Edgar Filing: TRANSMONTAIGNE INC

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TABLE OF CONTENTS
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

FORM 10-K

(Mark One)
/X/	Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended June 30, 2004
OR
/ /	Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period to

Commission File Number 001-11763

TRANSMONTAIGNE INC.

Delaware (State or other jurisdiction of incorporation or organization)		06-1052062 (I.R.S. Employer Identification No.)
Suite 3100, 1670 Broadway Denver, Colorado 80202 (Address, including zip code, of principal executive offices)
(303) 626-8200 (Telephone number, including area code)

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

Title of Each Class		Name of Each Exchange on Which Registered
Common Stock; $.01 par value		American Stock Exchange

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

NONE

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 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 report), and (2) has been subject to such filing requirements for the past 90 days. Yes /X/ No / /

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

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

The aggregate market value of the voting stock held by non-affiliates of the Registrant was $194,621,363. The aggregate market value was computed by reference to the last sale price ($6.42 per share) of the Registrant's Common Stock on the American Stock Exchange on August 30, 2004.

The number of shares of the registrant's Common Stock outstanding on August 30, 2004 was 41,114,144.

DOCUMENTS INCORPORATED BY REFERENCE

Items 10, 11, 12, 13 and 14 of Part III have been omitted from this report, as we expect to file with the Securities and Exchange Commission, not later than 120 days after the close of our fiscal year ended June 30, 2004, a definitive proxy statement for our annual meeting of stockholders or a subsequent amendment to this Form 10-K. The information required by Items 10, 11, 12, 13 and 14 of Part III of this report, which will appear in our definitive proxy statement or a subsequent amendment to this Form 10-K, is incorporated by reference into this report.

TABLE OF CONTENTS

Item
Part I
1.		Business
2.		Properties
3.		Legal Proceedings
4.		Vote of Security Holders
Part II
5.		Market for Common Stock
6.		Selected Financial Data
7.		Management's Discussion and Analysis of Financial Condition and Results of Operations
7A.		Quantitative and Qualitative Disclosures About Market Risk
8.		Financial Statements and Supplementary Data
9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosures
9A.		Controls and Procedures
Part III
10.		Directors and Executive Officers
11.		Executive Compensation
12.		Security Ownership of Certain Beneficial Owners and Management
13.		Certain Relationships and Related Transactions
14.		Principal Accountant Fees and Services
Part IV
15.		Exhibits, Financial Statement Schedules and Reports on Form 8-K

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, and any amendments to such reports, are available free of charge on our website at www.transmontaigne.com under the heading "Shareholder Information" "Financial Information" "SEC Filings", as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report contains certain forward-looking statements and information relating to TransMontaigne Inc., including the following:

i.: certain statements, including possible or assumed future results of operations, in "Management's Discussion and Analysis of Financial Condition and Results of Operations;"
ii.: any statements contained herein or therein regarding the prospects for our business or any of our services;
iii.: any statements preceded by, followed by or that include the words "may," "seeks," "believes," "expects," "anticipates," "intends," "continues," "estimates," "plans," "targets," "predicts," "attempts," "is scheduled," or similar expressions; and
iv.: other statements contained herein or therein regarding matters that are not historical facts.

Our business and results of operations are subject to risks and uncertainties, many of which are beyond our ability to control or predict. Because of these risks and uncertainties, actual results may differ materially from those expressed or implied by forward-looking statements, and investors are cautioned not to place undue reliance on such statements, which speak only as of the date thereof.

The following risk factors, discussed in more detail under the heading "Risk Factors" in our final prospectus, filed on May 14, 2003, related to our 9¹/8% Senior Subordinated Notes due 2010 are important factors that could cause actual results to differ materially from our expectations and may adversely affect our business and results of operations, include, but are not limited to:

–>: volumes of refined petroleum products shipped in our pipelines and throughput or stored in our terminal facilities;
–>: the availability of adequate supplies of and demand for petroleum products in the areas in which we operate;
–>: the effect of any inability to attract customers for our supply chain management service business;
–>: continued creditworthiness of, and performance by, contract counterparties;
–>: the effects of competition;
–>: our ability to renew customer contracts;
–>: operational hazards;
–>: availability and cost of insurance on our assets and operations;
–>: the success of our risk management activities;
–>: the effect of changes in commodity prices on our liquidity;
–>: the impact of any failure of our information technology systems;
–>: the impact of petroleum product price fluctuations;
–>: the availability of acquisition opportunities;
–>: successful integration and future performance of acquired assets;
–>: the threat of terrorist attacks or war;
–>: the impact of current and future laws and governmental regulations;
–>: liability for environmental claims; and

–>: the impact of the departure of any key officers.

In addition, other factors such as the following also could cause actual results to differ materially from our expectations:

–>: general economic, market or business conditions; and
–>: force majeure and acts of God.

We do not intend to update these forward-looking statements except as required by law.

Part I

ITEM 1. BUSINESS

The Company

TransMontaigne Inc., formed in 1995, is a refined petroleum products distribution and supply company based in Denver, Colorado with operations in the United States, primarily in the Gulf Coast, Midwest and East Coast regions. We provide integrated terminal, transportation, storage, supply, distribution and marketing services to refiners, wholesalers, distributors, marketers, and industrial and commercial end-users of refined petroleum products. Our principal activities consist of (i) terminal, pipeline and tug and barge operations, (ii) supply, distribution and marketing and (iii) supply chain management services.

We predominantly handle refined petroleum products, with the balance being fertilizer, chemicals and other commercial liquids. The refined petroleum products we handle include gasoline, diesel fuel, heating oil, jet fuel and kerosene. Our acquisition of terminals and related tug and barge operations in Florida from El Paso Corporation expanded our product and service offering to include the sale of bunker fuel, used to power ocean vessels, and No. 6 oil, for powering electricity generating plants, as well as the storage of jet fuel, crude oil and asphalt.

We have assembled an asset infrastructure and developed a shipping history on common carrier pipelines which are focused on the distribution of refined petroleum products from the Gulf Coast region to the Midwest and East Coast regions.

We own and operate terminal infrastructure that handles refined petroleum products and other commercial liquids with transportation connections by pipelines, tankers, barges, rail cars and trucks to our facilities or to third-party facilities. At our terminals, we provide throughput, storage, injection and distribution related services to distributors, marketers, retail gasoline station operators and industrial and commercial end-users of refined petroleum products and other commercial liquids. At June 30, 2004, we owned and operated 55 terminals with an aggregate capacity of approximately 21.4 million barrels.

In our supply, distribution and marketing operations, we purchase refined petroleum products primarily from refineries along the Gulf Coasts of Texas and Louisiana and schedule them for delivery to our terminals, as well as terminals owned by third parties, in the Gulf Coast, Midwest and East Coast regions of the United States. We then sell our products primarily through rack spot sales, contract sales, and bulk sales to cruise ship operators, commercial and industrial end-users, independent retailers, distributors, marketers, government entities and other wholesalers of refined petroleum products.

We also provide supply chain management services to industrial, commercial and governmental customers that have large ground vehicle fleets. We often combine these services with price management solutions to provide our customers an assured source of fuel at a predictable price. Our customer base includes companies involved in the manufacture and distribution of consumer products, express shipping services, waste disposal services, transportation services, and state and local government entities.

TransMontaigne Inc. is a holding company that conducts its operations through four primary subsidiaries: TransMontaigne Product Services Inc., which owns the majority of our terminaling facilities and conducts the majority of our supply, distribution and marketing operations; Coastal Fuels Marketing, Inc., which owns the Florida marine terminals and conducts supply, distribution and

marketing operations principally to marine vessels and power generation plants; Coastal Tug and Barge, Inc., which owns and operates our fleet of tugboats and barges and provides transportation services; and TransMontaigne Transport Inc., which operates our turbo prop aircraft to transport our personnel among locations.

Industry Overview

Product description

Refineries produce refined petroleum products by processing crude oil. Refined petroleum products generally are classified in two groups, "light oils" and "heavy oils." Light oils include gasoline and distillates, such as diesel fuel, heating oil, jet fuel and kerosene. Heavy oils include No. 6 oil and asphalt. When produced at the refinery, refined products of a specific grade, such as unleaded gasoline, are substantially identical in composition from one refinery to the next and are referred to as being "fungible."

Regional production and consumption

The continental United States refined petroleum products market is divided in two distinct regions: the Western United States, which is primarily served by refineries located in the Pacific Coast region; and the Gulf Coast, Midwest and East Coast markets, which are primarily served by refineries located in the Gulf Coast region and imports of refined petroleum products from South America and Europe. Substantially all of TransMontaigne's supply, marketing and distribution operations occur in the Gulf Coast, Midwest and East Coast regions.

The U.S. Department of Energy divides the United States into five geographic regions. These regions are referred to as Petroleum Administration Defense Districts or PADDs. PADD III, which is the Gulf Coast region of the United States, is the largest petroleum refining hub in the U.S. with 55 refineries, responsible for approximately 47% of total U.S. daily refining capacity. The Gulf Coast historically has had an excess supply of refined petroleum products, which are shipped mainly to the East Coast and the Midwest. For the year ended December 31, 2003, the Gulf Coast had average refined petroleum production of approximately 7.6 million barrels per day and average refined petroleum product consumption of approximately 3.5 million barrels per day. For the year ended June 30, 2004, we purchased and scheduled for transportation out of the Gulf Coast approximately 228,000 barrels per day of refined petroleum products through pipelines and an additional 51,000 barrels per day of refined petroleum products by waterborne vessels.

PADD II, which is the Midwest region, is the second largest PADD in terms of crude oil throughput capacity. Production of petroleum product by refiners located in the Midwest region historically has been less than the demand for such product within that region, resulting in product being supplied from surrounding regions, primarily from the Gulf Coast via common carrier pipelines including the Explorer, TEPPCO, Seaway, Phillips and Centennial pipelines. Supply also is available via barge transport up the Mississippi River with significant deliveries into local markets along the Ohio River. For the year ended December 31, 2003, the Midwest region had average refined petroleum production of approximately 3.5 million barrels per day and average refined petroleum product consumption of approximately 4.5 million barrels per day.

PADD I is the East Coast region, and includes the Southeast, Mid-Atlantic and Northeast regions. Production of petroleum product by refiners located in the East Coast region historically has been less than the demand for such product within that region, resulting in product being supplied from surrounding regions, primarily from the Gulf Coast via the Colonial and Plantation pipelines, via barge and tanker and imports from foreign producers directly into East Coast ports. For the year ended December 31, 2003, the East Coast region had average refined petroleum production of approximately 1.9 million barrels per day and average refined petroleum product consumption of approximately 5.6 million barrels per day.

We believe that our geographically diverse terminal infrastructure and our significant pipeline shipping history position us to take advantage of the supply and demand imbalances among the Gulf Coast, Midwest and East Coast regions.

Refining and distribution

Refining. Refineries in the Gulf Coast region, which are owned predominantly by major oil companies, refine crude oil into products that have various characteristics, such as sulfur content, octane level, Reid-vapor pressure, and chemical characteristics. The refined products initially are stored at the refineries' own terminal facilities. The refineries owned by major oil companies then schedule for delivery some of their product output to satisfy their own retail delivery obligations, at branded gasoline stations, for example, and sell the remainder of their product output to independent marketing and distribution companies, such as TransMontaigne, for resale. The major refineries typically prefer to sell their excess product to independent marketing and distribution companies rather than to other refineries, which are their primary competitors.

Transportation. For an independent marketing and distribution company to distribute product from its terminals, it must first schedule that product, at least five to eight days in advance, for shipment on common carrier pipelines. Common carrier pipelines are pipelines with published tariff rates that are regulated by the Federal Energy Regulatory Commission ("FERC"). These pipelines ship product in batches, with each batch consisting of fungible product owned by several different companies. Once in the pipeline, a product may take up to twenty plus days to move from the Gulf Coast to the New York market, with much of the product in the batch being delivered to terminals located along the routes of the common carrier pipelines. A batch of one product, gasoline for example, will then be followed by a batch of different product, such as diesel fuel.

During periods of high demand for a particular product, companies may seek to ship more volume of product than space available in the pipelines, in which case the common carrier pipelines will allocate volume based on the historical shipping history of each company seeking to ship. Companies that consistently ship significant amounts of product on common carrier pipelines are allocated space on these regulated pipelines for future shipments. Companies without significant shipping histories are not guaranteed similar space on the pipelines and have more difficulty shipping their product to various locations around the country when there is high demand for pipeline capacity to those locations. TransMontaigne has a significant shipping history on the Colonial, Plantation, Explorer and TEPPCO pipelines that allows us to ship product through these pipelines during periods of high demand for pipeline capacity.

As a batch of co-mingled product is shipped on a pipeline, each terminal along the way draws the volume of fungible product that is scheduled for that facility as the batch passes in the pipeline. Consequently, each terminal must monitor the type of product in the common carrier pipeline at any time to determine when to draw product scheduled for delivery to that terminal. In addition, both the common carrier pipeline and the terminal monitor the volume of product drawn to ensure that the precise amount scheduled for delivery at that location is actually received.

With respect to product that is shipped to marine terminals, volumes of product are transported by tankers or barges.

At both inland and marine terminals, the various refined petroleum products are segregated and stored in tanks. Because the characteristics of gasoline are required to be changed at least twice per year in many locations to meet government regulations, regular unleaded gasoline produced for winter cannot be stored in a tank together with regular unleaded gasoline produced for summer. Our 55 terminal facilities include over 720 tanks ranging in capacity from 500 to 325,000 barrels per tank.

Delivery. Each inland terminal has a tanker truck loading facility commonly referred to as a "rack." Often, commercial and industrial end-users and independent retailers will rely on independent trucking companies to pick up product at the rack and transport it to the end-user or retailer at its location. Each truck holds an aggregate of approximately 8,000 gallons of various products in different compartments. The driver will swipe a magnetic card that identifies the customer purchasing the product, the carrier and the driver as well as the products to be pumped into the truck. Our computerized system electronically reviews the credentials of the carrier, including insurance and certain mandated certifications, the credit of the customer and confirms the customer is within scheduled allocation limits. When all conditions are verified as being current and correct, the system authorizes the delivery of the product to the truck. As product is being loaded into the truck, additives are blended into products, including all gasoline, to conform to government specifications and individual customer requirements. If a truck is loading gasoline for retail sale by an independent gasoline station, generic additives will be added to the gasoline as it is loaded into the truck. If the gasoline is for delivery to a branded retail gasoline station, the proprietary additive compound of that particular retailer will be added to the gasoline as it is loaded. The type and amount of additive are electronically and mechanically controlled by equipment located at the truck loading rack.

At marine terminals, the product will be stored in tanks and may be delivered to tanker trucks over a rack in the same manner as at an inland terminal. Product also may be delivered to cruise ships and other vessels, known as "bunkering," either at the dock, through a pipeline or truck, or by barge. Cruise ships typically purchase approximately 6,000 to 8,000 barrels, the equivalent of approximately 42 truckloads, of product per refueling. Bunker fuel is a mixture of diesel fuel and No. 6 oil. Each large vessel essentially requires its own mixture of bunker fuel to match the distinct characteristics of that ship's engines. Because the mixture for each ship requires precision to mix and deliver, cruise ships often prefer to refuel in United States ports with experienced companies.

Our Operations

We conduct business in the following business segments:

–>: Terminals, pipelines, and tugs and barges—consists of a terminal and pipeline infrastructure that handles refined petroleum products with transportation connections via pipelines, barges, vessels, rail cars and trucks to our facilities or to third-party facilities with an emphasis on transportation connections primarily through the Colonial, Plantation, TEPPCO, Explorer and Magellan pipeline systems.
–>: Supply, distribution and marketing—consists of services for the supply and distribution of refined petroleum products through rack spot sales, contract sales, and bulk sales in the physical and derivative markets, with retail, wholesale, industrial and commercial customers using our terminal racks and marine refueling equipment, and providing related value-added fuel procurement and supply chain management services.

Additional information regarding our business segments, including financial information, is set forth under the caption "Management's Discussion and Analysis of financial Condition and Results of Operations" and in the Notes to our Consolidated Financial Statements elsewhere herein.

Terminals, pipelines, and tugs and barges

The refined petroleum product distribution system in the United States links refineries to end-users of gasoline and other refined petroleum products through a network of terminals, pipelines, tankers, barges, rail cars and trucks. We own and operate terminal infrastructure of 55 terminals with

approximately 21.4 million barrels of aggregate capacity that handles refined petroleum products and other commercial liquids. At our terminals, we provide throughput, storage, injection and other distribution related services to wholesalers, distributors, marketers, retail gasoline station operators and industrial and commercial end-users of refined petroleum products and other commercial liquids. The two basic types of terminals are inland terminals, which are supplied by pipelines, rail cars and trucks, and marine terminals, which are supplied by ships and barges. We currently own and operate the following terminal facilities:

–>: 31 terminals with approximately 9.5 million barrels of capacity, located at various points along the Plantation and Colonial pipeline corridor, which extends from the Gulf Coast through the Southeast, Mid-Atlantic and Northeast regions;
–>: 15 terminals with approximately 3.6 million barrels of capacity, located in the Midwest and upper and lower Mississippi River areas;
–>: 8 terminals with approximately 6.0 million barrels of capacity, at various locations in Florida; and
–>: 1 terminal complex in Brownsville, Texas with approximately 2.3 million barrels of capacity.

Our network of terminals is geographically diverse with our largest terminal, the Brownsville complex, accounting for approximately 10% of our total capacity. Brownsville handles a large volume of liquid product movements between Mexico and south Texas. Fee based revenue generating activities include storage tank rentals, truck scale operations, additive injection, steam generation and handling, direct transfer operations and product blending activities.

