase primarily resulted from increased overhead relating to the nine tugs and nine tank barges acquired on May 31, 2001 and increased costs associated with reporting obligations under federal securities laws that we were subject to during all of 2002 but during only a portion of 2001.

Interest Expense. Interest expense from debt obligations was $16.2 million in 2002, compared to $13.7 million in 2001, an increase of $2.5 million or 18.2%. The increase in interest expense from debt obligations resulted from the refinancing of our conventional floating rate debt through the issuance of $175.0 million of 10⁵/8% senior notes in July 2001 with a higher fixed rate and average balance of debt outstanding for 2002. This increase was offset in part by the capitalization of interest costs of $3.9 million and $3.1 million for 2002 and 2001, respectively. Higher capitalized interest in 2002 was related to the construction in progress of seven offshore supply vessels compared to six vessels during 2001. Included in interest expense was a loss of approximately $3.0 million incurred during 2001 resulting from the early extinguishment of debt. This loss related to the write-off of deferred financing costs upon the refinancing of our debt through the issuance of our senior notes. For more information, please read “Recent Accounting Pronouncements” below.

Interest expense also includes the results of fair value adjustments to warrants having put options. There was no such adjustment for 2002 compared to an adjustment for 2001 of $3.0 million as the warrants were repurchased and terminated during October 2001.

Interest Income. Interest income was $0.7 million in 2002, compared to $1.5 million in 2001, a decrease of $0.8 million or 53.3%. The decrease in interest income resulted from substantially lower interest rates earned on lower average cash balances invested during 2002 compared to 2001.

Income Tax Expense. Our effective income tax provision for 2002, compared to 2001 was higher primarily due to foreign and state income taxes and the impact of non-deductible interest expense resulting from fair value adjustments for warrants with put options, which was $3.0 million lower in 2002 than in 2001. Our income tax expense primarily consists of deferred taxes due to our federal tax net operating loss carryforwards. Our income tax rate is higher than the federal statutory rate due primarily to expected state tax liabilities, foreign taxes and items not deductible for federal income tax purposes.

Our capital requirements have historically been financed with cash flow from operations, issuances of our common equity and debt securities, and borrowings under our credit facilities. We require capital to fund ongoing operations, the construction of new vessels, acquisitions, vessel recertifications, discretionary capital expenditures and debt service. The

nature of our capital requirements and the types of our financing sources are not expected to significantly change during 2004.

Pursuant to an amendment and restatement of our revolving credit facility on February 13, 2004, we have a five-year $100 million senior secured revolving credit facility with a borrowing base of $60 million. As of December 31, 2003, we had $40 million outstanding and $20 million of available borrowing capacity under the then-existing facility. We have made, and may make additional, short-term draws on our revolving credit facility from time to time to satisfy scheduled capital expenditure requirements or other corporate purposes. Any liquidity in excess of our planned capital expenditures will be utilized to repay debt or finance the implementation of our growth strategy, which includes expanding our fleet through the construction, retrofit or acquisition of additional vessels, including OSVs and ocean-going tugs and tank barges, as needed to take advantage of the demand for such vessels. The two double-hulled tank barges currently being constructed will replace two single-hulled vessels that are required to be retired under OPA 90 prior to January 1, 2005.

We believe that our current working capital, projected cash flow from operations and available capacity under our revolving credit facility, will be sufficient to meet our cash requirements for the forseeable future. Although we expect to continue generating positive working capital through our operations, events beyond our control, such as mild winter conditions, a reduction in domestic consumption of refined petroleum products, or declines in expenditures for exploration, development and production activity may affect our financial condition or results of operations. However, depending on the market demand for OSVs, tugs and tank barges and other growth opportunities that may arise, we may require additional debt or equity financing.

Operating Activities. We rely primarily on cash flows from operations to provide working capital for current and future operations. Cash flows from operating activities totaled $33.3 million in 2001, $25.0 million in 2002 and $25.5 million in 2003. The increase in operating cash flows in 2003 over 2002 was primarily due to the growth of our fleet and the decrease from 2001 to 2002 was primarily related to increased cash interest paid. Our cash flow from operations is expected to trend higher as we will have a full year of revenue contribution from the nine vessels we added to our fleet in 2003 and nine months of activity for one OSV added in 2004. However, continued soft market conditions in the U.S. Gulf of Mexico could temper expected increases in cash flows from operations. Cash flows from operations from 2001 to 2003 were also impacted by year-over-year increases in cash outlays for drydock recertification activity. In 2004, we expect to drydock a total of eight OSVs, six tugs, and eight tank barges for recertification and/or discretionary vessel enhancements at an estimated cost of approximately $12.8 million, compared to $1.7 million in 2001, $6.5 million in 2002 and $9.9 million in 2003.

As of December 31, 2003, we had federal tax net tax operating loss carryforwards of approximately $37.4 million available through 2018 to offset future taxable income. These tax net tax operating losses were generated primarily through accelerated tax depreciation applied to our vessels. Our use of these tax net operating losses and additional tax benefits may be limited due to U.S. tax laws. Based on the age and composition of our current fleet, however, we expect to continue generating federal tax net operating losses over the near term.

Investing Activities. Investing activities for 2003 were approximately $99.8 million primarily for the construction of new vessels, acquisitions of OSVs and a double-hulled tank barge, and miscellaneous capital expenditures. These 2003 expenditures were offset by $1.7 million in cash proceeds from the sale of one tank barge. During 2002, investing activities were $56.1 million for new construction of vessels offset by $0.3 million in cash proceeds from the sale of a tug. Investing activities in 2001 were $88.3 million for the construction of new vessels, vessel acquisitions and other equipment purchases and improvements. In 2004, investing activities are anticipated to include costs for new vessel construction to complete construction of two double-hulled tank barges and one OSV, and capital expenditures comprised of vessel modifications and miscellaneous corporate equipment purchases. Refer to the Contractual Obligation table below for a recap of anticipated vessel construction commitments in 2004.

Financing Activities. Financing activities during 2003 consisted primarily of the private placement of approximately 1.9 million shares of our common stock, raising net cash proceeds of approximately $23.3 million and net short-term borrowings under our revolving credit facility of $40 million. Financing activities during 2002 consisted primarily of the incurrence of variable rate debt financing under our revolving credit facility for asset purchases. In 2001, we issued $175 million of 10⁵/8% senior notes and realized net proceeds of approximately $165 million, a substantial portion of which was used to repay and fully extinguish approximately $130 million of the amounts outstanding under our then-existing credit facilities. In October 2001, we paid $14.5 million to repurchase the warrants that were originally issued in connection with

one of our credit facilities paid off with the proceeds of the senior notes. These warrants allowed for the purchase of 4.2 million shares of common stock with an exercise price of $4.20 per share. In 2004, we expect to generate cash from financing activities resulting from borrowings under our revolving credit facility.

In addition, we have filed a registration statement on Form S-1 with the Commission in connection with a proposed initial public offering of our common stock. We also filed an amendment to the registration statement on the filing date of this annual report on Form 10-K. If the offering is completed under such registration statement, we would expect to use the net proceeds from such offering in the manner set forth in the registration statement.

The following table sets forth an aggregation of our contractual obligations as of December 31, 2003 (in thousands).

We have a senior secured revolving credit facility that was recently amended and restated primarily to extend its maturity and increase its nominal size from $60 million to $100 million. Our borrowing base remains unchanged at $60 million. The revolving credit facility expires on February 13, 2009. The maturity of this facility will automatically accelerate to March 31, 2008, if by that date we have not redeemed our senior notes or refinanced them with debt having a maturity later than July 31, 2009. As of December 31, 2003, seven OSVs and four ocean-going tugs and associated personalty collateralized the revolving credit facility. Borrowings under the revolving credit facility accrue interest, at our option, at either (1) the prime rate announced by Citibank, N.A. in New York, plus a margin of up to 1.0%, or (2) the London Interbank Offered Rate, plus a margin of 1.5% to 3.5%. As of December 31, 2003, our weighted average interest rate was 4.5% under our revolving credit facility. We are also required to pay a commitment fee on available but unused amounts ranging from 0.25% to 0.50%. The interest rate margin and commitment fee are based on our leverage ratio, as defined in the revolving credit facility. We can use the amounts we draw under such facility for working capital purposes, acquisitions and new vessel construction. As of December 31, 2003, we had $40 million outstanding and $20 million of available borrowing capacity under the facility.

As of December 31, 2003, we had outstanding debt of $172.7 million, net of original issue discount, under our senior notes. The effective interest rate on the senior notes is 11.18% and is payable semi-annually each February 1 and August 1. The senior notes do not require any payments of principal prior to their stated maturity on August 1, 2008, but pursuant to the indenture under which the senior notes are issued, we are required to make offers to purchase the senior notes upon the occurrence of specified events, such as certain asset sales or a change in control. The senior notes are unsecured senior obligations and rank equally in right of payment with other existing and future senior indebtedness and senior in right of payment to any subordinated indebtedness incurred by us in the future. The senior notes are guaranteed by all of our subsidiaries. We may, at our option, redeem all or part of the senior notes from time to time at specified redemption prices, subject to certain conditions required by the indenture. We are permitted under the terms of the indenture to incur additional indebtedness, provided that we satisfy certain financial conditions. The revolving credit facility and indenture impose certain operating and financial restrictions on us. Such restrictions affect, and in many cases limit or

prohibit, among other things, our ability to incur additional indebtedness, make capital expenditures, redeem equity, create liens, sell assets and pay dividends or make other restricted payments.

During the year ended December 31, 2003, we expended $35.8 million for new vessel construction, before allocation of construction period interest. As of December 31, 2003, we were committed under vessel construction contracts to complete construction of one new generation OSV under our most recent OSV newbuild program, and two double-hulled tank barges under our tank barge newbuild program. Aggregate construction costs before allocation of construction period interest for the four OSVs constructed under our most recent OSV newbuild program are not expected to exceed $53 million, including $32.3 and $18.4 million that was incurred with respect to such vessels during 2003 and 2002, respectively. We took delivery of the HOS Bluewater on March 17, 2003, the HOS Gemstone on June 19, 2003, the HOS Greystone on September 17, 2003 and the HOS Silverstar on January 21, 2004. As of December 31, 2003, the amount expected to be expended to complete construction of the fourth OSV and the two double-hulled tank barges was approximately $31.2 million, which becomes due at various dates during calendar 2004. During the year ended December 31, 2003, we expended approximately $9.9 million for drydocking-related expenses for vessels, of which $6.1 million was accounted for as deferred charges and $3.8 million for other vessel capital improvements. Under our accounting policy, we generally capitalize drydocking expenditures related to vessel recertification to deferred charges and amortize the amount over 30 or 60 months. During the year ended December 31, 2003, we also expended approximately $2.2 million for miscellaneous non-vessel related additions to property, plant and equipment.

To date, general inflationary trends have not had a material effect on our operating revenues or expenses.

In July 2001, the Financial Accounting Standards Board, or FASB, issued SFAS No. 141, “Business Combinations.” SFAS 141 eliminated the pooling-of-interests method of accounting for business combinations except for qualifying business combinations that were initiated prior to July 1, 2001. The purchase method of accounting is required to be used for all business combinations initiated after June 30, 2001. SFAS 141 also requires separate recognition of intangible assets that meet certain criteria.

In July 2001, the FASB issued SFAS No. 142, “Goodwill and Other Intangible Assets.” Under SFAS 142, goodwill and indefinite-lived intangible assets are no longer amortized but are reviewed for impairment annually, or more frequently if circumstances indicate potential impairment. Separable intangible assets that are not deemed to have an indefinite life will continue to be amortized over their useful lives. For goodwill and indefinite-lived intangible assets acquired prior to July 1, 2001, goodwill continued to be amortized through 2001 at which time amortization ceased and a transitional goodwill impairment test was performed. Any impairment charges resulting from the initial application of the new rules were classified as a cumulative change in accounting principle. We completed our initial transition evaluation by June 30, 2002, which is within the six-month transition period allowed by the new standard. We determined that our goodwill balances would not be impaired. Goodwill amortization for each of the years ended December 31, 2003, 2002 and 2001 was $0, $0, and $126,000, respectively. The following table presents our net income as reported in our consolidated financial statements compared to what would have been reported had SFAS 142 been in effect as of January 1, 2001 (in thousands).

In August 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” which supersedes FASB Statement No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of.” SFAS 144 also supersedes certain aspects of APB Opinion No. 30, “Reporting the Results of Operations—Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions” with regard to reporting the effects of a disposal of a segment of a business and will

require expected future operating losses from discontinued operations to be reported in discontinued operations in the period incurred rather than as of the measurement date as presently required by APB 30. Additionally, certain dispositions may now qualify for discounted operations treatment. The provisions of SFAS 144 are required to be applied for fiscal years beginning after December 15, 2001 and interim periods within those fiscal years. The adoption of this statement did not have any effect on our consolidated financial statements.

In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” SFAS 145 requires that gains or losses recorded from the extinguishment of debt that do not meet the criteria of APB 30 should not be presented as extraordinary items. This statement is effective for fiscal years beginning after May 15, 2002 as it relates to the reissued FASB Statement, with earlier application permitted. Any gain or loss on extinguishment of debt that was classified as an extraordinary item in prior periods presented that does not meet the criteria in APB 30 for classification as an extraordinary item should be reclassified. A loss of approximately $3.0 million was incurred during the third quarter of 2001 resulting from the early extinguishment of debt. This loss relates to the write-off of deferred financing costs upon the refinancing of our debt through the issuance of $175 million of senior notes in July 2001 and has been reclassified as interest expense in our consolidated financial statements.