In Florida, we currently own and operate 11 tugboats and 14 barges and a proprietary pipeline in Port Everglades, which we use to transport our product to cruise ships and other marine vessels for refueling. We also use our tugs and barges to transport third party product from our storage tanks to their facilities and to relocate our product among our Florida terminals when needed to augment our capacity. We use our tank capacity at our Florida terminals to blend diesel fuel and No. 6 oil into bunker fuel meeting our customers' specifications. In addition, we use our diesel fuel and No. 6 oil hydrant pipeline at Port Everglades to blend these products at dockside for direct delivery into our customers' vessels.

Along the Mississippi River we own and operate a dock facility in Baton Rouge, Louisiana that is interconnected to the Colonial Pipeline. This connection provides the ability to load product originating from the Colonial Pipeline onto barges for distribution up the Mississippi River, as well as serves as an injection point into the Colonial Pipeline for product unloaded from barges transporting it down the Mississippi River.

We own, operate and currently are the sole shipper on an interstate refined petroleum products pipeline operating from Mt. Vernon, Missouri to Rogers, Arkansas known as the Razorback Pipeline, together with associated terminal facilities at Mt. Vernon and Rogers. The Rogers terminal, together with the Mt. Vernon terminal and Razorback Pipeline, allows us flexibility to ship product from the Gulf Coast to this Midwest market via its connection to the Explorer Pipeline.

We generate revenues in our terminal, pipeline and tug and barge operations from throughput fees, storage fees, additization fees, pipeline transportation fees, barge and ship-assist fees, management fees and cost reimbursements and fees from other ancillary services.

Throughput Revenues. We earn throughput fees for each barrel of refined petroleum product that is distributed at our terminals. A significant majority of the throughput at our terminals consists of product that we have purchased, marketed, sold and dispensed over the rack at our terminals. The

remainder of the throughput volume at our terminals is generated from exchange agreements and throughput arrangements with third parties. Terminal throughput fees are based on the volume of products distributed at the facility's truck loading racks, generally at a standard rate per barrel of product. Unlike common-carrier pipeline services, terminal services are not subject to price (tariff) regulations, allowing the marketplace to determine the prices that are charged for services.

For example, our supply, distribution and marketing business may purchase a specific volume of product in the Gulf Coast and enter into a sale agreement for the product in Virginia. The product may be shipped to our terminals serving that area for delivery to the customer or the delivery obligation may be satisfied from our existing inventory in those terminals. In either event, the delivery of product from our terminal constitutes throughput. Third-party throughput operates in the same manner except that it is a third party that directs the product delivery to our terminals rather than our own supply, distribution and marketing business.

Exchange agreements generally are term agreements that involve our receipt of a specified volume of product at one location in exchange for delivery by us of product at a different location. We enter into exchange agreements with major oil companies to increase throughput at our terminals and establish greater shipping history on the common carrier pipelines. We generally receive a fee based on the volume of the product exchanged. The exchange fee takes into account the terminal throughput fee, the cost of transportation from the receipt location to the delivery location, as well as a fee for "regrading" if we deliver one type of product and receive a different type of product. For example, if a major oil company has a one-year agreement to deliver premium gasoline in Atlanta, but does not have a terminal there, that company may enter into an exchange agreement with us whereby we will provide the product at our truck rack in Atlanta and, in exchange, they will provide us with product, which may be the same or a different grade of gasoline, in the Gulf Coast and pay us a negotiated fee.

Storage Revenues. We lease storage capacity at our terminals to third parties and our supply, distribution and marketing operation and earn a storage fee based on the volume of the storage capacity leased. Terminal storage fees generally are based on a per barrel of leased capacity per month rate and will vary with the duration of the storage arrangement (generally less than 18 months), the type of product stored and special handling requirements, particularly when certain types of chemicals and other commercial liquids are involved. For example, the entire 2.3 million barrel capacity at our Brownsville terminal facility is leased, or available for lease, to third parties.

Additization Revenues. Additization or injection is the process of injecting refined petroleum products with additives and dyes. Some injected products, such as detergent additives, are standard and are required to comply with governmental regulations, while other injected products are proprietary to certain of our customers. We provide injection services to our customers in connection with the delivery of product at our terminals. These fees are generally based on the volume of product injected and delivered over the rack at our terminals.

Pipeline Revenues. We earn pipeline transportation fees at our Razorback pipeline based on the volume of product transported and the distance from the origin point to the delivery point. Tariff rates on the Razorback Pipeline are regulated by the FERC. We also earn transportation fees at our Port Everglades pipeline hydrant delivery system based on the volume of product delivered to cruise ships and freight vessels. The Port Everglades hydrant system allows a more efficient refueling process than barge to ship refueling.

Barge and Ship-Assist Revenues. Our barges earn transportation fees from third parties at negotiated rates based on the volume of product that is shipped and the distance to the delivery point. Our barges also provide marine vessel fueling services, referred to as bunkering, at our Port Everglades/Ft.

Lauderdale, Cape Canaveral, Port Manatee/Tampa and Fisher Island/Miami terminals. Bunkering fees are based on the volume and type of product sold. Our tugboats also earn fees for providing docking and other ship-assist services to cruise and cargo ships and other vessels in South Florida ports based on a per docking per tug basis.

Management Fees and Cost Reimbursements. We manage and operate for a major oil company 17 terminals that are adjacent to our Southeast facilities and receive a reimbursement of costs. We also manage and operate for a foreign oil company a bi-directional products pipeline connected to our Brownsville, Texas terminal facility.

Other Service Revenues. In addition to providing storage and distribution services at our terminal facilities, we also provide ancillary services including heating and mixing of stored products and product transfer services. Many heavy oil products, such as No. 6 oil, bunker fuel and asphalt require heating to keep them in a liquid state suitable for shipping. For example, heavy oil products may be transported to a terminal in non-insulated tank rail cars and, therefore, must be re-heated before being transferred into terminal storage tanks or into trucks or barges. We provide these heating services to our customers and charge negotiated fees based on the type and volume of product heated. We also earn transfer fees for transferring product between tanks and transportation equipment. For example, we would charge a fee to transfer product from a rail car or a barge to a storage tank at a customer's request. We also recognize revenues upon the sale of product to our supply, distribution, and marketing operation resulting from the excess of product deposited by third parties into our terminals over the amount of product that the customer is contractually permitted to withdraw from those terminals.

Supply, distribution and marketing

We generally purchase our inventory of refined petroleum products at prevailing prices from refiners and marketers at production points and common trading locations along the Gulf Coasts of Texas and Louisiana. Once we purchase these products, we schedule them for delivery via pipelines and vessels to our terminals, as well as terminals owned by third parties with which we have storage or throughput agreements, in the Midwest and East Coast regions. From these terminal locations, we then sell our products to customers primarily through three types of arrangements: rack spot sales, contract sales, and bulk sales.

Rack Spot Sales. Rack spot sales are sales that do not involve continuing contractual obligations to purchase or deliver product. Rack spot sales are priced and delivered on a daily basis through truck loading racks or marine fueling equipment. At the end of each day for each of our terminals, we establish the next day selling price for each product for each of our delivery locations. We announce or "post" to independent local jobbers via facsimile, website, e-mail, and telephone communications the rack spot sale price of various products for the following morning. Typical rack spot sale purchasers include commercial and industrial end-users, independent retailers and small, independent marketers, referred to as "jobbers," who resell product to retail gasoline stations or other end-users. Our selling price of a particular product on a particular day is a function of our supply at that delivery location or terminal, our estimate of the costs to replenish the product at that delivery location, and our desire to reduce inventory levels at that particular location that day.

We manage the physical quantity of our inventories of product through rack spot sales. Our rack spot sales volume for a particular product is sensitive to changes in price. If our objective is to increase rack spot sales volume for a particular product of ours at a specific delivery location, then we would post the selling price of that product at the low end of the range of competitive prices being offered in the applicable market to induce purchasers in that market to choose to buy our product as opposed to product offered by competitors in that market. This would occur if, for example, we expect that prices for that product will decrease at that location in the near future or if we have significant deliveries scheduled to arrive at that location in the near term.

Contract Sales. Contract sales are made pursuant to negotiated contracts, generally ranging from one to twelve months in duration, that we enter into with local market wholesalers, independent gasoline station chains, heating oil suppliers, cruise ship operators and other customers. Contract sales provide these customers with a specified volume of product during the agreement term. Delivery of product sold under these arrangements generally is at our truck racks or via our marine fueling equipment. At the customer's option, the pricing of the product delivered under a contract sale may be fixed at a stipulated price per gallon, or it may vary based on changes in published indices.

For example, we may enter into an agreement with a retail heating oil supplier in the Northeast to provide the supplier with heating oil, for delivery at our truck rack or a rack owned by a third party, during the high demand winter months at a fixed price.

Bulk Sales. Bulk sales generally involve the sale of products in large quantities in the major cash markets including the Houston Gulf Coast, New York Harbor, Chicago, Illinois and the Tulsa, Oklahoma refining area. We also may make a bulk sale of products while the product is being transported in the common carrier pipelines or by barge or vessel. Finally, we may make a bulk sale to purchasers while our product is in the Gulf Coast prior to the time when this product enters the common carrier pipelines.

Supply disruptions, extreme weather, and other unforeseen factors may cause supply and demand imbalances in major cash markets around the country resulting in price differences, referred to as "basis differentials," between these markets. These price differences often exceed the costs of transporting product between the markets. Bulk sales of products are entered into with major oil companies and independent wholesalers and distributors who purchase product in the market to cover their delivery obligations during such periods of supply and demand imbalance. We attempt to capitalize on these variations by monitoring prices in the major cash markets, re-scheduling shipments and making bulk sales of product in the markets that achieve the highest value to us.

For example, a major oil company may become aware that it is going to have a production outage at its refinery in the Gulf Coast region and may determine that the outage will cause several of its terminals in the Northeast to be short of product within a few days. If the major oil company cannot replace the product, it could fail to meet delivery obligations from the affected terminals and, therefore, must turn to the market to supply its needs. In that case, if we had the required type and volume of product available, either prior to the time when this product enters the common carrier pipelines or in-transit along a pipeline, we may enter into a bulk sales agreement to sell the product to the major oil company in exchange for cash.

Supply chain management services

Industrial, commercial and governmental entities with significant ground fleets need to ensure adequate fuel supplies for their fleet vehicles. For many of these companies and governmental entities, the cost of fuel is a significant expenditure and the administration and record keeping involved is burdensome. Some companies also maintain their own proprietary refueling facilities, which requires monitoring fuel levels, scheduling deliveries, controlling inventories and filing excise tax returns. Other companies use retail gasoline stations to refuel their vehicles, resulting in extensive payment handling as well as exposure to price differences among stations and price fluctuations in the market. In response to these market needs, we developed our supply chain management services business segment. We provide supply chain management services to companies and governmental entities that desire to outsource their fuel supply function to focus their efforts on their core competencies and to reduce the price volatility associated with their fuel supplies for budgetary reasons. These services often include price management solutions that provide our customers an assured source of fuel at a predictable price. Our

customer base includes companies involved in the manufacture and distribution of consumer products, express shipping services, waste disposal services, transportation services, and state and local government entities.

These customers use our proprietary web-based technology, which provides them the ability to budget their fuel costs while outsourcing all or a portion of their procurement, scheduling, routing, excise tax and payment processes. Using electronic metering equipment, we can monitor the amounts of product stored and delivered at our customers' proprietary refueling locations. In addition, through our strategic relationship with Comdata-Comchek MasterCard, we can monitor the volume of fuel purchased by our customers' ground fleet vehicles at retail truck stops and service stations.

We currently offer three types of supply chain management services: delivered fuel price management, retail price management and logistical supply chain management services.

Delivered Fuel Price Management. Delivered fuel price management contracts involve the sales of committed quantities of specific motor fuels delivered to our customer's proprietary fleet refueling locations, at fixed prices for terms up to three years. On a daily basis, for each of our customer's facilities, we procure product, schedule delivery, manage local inventory quantities and summarize each customer's purchases by location and vehicle. Typical customers for delivered fuel price management services have large fleets of vehicles that drive fixed, scheduled routes, making refueling at a proprietary refueling location an attractive choice.

For example, we may enter into a delivered fuel price management contract with a customer that has storage and refueling facilities at its fleet operations centers. We will agree to deliver diesel fuel directly to the customer's proprietary refueling location at a fixed price per gallon. We then monitor the customer's fuel usage and schedule additional fuel deliveries as needed. We will provide the customer with a single invoice for all of the fuel deliveries that includes reconciliation of all bills of lading against deliveries and breaks out accumulated third-party transportation costs. This information is available to the customer on a customized web-based portal.

Retail Price Management. Retail price management contracts typically are entered into for a period of up to 18 months with customers that require flexibility in refueling locations, either because they do not have proprietary refueling facilities or because they generally do not operate along fixed routes. Under these arrangements, customers commit to a specific monthly notional quantity of product within one or more metropolitan areas. The customer's drivers will purchase fuel at a retail gasoline station within the metropolitan area and use their Comdata-Comchek MasterCard to pay the retail price at that station. We then settle with our customer the net financial difference between a stipulated retail price index for that metropolitan area and our customer's contract price on a monthly basis. If the contract price is less than the average indexed price, we will pay the customer the net difference. If the contract price exceeds the average indexed price, the customer will pay us the net difference. In either case, the customer will have effectively managed its exposure to fuel costs at the contract price. Through our proprietary web-based software, our customers receive a monthly report of each of these activities. Typical customers for retail price management services include companies that have large fleets that are dispatched to specific service or delivery locations on an as-needed basis.

For example, we may enter into a retail price management contract with a customer for a price per gallon of gasoline equal to a stipulated retail price index plus a negotiated fee. The customer's fleet drivers are able to purchase fuel at almost any retail gasoline station using their Comdata-Comchek MasterCard. At the time of purchase, the driver pays for the gasoline using the company fleet card, and the vehicle number and the amount and price of fuel purchased are recorded. Comdata-Comchek MasterCard sends daily electronic reports to us indicating a summary of the data collected by the

credit cards. This information is made available to the customer on our proprietary web-site. We then settle the net difference between the indexed price and the customer's contract price on a monthly basis.

Logistical Supply Chain Management. Under our logistical supply chain management arrangements, we provide our proprietary web-based refined petroleum product procurement, inventory management, scheduling, routing, excise tax and consolidated billing services to customers on a stand alone basis without any delivery or price management products. These services also are often integrated with our Comdata-Comchek MasterCard relationship, thereby affording our customers complete flexibility to obtain their supply of products at almost any retail gasoline station. These services typically are charged to the customer on a per gallon basis or at negotiated rates. Typical logistical service customers include governments and customers that are seeking to outsource or streamline record keeping functions but are willing to continue to bear price fluctuations. Often, a customer will initially contract for logistical supply chain management services and later use our delivered fuel price management or retail price management services.

For example, a customer may want the benefits of a single invoice for all fuel purchases and the ability to manage its fuel usage on-line. We provide access to fuel purchase data in real time, providing an automated platform for analysis tailored to each customer. In addition, many customers have diverse logistical requirements, buying fuel in bulk, at retail locations and through mobile refueling services. We can provide integrated management of all supply and logistical requirements for our customers' bulk locations and use our Comdata-Comchek MasterCard relationship to manage the retail and mobile refueling volumes. The company fleet card would capture the fueling transaction data for the bulk, retail and mobile refueling activity facilitating customized reporting on our proprietary web site. Our customers benefit from a single resource for the procurement, pricing and reporting of all fuel data regardless of the logistical requirements.

We have received a revenue ruling from the Internal Revenue Service that allows us to provide state and local government vehicle fleets with a simplified process for managing and obtaining fuel tax exemptions. State and local governments are exempt from paying federal excise taxes on the fuel consumed by their vehicle fleets. Normally, fleet vehicles would purchase gasoline at retail gasoline stations, where excise taxes are included in the price of gasoline, and the government agency would file a tax return to obtain a refund of excise taxes paid. By using our supply chain management services, these tax-exempt government fleets can purchase fuel at almost any retail location using their Comdata-Comchek MasterCard. Comdata pays the merchant and transfers the balance to our account. We then bill our customer net of federal excise taxes. We file all necessary excise tax returns on behalf of these customers with the applicable taxing authorities and we receive a credit against our excise tax payment obligations. We believe that this additional service gives us a competitive advantage that will allow us to attract additional government fleet customers.

Acquisitions

Coastal Fuels assets

On February 28, 2003, we acquired the Coastal Fuels assets, including five Florida terminals, with aggregate storage capacity of approximately 4.9 million barrels, and a related tug and barge operation. The purchase price for the transaction was approximately $156 million, including approximately $37 million of inventory.

The Coastal Fuels assets primarily provide sales and storage of bunker fuel, No. 6 oil, diesel fuel and gasoline at Cape Canaveral, Port Manatee/Tampa, Port Everglades/Ft. Lauderdale and Fisher

Island/Miami, and storage of asphalt at Jacksonville, Florida. In addition, the Coastal Fuels assets facilities provide a variety of third-party lease capacity to the asphalt, jet fuel, power generation and crude oil industries.

With the addition of the Coastal Fuels assets, we have significantly expanded our existing Florida operations at our Port Everglades and Tampa terminals. In addition, the acquisition of the Coastal Fuels assets provide the following benefits:

–>: we have established a leading presence in key bunkering locations in various Florida ports, including the Ports of Miami, Port Everglades, Cape Canaveral and Tampa;
–>: the ports served are among the top cruise ship ports in the U.S., providing steady year-round demand with greater demand in the winter months;
–>: the terminals are located primarily in areas with limited opportunity for new terminal expansion because of zoning, land values and environmental considerations;
–>: no refineries exist in Florida and the major Florida markets are served by waterborne vessels due to the absence of major product supply pipelines;
–>: Florida is one of the fastest growing states in population, with additional potential demand growth in both the cruise ship bunkering and light oil businesses;
–>: the Coastal Fuels assets include the only pipeline hydrant delivery system serving Port Everglades, which allows a more efficient refueling process than barge to ship refueling; and
–>: a number of opportunities to increase operational efficiency exist with our current operations in Florida.