In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS 146 nullifies EITF Issue 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity,” under which a liability for an exit cost was recognized at the date of an entity’s commitment to an exit plan. SFAS 146 requires that a liability for a cost associated with an exit or disposal activity be recognized at fair value when the liability is incurred. The provisions of this statement are effective for exit or disposal activities that are initiated after December 31, 2002. SFAS 146 had no impact on our consolidated financial statements for the year ended December 31, 2002.

In November 2002, the FASB issued FASB Interpretation No. 45, or FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” which elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of the guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of this Interpretation are applied prospectively to guarantees issued or modified after December 31, 2002. The adoption of these recognition provisions will result in recording liabilities associated with certain guarantees we may provide in the future. The disclosure requirements of this Interpretation are effective for financial statements of interim or annual periods ending after December 15, 2002. FIN 45 did not have an impact on our consolidated financial statements.

In December 2002, SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure—An Amendment of FASB Statement No. 123” was issued by the FASB and amends FASB Statement No. 123, “Accounting for Stock-Based Compensation.” This Statement provides alternative methods of transition for an entity that voluntarily changes to the fair value based method of accounting for stock-based employee compensation and amends the disclosure provisions of SFAS 123 to require prominent disclosure about the effects on reported net income of an entity’s accounting policy decisions with respect to stock-based employee compensation. We have not adopted either of the alternative methods of transition and continue to apply APB Opinion No. 25.

In January 2003, the FASB issued FIN 46, “Consolidation of Variable Interest Entities,” which clarifies the application of Accounting Research Bulletin, or ARB, No. 51, “Consolidated Financial Statements” to certain entities (called variable interest 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 disclosure requirements of this Interpretation are effective for all financial statements issued after January 31, 2003. The consolidation requirements apply to all variable interest entities created after January 31, 2003. In addition, public companies must apply the consolidation requirements to variable interest entities that existed prior to February 1, 2003 and remain in existence as of the beginning of annual or interim periods beginning after March 15, 2004. FIN 46 is not expected to have a material impact on our consolidated financial statements upon adoption.

In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” to clarify under what circumstances a contract with an initial net investment meets the characteristics of a

derivative, to clarify when a derivative contains a financing component, to amend the definition of “underlying” to conform it to language in FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” and to amend certain other existing pronouncements. SFAS 149 is effective for contracts entered into or modified after June 30, 2003, and is to be applied prospectively. Implementation of SFAS 149 did not have a material effect on our consolidated financial statements as of and for the period ended December 31, 2003, as it did not have any derivative instruments or hedging arrangements.

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” SFAS 150 requires that certain financial instruments issued in the form of shares that are mandatorily redeemable, as well as certain other financial instruments, be classified as liabilities in the financial statements. SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003 and otherwise is effective beginning with our second quarter of 2004. The provisions of this statement did not have a material impact on our consolidated financial statements as of and for the period ended December 31, 2003.

On September 9, 2003, the Accounting Standards Executive Committee, or AcSEC, of the American Institute of Certified Public Accountants voted to approve a Statement of Position, or SOP, “Accounting for Certain Costs and Activities Related to Property, Plant, and Equipment.” The SOP is expected to be presented for approval by the FASB in the second quarter of 2004. If approved, the SOP would require us to expense as incurred some or all of the recertification costs in connection with the drydocking of our vessels. The SOP was undertaken to clarify the diversity in practice that exists in accounting for these and other costs related to property, plant and equipment and has an anticipated effective date for years ending after December 15, 2005. We will continue to monitor the progress related to the potential new rules and their impact on our consolidated financial statements.

We make forward-looking statements in this Form 10-K, including certain information set forth in the sections entitled “Business and Properties” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” We have based these forward-looking statements on our current views and assumptions about future events and our future financial performance. You can generally identify forward-looking statements by the appearance in such a statement of words like “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “should” or “will” or other comparable words or the negative of these words. When you consider our forward-looking statements, you should keep in mind the cautionary statements we make in this Form 10-K.

Among the risks, uncertainties and assumptions to which these forward-looking statements may be subject are:

Our forward-looking statements are only predictions based on expectations that we believe are reasonable. Actual events or results may differ materially from those described in any forward-looking statement. We undertake no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. To the extent these risks, uncertainties and assumptions give rise to events that vary from our expectations, the forward-looking events discussed in this annual report on Form 10-K may not occur.

We have not entered into any derivative financial instrument transactions to manage or reduce market risk or for speculative purposes.

We are subject to interest rate risk on our long-term fixed interest rate senior notes. In general, the fair market value of debt with a fixed interest rate will increase as interest rates fall. Conversely, the fair market value of debt will decrease as interest rates rise. The senior notes accrue interest at the rate of 10⁵/8% per annum and mature on August 1, 2008. There are no scheduled principal payments under the senior notes prior to the maturity date. Our revolving credit facility has a variable interest rate and, therefore, is not subject to interest rate risk.

Our operations are primarily conducted between U.S. ports, including along the coast of Puerto Rico, and historically we have not been exposed to foreign currency fluctuation. However, as we expand our operations to international markets, we may become exposed to certain risks typically associated with foreign currency fluctuation. We currently have fixed time charters for three of our OSVs for service in Trinidad & Tobago. Although such contracts are denominated and will be paid in U.S. Dollars, value added tax (“VAT”) payments are paid in Trinidad dollars which creates an exchange risk related to currency fluctuations. In addition, we are currently operating under a fixed time charter with one of our other OSVs for service in Mexico. Although we are paid in U.S. Dollars, there is an exchange risk to foreign currency fluctuations related to the payment terms of such time charter. To date, we have not hedged against any foreign currency rate fluctuations associated with foreign currency VAT payments or other foreign currency denominated transactions arising in the normal course of business. We continually monitor the currency exchange risks associated with conducting international operations. To date, gains or losses associated with such fluctuations have not been material.

The financial statements and information required by this Item appear on pages F-1 through F-22 of this report.

Item 9—Changes in and Disagreements with Accountants on Accounting and Financial Disclosures

Effective June 24, 2002, we dismissed Arthur Andersen LLP as our independent public accountants and auditors and engaged Ernst & Young LLP as our new independent public accountants and auditors. The decision to change our independent public accountants and auditors was approved by our board of directors upon the recommendation of our audit committee. For more information, please refer to our Report on Form 8-K filed on June 26, 2002.

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under

the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

We also maintain a system of internal accounting controls that are designed to provide reasonable assurance that our books and records accurately reflect our transactions and that our policies and procedures are followed. There have not been any changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fiscal quarter to which this report relates that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Todd M. Hornbeck has served as our President and Secretary and as a director since our formation in June 1997. Until February 2002, he also served as Chief Operating Officer. In February 2002, he was appointed Chief Executive Officer. Mr. Hornbeck worked for the original Hornbeck Offshore Services, Inc., a publicly traded offshore service vessel company, from 1991 to 1996, serving in various positions relating to business strategy and development. Following the merger of Hornbeck Offshore Services, Inc. with Tidewater, Inc. (NYSE:TDW) in March 1996, he accepted a position as Marketing Director—Gulf of Mexico with Tidewater, where his responsibilities included managing relationships and overall business development in the U.S. Gulf of Mexico region. He remained with Tidewater until our formation. Mr. Hornbeck is the son of Larry D. Hornbeck and serves as a board designee for himself and his brother, Troy A. Hornbeck, in accordance with a stockholders’ agreement.

Carl G. Annessa has served as our Vice President of Operations since September 1997. In February 2002, he was appointed Vice President and Chief Operating Officer. Mr. Annessa is responsible for operational oversight and design and implementation of our vessel construction program. Prior to joining us, he was employed for 17 years by Tidewater, Inc. in various technical and operational management positions, including management of large fleets of OSVs in the Arabian Gulf, Caribbean and West African markets, and was responsible for the design of several of Tidewater’s vessels. Mr. Annessa was employed for two years by Avondale Shipyards, Inc. as a naval architect before joining Tidewater. Mr. Annessa received a degree in naval architecture and mechanical engineering from the University of Michigan in 1979.

James O. Harp, Jr. has served as our Vice President and Chief Financial Officer since January 2001. Prior to joining us, Mr. Harp served as Vice President in the Energy Group of RBC Dominion Securities Corporation, an investment banking firm, from August 1999 to January 2001 and as Vice President in the Energy Group of Jefferies & Company, Inc., an investment banking firm, from June 1997 to August 1999. During his investment banking career, Mr. Harp worked extensively with marine-related oil service companies, including as our investment banker in connection with our private placement of common stock in November 2000. From July 1982 to June 1997 he served in a variety of capacities, most recently as Tax Principal, with Arthur Andersen LLP, and had a significant concentration of international clients in the oil service and maritime industries. Since April 1992, he has also served as Treasurer and Director of SEISCO, Inc., a seismic brokerage company.

Timothy P. McCarthy has served as our Controller since May 2002. Prior to joining us, Mr. McCarthy served in a variety of capacities, most recently as an Audit Manager, in the assurance practice section of the New Orleans office of Arthur Andersen LLP from July 1994 to May 2002. Previously, he served in the foreign joint interest accounting group with Ocean Drilling and Exploration Company. Mr. McCarthy is a certified public accountant.

Paul M. Ordogne has served as our Treasurer since our formation in June 1997. Until May 2002, he also served as our Controller. From 1980 to June 1997, he worked for Cari Investment Company, a privately owned holding company for energy-related investments, serving in various financial and accounting positions, including those of controller and assistant treasurer. Mr. Ordogne is a certified public accountant.

Bernie W. Stewart has served as one of our directors since November 2001 and was appointed Chairman of the Board in February 2002. Mr. Stewart was Senior Vice President, Operations of R&B Falcon Corporation, a contract drilling company, and President of R&B Falcon Drilling U.S., its domestic operating subsidiary, from May 1999 until R&B Falcon Corporation (NYSE:FLC) merged with Transocean Sedco Forex Inc. (NYSE:RIG) in January 2001. Between April 1996 and May 1999, he served as Chief Operating Officer of R&B Falcon Holdings, Inc. and as its President from January 1998. From 1993 until joining R&B Falcon Holdings, he was Senior Vice President and Chief Operating Officer for the original Hornbeck Offshore Services, Inc., a publicly traded offshore service vessel company, where he was responsible for overall supervision of the company’s operations. From 1986 until 1993, he was President of Western Oceanics, Inc., an offshore drilling contractor. Since leaving R&B Falcon Corporation upon its merger with Transocean Sedco Forex, Mr. Stewart has been an independent business consultant. From February 27, 2002 to February 27, 2003, Mr. Stewart advised the company under an advisory services agreement discussed below.

Richard W. Cryar has served as one of our directors since our formation in June 1997. Since 1994, he has served as Managing Member of Cari Capital Company, L.L.C., a merchant banking firm. Since October 1999, Mr. Cryar has served as a general partner in the equity fund, Audubon Capital Fund I, L.P. Mr. Cryar serves as a board designee of Cari Investment Company in accordance with a stockholders’ agreement.

Larry D. Hornbeck has served as one of our directors since August 2001. An executive with over 30 years experience in the OSV business worldwide, Mr. Hornbeck was the founder of the original Hornbeck Offshore Services, Inc., a publicly traded offshore service vessel company with over 100 vessels operating worldwide. From its inception in 1981 until its merger with Tidewater Inc., Mr. Hornbeck served as Chairman of the Board, President and Chief Executive Officer of the original Hornbeck Offshore Services. Following the merger, Mr. Hornbeck served as a director of Tidewater from March 1996 until October 2000. From 1969 to 1980, Mr. Hornbeck was Chairman, President and Chief Executive Officer of Sealcraft Operators, Inc., a publicly held, specialty service OSV company operating worldwide. Mr. Hornbeck is the father of Todd M. Hornbeck and serves as a board designee for Todd M. Hornbeck and Troy A. Hornbeck in accordance with a stockholders’ agreement.

Bruce W. Hunt has served as one of our directors since August 1997. He has been President of Petrol Marine Corporation since 1988 and President and Director of Petro-Hunt, L.L.C. since 1997, each of which is an energy-related company. Mr. Hunt served as a director of the original Hornbeck Offshore Services, Inc., a publicly traded offshore service vessel company, from November 1992 to March 1996.

Patricia B. Melcher joined our board of directors in October 2002. Ms. Melcher has served as the President of Allegro Capital Management, Inc., a privately-owned investment company focused on private equity investments in and consulting to energy-related companies, since 1997, and has served as Interim CEO of Petrocom Energy Ltd., a privately held energy trading firm, since October 1, 2003. From 1989 to 1994, she worked for SCF Partners, L.P., an investment fund sponsor specializing in private equity investments in oilfield service companies, and from 1995 to 1997, she served as a board member and advisory board member of its general partner, L. E. Simmons & Associates, Incorporated. From 1986 to 1989, Ms. Melcher worked for Simmons & Company International, an investment banking firm serving the energy industry.

David A. Trice joined our board of directors in October 2002. Mr. Trice has served as the President of Newfield Exploration Company (NYSE:NFX), an independent oil and gas company engaged in the exploration, development and acquisition of crude oil and natural gas properties since May 1999. At Newfield, he has also served as the Chief Executive Officer since February 2000 and as a director since 2000. From May 1999 to February 2000, he served as its Chief Operating Officer and from July 1997 to May 1999, he served as its Vice President—Finance and International. Mr. Trice

served as the President, Chief Executive Officer and Director of the Huffco Group, an offshore drilling contractor, from 1991 to July 1997.