Fairfax, Virginia terminal

On January 31, 2003, we acquired a terminal in Fairfax, Virginia, which extended our supply, distribution and marketing presence in the Mid-Atlantic market. The Fairfax terminal supplies petroleum products to the Washington D.C. market and receives product off the Colonial Pipeline. The strategic reasons for acquiring the Fairfax terminal included:

–>: the attractive geographic location of the terminal:
–>: the terminal expands our delivery capabilities into and around Washington, D.C.;
–>: the terminal is located in an area with limited opportunity for new terminal expansion because of zoning, land values and environmental considerations; and
–>: the Washington, D.C. area is growing and provides future growth opportunities.
–>: potential synergies that would result with our existing terminal infrastructure along the Colonial Pipeline.

Norfolk, Virginia terminal

On October 1, 2003, we closed on the purchase of a terminal in Norfolk, Virginia, which increased our supply, distribution and marketing presence in the Mid-Atlantic market. The strategic reasons for acquiring the Norfolk terminal included:

–>: an opportunity to realize operating synergies by combining these operations with our existing Norfolk, Virginia terminal;
–>: the acquired terminal provides us with additional storage in the market; and

–>: the terminal has a docking facility that will permit us to receive shipments from and deliver shipments to the water.

Risk Management

Our risk management committee, composed of senior executives of TransMontaigne, has established risk management policies to monitor and manage commodity price risks. Our risk management strategy generally is intended to maintain a balanced position of forward sale and forward purchase commitments, discretionary inventories held for immediate sale or exchange and risk management contracts, thereby reducing exposure to commodity price fluctuations. We evaluate our exposure to commodity price risk from an overall portfolio basis that considers the continuous movement of discretionary inventory volumes held for immediate sale or exchange and our obligations to deliver products at fixed prices through our sales contracts and supply chain management contracts. Our physical inventory position, which includes firm commitments to buy and sell product, is reconciled daily through the use of our inventory monitoring equipment and software and that position is offset with risk management contracts, principally futures contracts on the New York Mercantile Exchange ("NYMEX"). Futures contracts are obligations to purchase or sell a specific volume of product at a fixed price at a future date.

We purchase product primarily from refineries along the Gulf Coast in Texas and Louisiana. To the extent that we have physical inventory or purchase commitments, we enter into a futures contract on the NYMEX to sell product at a specified future date and, thereby, reduce our exposure to changes in commodity prices. Upon sale of the physical inventory of product to a third party, we enter into a futures contract that offsets all or a portion of the original futures contract and, effectively, cancels our original NYMEX position to the extent of the product sold. If there is correlation in price changes between the NYMEX futures market and the value of physical products in the cash market, the net losses on our risk management activities should be offset by the net operating margins we receive when we sell the underlying discretionary inventory. Conversely, the net gains on our risk management activities should be offset by the net operating deficiencies we incur when we sell the underlying discretionary inventory. Therefore, in order to effectively manage commodity price risk, we must predict when we will sell the underlying product. If we fail to accurately predict the timing of those future sales, and the product remains in our inventory longer than the expiration date of the futures contract, we must settle the old futures contract and enter into a new futures contract to sell the product to manage the commodity price risk against the same inventory. We refer to this as "rolling" the risk management contracts. Furthermore, we may be unable to precisely match the underlying product in our futures contracts with the exact type of product in our physical inventory. To the extent that price fluctuations of the product covered by the NYMEX futures contract does not match the price fluctuations of the product in our physical inventory, our exposure may not be mitigated.

We also manage our exposure to commodity price risks in our supply chain management services business. At the execution of each contract for which we provide price management solutions, we enter into NYMEX futures contracts in volumes equal to the customer's contractual commitment to purchase product to mitigate our exposure to commodity price fluctuations throughout the contract period. However, with respect to a portion of our contracts, we are unable to precisely match the underlying product in our risk management contract to the exact type of product contemplated by our delivered fuel price management contract or retail price management contract. To the extent that the price fluctuations of the product covered in our price management contracts do not match the price fluctuations of the product covered by the NYMEX futures contract that we use, our exposure may not be entirely mitigated.

There are certain risks that we either do not attempt to manage or that cannot be completely managed. For example, we generally do not manage the price risk relating to basis differentials. We attempt to capitalize on basis differentials by transporting product to the delivery location that maximizes the value of the product to us. These basis differentials create opportunities for increased operating margins when we successfully exploit the highest value location for sales of our discretionary inventories of products. However, the margins created from exploiting these market inefficiencies do not occur evenly or predictably from period to period and may cause fluctuations in our results of operations.

Our existing operations require us to maintain base operating inventory volumes of approximately 4.0 million barrels, consisting primarily of product in transit generally on common carrier pipelines. We also maintain product linefill and tank bottom volumes of approximately 1.0 million barrels in our terminals and pipeline connections. Our base operating inventory volumes and product linefill and tank bottom volumes are collectively referred to by us as our minimum volumes. We generally do not manage the commodity price risk relating to minimum volumes because these volumes generally are not available for immediate sale or exchange. As a result, any futures contracts used to manage the commodity price risk relating to the minimum volumes would have to be continuously rolled from period to period, which, during unfavorable market conditions, would result in a realized loss on the futures contract without the realization of an offsetting gain in the value of the base operating inventory. Changes in our operation, such as the acquisition of additional terminals or increases in our contract sales volumes, may result in changes to our minimum volumes.

Our risk management policy allows our management team the discretion under certain market conditions to manage the commodity price risk relating to up to 500,000 barrels of our base operating inventory, which would reduce the unmanaged inventory to approximately 4.5 million barrels, or to leave unmanaged up to 500,000 barrels of our discretionary inventory available for immediate sale or exchange, which would increase our unmanaged inventory to approximately 5.5 million barrels. Management is allowed this discretion in order to create the opportunity to capture financial gains, or prevent financial losses, on predictable price movements with respect to up to 500,000 barrels of physical product. We decide whether to manage the commodity price risk relating to a portion of our base operating inventory or to leave a portion of our discretionary inventory available for immediate sale or exchange unmanaged depending on our expectations of future market changes. To the extent that we do not manage the commodity price risk relating to a portion of our inventory and commodity prices move adversely, we could suffer losses on that inventory value. If, however, prices move favorably, we would realize a gain on the sale of the inventory that we would not realize if substantially all of our inventory was managed.

All of our futures contracts are traded on the NYMEX and, therefore, require daily settlements for changes in commodity prices. Unfavorable commodity price changes subject us to margin calls that require us to provide cash collateral to the NYMEX in amounts that may be material. For example, we may enter into a futures contract to manage the commodity price risk relating to discretionary inventory held for immediate sale or exchange. If commodity prices rise before the expiration date of the futures contract, the futures contract will be "out of the money," which means that we will be obligated to deposit funds to cover a margin call based on the increase in the commodity price. If commodity prices fall before the expiration date of the futures contract, a portion of our margin call deposits with the NYMEX will be returned to us. If there is correlation in pricing and timing between the futures market and the physical products market, the net changes in our margin position should be offset by the net operating margins we receive when we sell the underlying discretionary inventory. We use our credit lines to fund these margin calls, but such funding requirements could exceed our ability to access capital. If we are unable to meet these margin calls with borrowings or cash on hand, we

would be forced to sell product to meet the margin calls or to unwind futures contracts. If we are forced to sell product to meet margin calls, we may have to sell at prices or in locations that are not advantageous, and could incur financial losses as a result.

Industry Trends

Petroleum imports and Gulf Coast production

United States crude oil production has declined from 6.8 million barrels per day in 1993 to 5.6 million barrels per day in 2003. Imports of petroleum from the Middle East, South America and elsewhere have increased substantially over this period from 8.6 million barrels per day in 1993 to 12.3 million barrels per day in 2003. Domestic crude oil production may be refined at any of the regional refineries around the United States. However, the imported crude oil generally is shipped by vessel into the Gulf Coast for processing at the large refining complexes. Crude oil production in the Gulf of Mexico, one of the largest sources of domestic production, also is refined primarily in these Gulf Coast refineries. The refined petroleum products then are shipped to other regions of the United States. We believe that this trend will lead to more refined petroleum product shipment from the Gulf Coast to the Midwest and East Coast, requiring additional transportation and storage capacity in the Midwest and East Coast.

New sulfur regulations

In February 2002, the Environmental Protection Agency ("EPA"), promulgated the Tier 2 Motor Vehicle Emissions Standards Final Rule for all passenger vehicles, establishing standards for sulfur content in gasoline. These regulations mandate that the average sulfur content of gasoline for highway use produced at any refinery not exceed 30 parts per million during any calendar year by January 1, 2006. In addition, in January 2001, the EPA promulgated its on-road diesel regulations, which will require a 97% reduction in the sulfur content of diesel fuel sold for highway use by June 1, 2006. Regulations for off-road diesel equipment also are pending. The stricter regulations will require refining companies to make significant capital expenditures to upgrade their facilities to comply with the new standards. Because of the technical sophistication and the capital outlays that will be required for compliance with such regulations, the large oil companies with major refining operations in the Gulf Coast are expected to be better prepared to meet the new standards than the smaller independent refiners. The large oil companies also may choose to partially refine crude oil in the larger and better-equipped Gulf Coast refineries for the purpose of reducing its sulfur content, and then ship the partially refined product to their smaller and less technically sophisticated inland refineries for final processing. We believe that these trends will lead to more refined petroleum product shipment from the Gulf Coast to the Midwest and East Coast, requiring additional transportation and storage capacity in the Midwest and East Coast.

Consolidation and specialization

In the 1990's, the petroleum industry entered a period of consolidation and specialization.

–>: Refiners and marketers began to pursue development of large-scale, cost-efficient operations, thus leading to several refinery acquisitions, alliances and joint ventures. The companies involved in several of the mergers of large oil companies have sold retail and terminal assets in order to rationalize merged operations, and to comply with legal requirements to divest assets in certain geographic markets.

–>: Major oil companies also began to re-deploy their resources to focus on their core competencies of exploration and production, refining and retail marketing. Industry participants have sought to sell portions of their proprietary transportation and storage and distribution networks.

This industry trend towards consolidation and specialization has created opportunities to capitalize on storage and distribution services. We expect that acquisition opportunities will continue to be generated as this trend continues.

The growth in Gulf Coast refining capacity has resulted in part from consolidation in the petroleum industry to take advantage of economies of scale from operating larger, concentrated refineries. The growth in refining capacity and increased product flow attributable to the Gulf Coast region has created a need for additional transportation, storage and distribution facilities in the Gulf Coast, Midwest and East Coast regions. The competition among refiners resulting from the consolidation trend, combined with continued environmental pressures, governmental regulations and market conditions, increasingly is resulting in the closing of smaller, independent inland refiners, creating even greater demand for petroleum products refined by the major oil companies in the Gulf Coast region.

Hypermarkets and alternative retail gasoline outlets

The retail distribution of gasoline is experiencing a transformation as consumer consumption patterns are moving away from gasoline distributed at the retail outlets of large oil companies, or "branded gasoline," toward unbranded gasoline from independent retail outlets offering lower prices and convenient locations. For example, many hypermarkets, grocery stores, convenience stores, discount retailers and wholesale outlets have installed gasoline pumps in their parking lots as a way to expand their product and service offerings and to allow their customers the benefit of "one-stop shopping." The increase in popularity of unbranded outlets has created new sales and distribution opportunities for independent petroleum product suppliers.

Competitive Strengths

We believe that we have the following competitive strengths, which allow us to take advantage of the industry trends outlined above:

Significant asset base and shipping history

The Gulf Coast is a large shipper of refined petroleum products to the Midwest and East Coast regions. We have a geographically diverse network of terminals that allows us to take advantage of the differences between supply in the Gulf Coast and demand in the Midwest and East Coast. Our size, both in terms of number of terminals and total storage capacity, compares favorably with any integrated oil company.

This geographic diversity also allows us to quickly sell our product inventory from time to time in one or more locations while maximizing value to us. To purchase products in the Gulf Coast and sell the products in the Midwest and East Coast, it is necessary to have a shipping history on common carrier pipelines and an extensive network of terminals. Our shipping history on the Colonial, Plantation, Explorer and TEPPCO pipelines allows us to ship large volumes of products over these pipelines to our and third-party terminals. This shipping history provides us the benefit of allocated space on these common carrier pipelines during high demand periods, which is an advantage over competitors that do not have as significant a shipping history when pipeline capacity is over-subscribed.

We believe that we will be able to further capitalize on our network of terminals in the Gulf Coast, Midwest and East Coast following implementation of the new sulfur standards promulgated by the EPA. We anticipate that refining companies will be required to make significant capital expenditures to

upgrade facilities to comply with such new sulfur regulations. Because of the technical sophistication and the capital outlays that will be required for compliance with such regulations, we expect that the large oil companies with major refining operations in the Gulf Coast will gain a competitive advantage over the smaller independent refiners. We believe that this will lead to more petroleum product shipment from the Gulf Coast to the Midwest and the East Coast, and require additional storage capacity in the Midwest and East Coast, providing additional growth opportunities for us.

Ability to link asset base, product supply and management services

Our supply, distribution and marketing operations and our terminal, pipeline and tug and barge operations each utilize and benefit from each other, creating opportunities to realize additional value in each of our business segments that could not be realized if each business segment were operated independently.

Our supply, distribution and marketing operations generally use our terminal, tug and barge and pipeline infrastructure to market various products and provide specialized supply, logistical and risk management services to our customers. A significant portion of the throughput on our terminal and pipeline infrastructure is driven by our own supply, distribution and marketing business. As a result, we do not rely solely on third parties for our throughput activity.

We own and operate terminals located throughout the regions served by four major petroleum product pipelines on which we have a significant shipping history. In addition, we own and operate a petroleum product pipeline and a fleet of tugboats and barges. Also, we own and operate a dock strategically located on the Mississippi River with an interconnection to the Colonial Pipeline. We also have substantial experience in managing complex petroleum product supply and demand arrangements, utilizing equipment and software, that allow us to monitor supplies in all of our facilities on a daily basis.

Because we link our asset base with our supply, distribution and marketing operations, we have the flexibility to market product during adverse market conditions to meet our contractual volume obligations, maintain our common carrier pipeline shipping history and generate throughput revenues.

Our geographically diverse terminal infrastructure allows our supply, distribution and marketing operations to pursue product purchase and sale opportunities across various regions in transactions that maximize value to us. For example, if we have product in the Colonial Pipeline, which serves the Mid-Atlantic and the Northeast, but there is a supply disruption in Chicago, we can take advantage of our Baton Rouge dock facility to redirect the product by drawing it off the Colonial Pipeline and loading it on barges for shipment to the Chicago area to take advantage of the basis differential. We then quickly evaluate whether the redirection of this shipment will result in shortages at any of our other terminals along the Colonial Pipeline and, if so, reduce demand at those terminals by posting a higher rack spot sales price. In addition, we can purchase additional product in the Gulf Coast region and take advantage of our extensive shipping history to be allocated pipeline capacity to increase subsequent shipments on the Colonial Pipeline to make up any shortfall caused by the original redirection of product to Chicago.

Supply chain management services

In order to operate more efficiently and to reduce overhead costs, many companies and governmental entities have begun to outsource their fuel supply function. This trend is creating an emerging market for services that allow these customers to focus their efforts on their core competencies and to reduce the price volatility associated with fuel supply for budgetary reasons. We provide a broad scope of services that include fuel supply, monitoring, excise tax administration and price management

solutions, allowing our customers to obtain all of the required fuel supply chain management functions from a single source. We believe that we are the only significant independent fuel supply chain management services provider in the United States offering this extensive suite of services.

Technology and back-office infrastructure

We have assembled monitoring equipment and software to create an integrated, flexible system that allows us to effectively manage petroleum products throughout our terminal, pipeline and water-borne infrastructure on a real time basis.

All of our terminals are equipped with equipment to monitor product supplies and outflows as well as for any environmentally harmful releases of product, such as leaks or spills. This equipment is interconnected electronically with our central inventory management office and automatically reports supply levels in all of our facilities several times daily. The electronic linkage of our terminals with our product supply function creates an inherent competitive strength by allowing us to make real time decisions on product purchases and sales.

We use a magnetic card system at our terminals that allows us to control product sales deliveries and also allows us to manage our credit risk exposure. Each of our rack customers is given a magnetic card that can be used only at our terminals. Upon arrival at one of our racks, the driver of the truck swipes the magnetic card and inputs a product and volume request. This information is processed through our computerized inventory management system to determine the credentials of the carrier and whether the driver's product and volume request is within the customer's allocation of product for that month. The system also determines if the customer is current in its payments to us. If it is determined that the customer's allocation of product already has been drawn or if the customer is delinquent in paying its invoices to us, then the sale will not be allowed. The magnetic card system at each terminal is interconnected with our inventory management and billing system.

We also use a proprietary web-based system in our supply chain management services business that allows us to provide refined petroleum product procurement, inventory management, scheduling, routing and excise tax and consolidated billing services to our customers. Through our relationship with Comdata-Comchek MasterCard, we provide integrated billing services to our supply chain management services customers. These customers receive MasterCard credit cards that are distributed to their fleet vehicle operators for use in purchasing gasoline at any retail gasoline station that accepts MasterCard as a method of payment. On a daily basis, we receive information on these accounts electronically from Comdata-Comchek MasterCard into our billing system. This information is posted on our web-based system, which can be accessed by our supply chain management services customers, allowing them to closely monitor fuel usage and costs by vehicle on a real time basis.

The refined petroleum products that arrive at terminals do not have excise taxes included in their price. At the time the products are sold over the rack, however, excise tax must be added to the price and paid by the purchasers of our products. The process of calculating, collecting, paying and reporting the excise taxes imposed by state and federal authorities requires extensive knowledge, expertise and administrative infrastructure. For example, we may make a delivery of gasoline at our rack that is located in one state to a truck that will transport the fuel to a neighboring state. Because taxation rules differ among locations, we must keep track of where the fuel will be ultimately delivered, charge the appropriate excise tax and file excise tax returns in the appropriate jurisdictions. We have developed an infrastructure to administer excise taxes on product that is handled at our terminals.

Strategies

The goal of our business strategies is to enhance our position as a leading independent provider of integrated refined petroleum products terminal, storage, supply, distribution and marketing services. Our strategies include:

–>: Capitalize on the acquisition of the Coastal Fuels assets in Florida.
–>: We intend to take advantage of the steady year-round demand in the ports served.
–>: We intend to pursue growth opportunities in both the cruise ship bunkering and light oil businesses.
–>: We intend to expand our bunkering service to shipping markets outside of the cruise ship industry.
–>: Capitalize on our infrastructure by linking our significant asset base to our supply, distribution and marketing business.
–>: We intend to take advantage of our extensive network of terminals, as well as our shipping history on common carrier pipelines, to exploit supply and demand variations and basis differentials among the Gulf Coast, Midwest and East Coast regions.
–>: We intend to use our significant terminal capacity to meet the growing demand for boutique blends of gasoline spurred by recent and anticipated changes in government regulations.
–>: We intend to capitalize on the favorable location of our Baton Rouge docking facility, which allows us to transfer product between the Colonial Pipeline which serves the East Coast, and the Mississippi River, which serves portions of the Midwest. This allows us to redirect product to the Midwest or the East Coast to take advantage of basis differentials.
–>: Pursue attractive acquisitions.
–>: We intend to acquire additional terminal and storage facilities that will either complement our existing asset base and distribution capabilities, or provide entry into new markets. In light of the recent industry trend large energy companies divesting their distribution and terminal operations, we believe there will continue to be significant acquisition opportunities.
–>: Actively pursue new sales and distribution opportunities by marketing our services to hypermarkets.
–>: Expand our supply chain management services.
–>: We intend to expand our existing supply chain management team and equipment to enable us to provide supply chain management services to additional customers with large ground transportation fleets.
–>: We intend to actively market our supply chain management solution for managing and obtaining excise tax exemptions on fuel purchases to government fleet customers.
–>: Continue to manage our exposure to commodity price volatility.
–>: Our risk management strategy allows us to continue to have product throughput at our terminals regardless of commodity price volatility, permitting us to buy, market and sell product and services even during adverse commodity market conditions.
–>: Our risk management strategy also allows us to keep our efforts focused on maximizing the value of our physical assets and expanding our supply chain management services business.

Environmental Matters

Our operations are subject to extensive federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, and which require expenditures for remediation at various operating facilities, as well as expenditures in connection with the construction of new facilities. We believe that our operations and facilities are in material compliance with applicable environmental regulations. Environmental laws and regulations have changed substantially and rapidly over the last 20 years, and we anticipate that there will be continuing changes in the future. The trend in environmental regulation is to place more restrictions and limitations on activities that may impact the environment, such as emissions of pollutants, generation and disposal of wastes and use and handling of chemical substances. Increasingly strict environmental restrictions and limitations have resulted in increased operating costs for us and other businesses throughout the United States, and the costs of compliance with environmental laws and regulations may continue to increase. We will attempt to anticipate future regulatory requirements that might be imposed and to plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. We do not anticipate that we will be required in the near future to expend amounts that are material in relation to our total capital expenditures program to comply with environmental laws and regulations, but inasmuch as such laws and regulations are frequently changed, we are unable to predict the ultimate costs of compliance.

TransMontaigne's operations require environmental permits under various federal, state and local environmental statutes and regulations. The cost involved in obtaining and renewing these permits is not material.

Water

The Federal Water Pollution Control Act of 1972, as renamed and amended as the Clean Water Act ("CWA"), imposes strict controls against the discharge of oil and its derivates into navigable waters. The CWA provides penalties for any discharges of petroleum products in reportable quantities and imposes substantial potential liability for the costs of removing an oil or hazardous substance spill. State laws for the control of water pollution also provide for various civil and criminal penalties and liabilities in the event of a release of petroleum or its derivatives in surface waters or into the groundwater. Spill prevention control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum tank spill, rupture or leak. A containment berm is an earthen or cement barrier, impervious to liquids, which surrounds a storage tank holding between 1,000 and 500,000 gallons of petroleum products or other hazardous materials and used to prevent spilling and extensive damage to the environment. The berm is a form of secondary containment with the storage tank itself being the primary instrument of containment.

Contamination resulting from spills or releases of refined petroleum products is an inherent risk in the petroleum terminal and pipeline industry. To the extent that groundwater contamination requiring remediation exists around the assets we own as a result of past operations, we believe any such contamination can be controlled or remedied without having a material adverse effect on our financial condition. However, such costs are often unpredictable and are site specific and, therefore, the effect may be material in the aggregate.

The primary federal law for oil spill liability is the Oil Pollution Act of 1990 ("OPA"), which addresses three principal areas of oil pollution—prevention, containment and cleanup. It applies to vessels, offshore platforms, and onshore facilities, including terminals, pipelines and transfer facilities. In order to handle, store or transport oil, shore facilities are required to file oil spill response plans with the

United States Coast Guard, the United States Department of Transportation Office of Pipeline Safety ("OPS"), or the EPA. Numerous states have enacted laws similar to OPA. Under OPA and similar state laws, responsible parties for a regulated facility from which oil is discharged may be liable for removal costs and natural resources damages. We believe that we are in material compliance with regulations pursuant to OPA and similar state laws.

The EPA has adopted regulations that require us to obtain permits to discharge certain storm water run-off. Storm water discharge permits also may be required by certain states in which we operate. Such permits may require us to monitor and sample the effluent from our operations. We believe that we are in material compliance with effluent limitations at our facilities.

Water permits are required for various types of terminal stormwater discharges. There are no TransMontaigne terminal locations that discharge any type of process wastewater. Such discharges generally fall into two categories: petroleum contact and non-contact. The sources of contact water are the truck loading operations at some of the terminals. Many TransMontaigne terminal locations do not have contact water discharges, and thus no need for discharge permits, by virtue of employment of closed-loop water handling systems. The water generated in these systems is transported offsite and disposed of properly. At locations where contact water is discharged on site, permit conditions dictate control technology requirements, effluent limitations and confirmation sampling. Non-contact stormwater is generated at most terminal locations, primarily from rainfall collection in aboveground storage tank secondary containment enclosures or dikes. Various types of permits regulate these discharges, with most being "General" state-wide industry specific mechanisms. The cost involved in obtaining and renewing these permits is not material.

Air emissions

Our operations are subject to the federal Clean Air Act and comparable state and local statutes. The Clean Air Act Amendments of 1990 require most industrial operations in the United States to incur capital expenditures to meet the air emission control standards that are developed and implemented by the EPA and state environmental agencies. Pursuant to the Clean Air Act, any of our facilities that emit volatile organic compounds or nitrogen oxides and are located in ozone non-attainment areas face increasingly stringent regulations, including requirements to install various levels of control technology on sources of pollutants. Some of our facilities have been included within the categories of hazardous air pollutant sources. The Clean Air Act regulations are still being implemented by the EPA and state agencies. We believe that we are in material compliance with existing standards and regulations pursuant to the Clean Air Act and similar state and local laws, and we do not anticipate that implementation of additional regulations will have a material adverse effect on us.

Air permits are required for TransMontaigne's terminaling operations that result in the emission of regulated air contaminants. These operations in general include fugitive volatile organic compounds (primarily hydrocarbons) from truck loading activities and tank working losses. The sources of these emissions are strictly regulated through the permitting process. Such regulation includes stringent control technology, extensive permit review and periodic renewal. The cost involved in obtaining and renewing these permits is not material.

CERCLA

Other than Coastal Fuels Marketing Inc. ("CFMI"), neither TransMontaigne nor any of its subsidiaries is a named party in any Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA") related action. CFMI, which is now a wholly owned subsidiary of TransMontaigne, had been named as a PRP in four State of Florida CERCLA actions which originated from waste disposal by third parties at off-site locations prior to TransMontaigne's acquisition of CFMI from El Paso

Corporation in 2003. TransMontaigne has been indemnified by El Paso for any costs TransMontaigne may incur for these issues. Due diligence research at the time of the acquisition of CFMI indicated that El Paso would not be likely to incur any future costs related to these actions; a worst-case analysis estimated El Paso's potential exposure at a total of $850,000.

All of TransMontaigne's terminal facilities are classified by the United States EPA as Conditionally Exempt Small Quantity Generators and do not generate hazardous waste except on isolated and infrequent cases. At such times, only third party disposal sites which have been audited and approved by TransMontaigne are used.

Tariff Regulations

The Razorback Pipeline, which runs between Mt. Vernon, Missouri and Rogers, Arkansas, is an interstate petroleum products pipeline and is subject to regulation by FERC under the Interstate Commerce Act and the Energy Policy Act of 1992 and rules and orders promulgated under those statutes. FERC regulation requires that interstate oil pipeline rates be posted publicly and that these rates be "just and reasonable" and nondiscriminatory. Rates of interstate oil pipeline companies are currently regulated by FERC primarily through an index methodology, whereby a pipeline is allowed to change its rates based on the change from year to year in the Producer Price Index for finished goods, less 1%. In the alternative, interstate oil pipeline companies may elect to support rate filings by using a cost-of-service methodology, competitive market showings or actual agreements between shippers and the oil pipeline company.

Under current FERC regulations, we are permitted to charge "just and reasonable," non-discriminatory tariffs for the transportation of refined products through the Razorback Pipeline. Given our ability to utilize either posted rates subject to increases tied to the Producer Price Index, to utilize rates tied to cost of service methodology, competitive market showing or actual agreements between shippers and TransMontaigne, we do not believe that these regulations would have any negative material monetary impact on us unless the regulations were substantially modified in such a manner so as to prevent a pipeline transportation company's ability to earn a fair return for the shipment of petroleum products utilizing its transportation system, which we believe to be an unlikely scenario.

Safety Regulation

We are subject to regulation by the United States Department of Transportation under the Accountable Pipeline and Safety Partnership Act of 1996, sometimes referred to as the Hazardous Liquid Pipeline Safety Act ("HLPSA"), and comparable state statutes relating to the design, installation, testing, construction, operation, replacement and management of our pipeline facilities. HLPSA covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to comply with such regulations and also to permit access to and copying of records and to make certain reports and provide information as required by the Secretary of Transportation. We believe that we are in material compliance with these HLPSA regulations.

OPS regulations require qualification of pipeline personnel. These regulations require pipeline operators to develop and maintain a written qualification program for individuals performing covered tasks on pipeline facilities. The intent of this regulation is to ensure a qualified work force and to reduce the probability and consequence of incidents caused by human error. The regulation establishes qualification requirements for individuals performing covered tasks, and amends certain training requirements in existing regulations. We believe that we are in material compliance with these OPS regulations.

We also are subject to OPS regulation for High Consequence Areas ("HCAs"), for Category 2 pipeline systems (companies operating less than 500 miles of jurisdictional pipeline). This regulation specifies how to assess, evaluate, repair and validate the integrity of pipeline segments that could impact populated areas, areas unusually sensitive to environmental damage and commercially navigable waterways, in the event of a release. Our assets that are subject to these requirements are: (1) the Pinebelt Pipeline (the pipeline connecting the Collins and Purvis, Mississippi complexes); (2) the Razorback Pipeline; (3) the Bellemeade Pipeline (pipeline connecting the Richmond Terminal to the nearby Virginia Power plant); (4) the Birmingham Terminal pipeline connection to Plantation Pipeline; and (5) the Bainbridge Terminal pipeline connection to the nearby SEGCO Power Plant. The regulation requires an integrity management program that utilizes internal pipeline inspection, pressure testing, or other equally effective means to assess the integrity of pipeline segments in HCAs. The program requires periodic review of pipeline segments in HCAs to ensure adequate preventative and mitigative measures exist. Through this program, we evaluated a range of threats to each pipeline segment's integrity by analyzing available information about the pipeline segment and consequences of a failure in a HCA. The regulation requires prompt action to address integrity issues raised by the assessment and analysis. The complete baseline assessment of all segments must be performed by February 17, 2009, with intermediate compliance deadlines prior to that date. We believe that we are in material compliance with the OPS regulation of HCAs.

We also are subject to the requirements of the federal Occupational Safety and Health Act ("OSHA"), and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act, and comparable state statutes require us to organize and disclose information about the hazardous materials used in our operations. Certain parts of this information must be reported to employees, state and local governmental authorities, and local citizens upon request. We believe that we are in material compliance with OSHA and state requirements, including general industry standards, record keeping requirements and monitoring of occupational exposures.

In general, we expect to increase our expenditures during the next decade to comply with higher industry and regulatory safety standards such as those described above. Although we cannot estimate the magnitude of such expenditures at this time, we do not believe that they will have a material adverse impact on our results of operations.

Other Regulations

We also are subject to the Jones Act and the Merchant Marine Act of 1936 because of our ownership and operation of ocean vessels. Numerous other federal, state and local rules regulate our operations pursuant to which governmental agencies have the ability to suspend, curtail or modify our operations. We believe that we are in material compliance with these regulations.

Operational Hazards and Insurance

Our terminal and pipeline facilities may experience damage as a result of an accident or natural disaster. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain insurance of various types that we consider adequate to cover our operations and properties.

The insurance covers all of our assets in amounts that we consider to be reasonable. The insurance policies are subject to deductibles that we consider reasonable and not excessive. Our insurance does

not cover every potential risk associated with operating pipelines, terminals and other facilities including the potential loss of significant revenues. Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences. The events of September 11, 2001, and their overall effect on the insurance industry have adversely impacted the availability and cost of coverage. Due to these events, insurers have excluded acts of terrorism and sabotage from our insurance policies. On certain of our key assets, we have purchased a separate insurance policy for acts of terrorism and sabotage.

Competition

We face intense competition in our terminal and pipeline operations as well as in our supply and marketing operations. Our competitors include other terminal and pipeline companies, the major integrated oil companies, their marketing affiliates and independent gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Some of these competitors have capital resources many times greater than ours, and control greater supplies of refined petroleum products.

Employees

We had 658 employees at August 30, 2004. No employees are subject to representation by unions for collective bargaining purposes.

Market and Industry Data

Market and industry data and other statistical information used throughout this report are based on independent industry publications by market research firms or other published independent sources. Some data are also based on our good faith estimates, which are derived from our review of internal surveys, as well as the independent sources. Although we believe these sources are reliable, we have not independently verified the information derived from independent sources.

Comdata®, Comcheck®, MasterCard® and other registered trademarks referred to herein are the property of their respective owners.

ITEM 2. PROPERTIES

The locations and approximate shell capacity of our terminals (all of which are owned by us) as of June 30, 2004 are as follows:

Locations		Approximate Shell Capacity (in barrels)

Southeast Facilities:
Albany, GA		131,000
Americus, GA		31,000
Athens, GA		77,000
Atlanta, GA		116,000
Bainbridge, GA		99,000
Belton, SC		130,000
Belton, SC—Piedmont		297,000
Birmingham, AL		370,000
Charlotte, NC		223,000
Charlotte, NC—Piedmont		324,000
Collins, MS		138,000
Collins, MS (Pipeline Injection Facility)		1,470,000
Doraville, GA—Piedmont		436,000
Fairfax, VA		502,000
Greensboro, NC		181,000
Greensboro, NC—Piedmont		484,000
Griffin, GA		51,000
Lookout Mountain, GA		109,000
Macon, GA		100,000
Meridian, MS		82,000
Montgomery, AL		59,000
Montvale, VA		489,000
Norfolk, VA		673,000
Purvis, MS—Piedmont		870,000
Purvis, MS		135,000
Rensselaer, NY		530,000
Richmond, VA		459,000
Rome, GA		59,000
Selma, NC—Piedmont		507,000
Spartanburg, SC		85,000
Spartanburg, SC—Piedmont		305,000

Total		9,522,000

Midwest Facilities:
Mount Vernon, MO		215,000
Rogers, AR		171,000
Chippewa Falls, WI		126,000

Total		512,000

Upper River Facilities:
Evansville, IN		239,000
Greater Cincinnati, KY (Covington)		191,000
Henderson, KY		273,000
New Albany, IN		219,000
Louisville, KY		138,000
Cape Girardeau, MO		140,000
East Liverpool, OH		219,000
Owensboro, KY		152,000
Paducah, KY Complex		306,000

Total		1,877,000

Lower River Facilities:
Baton Rouge, LA—Dock facility		—
Arkansas City, AR		773,000
Greenville, MS Complex		396,000

Total		1,169,000

Brownsville Facilities:
Brownsville, TX Complex		2,257,000

Total		2,257,000

Florida Facilities:
Pensacola, FL		272,000
Port Everglades, FL		369,000
Tampa, FL		475,000

Total		1,116,000

Coastal Fuels Facilities:
Jacksonville, FL		385,000
Cape Canaveral, FL		708,000
Port Everglades, FL		1,650,000
Fisher Island, FL		670,000
Port Manatee/Tampa, FL		1,517,000

Total		4,930,000

TOTAL CAPACITY		21,383,000

The name, approximate length in miles and geographical location of our pipeline as of June 30, 2004 is as follows:

Pipeline Name		Approximate Miles of Pipeline		Geographical Location

Razorback		67		Mt. Vernon, Missouri south to Rogers, Arkansas

Our executive offices are located at 1670 Broadway, Suite 3100, Denver, CO 80202; telephone number (303) 626-8200 and facsimile number (303) 626-8228. In addition, we have an operations office located at 200 Mansell Court East, Suite 600, Roswell, Georgia 30076; telephone number (770) 518-3500 and facsimile number (770) 518-3567.