Christian G. Vaccari has served as one of our directors since our formation in June 1997 and served as our Chairman of the Board and Chief Executive Officer from June 1997 until February 2002. Since 1989, Mr. Vaccari has served as President, Chief Executive Officer and Chairman of the Board of Cari Investment Company. From 1988 to 1994, he served as Director of Corporate Development and Marketing for JAMO, Inc., a leading building materials company in the southeastern United States. From 1984 to 1988, Mr. Vaccari was an investment advisor with Thomson McKinnon, Inc., an investment banking firm. Since July 1997, Mr. Vaccari has served as a director of Riverbarge Excursion Lines, Inc. and since October 1999, he has served as a general partner in the equity fund, Audubon Capital Fund I, L.P. Mr. Vaccari serves as a board designee of Cari Investment Company in accordance with a stockholders’ agreement.

Andrew L. Waite has served as one of our directors since November 2000. He was appointed to our board as the designee of SCF-IV, L.P. in accordance with a stockholders’ agreement. Mr. Waite is a Managing Director of L.E. Simmons & Associates, Incorporated and has been an officer of that company since October 1995. He was previously Vice President of Simmons & Company International, an investment banking firm serving the energy industry, where he served from August 1993 to September 1995. From 1984 to 1991, Mr. Waite held a number of engineering and management positions with the Royal Dutch/Shell Group, an integrated oil and gas company. He currently serves as a director of Oil States International, Inc. (NYSE:OIS), a diversified oilfield equipment and service company.

Our board of directors has a compensation committee comprised of Messrs. Stewart, Hunt and Trice, which:

The board has also established an audit committee comprised of Ms. Melcher and Messrs. Hunt and Stewart. The audit committee recommends to the board the independent public accountants to audit our annual financial statements. The board selects the independent public accountants, subject to shareholder approval. The audit committee also establishes the scope of, and oversees, the annual audit and approves any other services provided by public accounting firms. The board has determined that Ms. Melcher is an independent director and qualifies as the “audit committee financial expert” as defined in Item 401(b) of Regulation S-K of the Securities Exchange Act of 1934, based on her previous experiences as an investment banker and in other finance-related capacities, as described in her biographical information under “Management—Executive Officers and Directors.” The audit committee provides assistance to the board in fulfilling its oversight responsibility to the stockholders, potential stockholders, the investment community and others relating to the integrity of our financial statements, our compliance with legal and regulatory requirements, the independent auditor’s qualifications and independence, the performance of our internal audit function and independent auditor, and oversees our system of disclosure controls and procedures and system of internal controls regarding finance, accounting, legal compliance and ethics that management and the board have established. In doing so, it is the responsibility of the committee to maintain free and open communication between the committee and our independent auditors, the internal accounting function and management of the company.

The board has also established an ad hoc committee comprised of Messrs. Todd Hornbeck, Larry Hornbeck, Waite, Hunt and Stewart. The purpose of this committee is to address any issues related to the separation of Christian G. Vaccari (who ceased serving as our Chief Executive Officer and Chairman of the Board in February 2002) from the company, including our ongoing relationship with Mr. Vaccari, his family, Cari Investment Company (which is the holder of more than 5% of our common stock and for which Mr. Vaccari serves as President, Chief Executive Officer and Chairman of the Board) and certain shipyards affiliated with Mr. Vaccari and with which we have contracted from time to time for the construction of certain of our OSVs.

Our board may establish other committees from time to time to facilitate the management of the business and affairs of our company.

The compensation committee currently consists of Messrs. Stewart, Hunt and Trice. None of our executive officers, employees or former executive officers serve on the compensation committee. None of our executive officers serves as a member of a compensation committee or board of directors of any other entity which has an executive officer serving as a member of our board of directors.

The members of our board of directors are divided into three classes and are elected for a term of three years, or until a successor is duly elected and qualified. The terms of office of the Class I, Class II and Class III directors expire at the annual meeting of stockholders to be held in 2004, 2006 and 2005, respectively.

Directors who are also our employees receive no additional compensation for serving as directors or committee members. Non-employee directors historically have received compensation in the form of stock option grants for their service as directors.

Effective July 18, 2002, the board of directors approved a compensation plan applicable to our non-employee directors. Each non-employee director is entitled to receive a total annual retainer of $20,000, paid quarterly. Each non-employee director is also entitled to receive $1,200 for each board meeting attended in person and $800 for each board meeting attended by telephonic communications. Board committee members are entitled to receive $600 for each committee meeting attended, with the committee chairman entitled to receive $800 for each committee meeting attended. Committee members must attend meetings in person or by telephonic communications to receive the applicable compensation. Non-employee directors are entitled to receive a minimum annual grant of 2,000 options to purchase common stock with such options being granted under the Incentive Compensation Plan. The minimum annual grant is subject to annual review and may be increased at the discretion of the compensation committee. After three years of service as a non-employee director, a non-employee director and his immediate family may elect to participate in the same insurance benefit programs sponsored by the company on the same monetary terms as the executive officers. Effective May 6, 2003, the board of directors approved a modification to the compensation plan to provide that the chairman of the board be paid $1,800 for each regularly scheduled board meeting and $1,500 for each special board meeting. All directors are reimbursed for their out-of-pocket expenses incurred in connection with serving on our board.

The non-employee director compensation plan also provides for longevity service awards to non-employee directors. Upon completion of three years of service following adoption of the compensation plan, a director will be granted options to purchase the number of shares of common stock equaling 25% of the options granted to such director over the previous three years. Upon completion of five years of service as a non-employee director, a director will be granted options to purchase the number of shares of common stock equaling 50% of the options granted to such director over the previous five years less the number of shares covered by the options awarded to such director after three years of service. Thereafter, upon completion of each successive period of five years of service, a non-employee director will be granted options to purchase the number of shares of common stock equaling 50% of the options granted to such director over the previous five years. Under the terms of this compensation plan, neither Mr. Cryar nor Mr. Vaccari qualifies to participate.

In addition to the cash compensation received for their service as directors during 2003 under the terms of the plan described above, in March 2004 each of Ms. Melcher and Messrs. Larry Hornbeck, Hunt, Stewart, Trice and Waite were granted options to purchase shares of our common stock. Although the plan provides for the grant of options to purchase a minimum of 2,000 shares of common stock, as permitted under the plan, the Compensation Committee elected to award such directors options to purchase 4,000 shares of our common stock at an exercise price of $13.83 per share. One third of these options will become exercisable on each of the first three anniversaries of the date of grant.

On February 27, 2002, we entered into an advisory agreement with Bernie W. Stewart, our Chairman of the Board. Under the terms of this agreement, Mr. Stewart advised and made recommendations to our executive officers and board of directors on matters relating to our business, including our operations, finances, strategic planning and acquisitions. Mr. Stewart provided these services on a full-time basis through May 31, 2002 and on a part-time basis through February 27, 2003, at which time the agreement expired. He received $20,000 per month for his full-time advisory services and $8,335 per month for his part-time services. Under the terms of his advisory agreement, Mr. Stewart was granted options to

purchase 4,000 shares of our common stock at an exercise price of $6.63 per share. Also under the terms of the advisory agreement, Mr. Stewart purchased 30,189 shares of our common stock at a purchase price of $6.63 per share, and, upon such purchase, we granted Mr. Stewart an option to purchase 15,094 shares of our common stock at a purchase price of $6.63 per share, to be exercised in accordance with, and subject to the terms of our Incentive Compensation Plan. Mr. Stewart has agreed that for a period of two years following the expiration of the agreement, he will not solicit any of our employees, customers, suppliers or sales agents to terminate their relationship with us or employ or cause any of our competitors to employ any person who is or was recently one of our employees, sales representatives, contractors, advisors or agents.

The Company has adopted a code of ethics that applies to its principal executive officer and principal financial officers. A copy of this code is available to any person upon request at no charge. Requests should be directed to the Secretary of the Company at its principal executive office at the address and phone number as shown on the cover of this report.

The following table sets forth compensation information for the chief executive officer and our other executive officers whose total annual salary and bonus exceeded $100,000 for the years ended December 31, 2003, 2002, and 2001.

During the year ended December 31, 2003, other than as described below, we did not grant any options to acquire shares of our common stock to the executive officers named in the Summary Compensation Table above.

The following tables show information with respect to the exercise of options to purchase our common stock and all unexercised options held by the executive officers named in the Summary Compensation Table as of December 31, 2003. None of the executive officers named in the Summary Compensation Table have exercised any options to purchase our common stock during 2003.

Todd M. Hornbeck serves as our President, Chief Executive Officer and Secretary, Carl G. Annessa serves as our Vice President and Chief Operating Officer, James O. Harp, Jr. serves as our Vice President and Chief Financial Officer and Paul M. Ordogne serves as our Treasurer. Each of Messrs. Hornbeck, Annessa and Harp serves under an

employment agreement, as amended, with an initial term expiring December 31, 2006. On January 1, 2005, and on every January 1 thereafter, each of their agreements will automatically renew for one additional year, unless terminated before any such renewal date by the employee or us. Mr. Ordogne served under an employment agreement that expired December 31, 2003.

The employment agreements of Messrs. Hornbeck, Annessa and Harp, in each case, as amended, currently provide for annual base salaries of $240,000, $200,000 and $185,000 respectively, subject to review from time to time by our compensation committee for possible increases based on the employee’s performance. Our board has agreed to award a bonus or bonuses to each of Messrs. Hornbeck, Annessa and Harp if our company meets certain EBITDA and earnings per share targets with respect to any year during which their respective employment agreements are in effect. Our board may, in its discretion, award a smaller bonus if our company does not meet such targets or an additional bonus if our company exceeds such targets.

If, during the terms of their respective agreements, we terminate the employment of Messrs. Hornbeck, Annessa or Harp for any reason other than for cause, he will be entitled to receive his salary until the actual termination date of his agreement. If we should undergo a change in control while the agreements are in effect and Messrs. Hornbeck, Annessa or Harp is either constructively or actually terminated under the conditions set forth in his agreement, then he will be entitled to receive three times his salary for the year in which the termination occurs and, in general, three times the bonus he received for the previous year.

Mr. Hornbeck has agreed that during the term of his agreement and Messrs. Annessa and Harp have each agreed that during the term of their respective agreements and for a period of one year after termination, they will not (1) be employed by or associated with or own more than five percent of the outstanding securities of any entity that competes with us in the locations in which we operate, (2) solicit any of our employees to terminate their employment or (3) accept employment with or payments from any of our clients or customers who did business with us while employed by us. We may elect to extend Mr. Annessa’s noncompetition period for an additional year by paying his compensation and other benefits for an additional year.

Item 12—Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following table sets forth certain information regarding the beneficial ownership of our voting securities as of March 5, 2004:

Unless otherwise indicated, each person named below has an address in care of our principal executive offices and has sole power to vote and dispose of the shares of voting securities beneficially owned by them, subject to community property laws where applicable.

Voting Agreements. Under the terms of a stockholders’ agreement among SCF-IV, L.P., Todd M. Hornbeck, Troy A. Hornbeck, Cari Investment Company and the Company, Todd and Troy Hornbeck and Cari Investment Company have agreed to vote their shares in favor of SCF-IV, L.P.’s designee to our board, so long as SCF-IV, L.P. owns at least 5.0% of

our outstanding common stock or, prior to an initial public offering, it owns at least 80.0% of the common stock it acquired in November 2000. Under this agreement, SCF-IV, L.P. also agrees to vote its shares in favor of the two designees of Todd and Troy Hornbeck and the two designees of Cari Investment Company to the board of directors. Pursuant to a voting arrangement entered into between SCF-IV, L.P. and us in connection with our private equity offering completed in October 2001, SCF is restricted from voting 269,346 of its shares.

Under the terms of a voting agreement among Todd M. Hornbeck, Troy A. Hornbeck, Cari Investment Company and the Company, the Hornbecks and Cari Investment Company had agreed to vote their shares in such manner as to maintain equal representation of Todd and Troy Hornbeck, on the one hand, and Cari Investment Company, on the other hand, on our board and on any committee designated by our board until the earlier of completion of an initial public offering of our securities, the tenth anniversary of the agreement or certain other events specified in the Agreement. As a result of the closing of the registered exchange offer of our senior notes, it is our position and that of Todd and Troy Hornbeck that this voting agreement has terminated. Christian G. Vaccari, as representative of Cari Investment Company, has indicated that Cari Investment Company does not agree.

Registration Rights. Under the terms of a stockholders’ agreement among Todd M. Hornbeck, Troy A. Hornbeck, Cari Investment Company and us, Todd and Troy Hornbeck and Cari Investment Company are entitled to require us to file a registration statement under the Securities Act of 1933 to sell some or all of the shares of our common stock held by them. We are only required to make one such stand-alone registration for each of Todd and Troy Hornbeck and one for Cari Investment Company. In addition, holders of a majority of the shares of our common stock issued to the Hornbecks and Cari Investment Company on June 5, 1997 and shares issued with equivalent registration rights to other persons or entities may require us to register some or all of such shares if they have not already been registered and may not then be sold under Rule 144(k) of the Securities Act of 1933. Todd and Troy Hornbeck and Cari Investment Company also have the right to include some or all of their shares of common stock in any other registration statement that we file involving our common stock, subject to certain limitations.

Under the terms of a registration rights agreement among SCF IV, L.P., certain other stockholders that purchased shares of our common stock in the private placement of our common stock completed in November 2000 and us, such stockholders have the right to include some or all of such shares, and any shares issued in respect of such shares, in any registration statement that we file involving our common stock, subject to certain limitations. Also under the agreement, the holders of a majority of the shares of our common stock issued in the November 2000 private placement are entitled to require us to file a registration statement under the Securities Act of 1933 to sell some or all of the common stock held by them. At this time, only SCF-IV, L.P. holds a majority of these shares.

Under the terms of a registration rights agreement among us and several stockholders that purchased shares of our common stock in the private placement completed in July 2003, such stockholders have the right to include some or all of such shares, and any shares issued in respect of such shares, in any registration statement that we file involving our common stock, subject to certain limitations.

Contractual Restrictions on Transfer by Certain Stockholders. Todd M. Hornbeck, Troy A. Hornbeck and Cari Investment Company have agreed, beginning after we become a reporting company under the Securities Exchange Act of 1934, to give us notice of and an opportunity to make a competing offer regarding a decision by any of them to sell or consider accepting an offer to sell to a single person or entity shares of common stock representing 5.0% or more of our common stock, other than in compliance with Rule 144 or to an affiliate or family member of the holder. SCF-IV, L.P. has also agreed to give us notice of and an opportunity to make a competing offer regarding a decision by it to sell or consider accepting an offer to sell to a single person or entity shares of common stock representing 5.0% or more of our common stock. SCF-IV, L.P. is further prohibited from transferring any of its shares of our common stock to any person or entity that is a competitor of ours. In addition, certain purchasers that participated in our 2003 private placement agreed to a similar restriction prohibiting the transfer of any of their shares of our common stock to any person or entity that is a competitor of ours. Additionally, it is our position and that of Todd M. Hornbeck and Troy A. Hornbeck that, under the terms of an agreement entered into in 1998, until the earlier to occur of (i) the closing by the Company of an initial public offering of its common stock where the aggregate proceeds to the Company are at least $25 million or (ii) May 15, 2005, Todd M. Hornbeck, Troy A. Hornbeck and Cari Investment Company have each agreed not to transfer any of our common stock, except to immediate family members, trusts or partnerships created for the benefit of immediate family members or certain other related parties. Christian G. Vaccari, as representative of Cari Investment Company, has indicated that Cari Investment Company does not agree with such position.

Our board of directors and shareholders adopted an Incentive Compensation Plan. The purpose of the Incentive Compensation Plan is to strengthen our company by providing an incentive to our employees, officers, consultants, non-employee directors and advisors to devote their abilities and energies to our success. The plan provides for the granting or awarding of incentive and nonqualified stock options, stock appreciation and dividend equivalent rights, restricted stock and performance shares. All outstanding awards relate to our common stock. With the approval of our stockholders, we have reserved 3.5 million shares (after giving effect to the 1-for-2.5 reverse stock split) of our common stock for issuance pursuant to awards made under the plan, of which 2,168,956 shares were available for future grants as of March 5, 2004.

The following table summarizes information as of December 31, 2003 about our Incentive Compensation Plan. Further information regarding our Incentive Compensation Plan can be found in Note 9 of our consolidated financial statements included herein.

The Incentive Compensation Plan is administered by the compensation committee. Subject to the express provisions of the plan, the compensation committee has full authority, among other things:

Under the plan, awards other than stock options and stock appreciation rights given to any of our executive officers whose compensation must be disclosed in our annual securities filings and who is subject to the limitations imposed by Section 162(m) of the tax code must be based on the attainment of certain performance goals established by the board of directors or the compensation committee. The performance measures are limited to earnings per share, return on assets, return on equity, return on capital, net profits after taxes, net profits before taxes, operating profits, stock price and sales or expenses. Additionally, the performance goals must include formulas for calculating the amount of compensation payable if the goals are met; and both the goals and the formulas must be sufficiently objective so that a third party with knowledge of the relevant performance results could assess that the goals were met and calculate the amount to be paid.

Consistent with certain provisions of the tax code, there are other restrictions providing for a maximum number of shares that may be granted in any one year to a named executive officer and a maximum amount of compensation payable as an award under the plan (other than stock options and stock appreciation rights) to a named executive officer.

The following is a discussion of transactions between our company and its executive officers, directors and shareholders owning more than 5% of our common stock. We believe that the terms of each of these transactions were at least as favorable as could have been obtained in similar transactions with unaffiliated third parties.

Effective May 29, 2002, we changed our name to Hornbeck Offshore Services, Inc. from HORNBECK-LEEVAC Marine Services, Inc., and one of our subsidiaries changed its name to Hornbeck Offshore Transportation, LLC from LEEVAC Marine, LLC. In connection with these name changes, we terminated a cross-license with Cari Investment Company covering the use of the name “LEEVAC” and certain logos associated with such name, and assigned all of our interests therein to Cari Investment Company. In consideration for the assignment, Cari Investment Company agreed not to use the name “LEEVAC” or its related logos in any activity that would compete with our business. Cari Investment Company is a holder of more than 5% of our common stock and Christian G. Vaccari, who served as our Chairman of the Board and Chief Executive Officer until February 2002 and who serves as one of our directors, is the President, Chief Executive Officer and Chairman of the Board of Cari Investment Company.

Mr. Vaccari is also a member of LEEVAC Industries, LLC. Two of our OSVs delivered in 2002 and three delivered in 2003 were built by LEEVAC Industries. As of December 31, 2003, we had a contract with LEEVAC Industries for the completion of the HOS Silverstar, which was delivered in January 2004, and the construction of one double-hulled tank barge. Between January 1, 2002 and December 31, 2003, we made payments under various shipyard contracts with LEEVAC Industries aggregating $45.9 million, and at December 31, 2003 our remaining contracts with LEEVAC Industries provided for the payment of an additional $17.7 million for the remaining construction of the HOS Silverstar and the construction of the double-hulled tank barge, the delivery of which is expected in December 2004. We entered into our current and past contracts with LEEVAC Industries following a competitive bidding process. In connection with our contract with LEEVAC Industries relating to the construction of four vessels under our most recent OSV newbuild program, we received a fairness opinion from an independent appraiser with respect to the terms of the transaction.

In 2002, the board approved an amendment to Mr. Cryar’s outstanding stock options providing for full vesting at the closing of an initial public offering of our common stock of any unvested options previously granted to Mr. Cryar. As a result, options covering 2,800 shares of our common stock that would not otherwise be exercisable at that time will become exercisable at the closing of any such offering.

We have entered into registration rights agreements, voting agreements and stockholders’ agreements with Todd M. Hornbeck, Troy A. Hornbeck, Cari Investment Company and SCF-IV, L.P. Please read the sections entitled “Principal Stockholders—Voting Agreements,” “Description of Capital Stock—Common Stock,” “—Registration Rights” and “—Anti-Takeover Effects of Certificate, Bylaws, Stockholder Rights Plan and Delaware Law” for information regarding the terms of these agreements.

The following table presents fees for professional audit services rendered by Ernst & Young LLP for the audit of the Company’s annual financial statements for the years ended December 31, 2003 and December 31, 2002, and fees billed for other services rendered by Ernst & Young LLP during those periods.

The Audit Committee has considered whether the provision of services to the Company, other than audit services, is compatible with maintaining Ernst & Young LLP’s independence from the Company.

Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Auditor.

The Audit Committee is responsible for appointing, setting compensation, and overseeing the work of the independent auditor. The Audit Committee has established a policy regarding pre-approval of all audit and permissible non-audit services provided by the independent auditor. Requests for approval are generally submitted at a meeting of the Audit Committee.

1. Financial Statements. The financial statements and information required by Item 8 appear on pages F-1 through F-22 of this report. The Index to Consolidated Financial Statements appears on page F-1.

2. Financial Statement Schedules. All schedules are omitted because they are not applicable or the required information is shown in the financial statements or the notes thereto.

On November 6, 2003, we furnished a report on Form 8-K announcing that we had issued a press release that reported third quarter 2003 results, the delivery of the 240 ED class HOS Greystone, the commencement of a double-hulled tank barge newbuild program and the expansion of our revolving credit facility.

On February 19, 2004, we furnished a report on Form 8-K announcing that we had issued a press release that reported the results of our operations for the three months ended December 31, 2003, and certain recent developments.

We have audited the accompanying consolidated balance sheets of Hornbeck Offshore Services, Inc. and subsidiaries as of December 31, 2003 and 2002, and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with 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 financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Hornbeck Offshore Services, Inc. and subsidiaries 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.

As discussed in Note 2 to the financial statements, effective January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets.”

Hornbeck Offshore Services, Inc. (or the Company) was incorporated in the state of Delaware in 1997. The Company wholly owns Hornbeck Offshore Transportation, LLC, Hornbeck Offshore Services, LLC, HOS-IV, LLC, Hornbeck Offshore Operators, LLC and Energy Services Puerto Rico, LLC. All of the subsidiaries were converted from C corporations to limited liability companies (or LLCs) in 2001. The accompanying financial statements include the accounts of the Company and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated.

Hornbeck Offshore Services, LLC (HOS) operates offshore supply vessels (OSVs) to provide support and specialty services to the offshore oil and gas exploration and production industry, primarily in the U.S. Gulf of Mexico and select international markets. In two separate acquisitions, on June 26, 2003 and August 8, 2003, a wholly-owned subsidiary of the Company, HOS-IV, LLC, acquired a total of six new generation OSVs from Candy Marine Investment Corporation (see Note 16). Hornbeck Offshore Transportation, LLC (HOT) operates ocean-going tugs and tank barges that provide transportation of petroleum products. On May 31, 2001, the Company purchased a fleet of nine ocean-going tugs and nine ocean-going tank barges and the related coastwise transportation businesses from the Spentonbush/Red Star Group, affiliates of Amerada Hess Corporation. HOT services the northeastern seaboard of the United States and Puerto Rico. The results of these acquisitions have been included since the date of acquisition (see Note 16). Hornbeck Offshore Operators, LLC (HOO) is a service subsidiary that provides administrative and personnel support to the other subsidiaries. Energy Services Puerto Rico, LLC (ESPR) provides administrative and personnel support to vessels operating in Puerto Rico.

During 2002, the Company obtained a 49% interest in Hornbeck Offshore Trinidad and Tobago Limited (HOTT). HOTT is a vessel crewing and management services company established to support the Company’s Trinidad-based operations. The 49% interest owned by the Company is being recorded using the equity method. The Company’s equity in income from investments is not material.

HOS charters its OSVs to clients under time charters based on a daily rate of hire and recognizes revenue as earned on a daily basis during the contract period of the specific vessel.

HOT contracts its vessels to clients primarily under contracts of affreightment, under which revenue is recognized based on the number of days incurred for the voyage as a percentage of total estimated days applied to total estimated revenues. Voyage related costs are expensed as incurred. Substantially all voyages under these contracts are less than 10 days in length. HOT also contracts certain of its vessels under time charters based on a daily rate of hire. Revenue is recognized on such contracts as earned on a daily basis during the contract period of the specific vessel.

Cash and cash equivalents consist of all highly liquid investments in money market funds and investments available for current use with an initial maturity of three months or less.

Property, plant and equipment are recorded at cost. Depreciation and amortization of equipment and leasehold improvements are computed using the straight-line method based on the estimated useful lives of the related assets. Major modifications and improvements, which extend the useful life of the vessel, are capitalized and amortized over the remaining useful life of the vessel. Gains and losses from retirements or other dispositions are recognized as incurred.

All of the Company’s single-hulled tank barges have estimated useful lives based on their classification under the Oil Pollution Act of 1990, while the Company’s double-hulled tank barges have an estimated useful life of 25 years.

The Company’s tugs, tank barges, and OSVs are required by regulation to be recertified after certain periods of time. The Company defers the drydocking expenditures incurred due to regulatory marine inspections and amortizes the costs on a straight-line basis over the period to be benefited from such improvements (generally 30 or 60 months). Financing charges are amortized over the term of the related debt using the interest method.

Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases.

Deferred tax assets and liabilities are measured using currently enacted tax rates. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. The provision for income taxes includes provisions for federal, state and foreign income taxes.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

Customers are primarily major and independent, domestic and international, oil and oil service companies. The Company’s customers are granted credit on a short-term basis and related credit risks are considered minimal. The Company usually does not require collateral. The Company provides an estimate for uncollectible accounts based primarily on management’s judgment. Management uses historical losses, current economic conditions and individual evaluations of each customer to make adjustments to the allowance for doubtful accounts. The Company’s historical losses have not been significant. However, because amounts due from individual customers can be significant, future adjustments to the allowance can be material if one or more individual customer’s balances are deemed uncollectible.

Property taxes receivable represents assessed property taxes on the Company’s vessels by local municipalities that are refunded upon the filing of state tax returns.

Goodwill reflects the excess of cost over the estimated fair value of the net assets acquired. Before January 1, 2002, realization of goodwill was periodically assessed by management based on the expected future profitability and undiscounted future cash flows of acquired entities and their contribution to the overall operations of the Company. If the review indicated that the carrying value was not recoverable, the excess of the carrying value over the undiscounted cash flow was recognized as an impairment loss. Effective January 1, 2002, the Company has performed goodwill impairment reviews by reporting unit based on a fair value concept as required by Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets.” See Recent Accounting Pronouncements.