ITEM 3. LEGAL PROCEEDINGS

We have been named as a defendant in various lawsuits and a party to various other legal proceedings, in the ordinary course of business, some of which are covered in whole or in part by insurance. We believe that the outcome of such lawsuits and other proceedings will not individually or in the aggregate have a material adverse effect on our consolidated financial condition, results of operations, or cash flows.

ITEM 4. VOTE OF SECURITY HOLDERS

At the TransMontaigne Annual Meeting of Stockholders held on May 6, 2004, the stockholders of TransMontaigne elected nine directors to serve until the next Annual Meeting of Stockholders and until their successors have been elected and qualified and approved the amendment of the Restated Certificate of Incorporation of the Company to increase the number of authorized shares of common stock par value $0.01 per share, from 80,000,000 shares to 150,000,000 shares.

The following persons were elected as directors:

	Votes For	Votes Against

Cortlandt S. Dietler	33,297,271	1,594,994
Donald H. Anderson	33,402,644	1,489,621
David J. Butters	33,391,787	1,500,478
John A. Hill	33,325,987	1,566,278
Bryan H. Lawrence	33,343,400	1,548,865
Harold R. Logan, Jr.	33,297,471	1,594,794
Edwin H. Morgens	33,332,544	1,559,721
Wayne W. Murdy	33,304,272	1,587,993
Walter P. Schuetze	33,304,028	1,588,237

There were no other directors whose term of office continued after the meeting.

A total of 31,110,399 votes were cast in favor of the proposal to amend the Restated Certificate of Incorporation to increase the number of authorized shares of common stock, while 3,764,874 votes were cast against the proposal and 16,992 abstained.

David J. Butters resigned from the Board of Directors effective July 1, 2004. Accordingly, we have a vacant seat on our Board of Directors.

Part II

ITEM 5. MARKET FOR COMMON STOCK

Our common stock is traded on the American Stock Exchange under the symbol "TMG". The following table sets forth, for the periods indicated, the range of high and low per share sale prices for our common stock as reported on the American Stock Exchange.

	Low		High

July 1, 2002 through September 30, 2002	$	4.50	$	6.30
October 1, 2002 through December 31, 2002	$	3.26	$	4.98
January 1, 2003 through March 31, 2003	$	3.75	$	4.85
April 1, 2003 through June 30, 2003	$	4.02	$	6.48
July 1, 2003 through September 30, 2003	$	5.14	$	6.20
October 1, 2003 through December 31, 2003	$	5.78	$	6.45
January 1, 2004 through March 31, 2004	$	5.50	$	7.23
April 1, 2004 through June 30, 2004	$	4.65	$	6.43

On August 30, 2004, the last reported sale price for our common stock on the American Stock Exchange was $6.42 per share. As of August 30, 2004, there were 588 stockholders of record of our common stock. This number does not include stockholders whose shares are held in trust by other entities. The actual number of stockholders is greater than the number of stockholders of record. Based on the number of annual reports requested by brokers, we estimate that we have approximately 2,300 beneficial owners of our common stock as of August 30, 2004.

On June 28, 2002, we issued 72,890 shares of Series B Redeemable Convertible Preferred Stock in a transaction exempt from registration pursuant to Regulation D of the Securities Act of 1933 (see Note 12 of Notes to consolidated financial statements). The offering was made solely to TransMontaigne's existing holders of Series A Preferred Stock, each of whom represented that it was an "accredited investor" as defined by Rule 501 under the Securities Act. The offering was made in accordance with the requirements of Regulation D applicable to an offering of securities under Rule 506.

No dividends were declared or paid on our common stock during the periods reported in the table above. We intend to retain future cash flow for use in our business and have no current intention of paying dividends to our common stockholders in the foreseeable future. Any payment of future dividends to our common stockholders and the amounts thereof will depend upon our earnings, financial condition, capital requirements and other factors deemed relevant by our Board of Directors. Our Senior Secured Working Capital Credit Facility, 9¹/8% Senior Subordinated Notes due 2010 and certificate of designation of our Series B Redeemable Convertible Preferred stock contain restrictions on the payment of dividends on our common stock. Our Senior Secured Working Capital Credit Facility and Senior Subordinated Notes restrict the payment of cash dividends on our common stock unless we comply with certain financial covenants relating to restricted payments. Our Series B Redeemable Convertible Preferred stock certificate of designation restricts the payment of cash dividends on our common stock unless the holders of our preferred stock have received a cash dividend for their immediately preceding dividend payment date. Additionally, we are precluded from paying dividends on our common stock in excess of $10 million during any 12-month period without the express consent of holders of two-thirds of the then outstanding shares of preferred stock.

Following is a summary of common stock repurchases for the quarter ended June 30, 2004 (in thousands, except average price per share):

Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs

April 1, 2004 through April 30, 2004	—		—	—		—
May 1, 2004 through May 31, 2004	6,527	$	5.71	N/a	(1)	N/a	(1)
June 1, 2004 through June 30, 2004	—		—	—		—

Total	6,527	$	5.71

No common stock was repurchased for the periods April 1, 2004 through April 30, 2004 and June 1, 2004 through June 30, 2004.

(1): Common stock was repurchased from employees during the above period for withholding taxes as a result of vesting of common stock under our restricted stock plan (see Note 13 of Notes to consolidated financial statements).

ITEM 6. SELECTED FINANCIAL DATA

The following selected financial data for each of the years in the five-year period ended June 30, 2004, has been derived from our consolidated financial statements. You should not expect the results for any prior periods to be indicative of the results that may be achieved in future periods. You should read the following information together with our historical consolidated financial statements and related notes and with "Management's Discussion and Analysis of Financial Condition and Results of Operations" included elsewhere in this annual report.

	Years Ended June 30,
	2004			2003(4)			2002			2001			2000
	(dollars in thousands)

Statement of Operations Data:
Supply, distribution and marketing:
Revenues	$	11,215,351		$	8,241,001		$	6,001,170		$	5,182,492		$	5,014,752
Less costs of products sold and other direct costs and expenses		(11,145,501	)		(8,190,918	)		(5,932,423	)		(5,136,174	)		(4,995,899	)

Net operating margin(1)		69,850			50,083			68,747			46,318			18,853

Terminals, pipelines, and tugs and barges:
Revenues		109,240			86,967			68,285			84,911			80,650
Direct operating costs and expenses		(53,966	)		(39,175	)		(32,567	)		(39,021	)		(36,396	)

Net operating margin(1)		55,274			47,792			35,718			45,890			44,254

Natural gas services:
Revenues		—			—			—			—			18,249
Direct operating costs and expenses		—			—			—			—			(7,759	)

Net operating margin(1)		—			—			—			—			10,490

Total net operating margins(1)	$	125,124		$	97,875		$	104,465		$	92,208		$	73,597

		Years Ended June 30,
		2004			2003(4)			2002			2001			2000
		(dollars in thousands)

Total net operating margins(1)		$	125,124		$	97,875		$	104,465		$	92,208		$	73,597
Costs and expenses:
Selling, general and administrative			(40,747	)		(40,491	)		(35,211	)		(34,072	)		(41,680	)
Depreciation and amortization			(23,015	)		(19,371	)		(16,556	)		(19,510	)		(22,344	)
Lower of cost or market write-downs on product linefill and tank bottom volumes			(60	)		(633	)		(12,963	)		(18,318	)		—
Corporate relocation and transition			—			(1,449	)		(6,316	)		—			—
Impairment of long-lived assets			—			—			—			—			(50,136	)
Gain (loss) on disposition of assets, net			(978	)		—			(13	)		22,146			13,930

Operating income (loss)			60,324			35,931			33,406			42,454			(26,633	)
Interest expense, net			(26,272	)		(14,419	)		(11,837	)		(15,215	)		(25,121	)
Other expense, net			(3,463	)		(4,902	)		(7,546	)		(9,235	)		(5,350	)

	Earnings (loss) before income taxes		30,589			16,610			14,023			18,004			(57,104	)
Income (taxes) benefit			(12,060	)		(8,510	)		(5,465	)		(6,666	)		19,167

	Earnings (loss) before cumulative effect of a change in accounting principle		18,529			8,100			8,558			11,338			(37,937	)
Cumulative effect adjustment, net of tax benefit			—			(1,297	)		—			—			—

	Net earnings (loss)	$	18,529		$	6,803		$	8,558		$	11,338		$	(37,937	)

Earnings (loss) per common share:
	Basic	$	0.36		$	0.07		$	(0.09	)	$	0.08		$	(1.52	)
	Diluted	$	0.36		$	0.07		$	(0.09	)	$	0.08		$	(1.52	)

	Years Ended June 30,
	2004			2003(4)			2002			2001			2000
	(dollars in thousands)

Other Financial Data:
Net cash provided (used) by operating activities	$	69,704		$	33,323		$	(101,512	)	$	51,936		$	267,526
Net cash provided (used) by investing activities	$	(18,283	)	$	(170,625	)	$	102,778		$	(18,969	)	$	77,902
Net cash provided (used) by financing activities	$	(73,232	)	$	134,419		$	3,811		$	(61,130	)	$	(305,417	)
Total debt to total capital		50.5	%		56.7	%		39.0	%		30.5	%		38.4	%
Ratio of earnings to fixed charges(2)		1.7	x		1.7	x		1.6	x		1.6	x		—

	Years Ended June 30,
	2004		2003(4)		2002		2001		2000
	(dollars in thousands)

Balance Sheet Data:
Cash and cash equivalents	$	6,158	$	27,969	$	30,852	$	25,775	$	53,938
Working capital(3)	$	118,320	$	79,325	$	168,092	$	31,934	$	134,807
Total assets	$	974,356	$	1,020,466	$	735,328	$	712,365	$	834,572
Total debt	$	311,923	$	379,534	$	198,312	$	150,000	$	206,995
Total preferred stock	$	77,719	$	79,329	$	105,360	$	174,825	$	170,115
Total common stockholders' equity	$	228,289	$	210,269	$	205,350	$	167,550	$	161,983

(1): Net operating margins represents revenues, less cost of product sold and other direct operating costs and expenses.

(2): For purposes of computing the ratio of earnings to fixed charges, "earnings" consists of earnings before income taxes plus fixed charges. "Fixed charges" represent interest incurred (whether expensed or capitalized), amortization of deferred financing costs, and that portion of rental expense on operating leases deemed to be the equivalent of interest. We reported a loss for the year ended June 30, 2000 and the earnings for such period were insufficient to cover fixed charges by approximately $57.1 million.
(3): Working capital is defined as current assets less current liabilities.
(4): The consolidated financial statements include the results of operations of the Coastal Fuels assets from the closing date of the transaction (February 28, 2003).

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of the results of operations and financial condition should be read in conjunction with the accompanying consolidated financial statements.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

A summary of the significant accounting policies that we have adopted and followed in the preparation of our consolidated financial statements is detailed in Note 1 of Notes to the consolidated financial statements. Certain of these accounting policies require the use of estimates. We have identified the following estimates that, in our opinion, are subjective in nature, require the exercise of judgment, and involve complex analysis. These estimates are based on our knowledge and understanding of current conditions and actions that we may take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our financial condition and results of operations.

Allowance for Doubtful Accounts. At June 30, 2004, our allowance for doubtful accounts was approximately $0.6 million. Our allowance for doubtful accounts represents the amount of trade receivables that we do not expect to collect. The valuation of our allowance for doubtful accounts is based on our analysis of specific individual customer balances that are past due and, from that analysis, we estimate the amount of the receivable balance that we do not expect to collect. That estimate is based on various factors, including our experience in collecting past due amounts from the customer being evaluated, the customer's current financial condition, the current economic environment and the economic outlook for the future. At June 30, 2004 our trade accounts receivable balances that were more than 30 days past due totaled less than $1.0 million.

Inventories—Discretionary Volumes Held for Immediate Sale or Exchange. At June 30, 2004, we held products for sale or exchange in the ordinary course of business with a cost basis of approximately $55.3 million and a fair value of approximately $57.6 million. Our inventories—discretionary volumes held for immediate sale or exchange are carried at the lower of cost or market value in the accompanying consolidated balance sheet. For purposes of evaluating the financial performance of our business segments, our inventories—discretionary volumes held for immediate sale or exchange are reflected at market value. The market value of our inventories—discretionary volumes held for immediate sale or exchange is based on quoted prices, when available. Our refined petroleum products inventories are traded in large fungible bulk markets (Pasadena, TX, New York Harbor, Chicago, IL, Tulsa, OK refining area, and Los Angeles, CA); and in city-specific wholesale markets. Quoted market prices (e.g., NYMEX, Platt's—Bulk, and OPIS—Wholesale) are readily available for these markets.

However, quoted prices are not available from brokers for all delivery locations in which we maintain discretionary volumes held for immediate sale or exchange. When quoted prices are not available, the market value of our inventories—discretionary volumes held for immediate sale or exchange is based on the nearest quoted market price, plus quoted basis differentials to the various bulk market areas, plus the transportation cost to deliver the product from the bulk trading market to the city-specific markets. We estimate the basis differentials for certain city-specific locations because we cannot secure a forward traded basis differential quote from a broker. In those situations, our mark-to-market model estimates the basis differentials based on a rolling historical average, which is updated quarterly. We utilize this valuation methodology for all inventories—discretionary volumes held for immediate sale or exchange, along with any valuation of a related exchange imbalance with a trading partner. At June 30, 2004, a $0.05 per gallon change in basis differentials would have changed the fair value of our discretionary inventory held for immediate sale or exchange by approximately $1.2 million.

Derivative Contracts. At June 30, 2004, we are a party to certain derivative contracts that require us to receive and deliver physical quantities of refined petroleum products over a specified term at a specified price. Our derivative contracts are carried at fair value in the accompanying consolidated balance sheets. At June 30, 2004, our net unrealized losses on derivative contracts were approximately $23.5 million. The valuation of our derivative contracts is based on quoted prices, when available.

However, quoted prices are not available from brokers for all future periods and delivery locations in which we are committed to do business. When quoted prices are not available, we estimate the values based on a combination of published market prices and estimates based on historical market conditions. For market locations in which we have access to product via our terminals, dedicated pipeline capacity, a throughput agreement or an exchange arrangement, fair value is determined by adding the near month NYMEX futures quote to the appropriate basis differential and the transportation cost to deliver the product from the bulk trading location to the contract's specified delivery location. We estimate the basis differentials for certain deferred trading months and city-specific locations because we cannot secure a forward traded basis differential quote from a broker. In those situations, our mark-to-market model estimates the basis differentials based on a rolling historical average, which is updated quarterly. For our derivative contracts that settle against wholesale and retail pricing indices, we use a rolling historical average difference between the pricing index (e.g., Department of Energy National and OPIS—Wholesale indices) and the related NYMEX futures contract utilized to manage the commodity price risk associated with the commitment. For market locations in which we do not have access to product via our terminals, dedicated pipeline capacity, a throughput agreement or an exchange arrangement, we purchase product on a spot basis from approved vendors to satisfy our contractual obligations. In these contracts, we are exposed to the differential between the bulk trading locations and the city-specific markets, as we do not control the pipeline and terminal capacity to facilitate shipment of the physical product. Our mark-to-market model incorporates this basis differential to each city-specific location. At June 30, 2004, a $0.05 per gallon change in basis differentials would have changed the fair value of our derivative contracts, exclusive of risk management contracts, by approximately $1.2 million.

Accrued Lease Abandonment. At June 30, 2004, we have an accrued liability of approximately $2.5 million as our estimate of the future payments we expect to pay, net of sublease payments we expect to receive from subleasing our vacated office space. The valuation of our accrued lease abandonment liability is based on the timing and amount of sublease payments we expect to receive from subleasing our vacated office space. Our estimate of the timing and amount of sublease payments is based on information received from real estate brokers.

Accrued Transportation and Deficiency Agreements. At June 30, 2004, we have an accrued liability of approximately $0.9 million as our estimate of the future payments we expect to pay for the estimated shortfall in volumes for the remainder of the terms of our transportation and deficiency agreements. The valuation of our accrual for transportation and deficiency agreements is based on our estimate of the future volumes we expect to supply and ship with the counterparties to these agreements. We estimate the future volumes based on our historical volumes supplied and shipped with the counterparties. Our accrued liability would be adjusted if our current projections of future volumes to be supplied and shipped with the counterparties indicated a significant increase or decrease in expected volumes due to changes in the scope and breadth of our supply, distribution, and marketing operations. At June 30, 2004, a 1,000 barrel per day decline in our estimate of the future volumes we expect to supply and ship with the counter parties to these agreements would have increased our accrued liability by approximately $0.3 million.

Accrued Environmental Obligations. At June 30, 2004, our estimate of the future environmental costs to be incurred to remediate existing conditions attributable to past operations ranged from $2.1 million to $10.0 million. At June 30, 2004, we have an accrued liability of approximately $5.3 million as our best estimate of the undiscounted future payments we expect to pay for environmental costs to remediate existing conditions attributable to past operations. The valuation of our accrued environmental obligations is based on our estimate of the remediation costs to be incurred in the future. We estimate the future remediation costs based on specific site studies using enacted laws and regulations. Estimates of our environmental obligations are subject to change due to a number of factors and judgments involved in the estimation process, including the early stage of investigation at certain sites, the lengthy time frames required to complete remediation, technology changes affecting remediation methods, alternative remediation methods and strategies, and changes in environmental laws and regulations.