SFAS No. 123, “Accounting for Stock-Based Compensation” established accounting and disclosure requirements using a fair-value-based method of accounting for stock-based employee compensation plans. As provided for under SFAS 123, the Company accounts for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees.” For all periods presented, the Company has used the intrinsic value method, in which compensation cost for stock options, if any, is measured as the excess of the estimated fair value market price of the Company’s stock at the date of grant over the amount an employee must pay to acquire the stock.

When events or circumstances indicate that the carrying amount of long-lived assets to be held and used or intangible assets might not be recoverable, the expected future undiscounted cash flows from the assets are estimated and compared with the carrying amount of the assets. If the sum of the estimated undiscounted cash flows is less than the carrying amount of the assets, an impairment loss is recorded. The impairment loss is measured by comparing the fair value of the assets with their carrying amounts. Fair value is determined based on discounted cash flow or appraised values, as appropriate. Long-lived assets that are held for disposal are reported at the lower of the assets’ carrying amount or fair value less costs related to the assets’ disposition.

In July 2001, the FASB issued SFAS 142, “Goodwill and Other Intangible Assets.” Under SFAS 142, goodwill and indefinite-lived intangible assets are no longer amortized but are reviewed for impairment annually, or more frequently if circumstances indicate potential impairment. Separable intangible assets that are not deemed to have an indefinite life will continue to be amortized over their useful lives. For goodwill and indefinite-lived intangible assets acquired prior to July 1,

2001, goodwill continued to be amortized through 2001, at which time amortization ceased and a transitional goodwill impairment test was required to be performed. Any impairment charges resulting from the initial application of the new rules were classified as a cumulative change in accounting principle. The initial transition evaluation was completed by June 30, 2002, which was within the six-month transition period allowed by the new standard. The Company’s goodwill balances were determined not to be impaired. Goodwill amortization for each of the years ended December 31, 2003, 2002 and 2001 was $0, $0 and $126, respectively.

The following table presents the Company’s net income as reported in the Company’s consolidated financial statements compared to that which would have been reported if SFAS 142 had been in effect as of January 1, 2001.

In August 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” which supersedes FASB Statement No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of.” SFAS 144 also supersedes certain aspects of APB Opinion No. 30, “Reporting the Results of Operations-Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions” with regard to reporting the effects of a disposal of a segment of a business and will require expected future operating losses from discontinued operations to be reported in discontinued operations in the period incurred rather than as of the measurement date as presently required by APB Opinion 30. Additionally, certain dispositions may now qualify for discontinued operations treatment. The provisions of SFAS 144 are required to be applied for fiscal years beginning after December 15, 2001 and interim periods within those fiscal years. The adoption of this statement did not have any effect on the Company’s consolidated financial statements.

In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS 146 nullifies EITF Issue 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity,” under which a liability for an exit cost was recognized at the date of an entity’s commitment to an exit plan. SFAS 146 requires that a liability for a cost associated with an exit or disposal activity be recognized at fair value when the liability is incurred. The provisions of this statement are effective for exit or disposal activities that are initiated after December 31, 2002. SFAS 146 had no impact on the consolidated financial statements of the Company for the year ended December 31, 2002.

In November 2002, the FASB issued FASB Interpretation No. 45, or FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” which elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of the guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of FIN 45 are applied prospectively to guarantees issued or modified after December 31, 2002. The adoption of these recognition provisions will result in recording liabilities associated with certain guarantees if and when provided by the Company. The disclosure requirements of FIN 45 are effective for financial statements of interim or annual periods ending after December 15, 2002. FIN 45 did not have an impact on the Company’s consolidated financial statements. The Company has no guarantees applicable under FIN 45.

In December 2002, SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure—An Amendment of FASB Statement No. 123,” was issued by the FASB and amends SFAS 123, “Accounting for Stock-Based Compensation.” SFAS 148 provides alternative methods of transition for an entity that voluntarily changes to the fair value based method of accounting for stock-based employee compensation and amends the disclosure provisions of SFAS 123 to require prominent disclosure about the effects on reported net income of an entity’s accounting policy decisions with respect to stock-based employee compensation. The Company has not adopted any of the alternative methods of transition and continues to apply APB Opinion No. 25.

In January 2003, the FASB issued FIN 46, “Consolidation of Variable Interest Entities,” which clarifies the application of Accounting Research Bulletin (ARB) No. 51, “Consolidated Financial Statements,” to certain entities (called variable interest 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 disclosure requirements of this Interpretation are effective for all financial statements issued after January 31, 2003. The consolidation requirements apply to all variable interest entities created after January 31, 2003. In addition, public companies must apply the consolidation requirements to variable interest entities that existed prior to February 1, 2003 and remain in existence as of the beginning of annual or interim periods beginning after March 15, 2004. FIN 46 is not expected to have a material impact on the Company’s consolidated financial statements upon adoption.

In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” to clarify under what circumstances a contract with an initial net investment meets the characteristics of a derivative, to clarify when a derivative contains a financing component, to amend the definition of an “underlying” to conform it to language in FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” and to amend certain other existing pronouncements. SFAS 149 is effective for contracts entered into or modified after June 30, 2003, and is to be applied prospectively. Implementation of SFAS 149 did not have a material effect on the Company’s consolidated financial statements as of and for the period ended December 31, 2003, as it did not have any derivative instruments or hedging arrangements.

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” SFAS 150 requires that certain financial instruments issued in the form of shares that are mandatorily redeemable, as well as certain other financial instruments, be classified as liabilities in the financial statements. SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003 and otherwise is effective beginning with the Company’s second quarter of 2004. The provisions of this statement did not have a material impact on the Company’s consolidated financial statements as of and for the year ended December 31, 2003.

Certain reclassifications of amounts reported in prior years have been made to conform to the current year presentation. The compensation costs for certain vessel support personnel were reclassified from general and administrative expenses to operating expenses for all periods presented.

On March 5, 2004, the Company effected a 1-for-2.5 reverse stock split of its common stock that caused the number of outstanding shares to decrease from 36,320 to 14,528. For all periods, the share amounts and per share data reflected throughout these financial statements have been adjusted to give effect to the reverse stock split.

A loss of $3,029 was incurred during the third quarter of 2001 resulting from the write-off of deferred financing costs upon the refinancing of the Company’s debt through the issuance of $175,000 of senior notes in July 2001 (see Note 7). The loss was classified as an extraordinary item in the previously issued 2001 financial statements. In connection with the adoption of SFAS 145 on January 1, 2003, this loss has been reclassified in the accompanying financial statements as an increase to interest expense (see Note 2 – Recent Accounting Pronouncements).

The Company was a participating employer in the Cari Investment Company 401(k) Plan, a defined contribution plan with a cash or deferred arrangement pursuant to Section 401(k) of the Internal Revenue Code. The Company established a simple employer plan on March 1, 2001. Employees must be at least twenty-one years of age and have completed three months of service to be eligible for participation. Participants may elect to defer up to 20% of their compensation, subject to certain statutorily established limits. The Company may elect to make annual matching and/or profit sharing contributions to the plan. During the years ended December 31, 2003, 2002 and 2001, the Company made contributions of $280, $125 and $75, respectively.

Interest expense of $2,734, $3,867 and $3,075 was capitalized for the years ended December 31, 2003, 2002 and 2001, respectively.

On June 5, 1998, the Company entered into a $20,000 line of credit agreement (credit facility) with a venture capital company to refinance existing indebtedness and partially finance the construction of OSVs (see Note 11). The Company issued detachable warrants to purchase 4,762 shares of common stock in connection with the Credit Facility. The warrants were assigned an estimated market value of $500. Warrants for the purchase of 4,200 shares of common stock were exercisable with an exercise price of $4.20 per share. The remaining warrants became exercisable only on the occurrence of an event of default under the Credit Facility, the Company filing for bankruptcy or if the indebtedness under the Credit Facility was not discharged in full by June 5, 2003. All of the warrants issued in connection with establishment of the Credit Facility provided the holders with a put option whereby the holders had the right, if the Company’s stock was not publicly traded by June 5, 2003, to require the Company to repurchase the warrants at their fair market value.

According to EITF Issue No. 88-9 “Accounting for Put Warrants”, issued by the Emerging Issues Tax Force and supplemented by EITF Issue No. 00-19 “Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company’s Own Stock” a company whose stock is publicly traded is required to account for warrants that contain put options as a liability. Upon the Company’s filing of a Registration Statement on Form S-1 in July 2002, which was subsequently withdrawn in October 2002, the accounting for put warrants as a liability became effective. As previously discussed, the Company assigned a market value of $500 to the warrants at issuance based on the relative fair value of the Credit Facility and the warrants. The $500 was allocated to debt with all subsequent changes to the fair market value of the warrants for each period presented being recorded as an adjustment to interest expense.

The Company repurchased and terminated all of the warrants for $14,500 in October 2001. The repurchase of the warrants was funded by a private placement of the Company’s common stock for gross proceeds of $14,650. The remaining funds were used for payment of expenses incurred in connection with the private placement.

On July 24, 2001, the Company issued $175,000 in principal amount of 10⁵/₈% senior notes. The Company realized net proceeds of approximately $165,000, a substantial portion of which was used to repay and fully extinguish all of the

then existing credit facilities. The senior notes mature on August 1, 2008 and require semi-annual interest payments at an annual rate of 10⁵/₈% on February 1 and August 1 of each year until maturity. The effective interest rate on the senior notes is 11.18%. No principal payments are due until maturity. The senior notes are unsecured senior obligations and rank equally in right of payment with other existing and future senior indebtedness and senior in right of payment to any subordinated indebtedness incurred by the Company in the future. The senior notes are guaranteed by all of the Company’s subsidiaries. The Company may, at its option, redeem all or part of the senior notes from time to time at specified redemption prices and subject to certain conditions required by the indenture. The Company is permitted under the terms of the indenture to incur additional indebtedness in the future, provided that certain financial conditions set forth in the indenture are satisfied by the Company.

In connection with the issuance of the senior notes, the Company wrote-off deferred financing costs related to previous credit facilities. The write-off in the amount of $3,029 has been presented as an adjustment to interest expense in the accompanying statements of operations (see Note 4).

The Company completed an exchange offer on January 18, 2002, whereby the 10⁵/₈% Series A senior notes, due August 1, 2008, were exchanged for 10⁵/₈% Series B senior notes with the same terms, the offering of which was publicly registered.

Effective December 31, 2001, the Company entered into a new senior secured revolving line of credit for $50,000 (revolving credit facility) with a borrowing base initially set at $25,000. Pursuant to the indenture governing the senior notes, unless the Company meets a specified consolidated interest coverage ratio test, the level of permitted borrowings under this facility is limited to $25,000 plus 15% of the increase in the Company’s consolidated net tangible assets over the consolidated net tangible assets as of March 31, 2001 determined on a pro forma basis to reflect the Spentonbush/Red Star Group acquisition. Unused commitment fees are payable quarterly at the annual rate of one-quarter to three-eighths of one percent on the revolving credit facility, based on the leverage ratio defined by the agreement.

On June 26, 2003, concurrent with the acquisition of five OSVs from Candy Fleet, the Company amended the $50,000 revolving credit facility to increase its borrowing base from $25,000 to $50,000. In connection with this amendment, the Company pledged two additional OSVs as collateral.

On September 30, 2003, the Company amended the revolving credit facility to increase its borrowing base from $50,000 to $60,000. The Company pledged one additional OSV as collateral in connection with this amendment. As of September 30, 2003, seven OSVs and four ocean-going tugs collateralized the revolving credit facility. As of December 31, 2003, the Company had a balance outstanding of $40,000 under the revolving credit facility, which primarily funded the acquisition of a double-hulled tank barge and a portion of the costs of six acquired OSVs, and had $20,000 of additional credit immediately available under the revolving credit facility.

On February 13, 2004, the Company amended and restated the revolving credit facility to extend its maturity and increase its size to $100,000. The current borrowing base remains unchanged at $60,000. This facility had an original expiration date of December 31, 2004. The new expiration date of the amended and restated facility is February 13, 2009. The maturity of this facility will automatically accelerate to March 31, 2008, if by that date the Company has not redeemed its senior notes or refinanced them with debt having a maturity later than July 31, 2009.

The revolving credit facility and indenture impose certain operating and financial restrictions on the Company. Such restrictions affect, and in many cases limit or prohibit, among other things, the Company’s ability to incur additional indebtedness, make capital expenditures, redeem equity, create liens, sell assets and make dividend or other restricted payments.

As of the dates indicated, the Company had the following outstanding long-term debt:

Annual maturities of long-term debt during each year ending December 31, are as follows:

The Company’s charter authorizes 5,000 shares of preferred stock. The Board of Directors has the authority to issue preferred stock in one or more series and to fix the rights, preferences, privileges and restrictions thereof, including dividend rights, conversion rights, voting rights, terms of redemption, redemption prices, liquidation preferences and the number of shares constituting any series or the designation of such series, without further vote or action by the Company’s shareholders.

The Company’s Board of Directors implemented a stockholder rights plan on June 18, 2003, declaring a dividend of one right for each outstanding share of common stock to stockholders of record on June 18, 2003. One right will also attach to each share of common stock issued after June 28, 2003. The rights become exercisable, and transferable apart from the Company’s common stock, 10 business days following a public announcement that a person or group has acquired beneficial ownership of, or has commenced a tender or exchange offer for, 10% or more of the Company’s common stock.

The rights have anti-takeover effects, causing substantial dilution to a person or group who attempts to acquire the Company without the approval of the Board of Directors. As a result, the overall effect of the rights may be to render more difficult or discourage any attempt to acquire the Company even if such acquisition may be favorable to the interests of the Company’s stockholders. Because the Board of Directors can redeem the rights or approve certain offers, the rights should not interfere with any merger or other business combination approved by the Company’s Board of Directors.

In May 2003, the Company commenced a private placement of its common stock to accredited investors to raise gross proceeds of $30,000, including $6,000 of common stock, or 480 shares, issued to Candy Fleet as partial consideration for the June 26, 2003 acquisition of five deepwater OSVs. The private placement was completed in July 2003 with 1,920 shares distributed for gross cash proceeds of $24,000. Costs incurred for the private placement were approximately $700 and were recorded as a reduction in additional paid-in capital.

SFAS No. 123, “Accounting for Stock-Based Compensation,” established financial accounting and reporting standards for stock-based compensation plans. The Company’s incentive compensation plan includes all arrangements by which employees and directors receive shares of stock or other equity instruments of the Company, or the Company incurs liabilities to employees or directors in amounts based on the price of the stock. SFAS 123 defines a fair-value-based method of accounting for stock-based compensation. However, SFAS 123 also allows an entity to continue to measure stock-based compensation cost using the intrinsic value method of APB Opinion No. 25, “Accounting for Stock Issued to

Employees.” Entities electing to retain the accounting prescribed in APB 25 must make pro forma disclosures of net income assuming dilution as if the fair-value-based method of accounting defined in SFAS 123 had been applied. The Company retained the provisions of APB 25 for expense recognition purposes. Under APB 25, where the exercise price of the Company’s stock options equals the market price of the underlying stock on the date of grant, no compensation expense is recognized.

The Company established an incentive compensation plan which provides the Company with the ability to grant options for a maximum of 3,500 shares of common stock. The purchase price of the stock subject to each option is determined by the Board of Directors of the Company and cannot be less than the fair market value of the stock at the date of grant. During 2003 and 2002, options for 6 and 45 shares, respectively, were exercised. All options granted expire five to ten years after the date of grant, have an exercise price equal to or greater than the estimated market price of the Company’s stock at the date of grant and vest over a two- to four-year period.

The following summarizes the option activity in the plan during 2003, 2002 and 2001:

If compensation cost for the Company’s stock options had been determined based on the fair value at the grant date consistent with the method under SFAS 123, the Company’s income available to common stockholders for the years ended December 31, 2003, 2002 and 2001 would have been as indicated below:

The fair value of the options granted under the Company’s stock option plan during each of the three years ended December 31, 2003, 2002 and 2001, was estimated using the Black-Scholes pricing model using the minimum value method whereby volatility is not considered. The other assumptions used were: an average interest rate of 3.84%, 3.83% and 4.88%, respectively, and an expected life of five to seven years with no expected dividends for each year.

The net long-term deferred tax liabilities (assets) in the accompanying consolidated balance sheets include the following components:

At December 31, 2003, the Company had federal tax net operating loss carryforwards of approximately $37,385. The carryforward benefit from the federal net tax operating loss carryforwards begins to expire in 2018. The Company had a state tax net operating loss carryforward of approximately $1,515 related to one state tax jurisdiction. This carryforward can only be utilized if the Company generates taxable income in the appropriate tax jurisdiction. A valuation allowance of $95 has been established to fully offset the deferred tax asset related to the state tax jurisdiction.

The following table reconciles the difference between the Company’s income tax provision calculated at the federal statutory rate and the actual income tax provision:

At December 31, 2003, the Company was committed under a vessel construction contract with a shipyard affiliated with the Company’s former Chairman of the Board and Chief Executive Officer to construct one OSV and one double-hulled tank barge and with a third party shipyard for the construction of one double-hulled tank barge. At that date, the remaining amount expected to be incurred during 2004 to complete construction with respect to such contracts was approximately $31,245. The Company is obligated under the terms of the contracts to remit funds to the shipyards based on vessel construction milestones, which are subject to change during vessel construction.

The Company is obligated under certain operating leases for marine vessels, office space and vehicles. The Covington facility lease provides for a term of five years with two five-year renewal options. The Brooklyn facility lease provides for a term of five years with five one-year renewal options.

Future minimum payments under noncancelable leases for years subsequent to 2003 follow:

In addition, the Company leases marine vessels used in its operations under month-to-month operating lease agreements. Total rent expense related to leases was $1,012, $1,559 and $771 during the years ended December 31, 2003, 2002 and 2001, respectively.

See Note 16 for a description of the lease entered into in connection with the Spentonbush/Red Star Group acquisition.

In the normal course of its business, the Company becomes involved in various claims and legal proceedings in which monetary damages are sought. It is management’s opinion that the Company’s liability, if any, under such claims or proceedings would not materially affect its financial position or results of operations.

A former member of the Company’s Board of Directors, who served on the Board from June 1997 until August 2001 and is now serving as an advisory director, is a shareholder in a law firm that has provided legal services to the Company. The Company paid approximately $1,529 to the law firm during the year ended December 31, 2001, the year during which he served as a director.

During 2003, the Company was committed under vessel construction contracts to construct four OSVs and one double-hulled tank barge with a shipyard affiliated with the Company’s former Chairman of the Board and Chief Executive Officer. The Company incurred $25,200 of construction costs related to such vessels during 2003. The same shipyard has constructed 10 of the Company’s 22 OSVs in service as of December 31, 2003.

In the years ended December 31, 2003, 2002 and 2001, revenues from the following customers exceeded 10% of total revenues:

The Company provides marine transportation services through two business segments. The Company operates new generation offshore supply vessels in the U.S. Gulf of Mexico, Trinidad and Tobago and Mexico through its offshore supply vessel segment. The offshore supply vessels principally support complex exploration and production projects by transporting cargo to offshore drilling rigs and production facilities and provide support for specialty services. The tug and tank barge segment primarily operates ocean-going tugs and tank barges in the northeastern United States and in Puerto Rico. The ocean-going tugs and tank barges provide coastwise transportation of refined and bunker grade petroleum products from one port to another. The following shows reportable segment information for the years ended December 31, 2003, 2002 and 2001 reconciled to consolidated totals and prepared on the same basis as the Company’s consolidated financial statements.

On May 31, 2001, the Company purchased a fleet of nine ocean-going tugs and nine ocean-going tank barges and the related coastwise transportation businesses from the Spentonbush/Red Star Group for approximately $28,000 in cash. As part of the acquisition, the Company entered into a contract of affreightment with Amerada Hess as its exclusive marine logistics provider and coastwise transporter of petroleum products in the northeastern United States. The contract became effective on June 1, 2001 and its initial term continues through March 31, 2006. The Company also entered into a five-year lease for the Brooklyn marine facility of Amerada Hess where the tug and tank barge operations that were acquired are based and from which such operations are conducted. The lease expires in March 2006. The Company incurred approximately $600 in acquisition costs.

The purchase method was used to account for the acquisition of the tugs and tank barges from the Spentonbush/Red Star Group. There was no goodwill recorded as a result of the acquisition. The Company completed its final purchase price allocation and increased the liabilities related to assumed drydocking liabilities to $4,995. The following reflects the final allocation of the purchase price and recertification costs incurred during the allocation period following the acquisition date:

The following summarized unaudited pro forma income statement data reflects the impact the Spentonbush/Red Star Group acquisition would have had on the Company’s consolidated results of operations for the year ended December 31, 2001, if the acquisition had taken place at the beginning of the fiscal year:

On June 26, 2003, the Company acquired five 220-foot new generation offshore supply vessels and their related business from Candy Marine Investment Corporation, an affiliate of Candy Fleet Corporation (collectively, Candy Fleet), for $45,000, comprised of $39,000 in cash and of $6,000 of common stock, for the purpose of diversifying its offshore supply vessel fleet and expanding its service offerings. Candy Fleet is a privately held marine vessel operator in the Gulf of Mexico. The Company funded the cash portion of the purchase price with a combination of borrowings under the Company’s revolving credit facility as discussed in Note 7, and with part of the cash proceeds generated by the private

placement of its common stock discussed in Note 8. The new vessel names are HOS Explorer, HOS Express, HOS Pioneer, HOS Trader, and HOS Voyager.

On August 6, 2003, the Company completed the acquisition of an additional 220-foot new generation offshore supply vessel from Candy Fleet. The closing of the transaction was affected after satisfying certain conditions precedent to closing, including, among other things, receipt during July 2003 of $13,500 in proceeds relating to the previously announced $30,000 private placement of common stock and the satisfactory completion of a drydocking and survey of the vessel in early August. The purchase price of $9,000 was negotiated by the parties on an arms-length basis. The Company plans to continue operating the acquired vessel, which was renamed the HOS Mariner, in the Gulf of Mexico. In connection with the acquisition, the Company was also granted options to purchase three conventional 180-foot offshore supply vessels from Candy Fleet for an aggregate exercise price of $4,500. These options expire on August 6, 2004.

The purchase method was used to account for the acquisitions of the six new generation offshore supply vessels from Candy Fleet. There were no intangible assets or goodwill recorded as a result of the acquisition. Included in the purchase price allocation was approximately $300 of acquisition costs comprised of legal, consulting and accounting fees. As of December 31, 2003, the final purchase price was allocated to the acquired assets based on the estimated fair values as follows:

The unaudited pro forma income statement data from the Candy Fleet acquisition would not have had a material impact on the Company’s consolidated results of operations for the years ended December 31, 2003 and 2002, if the acquisition had taken place at the beginning of the fiscal year.

The Company has employment agreements with certain members of its executive management team. These agreements include, among other things, contractually stated base level salaries and a structured bonus plan dependent upon the Company achieving EBITDA and earnings per share targets in years during which the employment agreements are in effect. In the event a member of the executive management team is terminated due to events as defined in the agreement, the employee will continue to receive salary, bonus and other payments equal to the full amount payable under the agreement.

Effective February 27, 2002, the Company’s former Chairman of the Board and Chief Executive Officer ceased serving in that capacity and his employment under the terms of his agreement terminated. The Company accrued its contractual obligation as of the date of termination.

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Covington, the State of Louisiana, on March 10, 2004.


HORNBECK OFFSHORE SERVICES, INC.

By:		/s/ TODD M. HORNBECK

		Todd M. Hornbeck President and Chief Executive Officer

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


		Our Proprietary Design OSV Classes					Acquired OSVs
	Conventional 180’ OSV(1)	200	240	240 E	240 ED	265	220
Size
Class length overall (ft.)	180	200	240	240	240	265	220
Breadth (ft.)	40	54	54	54	54	60	46
Depth (ft.)	14	18	18	18	20	22	17
Maximum draft (ft.)	12	13	13	13	14.5	16	13.7
Deadweight (long tons)	950	1,750	2,250	2,380	2,850	3,756	1,607
Clear deck area (sq. ft.)	3,450	6,580	8,836	8,100	8,100	9,212	5,472
Capacity
Fuel capacity (gallons)	79,400	90,000	151,800	135,100	104,210	151,800	114,490
Fuel pumping rate (gallons per minute)	275	550	550	550	550	500	380
Drill water capacity (gallons)	120,000	240,000	240,000	240,000	311,000	413,000	99,000
Dry bulk capacity (cu. ft.)	4,000	7,000	8,400	8,400	6,000	10,800	8,040
Liquid mud capacity (barrels)	1,200	3,640	6,475	6,475	8,300	10,500	2,955
Liquid mud pumping rate (gallons per minute)	250	500	1,000	1,000	1,000	1,000	1,200
Potable water capacity (gallons)	11,500	52,200	52,200	52,200	30,400	20,430	26,800
Machinery
Main engines (horsepower)	2,250	4,000	4,000	4,000	4,000	6,700	3,900
Auxiliaries (number)	2	3	3	3	3	3	2
Total rating (kw)	200	750	750	750	750	860	250
Bow thruster (horsepower)	325	800	1,600	1,600	1,600	2,400	530
Type of Pitch	Fixed	Controllable	Controllable	Controllable	Controllable	Controllable	Fixed
Stern thruster (horsepower)	None	300	300	800	800	1,600	300
Type of Pitch	—	Controllable	Controllable	Controllable	Controllable	Controllable	Fixed
Fire fighting (gallons per minute)	None	1,250	2,700	2,700	2,700	2,700	2,600
Dynamic positioning(2)	None	DP0,1	DP1	DP2	DP2	DP2,3	DP0,1
Crew Requirements
Number of personnel(3)	5	6	6	7	7	8	6


Name	Gross Tonnage	Length (feet)	Year Built	Brake Horsepower
Ponce Service	190	107	1970	3,900
Caribe Service	194	111	1970	3,900
Atlantic Service	198	105	1978	3,900
Brooklyn Service	198	105	1975	3,900
Gulf Service	198	126	1979	3,900
Tradewind Service	183	105	1975	3,200
Yabucoa Service	183	105	1975	3,000
Spartan Service	126	102	1978	3,000
Sea Service	173	109	1975	2,820
North Service	187	100	1978	2,200
Bayridge Service	194	100	1981	2,000
Stapleton Service	146	78	1966	1,530