SIGNIFICANT DEVELOPMENTS DURING THE YEAR ENDED JUNE 30, 2004

On December 30, 2003, we sold our CETEX pipeline system for approximately $0.4 million, resulting in a loss on disposition of assets of approximately $0.7 million. For the six months ended December 31, 2003 and the year ended June 30, 2003, the CETEX pipeline system generated net operating margins (deficiencies) of approximately $0.1 million and $(0.2) million, respectively.

On October 1, 2003, we acquired for cash consideration of approximately $3.1 million a terminal, including product inventory, in Norfolk, Virginia. The acquired terminal provides us with additional storage, a docking facility that permits us to receive and deliver shipments off the water, and operating synergies with our existing facility in Norfolk, Virginia.

On May 30, 2003, we sold the Senior Subordinated Notes in a private placement transaction that was exempt from registration under the Federal Securities Act of 1933. We also entered into a registration rights agreement requiring us to make an exchange offer. On July 22, 2003, we filed a registration statement on Form S-4 with the Securities and Exchange Commission to effect the exchange offer. The registration rights agreement also required us to use our best efforts to cause the registration statement filed with respect to the exchange offer to be declared effective by October 27, 2003 and to consummate the exchange offer no later than December 26, 2003. The exchange offer was not consummated as of December 26, 2003 and, therefore, we incurred additional interest of 0.5% per annum on the Senior Subordinated Notes until the exchange offer was consummated. On March 16, 2004, the registration statement on Form S-4 was declared effective by the staff of the Securities and Exchange Commission and the exchange offer was consummated on April 15, 2004.

SUBSEQUENT EVENTS

On September 13, 2004, we entered into a new $400 million Senior Secured Working Capital Credit Facility among TransMontaigne, Wachovia Bank, National Association, as Agent, a syndicate of seventeen banks and other institutional lenders, JPMorgan Chase Bank and UBS AG Stamford Branch, as Syndication Agents, and Société Générale, New York Branch, and Wells Fargo Foothill, LLC, as Documentation Agents. Our operating subsidiaries have guaranteed our obligations under the Senior Secured Working Capital Credit Facility. The Senior Secured Working Capital Credit Facility replaces our former $275 million Working Capital Credit Facility.

The Senior Secured Working Capital Credit Facility matures on September 13, 2009. The Senior Secured Working Capital Credit Facility provides for a maximum borrowing line of credit equal to the lesser of (i) $400 million and (ii) the borrowing base, which is a function, among other things, of our cash, accounts receivable, refined petroleum product inventory, exchanges, margin deposits and open positions of derivative contracts. The borrowing base is also subject to reduction for certain reserves and, until certain fixed assets satisfying the requirements of the Senior Secured Working Capital Credit Facility have been granted as security for our obligations, the borrowing base will be subject to a further reduction of $50 million. In addition, outstanding letters of credit are counted against the maximum borrowing capacity available at any time.

The Senior Secured Working Capital Credit Facility contains affirmative and negative covenants (including limitations on indebtedness, limitations on dividends and other distributions, limitations on certain inter-company transactions, limitations on mergers, consolidation and the disposition of assets, limitations on investments and acquisitions and limitations on liens) that are customary for a facility of this nature. The Senior Secured Working Capital Credit Facility also contains customary representations and warranties (including those relating to corporate organization and authorization, compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults, covenant defaults, cross defaults and bankruptcy events). The only financial covenant contained in the Senior Secured Working Capital Credit Facility is a minimum fixed charge coverage ratio test that is tested on a quarterly basis only if the average minimum unused credit line falls below $75 million for the last month of any quarter.

RESULTS OF OPERATIONS—MARKET CONDITIONS

Prices for refined petroleum products increased significantly during the year ended June 30, 2004, resulting in higher per unit revenues from the sales of refined petroleum products. Prices for unleaded gasoline in the bulk market increased throughout the year from approximately $0.80 per gallon to in excess of $1.20 per gallon. Prices for distillates in the bulk market increased throughout the year from approximately $0.75 per gallon to in excess of $1.00 per gallon. The increase in commodity prices resulted in us distributing and transporting fewer barrels of discretionary inventories for immediate sale or exchange through our terminal infrastructure during the year ended June 30, 2004, resulting in lower inventory volumes available for rack spot sales. We were unable to maintain and hold larger inventory volumes due to an under-sized commitment under our former Working Capital Credit Facility. Our former Working Capital Credit Facility had a maximum committed amount of $275 million. On September 13, 2004, we repaid all outstanding borrowings under our former Working Capital Credit Facility with proceeds from our new $400 million Senior Secured Working Capital Credit Facility.

The combination of steeply backwardated futures markets (i.e., future prices lower than current prices) and refinery crack spreads at historic highs encouraged refiners to maximize production and quickly

sell the refined products in the bulk markets. The availability of supply of refined products in the bulk markets resulted in limited opportunities to exploit basis differentials in the bulk markets. However, the unfavorable market conditions in the bulk markets were offset by the favorable margin opportunities realized on rack spot sales and contract sales at the wholesale delivery locations (i.e., terminal truck racks).

We believe that the uncertainties of crude oil supply caused in part by the Iraq war and the increased participation of hedge funds in the futures markets resulted in a lack of correlation between the cash market and the futures market (i.e., the physical cash markets were driven by supply and demand, whereas, the futures markets were driven by geopolitical events and expectations). The lack of correlation between the cash market and the futures market resulted in a significant increase in the cost of managing the commodity price risk associated with our discretionary inventories held for immediate sale or exchange. As a result, we currently maintain and hold fewer barrels of discretionary inventories for immediate sale or exchange to minimize our exposure to the cost of managing the commodity price risk on these volumes.

RESULTS OF OPERATIONS—BUSINESS SEGMENTS

Under SFAS No. 131, we are required to report measures of profit and loss that are used by our chief operating decision maker (our Chief Executive Officer or CEO) in assessing the financial performance of our business segments. Our CEO assesses the financial performance of each of our reportable segments using a financial performance measure, which we refer to as "adjusted net operating margins."

Terminals, pipelines, tugs and barges—adjusted net operating margins

Our adjusted net operating margins for the terminal, pipelines, tugs and barges segment are identical to the net operating margins for such segment described under "Results of Operations—Historical Financial Statements." Selected quarterly adjusted net operating margins for the terminal, pipelines, tugs and barges segment for each of the quarters in the years ended June 30, 2004, 2003 and 2002 are summarized below (in thousands):

			Three Months Ended
			Three Months Ended								Year Ended June 30, 2004
			September 30, 2003		December 31, 2003		March 31, 2004		June 30, 2004		Year Ended June 30, 2004

Terminals, pipelines and tugs and barges:
	Historical facilities		$	11,133	$	10,852	$	8,856	$	8,993	$	39,834
	Coastal fuels assets			3,562		4,313		4,200		3,365		15,440

		Net operating margins	$	14,695	$	15,165	$	13,056	$	12,358	$	55,274

			Three Months Ended
			Three Months Ended								Year Ended June 30, 2003
			September 30, 2002		December 31, 2002		March 31, 2003		June 30, 2003		Year Ended June 30, 2003

Terminals, pipelines and tugs and barges:
	Historical facilities		$	10,928	$	10,745	$	10,874	$	9,837	$	42,384
	Coastal fuels assets			—		—		1,676		3,732		5,408

		Net operating margins	$	10,928	$	10,745	$	12,550	$	13,569	$	47,792

			Three Months Ended
			Three Months Ended								Year Ended June 30, 2002
			September 30, 2001		December 31, 2001		March 31, 2002		June 30, 2002		Year Ended June 30, 2002

Terminals and pipelines:
	Historical facilities		$	7,669	$	8,513	$	9,596	$	9,268	$	35,046
	Assets disposed			672		—		—		—		672

		Net operating margins	$	8,341	$	8,513	$	9,596	$	9,268	$	35,718

Supply, distribution and marketing—adjusted net operating margins

Our CEO assesses the "adjusted net operating margins" of our supply, distribution, and marketing segment using financial information that is prepared pursuant to the mark-to-market method of accounting. "Adjusted net operating margins" for the supply, distribution and marketing segment differs from net operating margins for that segment as presented in our accompanying historical statement of operations due to the treatment of our inventories—discretionary volumes. In determining our "adjusted net operating margins" for our supply, distribution and marketing segment, inventories—discretionary volumes held for immediate sale or exchange are reflected at fair value, which matches the treatment of our derivative and risk management contracts. Therefore, the effects of changes in the fair value of our inventories—discretionary volumes held for immediate sale or exchange are included in "adjusted net operating margins" attributable to our supply, distribution and marketing segment in the period in which the fair value actually changes. Additionally, for purposes of computing our "adjusted net operating margins," our discretionary inventories—base operating volumes are maintained at original cost.

Because our inventories—discretionary volumes held for immediate sale or exchange are composed of refined petroleum products, which are commodities with established trading markets and readily ascertainable market prices, we believe that the financial performance of our supply, distribution and marketing segment can be appropriately evaluated using the mark-to-market method rather than the lower-of-cost-or-market method of accounting for our inventories—discretionary volumes held for immediate sale or exchange.

Our inventories—discretionary volumes held for immediate sale or exchange are carried at the lower of cost or market in the accompanying historical balance sheets, while our derivative and risk management contracts are carried at fair value. As a result, if commodity prices are increasing during the end of a quarter, we may report in the accompanying historical statement of operations significant losses on derivative and risk management contracts and significant deferred gains on discretionary inventory volumes held for immediate sale or exchange at the end of that quarter and report significant gains on our beginning inventories—discretionary volumes held for immediate sale or exchange when they are sold in the following quarter.

The adjusted net operating margins attributable to our supply, distribution and marketing segment declined to $32.8 million in 2004 from $55.3 million in 2003 and $68.7 million in 2002.

Selected quarterly adjusted net operating margins for the supply, distribution and marketing segment for each of the quarters in the year ended June 30, 2004, are summarized below (in thousands):

			Three Months Ended
			Three Months Ended												Year Ended June 30, 2004
			September 30, 2003			December 31, 2003			March 31, 2004			June 30, 2004			Year Ended June 30, 2004

Supply, distribution and marketing:
Light oils:
	Rack spot margins		$	1,882		$	3,432		$	5,897		$	5,056		$	16,267
	Contract margins			1,345			2,526			4,444			5,732			14,047
Inventory roll (cost) benefit				(719	)		2,634			(5,142	)		(3,177	)		(6,404	)
Bulk activities and other margins				2,372			(971	)		562			(14,549	)		(12,586	)
Heavy oils—contract margins				1,440			3,424			5,416			3,376			13,656
Supply chain management services margins				2,351			4,070			2,783			(580	)		8,624
Trading activities, net				2,131			457			(2,582	)		(829	)		(823	)

		Adjusted net operating margins	$	10,802		$	15,572		$	11,378		$	(4,971	)	$	32,781

The adjusted net operating margins from our rack spot sales and contract sales improved quarter over quarter during the year ended June 30, 2004 due principally to increasing per unit margins. Per unit margins from rack spot sales and contract sales generally are more favorable during periods of expected future declining prices as major oil companies prefer to dispose of their refined product inventories in the bulk market as opposed to shipping the inventories to interior wholesale delivery markets due to the length of in-transit shipping times.

Rack spot margins were $16.3 million and $16.1 million for the years ended June 30, 2004 and 2003, respectively, on volumes of approximately 117,000 and 130,000 barrels per day, respectively. The adjusted net operating margins from our contract sales decreased to approximately $14.0 million in 2004 from approximately $18.2 million in 2003 due principally to lower per unit margins on deliveries at our terminal locations. The inventory roll (cost) benefit represents the (decrease) increase in the value of our discretionary volumes held for immediate sale or exchange from carrying inventory to future periods in a (declining) rising forward price environment. The adjusted net operating margins (deficiencies) from our bulk activities and other decreased to approximately $(12.6) million in 2004 from approximately $17.7 million in 2003 due principally to (i) limited opportunities to harvest basis differentials in the bulk markets due to fewer independent merchants engaged in energy trading activities, (ii) fewer supply disruptions from refinery outages during the year ended June 30, 2004, and (iii) a lack of correlation between the cash and futures markets during the quarter ended June 30, 2004. The cost of managing the commodity price risk associated with our discretionary gasoline inventory volumes during May 2004 exceeded the margins recognized by approximately $14.5 million as the price of gasoline in the bulk markets increased in value by approximately $0.02 per gallon while the loss on the related risk management contracts was approximately $0.14 per gallon. The Coastal Fuels assets, which we acquired on February 28, 2003, contributed heavy oil margins of approximately $13.7 million and $6.3 million during the years ended June 30, 2004 and 2003, respectively. The adjusted net operating margins from our supply chain management services decreased to approximately $8.6 million in 2004 from approximately $13.0 million in 2003 due principally to unfavorable per unit margins on retail price management contracts and West Coast delivered fuel price management contracts during the quarter ended June 30, 2004. The adjusted net operating margins from our trading activities were negatively impacted by speculative positions taken in anticipation of declining commodity prices during the quarters ended March 31, 2004 and June 30, 2004.

		Three Months Ended
		Three Months Ended												Year Ended June 30, 2004
		September 30, 2003			December 31, 2003			March 31, 2004			June 30, 2004			Year Ended June 30, 2004

Reconciliation to net operating margins: Adjusted net operating margins		$	10,802		$	15,572		$	11,378		$	(4,971	)	$	32,781
	Gains recognized on beginning inventories—discretionary volumes held for immediate sale or exchange		5,855			3,067			15,469			6,039			5,855
	Gains deferred on ending inventories—discretionary volumes held for immediate sale or exchange		(3,067	)		(15,469	)		(6,039	)		(2,330	)		(2,330	)
	Increase in FIFO cost basis of base operating inventory volumes		214			5,504			21,494			11,666			38,878
	Lower of cost or market write-downs on base operating inventory volumes		(2,062	)		(271	)		(128	)		(2,873	)		(5,334	)

Net operating margins—historical financial statements		$	11,742		$	8,403		$	42,174		$	7,531		$	69,850

During the year ended June 30, 2004, we increased the carrying amount of our base operating inventory volumes by approximately $38.9 million due to higher commodity prices during 2004 as compared to 2003.

Selected quarterly adjusted net operating margins for the supply, distribution and marketing segment for each of the quarters in the year ended June 30, 2003, are summarized below (in thousands):

			Three Months Ended
			Three Months Ended												Year Ended June 30, 2003
			September 30, 2002			December 31, 2002			March 31, 2003			June 30, 2003			Year Ended June 30, 2003

Supply, distribution and marketing:
Light oils:
	Rack spot margins		$	1,475		$	2,008		$	4,527		$	8,116		$	16,126
	Contract margins			1,452			1,456			5,373			9,947			18,228
Inventory roll cost				(1,569	)		(2,622	)		(6,400	)		(4,365	)		(14,956	)
Bulk activities and other margins				4,467			8,703			4,609			(40	)		17,739
Heavy oils—contract margins				—			—			2,489			3,810			6,299
Supply chain management services margins				4,382			3,158			3,530			1,947			13,017
Trading activities, net				(2,595	)		640			30			786			(1,139	)

		Adjusted net operating margins	$	7,612		$	13,343		$	14,158		$	20,201		$	55,314

On February 28, 2003, we acquired the Coastal Fuels assets, which contributed approximately $6.3 million in heavy oils—contract margins.

		Three Months Ended
		Three Months Ended											Year Ended June 30, 2003
		September 30, 2002		December 31, 2002			March 31, 2003			June 30, 2003			Year Ended June 30, 2003

Reconciliation to net operating margins: Adjusted net operating margins		$	7,612	$	13,343		$	14,158		$	20,201		$	55,314
	Gains recognized on beginning inventories—discretionary volumes held for immediate sale or exchange		—		12,644			33,490			—			12,644
	Gains deferred on ending inventories—discretionary volumes held for immediate sale or exchange		—		(33,490	)		—			(5,855	)		(5,855	)
	Change in FIFO cost basis of base operating inventory volumes		—		(1,421	)		9,723			(7,887	)		415
	Lower of cost or market write-downs on base operating inventory volumes		—		—			(12,412	)		(23	)		(12,435	)

Net operating margins—historical financial statements		$	7,612	$	(8,924	)	$	44,959		$	6,436		$	50,083

Prior to October 1, 2002, our inventories—discretionary volumes held for immediate sale or exchange were carried at fair value with changes in fair value included in net operating margins in the period of the change in value. Effective October 1, 2002, we adjusted the carrying amount of inventories—discretionary volumes to the lower of cost (FIFO) or market pursuant to the requirements of EITF 02-03. As of October 1, 2002, the fair value of our inventories—discretionary volumes held for immediate sale or exchange exceeded their cost basis by approximately $12.6 million.

Prior to October 1, 2002, our base operating inventory volumes were carried at original cost adjusted for impairment write-downs to current market values. Effective October 1, 2002, we adjusted the carrying amount of our base operating inventory to the lower of cost (FIFO) or market pursuant to the requirements of EITF 02-03. During the three months ended March 31, 2003 and June 2003, we recognized impairment losses of approximately $12.4 million and $23,000, respectively, due to the application of the lower of cost or market rule on certain of our base operating inventory volumes.