Name	Barrel Capacity		Length (feet)	Year Built		OPA 90 Date(1)
Ocean-Going Tank Barges:
Energy 13501	135,000	est.	450	TBD	(2)	N/A
Energy 11101	111,844		420	1979		2009
Energy 11102	111,844		420	1979		2009
Energy 11001	110,000	est.	390	TBD	(2)	N/A
Energy 9801	97,432		390	1967		2005
Energy 9501	94,442		346	1972		2005
Energy 8701	86,454		360	1976		2005
Energy 8001(3)	81,364		350	1996		N/A
Energy 7002	72,693		351	1971		2015
Energy 7001	72,016		300	1977		2015
Energy 6505	65,710		328	1978		2015
Energy 6504	66,333		305	1958		2015
Energy 6503	65,145		327	1988		2015
Energy 6502	64,317		300	1980		2015
Energy 6501	63,875		300	1974		2015
Energy 5501	57,848		341	1969		2015
Energy 2201	22,556		242	1973		2015
Energy 2202	22,457		242	1974		2015
Coastwise Tanker:
Energy Service 9001(4)	—		402	1992		N/A


For	Against	Abstentions
33,160,546*	None	None


For	Against	Abstentions
33,160,546*	None	None


PART I		1
Items 1 and 2.—Business and Properties		1
General		1
Offshore Supply Vessels		2
Tugs and Tank Barges		6
Our Competitive Strengths		9
Our Strategy		11
Customers and Charter Terms		12
Competition		12
Environmental and Other Government Regulation		13
Operating Hazards and Insurance		17
Employees		17
Properties		17
Recent Developments		17
Seasonality of Business		18
Item 3—legal Proceedings		18
Item 4—Submission of Matters to a Vote of Security Holders		18

PART II		19
Item 5—Market for the Registrant’s Common Stock and Related Stockholder Matters		19
Item 6—Selected Financial Data		19
Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations		22
General		22
Critical Accounting Policies		24
Results of Operations		26
Liquidity and Capital Resources		29
Contractual Obligations and Commercial Commitments		31
Inflation		32
Recent Accounting Pronouncements		32
Forward-Looking Statements		34
Item 7a—Quantitative and Qualitative Disclosures About Market Risk		35
Item 8—Financial Statements and Supplementary Data		35
Item 9—Changes in and Disagreements with Accountants on Accounting and Financial Disclosures		35
Item 9a—Controls and Procedures		35

PART III		37
Item 10—Directors and Executive Officers of the Registrant		37
Our Executive Officers and Directors		37
Committees of the Board of Directors		39
Compensation Committee Interlocks and Insider Participation		40
Term and Compensation of Directors		40
Item 11—Executive Compensation		42
Summary Compensation Table		42
Option Grants		43
Fiscal Year End Option Values		43
Employment Agreements		43
Item 12—Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		44
Principal Stockholders		44
Equity Compensation Plan Information		47
Item 13—Certain Relationships and Related Transactions		48


Item 14—Principal Accountant Fees and Services		48

PART IV		50
Item 15—Exhibits, Financial Statement Schedules and Reports on Form 8-K		50
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS		F-1
SIGNATURES		S-1


Name	Class	Current Service Function	Built (Acquired)	Deadweight (long tons)	Brake Horsepower
BJ Blue Ray	265	Well Stimulation	November 2001	3,756	6,700
HOS Brimstone	265	Supply	June 2002	3,756	6,700
HOS Stormridge	265	Supply	August 2002	3,756	6,700
HOS Sandstorm	265	Supply	October 2002	3,756	6,700
HOS Bluewater	240 ED	Supply	March 2003	2,850	4,000
HOS Gemstone	240 ED	Supply	June 2003	2,850	4,000
HOS Greystone	240 ED	Supply	September 2003	2,850	4,000
HOS Silverstar	240 ED	Supply	January 2004(2)	2,850	4,000
HOS Innovator	240 E	ROV Support(3)	April 2001	2,380	4,500
HOS Dominator	240 E	ROV Support(3)	February 2002	2,380	4,500
HOS Deepwater	240	Supply	November 1999	2,250	4,500
HOS Cornerstone	240	Supply	March 2000	2,250	4,500
HOS Explorer	220	Supply	February 1999 (June 2003)	1,607	3,900
HOS Express	220	Supply	September 1998 (June 2003)	1,607	3,900
HOS Pioneer	220	Supply	June 2000 (June 2003)	1,607	4,200
HOS Trader	220	Supply	November 1997 (June 2003)	1,607	3,900
HOS Voyager	220	Supply	May 1998 (June 2003)	1,607	3,900
HOS Mariner	220	Supply	September 1999 August 2003)	1,607	3,900
HOS Crossfire	200	Supply	November 1998	1,750	4,000
HOS Super H	200	Supply	January 1999	1,750	4,000
HOS Brigadoon	200	Supply	March 1999	1,750	4,000
HOS Thunderfoot	200	Supply	May 1999	1,750	4,000
HOS Dakota	200	Supply	June 1999	1,750	4,000


	Year Ended December 31,
	2003			2002			2001			2000			1999
Statements of Operations Data:
Revenues	$	110,813		$	92,585		$	68,791		$	36,102		$	25,723
Operating expenses		64,395			48,633			32,805			20,687			17,125
General and administrative expenses		10,731			9,681			8,039			3,078			2,617
Operating income		35,687			34,271			27,947			12,337			5,981
Interest income		178			667			1,455			305			170
Interest expense		18,523			16,207			16,646			15,478			7,524
Other income (expense)(1)		706			55			—			(138	)		(20	)
Income (loss) before income taxes		18,048			18,786			12,756			(2,974	)		(1,393	)
Income tax expense		(6,858	)		(7,139	)		(5,737	)		(1,550	)		(341	)
Net income (loss)(2)(3)		11,190			11,647			7,019			(4,524	)		(1,734	)

Balance Sheet Data (at period end):
Cash and cash equivalents	$	12,899		$	22,228		$	53,203		$	32,988		$	6,144
Working capital		17,698			22,265			48,516			29,524			(2,429	)
Property, plant, and equipment, net		316,715			226,232			180,781			98,935			85,700
Total assets		365,242			278,290			258,817			147,148			103,486
Total long-term debt(4)		212,677			172,306			171,976			82,557			79,076
Total stockholders’ equity		112,395			71,876			59,866			38,197			9,194

Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities	$	25,499		$	24,955		$	33,345		$	5,741		$	1,915
Investing activities		(98,166	)		(55,771	)		(88,328	)		(15,324	)		(42,313	)
Financing activities		63,322			(159	)		75,198			36,427			43,359

Other Financial Data (unaudited):
EBITDA(5)	$	54,161		$	47,289		$	37,072		$	17,667		$	9,263

Other Operating Data (unaudited):
Offshore Supply Vessels:
Average number(6)		17.3			11.0			7.8			6.8			4.1
Average utilization rate(7)		88.6	%		94.9	%		99.1	%		93.4	%		93.1	%
Average dayrate(8)	$	10,940		$	12,176		$	11,872		$	8,435		$	6,724
Tugs and Tank Barges:
Average number of tank barges(9)		15.9			16.0			12.3			7.0			7.1
Average fleet capacity (barrels)(9)		1,145,064			1,130,727			847,780			451,655			434,861
Average barge size (barrels)		72,082			70,670			68,109			64,522			61,464
Average utilization rate(7)		73.6	%		78.1	%		84.4	%		71.4	%		73.9	%
Average dayrate(10)	$	10,971		$	9,499		$	8,944		$	8,982		$	8,482


	Years Ended December 31,
	2003(1)			2002(2)			2001(3)
Offshore Supply Vessels:
Average number of vessels(4)		17.3			11.0			7.8
Average utilization rate(5)		88.6	%		94.9	%		99.1	%
Average dayrate(6)	$	10,940		$	12,176		$	11,872

Tugs and Tank Barges:
Average number of tank barges		15.9			16.0			12.3
Average fleet capacity (barrels)		1,145,064			1,130,727			847,780
Average barge size (barrels)		72,082			70,670			68,109
Average utilization rate(5)		73.6	%		78.1	%		84.4	%
Average dayrate(7)	$	10,971		$	9,499		$	8,944


Contractual Obligations	Total		Less than 1 Year		1-3 Years		3-5 Years		Thereafter
Senior notes(1)	$	175,000	$	—	$	—	$	175,000	$	—
Revolving credit facility		40,000		—		—		—		40,000
Operating leases(2)		2,995		1,166		1,570		259		—
Vessel construction commitments(3)		31,245		31,245		—		—		—

Total	$	249,240	$	32,411	$	1,570	$	175,259	$	40,000


Name	Age	Position	Class (1)
Todd M. Hornbeck	35	President, Chief Executive Officer, Secretary and Director	III
Carl G. Annessa	47	Vice President and Chief Operating Officer	N/A
James O. Harp, Jr.	43	Vice President and Chief Financial Officer	N/A
Timothy P. McCarthy	36	Controller	N/A
Paul M. Ordogne	52	Treasurer	N/A
Bernie W. Stewart	59	Director and Chairman of the Board	I
Richard W. Cryar	56	Director	II
Larry D. Hornbeck	65	Director	II
Bruce W. Hunt	46	Director	I
Patricia B. Melcher	44	Director	III
David A. Trice	55	Director	II
Christian G. Vaccari	44	Director	III
Andrew L. Waite	43	Director	I


		Annual Compensation						Long-Term Compensation Awards
Name and Position(1)	Fiscal Year	Salary (2)		Bonus (3)		Other Annual Compensation (4)		Securities Underlying Options(5,6,7)	All Other Compensation (7,8,9,10)
Todd M. Hornbeck	2003	$	240,000	$	169,553	$	—	60,000	$	1,254
President, Chief Executive Officer	2002		200,000		279,753		—	51,000		2,873
And Secretary	2001		195,833		400,000		—	—		1,940

Carl G. Annessa	2003		200,000		103,219		—	34,000		4,112
Vice President and	2002		170,000		178,342		—	17,000		2,386
Chief Operating Officer	2001		155,000		240,000		—	—		1,953

James O. Harp, Jr.	2003		185,000		95,477		—	32,000		3,720
Vice President and	2002		170,000		178,342		—	17,000		1,131
Chief Financial Officer	2001		163,571		255,000		—	40,000		1,103

Timothy P. McCarthy	2003		112,500		38,500		—	6,000		2,563
Controller	2002		59,500		20,000		—	11,600		359

Paul M. Ordogne	2003		116,000		20,000		—	2,000		2,906
Treasurer	2002		116,000		20,000		—	—		1,765
	2001		115,000		42,665		—	—		1,541


Name	Number of Securities Underlying Options Granted(1)(2)	% of Total Options Granted in Fiscal Year		Exercise or Base Price ($/ Share)(3)		Expiration Date	Potential Realizable Value at Assumed Annual Rates of Stock Appreciation For Option Term(4)
Name	Number of Securities Underlying Options Granted(1)(2)	% of Total Options Granted in Fiscal Year		Exercise or Base Price ($/ Share)(3)		Expiration Date	5%	10%
Todd M. Hornbeck	51,000	27	%	$	11.20	March 13, 2013	930,425	1,481,545
Carl G. Annessa	17,000	9	%	$	11.20	March 13, 2013	310,142	493,849
James O. Harp, Jr.	17,000	9	%	$	11.20	March 13, 2013	310,142	493,849
Timothy P. McCarthy	3,600	2	%	$	11.20	March 13, 2013	65,677	104,580


	Shares Acquired on Exercise	Value Realized	Number of Securities Underlying Unexercised Options at December 31, 2003		Value of Unexercised In-the-Money Options at December 31, 2003(1)
Name	Shares Acquired on Exercise	Value Realized	Exercisable	Unexercisable	Exercisable		Unexercisable
Todd M. Hornbeck	—	—	53,000	49,500	$	340,625	$	174,150
Carl G. Annessa	—	—	44,000	33,000		292,800		116,100
James O. Harp, Jr	—	—	26,667	30,333		156,667		100,433
Timothy P. McCarthy	—	—	2,000	9,600		11,750		39,930
Paul M. Ordogne	—	—	22,520	7,680		150,505		45,120


Name	Shares of Common Stock Beneficially Owned (#)		Percentage of Common Stock Beneficially Owned (%)
*Executive Officers and Directors:*
Todd M. Hornbeck	1,273,754	(1)	8.5
Carl G. Annessa	85,667	(2)	*
James O. Harp, Jr.	61,739	(3)	*
Timothy P. McCarthy	3,200	(4)	*
Paul M. Ordogne	66,080	(5)	*
Bernie W. Stewart	66,136	(6)	*
Richard W. Cryar	36,057	(7)	*
Larry D. Hornbeck	111,455	(8)	*
Bruce W. Hunt	37,367	(9)	*
Patricia B. Melcher	48,567	(10)	*
David A. Trice	2,567	(10)	*
Christian G. Vaccari	2,301,593	(11)	*
Andrew L. Waite	9,918	(12)	*
All directors and executive officers as a group (13 persons)	4,104,100	(13)	27.5
*Other 5% Stockholders:*
SCF-IV, L.P.	4,727,208	(14)	31.7
Cari Investment Company	2,051,746	(15)	13.7
William Herbert Hunt Trust Estate	2,058,390	(16)	13.8
Rock Creek Capital Group, Inc.	1,864,362	(17)	12.5


Plan Category	Number of Securities to be issued Upon Exercise of Outstanding Options, Warrants and Rights	Weighted Average Exercise Price of Outstanding Options, Warrants and Rights		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a))
	(a)		(b)	(c)
Equity compensation plans approved by security holders (1)	925,244	$	7.45	2,523,756
Equity compensation plans not approved by security holders	—		—	—

Total	925,244		7.45	2,523,756


Exhibit Number		Description of Exhibit

*3.1		—Second Restated Certificate of Incorporation of the Company filed with the Secretary of State of the State of Delaware on March 5, 2004.

3.2		—Certificate of Designation of Series A Junior Participating Preferred Stock filed with the Secretary of State of the State of Delaware on June 20, 2003 (incorporated by reference to Exhibit 3.6 to the Company’s Registration Statement on Form S-1 dated September 19, 2003, Registration No. 333-108943).

*3.3		—Third Restated Bylaws of the Company adopted February 17, 2004.

4.1		—Indenture dated as of July 24, 2001 between Wells Fargo Bank Minnesota, National Association (as Trustee) and the Company, including table of contents and cross-reference sheet (incorporated by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-4 dated September 21, 2001, Registration No. 333-69826).

4.2		—Supplemental Indenture dated as of December 17, 2001, between Wells Fargo Bank Minnesota, National Association (as Trustee), the Company, Hornbeck Offshore Services, LLC, (f.k.a. Hornbeck Offshore Services, Inc.), HORNBECK-LEEVAC Marine Operators, LLC, (f.k.a. HORNBECK-LEEVAC Marine Operators, Inc.), LEEVAC Marine, LLC and Energy Services Puerto Rico, LLC, with Notation of Subsidiary Guarantee by Hornbeck Offshore Services, LLC, (f.k.a. Hornbeck Offshore Services, Inc.), HORNBECK-LEEVAC Marine Operators, LLC, (f.k.a. HORNBECK-LEEVAC Marine Operators, Inc.), LEEVAC Marine, LLC and Energy Services Puerto Rico, LLC attached (incorporated by reference to Exhibit 4.1.1 to Amendment No. 2 to the Company’s Registration Statement on Form S-4 dated December 19, 2001, Registration No. 333-69826).

4.3		—Second Supplemental Indenture and Amendment dated as of June 18, 2003, between Wells Fargo Bank Minnesota, National Association (as Trustee), the Company and HOS-IV, LLC, with Notation of Subsidiary Guarantee by HOS-IV, LLC (incorporated by reference to Exhibit 4.12 to the Company’s Registration Statement on Form S-1 dated September 19, 2003, Registration No. 333-108943).

*4.4		—Third Supplemental Indenture and Amendment dated as of February 13, 2004, between Wells Fargo Bank Minnesota, National Association (as Trustee), the Company and Hornbeck Offshore Trinidad & Tobago, LLC, with Notation of Subsidiary Guarantee by Hornbeck Offshore Trinidad & Tobago, LLC.

4.5		—Stockholders’ Agreement dated as of October 27, 2000 between the Company, Todd M. Hornbeck, Troy A. Hornbeck, Cari Investment Company and SCF-IV, L.P. (incorporated by reference to Exhibit 4.6 to the Company’s Registration Statement on Form S-1 filed September 19, 2003, Registration No. 333-108943).


Exhibit Number		Description of Exhibit

4.6		—Rights Agreement dated as of June 18, 2003 between the Company and Mellon Investor Services LLC as Rights Agent, which includes as Exhibit A the Certificate of Designations of Series A Junior Participating Preferred Stock, as Exhibit B the form of Right Certificate and as Exhibit C the form of Summary of Rights to Purchase Stock (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed July 2, 2003).

4.7		—Stockholders’ Agreement dated as of June 5, 1997 between the Company, Todd M. Hornbeck, Troy A. Hornbeck and Cari Investment Company (incorporated by reference to Exhibit 4.3 to the Company’s Registration Statement on Form S-1 filed July 22, 2002, Registration No. 333-96833).

4.8		—Registration Rights Agreement dated as of October 27, 2000 between the Company and SCF-IV, L.P. (incorporated by reference to Exhibit 4.4 to the Company’s Registration Statement on Form S-1 filed July 22, 2002, Registration No. 333-96833).

4.9		—Registration Rights Agreement dated as of June 24, 2003 between the Company and certain purchasers of securities (incorporated by reference to Exhibit 4.11 to the Company’s Registration Statement on Form S-1 filed September 19, 2003, Registration No. 333-108943).

4.10		—Agreement Concerning Registration Rights dated as of October 27, 2000 between the Company, SCF-IV, LP, Joint Energy Development Investments II, LP and Sundance Assets, LP (incorporated by reference to Exhibit 4.5 to the Company’s Registration Statement on Form S-1 filed July 22, 2002, Registration No. 333-96833).

4.11		—Letter Agreement dated September 24, 2001 between the Company, Todd M. Hornbeck, Troy A. Hornbeck, Cari Investment Company and SCF-IV, L.P. (incorporated by reference to Exhibit 4.7 to the Company’s Registration Statement on Form S-1 filed September 19, 2003, Registration No. 333-108943).

4.12		—Specimen 10⁵/8% Series B Senior Note due 2008 (incorporated by reference to Exhibit 4.4 to the Company’s Registration Statement on Form S-4 dated September 21, 2001, Registration No. 333-69826).

*4.13		—Amendment to Rights Agreement dated as of March 5, 2004 between the Company and Mellon Investor Services LLC as Rights Agent.

10.1		—Amended and Restated Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to the Company’s Form 10-Q for the period ended September 30, 2003).

10.2		—Amendment to Senior Employment Agreement dated effective February 17, 2003 by and between Todd M. Hornbeck and the Company (incorporated by reference to Exhibit 10.15 to the Company’s Registration Statement on Form S-1 dated September 19, 2003, Registration No. 333-108943).

10.3		—Amendment to Employment Agreement dated effective February 17, 2003 by and between Carl G. Annessa and the Company (incorporated by reference to Exhibit 10.16 to the Company’s Registration Statement on Form S-1 dated September 19, 2003, Registration No. 333-108943).

10.4		—Amendment to Employment Agreement dated effective February 17, 2003 by and between James O. Harp, Jr. and the Company (incorporated by reference to Exhibit 10.17 to the Company’s Registration Statement on Form S-1 dated September 19, 2003, Registration No. 333-108943).

*10.5		—Amended and Restated Credit Agreement dated as of February 13, 2004 among Hornbeck Offshore Services, Inc. and Hibernia National Bank, as agent, and Hibernia National Bank, Fortis Capital Corp., Southwest Bank of Texas, N.A., DVB Bank Aktiengesellscheft and Wells Fargo Bank, N.A., as lenders.

10.7		—Form of First Amendment to Indemnification Agreement for Directors, Officers and Key Employees (incorporated by reference to Exhibit 10.6 to the Company’s Form 10-Q for the period ended September 30, 2003).


Exhibit Number		Description of Exhibit

10.8		—Asset Purchase Agreement dated as of June 20, 2003 by and among HOS-IV, LLC, Candy Marine Investment Corporation, Candy Fleet Corporation and Kenneth I. Nelkin, and joined for limited purposes by Hornbeck Offshore Services, Inc. (incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K filed July 7, 2003).

*10.9		—Director & Advisory Director Compensation Plan.

*21		—Subsidiaries of the Company.

*31.1		—Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*31.2		—Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*32.1		—Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*32.2		—Certification of the Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


		Page

CONSOLIDATED FINANCIAL STATEMENTS OF HORNBECK OFFSHORE SERVICES, INC.:

Report of Independent Auditors		F-2

Consolidated Balance Sheets as of December 31, 2003 and 2002		F-3

Consolidated Statements of Operations for Each of the Three Years in the Period Ended December 31, 2003		F-4

Consolidated Statements of Changes in Stockholders’ Equity for Each of the Three Years in the Period Ended December 31, 2003		F-5

Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2003		F-6

Notes to Consolidated Financial Statements		F-7


	December 31,
	2003		2002
ASSETS
Current assets:
Cash and cash equivalents	$	12,899	$	22,228
Accounts and claims receivable, net of allowance for doubtful accounts of $454 and $469, respectively		17,124		14,616
Prepaid insurance		291		569
Property taxes receivable		2,144		1,135
Other current assets		1,081		742

Total current assets		33,539		39,290
Property, plant and equipment, net		316,715		226,232
Goodwill, net		2,628		2,628
Deferred charges, net		12,316		10,113
Other assets		44		27

Total assets	$	365,242	$	278,290

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	3,884	$	5,350
Accrued interest		7,799		7,747
Accrued payroll and benefits		3,911		3,740
Other accrued liabilities		247		188

Total current liabilities		15,841		17,025
Revolving credit facility		40,000		—
Long-term debt, net of original issue discount of $2,323 and $2,694, respectively		172,677		172,306
Deferred tax liabilities, net		23,567		16,709
Other liabilities		762		374

Total liabilities		252,847		206,414
Stockholders’ equity:
Preferred stock: $0.01 par value; 5,000 shares authorized; no shares issued and outstanding		—		—
Common stock: $0.01 par value; 100,000 shares authorized; 14,528 and 12,122 shares issued and outstanding at December 31, 2003 and 2002, respectively		145		121
Additional paid-in capital		90,351		61,062
Retained earnings		21,883		10,693
Accumulated other comprehensive income		16		—

Total stockholders’ equity		112,395		71,876

Total liabilities and stockholders’ equity	$	365,242	$	278,290


	Common Stock				Additional Paid-In Capital			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income		Total Stockholders’ Equity
	Shares		Amount		Additional Paid-In Capital			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income		Total Stockholders’ Equity
Balance at January 1, 2001	9,830		$	98	$	46,072		$	(7,973	)	$	—	$	38,197
Shares issued	2,224			22		14,628			—			—		14,650
Net income	—			—		—			7,019			—		7,019

Balance at December 31, 2001	12,054		$	120	$	60,700		$	(954	)	$	—	$	59,866
Shares issued	75			1		412			—			—		413
Net income	—			—		—			11,647			—		11,647
Repurchase and retirement of shares	(7	)		—		(50	)		—			—		(50	)

Balance at December 31, 2002	12,122		$	121	$	61,062		$	10,693		$	—	$	71,876
Private placement of common stock	2,400			24		29,243			—			—		29,267
Other shares issued	6			—		46			—			—		46
Comprehensive income:
Net income	—			—		—			11,190			—		11,190
Foreign currency translation	—			—		—			—			16		16

Total comprehensive income														11,206

Balance at December 31, 2003	14,528		$	145	$	90,351		$	21,883		$	16	$	112,395


Tugs		14-25 years
Tank barges		3-25 years
Offshore supply vessels		25 years
Non-vessel related property, plant and equipment		5 years


	Year Ended December 31,
	2003		2002		2001
Net income, as reported	$	11,190	$	11,647	$	7,019
Amortization of goodwill		—		—		126

Net income, as adjusted	$	11,190	$	11,647	$	7,145


2004	$	—
2005		—
2006		—
2007		—
2008		172,677
Thereafter		40,000

	$	212,677


	Options Outstanding				Options Exercisable
	Shares	Weighted Average Remaining Contractual Life (Years)	Weighted Average Exercise Price		Shares	Weighted Average Exercise Price
Range of exercise prices:
$ 4.63 to $ 6.63	725	7.18	$	6.38	455	$	6.13
$11.20 to $12.50	200	9.23		11.30	—		—

Total	925			7.45	455		6.13


	Year Ended December 31,
	2003		2002		2001
Current tax expense	$	—	$	—	$	—
Deferred tax expense		6,858		7,139		5,737

Total	$	6,858	$	7,139	$	5,737


	At December 31,
	2003		2002		2001
Identifiable Assets:
Offshore supply vessels	$	276,567	$	195,825	$	140,580
Tugs and tank barges		68,589		72,490		67,937
Corporate		20,086		9,975		50,300

Total	$	365,242	$	278,290	$	258,817

Long-Lived Assets:
Offshore supply vessels	$	258,076	$	174,676	$	128,188
Tugs and tank barges		56,914		50,797		52,272
Corporate		1,725		759		321

Total	$	316,715	$	226,232	$	180,781


Property, plant and equipment	$	32,025
Other assets		1,000
Accrued liabilities		(4,995	)

Purchase price	$	28,030


Property, plant and equipment	$	54,437
Inventory		183
Accrued liabilities		(275	)

Purchase price	$	54,345


	Quarter Ended
	Mar 31		Jun 30		Sep 30		Dec 31
Fiscal Year 2003
Revenues	$	27,347	$	26,010	$	28,215	$	29,240
Operating income		10,358		8,620		8,276		8,433
Net income		4,290		2,673		2,159		2,068
Fiscal Year 2002
Revenues	$	22,743	$	21,315	$	22,322	$	26,204
Operating income		9,322		8,235		7,209		9,505
Net income		3,489		2,841		2,043		3,274


Signature	Title	Date

/s/ TODD M. HORNBECK (Todd M. Hornbeck)	President, Chief Executive Officer, Secretary and Director (Principal Executive Officer)	March 10, 2004

/s/ JAMES O. HARP, JR. (James O. Harp, Jr.)	Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)	March 10, 2004

/s/ BERNIE W. STEWART (Bernie W. Stewart)	Director and Chairman of the Board	March 10, 2004

/s/ RICHARD W. CRYAR (Richard W. Cryar)	Director	March 10, 2004

/s/ LARRY D. HORNBECK (Larry D. Hornbeck)	Director	March 10, 2004

/s/ BRUCE W. HUNT (Bruce W. Hunt)	Director	March 10, 2004

/s/ PATRICIA B. MELCHER (Patricia B. Melcher)	Director	March 10, 2004

/s/ DAVID A. TRICE (David A. Trice)	Director	March 10, 2004

/s/ CHRISTIAN G. VACCARI (Christian G. Vaccari)	Director	March 10, 2004

/s/ ANDREW L. WAITE (Andrew L. Waite)	Director	March 10, 2004