For the year ended June 30, 2002, our adjusted net operating margins for the supply, distribution and marketing segment are identical to the net operating margins for such segment described under "Results of Operations—Historical Financial Statements." Selected quarterly adjusted net operating

margins for the supply, distribution and marketing segment for each of the quarters in the year ended June 30, 2002, are summarized below (in thousands):

		Three Months Ended
		Three Months Ended											Year Ended June 30, 2002
		September 30, 2001			December 31, 2001		March 31, 2002			June 30, 2002			Year Ended June 30, 2002

Supply, distribution and marketing:
Light oils:
	Rack spot margins	$	1,493		$	1,366	$	(649	)	$	1,740		$	3,950
	Contract margins		1,342			1,287		(904	)		1,933			3,658
Inventory roll benefit			862			4,808		4,598			2,040			12,308
Bulk activities and other margins			23,458			3,719		8,302			(592	)		34,887
Supply chain management services margins			(721	)		1,484		9,144			3,981			13,888
Trading activities, net			1,165			1,065		(385	)		(1,789	)		56

Adjusted net operating margins		$	27,599		$	13,729	$	20,106		$	7,313		$	68,747

During the three months ended September 30, 2001, a disruption at a Chicago refinery resulted in significant volatility in basis differentials, which created significant margin opportunities in the bulk market. The adjusted net operating margins from our rack spot sales and contract sales were negatively impacted during the year ended June 30, 2002 due principally to weak per unit margins. Per unit margins from rack spot sales and contract sales generally are negatively impacted during periods of expected future rising prices as major oil companies prefer to ship their refined product inventories to interior wholesale delivery markets rather than dispose of their inventories in the bulk market. The availability of supply in the wholesale delivery markets resulted in limited opportunities to generate margins in the wholesale delivery markets.

RESULTS OF OPERATIONS—HISTORICAL FINANCIAL STATEMENTS

Selected annual results of operations data are summarized below (in thousands):

			Years ended June 30,
			2004			2003			2002

Net operating margins(1):
	Supply, distribution and marketing		$	69,850		$	50,083		$	68,747
	Terminals, pipelines and tugs and barges			55,274			47,792			35,718

		Total net operating margins		125,124			97,875			104,465
Selling, general and administrative expenses				(40,747	)		(40,491	)		(35,211	)
Depreciation and amortization				(23,015	)		(19,371	)		(16,556	)
Lower of cost or market write-downs on product linefill and tank bottom volumes				(60	)		(633	)		(12,963	)
Corporate relocation and transition				—			(1,449	)		(6,316	)
Loss on disposition of assets, net				(978	)		—			(13	)

		Operating income		60,324			35,931			33,406
Dividend income				6			374			1,450
Interest income				205			286			599
Interest expense and other financing costs, net				(29,946	)		(19,981	)		(21,432	)

		Earnings before income taxes		30,589			16,610			14,023
Income tax expense				(12,060	)		(8,510	)		(5,465	)

		Earnings before cumulative effect adjustment		18,529			8,100			8,558
Cumulative effect of a change in accounting principle, net				—			(1,297	)		—

		Net earnings	$	18,529		$	6,803		$	8,558

(1): Net operating margins represents revenues, less cost of product sold and other direct operating costs and expenses.

Selected quarterly results of operations data for each of the quarters in the three-year period ended June 30, 2004, are summarized below (in thousands):

		Three months ended
		Three months ended												Year ended June 30, 2004
		September 30, 2003			December 31, 2003			March 31, 2004			June 30, 2004			Year ended June 30, 2004

Net operating margins:
	Supply, distribution and marketing	$	11,742		$	8,403		$	42,174		$	7,531		$	69,850
	Terminals, pipelines and tugs and barges		14,695			15,165			13,056			12,358			55,274

	Total net operating margins		26,437			23,568			55,230			19,889			125,124
Selling, general, and administrative			(10,371	)		(10,944	)		(11,343	)		(8,089	)		(40,747	)
Depreciation and amortization			(5,537	)		(5,932	)		(5,738	)		(5,808	)		(23,015	)
Lower of cost or market write-downs on product linefill and tank bottom volumes			(32	)		(17	)		(11	)		—			(60	)
Loss on disposition of assets, net			—			(805	)		—			(173	)		(978	)

	Operating income		10,497			5,870			38,138			5,819			60,324
Other expense, net			(7,203	)		(7,442	)		(7,518	)		(7,572	)		(29,735	)
Income tax (expense) benefit			(1,318	)		629			(12,248	)		877			(12,060	)

	Net earnings (loss)	$	1,976		$	(943	)	$	18,372		$	(876	)	$	18,529

		Three months ended
		September 30, 2002			December 31, 2002			March 31, 2003			June 30, 2003			Year ended June 30, 2003

Net operating margins:
	Supply, distribution and marketing	$	7,612		$	(8,924	)	$	44,959		$	6,436		$	50,083
	Terminals, pipelines and tugs and barges		10,928			10,745			12,550			13,569			47,792

	Total net operating margins		18,540			1,821			57,509			20,005			97,875
Selling, general, and administrative			(9,331	)		(8,775	)		(10,440	)		(11,945	)		(40,491	)
Depreciation and amortization			(4,256	)		(4,293	)		(4,851	)		(5,971	)		(19,371	)
Lower of cost or market write-downs on product linefill and tank bottom volumes			—			—			(633	)		—			(633	)
Corporate relocation and transition			(1,084	)		(365	)		—			—			(1,449	)

	Operating income (loss)		3,869			(11,612	)		41,585			2,089			35,931
Other expense, net			(3,004	)		(2,001	)		(5,484	)		(8,832	)		(19,321	)
Income tax (expense) benefit			(329	)		5,173			(13,722	)		368			(8,510	)
Cumulative effect adjustment, net			—			(1,297	)		—			—			(1,297	)

	Net earnings (loss)	$	536		$	(9,737	)	$	22,379		$	(6,375	)	$	6,803

		Three months ended
		Three months ended												Year ended June 30, 2002
		September 30, 2001			December 31, 2001			March 31, 2002			June 30, 2002			Year ended June 30, 2002

Net operating margins:
	Supply, distribution and marketing	$	27,599		$	13,729		$	20,106		$	7,313		$	68,747
	Terminals and pipelines		8,341			8,513			9,596			9,268			35,718

	Total net operating margins		35,940			22,242			29,702			16,581			104,465
Selling, general, and administrative			(8,465	)		(8,185	)		(8,955	)		(9,606	)		(35,211	)
Depreciation and amortization			(4,282	)		(4,024	)		(4,143	)		(4,107	)		(16,556	)
Lower of cost or market write-downs on product linefill and tank bottom volumes			(849	)		(12,114	)		—			—			(12,963	)
Corporate relocation and transition			—			—			(315	)		(6,001	)		(6,316	)
Loss on disposition of assets, net			(1,295	)		—			—			1,282			(13	)

	Operating income (loss)		21,049			(2,081	)		16,289			(1,851	)		33,406
Other expense, net			(5,516	)		(2,660	)		(2,200	)		(9,007	)		(19,383	)
Income tax (expense) benefit			(5,902	)		1,801			(5,354	)		3,990			(5,465	)

	Net earnings (loss)	$	9,631		$	(2,940	)	$	8,735		$	(6,868	)	$	8,558

DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS FOR THE YEARS ENDED JUNE 30, 2004, 2003 AND 2002

We reported net earnings of $18.5 million for the year ended June 30, 2004, compared to net earnings of $6.8 million for the year ended June 30, 2003, and net earnings of $8.6 million for the year ended June 30, 2002. After earnings allocable to preferred stock, the net earnings (loss) attributable to common stockholders was $14.2 million, $2.8 million and $(2.8) million for the years ended June 30, 2004, 2003 and 2002, respectively. Basic earnings (loss) per common share for the years ended June 30, 2004, 2003 and 2002, was $0.36, $0.07 and $(0.09), respectively, based on 39.4 million, 39.1 million and 31.3 million weighted average common shares outstanding, respectively. Diluted

earnings (loss) per share for the years ended June 30, 2004, 2003 and 2002, was $0.36, $0.07 and $(0.09), respectively, based upon 51.0 million, 39.3 million and 31.3 million weighted average diluted shares outstanding, respectively.

Terminals, pipelines, and tugs and barges

In our terminals, pipelines, and tugs and barges operations, we provide distribution related services to wholesalers, distributors, marketers, retail gasoline station operators, cruise-ship operators and industrial and commercial end-users of refined petroleum products and other commercial liquids. The net operating margins from our terminals, pipelines, and tugs and barges operations for the year ended June 30, 2004 were $55.3 million, compared to $47.8 million for the year ended June 30, 2003 and $35.7 million for the year ended June 30, 2002. On February 28, 2003, we acquired the Coastal Fuels assets, which include five terminals, a hydrant delivery system, and a tug and barge operation. The results of operations of the Coastal Fuels assets are included from the closing date of the transaction (February 28, 2003). For the years ended June 30, 2004 and 2003, the Coastal Fuels assets generated revenues of approximately $37.9 million and $12.6 million, respectively, and net operating margins of approximately $15.4 million and $5.4 million, respectively, attributable to our terminals, pipelines, and tugs and barges operations. The increase of $7.5 million in total net operating margins for 2004 as compared to 2003 was due principally to the addition of the Coastal Fuels assets offset by a decline in net operating margins due to decreased throughput and storage volumes at our Upper River facilities.

The increase of $12.1 million in net operating margins for 2003 as compared to 2002 was attributable to the addition of the Coastal Fuels assets and increased throughput and storage volumes at our terminals.

The net operating margins from our terminals, pipelines, and tugs and barges operations are as follows (in thousands):

			Years ended June 30,
			2004			2003			2002

Throughput fees			$	32,019		$	30,359		$	26,544
Storage fees				36,036			25,979			18,053
Additive injection fees, net				7,908			7,921			6,611
Pipeline transportation fees				7,073			5,758			6,492
Tugs and barges				11,667			4,335			—
Management fees and cost reimbursements				4,975			4,461			4,899
Other				9,562			8,154			5,686

	Revenue			109,240			86,967			68,285
	Less direct operating costs and expenses			(53,966	)		(39,175	)		(32,567	)

		Net operating margins	$	55,274		$	47,792		$	35,718

Throughput Fees. We own and operate a terminal infrastructure that handles products with transportation connections via pipelines, barges, rail cars and trucks. We earn throughput fees for each barrel of product that is distributed at our terminals through our supply and marketing efforts, through exchange agreements, or for third parties. Terminal throughput fees are based on the volume of products distributed at the facility's truck loading racks, generally at a standard rate per barrel of product.

Exchange agreements provide for the exchange of product at one delivery location for product at a different location. We generally receive a terminal throughput fee based on the volume of the product

exchanged, in addition to the cost of transportation from the receipt location to the exchange delivery location. For the years ended June 30, 2004, 2003 and 2002, we averaged approximately 50,000, 51,000 and 61,000 barrels per day, respectively, of delivered volumes under exchange agreements.

Terminal throughput fees were approximately $32.0 million, $30.4 million and $26.5 million for the years ended June 30, 2004, 2003 and 2002, respectively. For the years ended June 30, 2004, 2003 and 2002, we averaged approximately 397,000 barrels, 342,000 barrels and 308,000 barrels per day of throughput volumes, respectively, at our terminals, including volumes under exchange agreements. The increase of $1.6 million in throughput fees for 2004 as compared to 2003 was due principally to increases of approximately $2.0 million as a result of our acquisition of the Coastal Fuels assets, approximately $0.9 million at our Southeast facilities and approximately $0.7 at our historical Florida facilities offset by a decrease of approximately $2.0 million at our Upper River facilities. The increase of $3.9 million in throughput fees for 2003 as compared to 2002 was due principally to increases of approximately $1.6 million at our Southeast facilities, approximately $0.8 million at our historical Florida facilities, approximately $0.8 million as a result of our acquisition of the Coastal Fuels assets, and approximately $0.4 million at our Northeast facility.

Included in the terminal throughput fees for the years ended June 30, 2004, 2003 and 2002 are fees charged to TransMontaigne's supply, distribution and marketing segment of approximately $28.5 million, $23.2 million and $19.0 million, respectively.

Storage Fees. We lease storage capacity at our terminals to third parties and to our supply, distribution and marketing segment. Terminal storage fees generally are based on a per barrel of leased capacity per month rate and will vary with the duration of the storage agreement and the type of product stored.

Terminal storage fees were approximately $36.0 million, $26.0 million and $18.1 million for the years ended June 30, 2004, 2003 and 2002, respectively. The increase of $10.0 million in storage fees for 2004 as compared to 2003 was due principally to an increase of approximately $11.5 million from our acquisition of Coastal Fuels assets offset by decreases of approximately $0.7 million at our Brownsville, Texas facilities, approximately $0.4 million at our Upper River facilities, and $0.2 million at our Lower River facilities. The increase of $7.9 million in storage fees for 2003 as compared to 2002 was due principally to an increase of approximately $5.9 million from our acquisition of Coastal Fuels assets, approximately $1.8 million at our Brownsville, Texas facilities and approximately $1.1 million at our Southeast facilities offset by decreases of approximately $0.4 million at our Upper River facilities and $0.4 million at our Lower River facilities.

Included in the terminal storage fees for the years ended June 30, 2004, 2003 and 2002 are fees charged to TransMontaigne's supply, distribution and marketing segment of approximately $12.3 million, $5.9 million and $3.5 million, respectively.

Additive Injection Fees, Net. We provide injection services in connection with the delivery of product at our terminals. These fees generally are based on the volume of product injected and delivered over the rack at our terminals.

Additive injection fees, net were approximately $7.9 million, $7.9 million and $6.6 million for the years ended June 30, 2004, 2003 and 2002, respectively. The additive injection fees, net for 2004 as compared to 2003 principally include an increase of approximately $0.3 million from our acquisition of Coastal Fuels assets offset by a decrease of approximately $0.4 million at our Upper River facilities. The increase of $1.3 million in additive injection fees, net for 2003 as compared to 2002 was due principally to an increase of approximately $0.4 million from our acquisition of Coastal Fuels assets

and approximately $0.7 million from increased throughput volumes from our supply, distribution and marketing operations at our Southeast facilities.

Included in additive injection fees, net for the years ended June 30, 2004, 2003 and 2002 are fees charged to TransMontaigne's supply, distribution and marketing segment of approximately $7.5 million, $6.7 million and $5.2 million, respectively.

Pipeline Transportation Fees. We own an interstate products pipeline operating from Mt. Vernon, Missouri to Rogers, Arkansas, or the Razorback Pipeline, together with associated terminal facilities at Mt. Vernon and Rogers. Effective June 30, 2002, we acquired for cash consideration of approximately $7.2 million the remaining 40% interest in the Razorback Pipeline system that we did not previously own. We earn pipeline transportation fees at our Razorback pipeline based on the volume of product transported and the distance from the origin point to the delivery point. Tariff rates on the Razorback Pipeline are regulated by the FERC. We also earn transportation fees at our Port Everglades pipeline hydrant delivery system based on the volume of product delivered to cruise ships and freight vessels. The Port Everglades hydrant system allows a more efficient refueling process than barge to ship refueling.

For the years ended June 30, 2004, 2003 and 2002, we earned pipeline transportation fees of approximately $7.1 million, $5.8 million and $6.5 million, respectively. The increase of $1.3 million in pipeline transportation fees for 2004 as compared to 2003 was due principally to an increase of approximately $1.1 million from our acquisition of the Coastal Fuels assets. The decrease of $0.7 million in pipeline transportation fees for 2003 as compared to 2002 was due principally to the sale of the NORCO system. On July 31, 2001, we sold the NORCO system. For the year ended June 30, 2002, the NORCO system generated pipeline transportation fees of approximately $0.8 million.

Included in the pipeline transportation fees for the years ended June 30, 2004, 2003 and 2002 are fees charged to TransMontaigne's supply, distribution and marketing segment of approximately $6.7 million, $5.3 million and $5.6 million, respectively.

Tugs and Barges. In Florida, we currently own and operate 11 tugboats and 14 barges that deliver product to cruise ships and other marine vessels for refueling and to transport third party product from our storage tanks to our customers' facilities. Our tugboats earn fees for providing docking and other ship-assist services to cruise and cargo ships and other marine vessels. Bunkering fees are based on the volume and type of product sold, transportation fees are based on the volume of product that is shipped and the distance to the delivery point, and docking and other ship-assist services are based on a per docking per tugboat basis.

For the years ended June 30, 2004 and 2003, we earned bunkering fees, transportation fees, and docking and other ship-assist services fees of approximately $11.7 million and $4.3 million, respectively. We acquired the tugs and barges operations on February 28, 2003 in connection with our acquisition of the Coastal Fuels assets.

Included in the tugs and barges fees for the years ended June 30, 2004 and 2003, are fees charged to TransMontaigne's supply, distribution and marketing segment of approximately $6.7 million and $2.8 million, respectively.

fees and cost reimbursements from our terminal and pipeline operations were approximately $5.0 million, $4.5 million, and $4.9 million, respectively.

Other Revenue. In addition to providing storage and distribution services at our terminal facilities, we also provide ancillary services including heating and mixing of stored products and product transfer services. We also recognize gains from the sale of product to our supply, distribution and marketing operation resulting from the excess of product deposited by third parties into our terminals over the amount of product that the customer is contractually permitted to withdraw from those terminals. For the years ended June 30, 2004, 2003 and 2002, other revenue from our terminals, pipelines, and tugs and barges operations was approximately $9.6 million, $8.2 million and $5.7 million, respectively. The increase of approximately $1.4 million in other revenue for 2004 as compared to 2003 was due principally to an increase of approximately $2.9 million from our acquisition of the Coastal Fuels assets offset by a decrease of approximately $1.3 million at our Brownsville, Texas facilities. The increase of approximately $2.5 million in other revenue for 2003 as compared to 2002 was due principally to an increase of approximately $1.4 million at our Brownsville, Texas terminal facility and an increase of approximately $0.7 million from our acquisition of the Coastal Fuels assets.

Included in other revenue for the years ended June 30, 2004, 2003 and 2002 are fees charged to TransMontaigne's supply, distribution and marketing segment of approximately $3.7 million, $3.1 million and $2.7 million, respectively.

Direct Operating Costs and Expenses. The direct operating costs and expenses of our terminals, pipelines, and tugs and barges operations include the directly related wages and employee benefits, utilities, communications, maintenance and repairs, property taxes, rent, vehicle expenses, environmental compliance costs, materials and supplies. For the years ended June 30, 2004, 2003 and 2002, the direct operating costs and expenses of the terminals, pipelines, and tugs and barges were approximately $54.0 million, $39.2 million and $32.6 million, respectively. The direct operating costs and expenses of our terminals, pipelines, and tugs and barges operations are as follows (in thousands):

		Years ended June 30,
		2004			2003			2002

Wages and employee benefits		$	23,539		$	16,266		$	12,631
Utilities and communication charges			4,513			3,616			3,024
Repairs and maintenance			14,416			9,697			8,146
Office, rentals and property taxes			5,676			4,298			4,707
Vehicles and fuel costs			1,509			860			425
Environmental compliance costs			3,718			3,244			2,241
Other			2,283			1,697			1,839
Less—property and environmental insurance recoveries			(1,688	)		(503	)		(446	)

	Direct operating costs and expenses	$	53,966		$	39,175		$	32,567

The increase of approximately $14.8 million in direct operating costs and expenses for 2004 as compared to 2003 was due principally to the addition of the Coastal Fuels assets which resulted in approximately $15.2 million of additional direct operating costs and expenses. The increase of approximately $6.6 million in direct operating costs and expenses for 2003 as compared to 2002 was due principally to the addition of the Coastal Fuels assets which resulted in approximately $7.2 million of additional direct operating costs and expenses.

Supply, distribution and marketing

The net operating margins from our supply, distribution and marketing operations for the year ended June 30, 2004 were $69.9 million, compared to $50.1 million for the year ended June 30, 2003, and $68.7 million for the year ended June 30, 2002.

The net operating margins from our supply, distribution and marketing operations are as follows (in thousands):

			Years ended June 30,
			2004			2003			2002

Rack spot sales			$	1,704,524		$	1,691,324		$	1,133,069
Contract sales				3,085,352			1,759,196			921,884
Bulk sales				6,063,222			4,613,167			3,815,420
Supply chain management services				362,253			177,314			130,797

	Gross sales			11,215,351			8,241,001			6,001,170
Cost of product sold				(11,060,105	)		(8,072,877	)		(5,875,791	)

		Net margin before other direct costs and expenses		155,246			168,124			125,379
Other direct costs and expenses:
	Net losses on risk management activities			(54,739	)		(84,146	)		(56,826	)
	Change in unrealized gains (losses) on derivative contracts			(25,323	)		(21,460	)		194
	Lower of cost or market write-downs on base operating inventory volumes			(5,334	)		(12,435	)		—

		Net operating margins	$	69,850		$	50,083		$	68,747

Our supply, distribution and marketing operations typically purchase products at prevailing prices from refiners and producers at production points and common trading locations. Once we purchase these products, we schedule them for delivery to our terminals, as well as terminals owned by third parties with which we have storage or throughput agreements. From these terminal locations, we then sell our products to customers primarily through three types of arrangements: rack spot sales, contract sales, and bulk sales.

Rack Spot Sales. Rack spot sales are sales to commercial and industrial end-users, independent retailers, cruise-ship operators and jobbers that do not involve continuing contractual obligations to purchase or deliver product. Rack spot sales are priced and delivered on a daily basis through truck loading racks or marine fueling equipment. Our selling price of a particular product on a particular day at a particular terminal is a function of our supply at that terminal, our estimate of the costs to replenish the product at that terminal, our desire to reduce inventory levels at that terminal that day, and other factors. Rack spot sales are recognized as revenue when the product is delivered to the customer through the truck loading rack or marine fueling equipment.

Rack spot sales were approximately $1,704.5 million, $1,691.3 million and $1,133.1 million for the years ended June 30, 2004, 2003 and 2002, respectively. For the years ended June 30, 2004, 2003 and 2002, we averaged approximately 117,000 barrels, 130,000 barrels and 111,000 barrels per day, respectively, of delivered volumes under rack spot sales.

Contract Sales. Contract sales are sales to commercial and industrial end users, independent retailers, cruise-ship operators and jobbers that are made pursuant to negotiated contracts, generally ranging from one to six months in duration. Contract sales provide these customers with a specified volume of product during the agreement term. At the customer's option, the pricing of the product delivered under a contract sale may be fixed at a stipulated price per gallon, or it may vary based on changes in

published indices. Contract sales are recognized as revenue when the product is delivered to the customer through the truck loading rack or marine fueling equipment.

Contract sales were approximately $3,085.4 million, $1,759.2 million and $921.9 million for the years ended June 30, 2004, 2003 and 2002, respectively. For the years ended June 30, 2004, 2003 and 2002, we averaged approximately 210,000 barrels, 136,000 barrels and 88,000 barrels per day, respectively, of delivered volumes under contract sales.

Bulk Sales. Bulk sales are sales of large quantities of product to wholesalers, distributors and marketers in major cash markets. We also may make a bulk sale of products while the product is being transported in the common carrier pipelines or by barge or vessel. Bulk sales are recognized as revenue when the title to the product is transferred to the customer, which generally occurs upon confirmation of the terms of the sale.

Bulk sales were approximately $6,063.2 million, $4,613.2 million and $3,815.4 million for the years ended June 30, 2004, 2003 and 2002, respectively. For the years ended June 30, 2004, 2003 and 2002, we averaged approximately 400,000 barrels, 363,000 barrels and 366,000 barrels per day, respectively, of delivered volumes under bulk sales.

Supply Chain Management Services Contracts. We provide supply chain management services to companies and governmental entities that desire to outsource their fuel supply function and to reduce the price volatility associated with their fuel supplies. We offer three types of supply chain management services: delivered fuel price management, retail price management, and logistical supply chain management services.

Sales pursuant to supply chain management services contracts were approximately $362.3 million, $177.3 million and $130.8 million for the years ended June 30, 2004, 2003 and 2002, respectively. For the years ended June 30, 2004, 2003 and 2002, we averaged approximately 26,000 barrels, 14,000 barrels and 11,000 barrels per day, respectively, of delivered volumes under supply chain management services contracts.

Cost of Product Sold. The cost of product sold includes the cost of the product inventory sold on a first-in, first-out basis, pipeline transportation and other freight costs, terminal throughput, additive and storage costs, and commissions. Cost of product sold is approximately $11,060.1 million, $8,072.9 million and $5,875.8 million for the years ended June 30, 2004, 2003 and 2002, respectively. Cost of product sold is as follows (in thousands):

		Years ended June 30,
		2004		2003		2002

Inventory product costs		$	10,860,620	$	7,922,563	$	5,767,341
Transportation and related charges			135,768		104,146		73,648
Throughput, storage and related charges			61,153		44,269		33,775
Other			2,564		1,899		1,027

	Cost of product sold	$	11,060,105	$	8,072,877	$	5,875,791

Net Losses on Risk Management Activities. Our risk management strategy generally is intended to maintain a balanced position of forward sale and purchase commitments against our discretionary inventories held for immediate sale or exchange and future contractual delivery obligations, thereby reducing exposure to commodity price fluctuations. We evaluate our exposure to commodity price risk from an overall portfolio basis that considers the continuous movement of discretionary inventory

volumes held for immediate sale or exchange and our obligations to deliver products at fixed prices through our sales contracts and supply chain management contracts. Our physical inventory position, which includes firm commitments to buy and sell product, is offset with risk management contracts, principally futures contracts on the NYMEX.

When we purchase refined petroleum products, we enter into futures contracts to sell a corresponding amount of product to protect against price fluctuations for the underlying commodity. When we ultimately sell the underlying inventory to a customer, we unwind the related risk management contract. In order to effectively manage commodity price risk, we must predict when we will sell the underlying product. If we fail to accurately predict the timing of those future sales, and the product remains in our inventory longer than the expiration date of the futures contract, we must settle the old futures contract and enter into a new futures contract to manage the commodity price risk until the inventory is sold. We refer to this as "rolling" the risk management contracts. During a period of rising prices, our risk management contracts (i.e., short futures contracts) that are entered into to reduce our risk to commodity price changes associated with our discretionary inventory volumes held for immediate sale or exchange will decline in value resulting in a loss.

Net losses on risk management activities were approximately $(54.7) million, $(84.1) million and $(56.8) million for the years ended June 30, 2004, 2003 and 2002, respectively, due principally to rising commodity prices during these periods.

Lower of Cost or Market Write-Downs on Base Operating Inventory Volumes. During the years ended June 30, 2004 and 2003, we recognized impairment losses of approximately $5.3 million and $12.4 million, respectively, due to lower of cost or market write-downs on certain base operating inventory volumes due principally to declining prices at the end of a quarterly reporting period. During the year ended June 30, 2002 and in prior years, we did not report any of our inventory volumes as base operating inventory volumes. During these years our base operating inventory volumes were a component of our product linefill and tank bottom volumes.

Costs and expenses

Selling, general and administrative expenses for the year ended June 30, 2004 were $40.7 million, compared to $40.5 million for the year ended June 30, 2003, and $35.2 million for the year ended June 30, 2002. Selling, general and administrative expenses are as follows (in thousands):

		Years ended June 30,
		2004		2003		2002

Wages and employee benefits		$	27,819	$	28,324	$	25,278
Office costs, utilities and communication charges			5,314		4,878		4,894
Accounting and legal expenses			1,618		2,502		1,306
Property and casualty insurance			3,857		2,831		1,871
Other			2,139		1,956		1,862

	Selling, general and administrative expenses	$	40,747	$	40,491	$	35,211

Depreciation and amortization for the years ended June 30, 2004, 2003 and 2002, was $23.0 million, $19.4 million and $16.6 million, respectively. The increase of $3.6 million in depreciation and amortization for 2004 as compared to 2003 is principally related to depreciation and amortization on the Coastal Fuels assets and current year additions to property, plant, and equipment. The increase of $2.8 million in depreciation and amortization for 2003 as compared to 2002 is principally related to depreciation and amortization on new additions to property, plant, and equipment.

During the years ended June 30, 2004, 2003 and 2002, we recognized impairment losses of approximately $60,000, $0.6 million and $13.0 million, respectively, due to write-downs on the product linefill and tank bottom volumes.

We recognized special charges of $1.4 million and $6.3 million during the years ended June 30, 2003 and 2002, respectively, related to our corporate relocation and transition. During the year ended June 30, 2003, we completed the relocation of our employees from Atlanta, Georgia to Denver, Colorado. In connection with our corporate relocation and transition, we entered into an operating lease for new office space in Denver, Colorado. Accordingly, we vacated certain office space in Denver, Colorado during June 2003 and we vacated our excess space in Atlanta, Georgia during October 2002.

Loss on disposition of assets for the year ended June 30, 2004, consists of a $(0.7) million loss on sale of CETEX pipeline system and a $(0.3) loss on the sale of other assets. Gain (loss) on the disposition of assets for the year ended June 30, 2002, consists of a $(9.9) million loss on the sale of West Shore, a $8.6 million gain on the sale of the NORCO system, a $1.4 million gain on the sale of our investment in ST Oil Company, and a $(0.1) million loss on the sale of other assets.

Other income and expenses

Dividend income for the year ended June 30, 2004 was $nil, compared to $0.4 million for the year ended June 30, 2003, and $1.5 million for the year ended June 30, 2002. The decrease of $0.4 million in dividend income for 2004 as compared to 2003 was due principally to a lack of dividends from Lion Oil Company. The decrease of $1.1 million in dividend income for 2003 as compared to 2002 was due principally to a decrease of $0.3 million in dividends received from Lion Oil Company and the absence of $0.8 million in dividends received from West Shore. We sold a portion of our investment in West Shore on July 27, 2001 and our remaining investment on October 29, 2001.

Interest income for the year ended June 30, 2004 was $0.2 million, as compared to $0.3 million for the year ended June 30, 2003, and $0.6 million for the year ended June 30, 2002. Pursuant to our cash management practices, excess cash balances are used to pay down our outstanding borrowings under our credit facility and commodity margin loan.

Interest expense for the year ended June 30, 2004 was $26.5 million, compared to $14.7 million during the year ended June 30, 2003, and $12.4 million during the year ended June 30, 2002. Interest expense is as follows (in thousands):

		Years ended June 30,
		2004		2003		2002

Senior subordinated notes		$	18,639	$	1,521	$	—
Working capital credit facility			7,216		1,724		—
Former bank credit facility			—		4,559		5,179
Letters of credit			468		351		338
Commodity margin loan			154		200		499
Interest rate swap			—		3,902		4,597
Term loan			—		2,441		—
Senior notes			—		—		1,823
Other			—		7		—

	Interest expense	$	26,477	$	14,705	$	12,436

Other financing costs for the year ended June 30, 2004, were $3.5 million, compared to $5.3 million for the year ended June 30, 2003, and $9.0 million for the year ended June 30, 2002. The decrease of $1.8 million in other financing costs for 2004 as compared to 2003 was due principally to the absence of a write-off of debt issuance costs of $5.8 million and an unrealized gain on the settlement of our interest rate swap of $2.2 million, offset by an increase of approximately $1.7 million in amortization of deferred debt issuance costs. The decrease of $3.7 million in other financing costs for 2003 as compared to 2002 was due principally to an unrealized gain on the settlement of our interest rate swap of $2.2 million during 2003, as compared to an unrealized loss on an interest rate swap of $(2.3) million during 2002, and the absence of an early payment penalty of $1.9 million, offset by an increase in the write-off of debt issuance costs of $2.8 million related to the repayment of our former bank credit facility and the Term Loan.

On February 28, 2003, we settled our obligations under the interest rate swap agreement when we repaid our former bank credit facility. Our former bank credit facility consisted of a $300 million revolving credit facility that was scheduled to mature on June 27, 2005. On May 30, 2003, we repaid the Term Loan with the proceeds from the issuance of the Senior Subordinated Notes. The Term Loan provided for a one-time borrowing of $200 million with a scheduled maturity of February 28, 2006. The proceeds from the Term Loan were used primarily to finance the acquisition of the Coastal Fuels assets.

Income taxes

Income tax expense was $12.1 million for the year ended June 30, 2004, compared to $8.5 million for the year ended June 30, 2003, and $5.5 million for the year ended June 30, 2002. The effective combined federal and state income tax rate was 39.4%, 51.2% and 38.9% for the years ended June 30, 2004, 2003 and 2002, respectively. The effective combined rate for 2003 includes a provision of approximately $1.7 million for a change in cumulative temporary differences.

Cumulative effect adjustment for a change in accounting principle

As a result of the consensus reached on EITF 02-03, we are no longer permitted to carry our inventories—discretionary volumes held for immediate sale or exchange at fair value nor are we permitted to carry our base operating inventory volumes at original cost adjusted for impairment write-downs. Effective October 1, 2002, we adjusted the carrying amount of our inventories—discretionary volumes to the lower of cost (FIFO) or market pursuant to the requirements of EITF 02-03. The change in the carrying amount of our inventories—discretionary volumes has been reflected in the accompanying consolidated statement of operations as a cumulative effect adjustment for a change in accounting principle.

Preferred stock dividends

Preferred stock dividends on our Series A Convertible Preferred stock were $nil, $1.2 million and $11.4 million for the years ended June 30, 2004, 2003 and 2002, respectively. The decrease in the dividend resulted from a reduction in the number of shares of Series A Convertible Preferred stock outstanding. The terms of the Series A Convertible Preferred Stock included an increase in the annual dividend rate from 5% of the liquidation value to 16% of the liquidation value commencing January 1, 2004. Therefore, on June 28, 2002, we entered into an agreement with the holders of the Series A Convertible Preferred stock, or the Preferred Stock Recapitalization Agreement, to redeem a portion of the outstanding Series A Convertible Preferred stock and warrants in exchange for cash, shares of common stock, and shares of a newly created and designated preferred stock, or the Series B Redeemable Convertible Preferred Stock, to reduce the financial impact of the scheduled increase in the dividend rate. The Preferred Stock Recapitalization Agreement resulted in the redemption of 157,715

shares of Series A Convertible Preferred stock and warrants to purchase 9,841,493 shares of common stock in exchange for the (i) issuance of 72,890 shares of Series B Redeemable Convertible Preferred Stock with a fair value of approximately $80.9 million, (ii) issuance of 11,902,705 shares of common stock with a fair value of approximately $59.5 million, and (iii) a cash payment of approximately $21.3 million. On June 30, 2003, we redeemed the remaining 24,421 shares of Series A Convertible Preferred stock and warrants that were outstanding for a cash payment of approximately $24.4 million.

Preferred stock dividends on our Series B Redeemable Convertible Preferred Stock were $2.8 million, $2.8 million and $nil for the years ended June 30, 2004, 2003 and 2002. There were no shares of Series B Redeemable Convertible Preferred Stock outstanding during the year ended June 30, 2002. The initial carrying amount of the Series B Redeemable Convertible Preferred Stock of approximately $80.9 million will be decreased ratably over its 5-year term until it equals its liquidation value of approximately $72.9 million with an equal reduction in the amount of preferred stock dividends recorded for financial reporting purposes. The amount of the dividend recognized for financial reporting purposes is composed of the amount of the dividend payable to the holders of the Series B Redeemable Convertible Preferred Stock of $4.4 million, offset by the amortization of the premium on the carrying amount of the Series B Redeemable Convertible Preferred Stock of $1.6 million.

LIQUIDITY, CAPITAL RESOURCES, AND COMMODITY PRICE RISK

At June 30, 2004, our current assets exceeded our current liabilities by $118.3 million, compared to $79.3 million at June 30, 2003. The increase of $39.0 million in working capital is due principally to decreased borrowings of approximately $65.0 million under the former Working Capital Credit Facility offset by an approximately $21.8 million decline in cash and cash equivalents. In the accompanying consolidated balance sheets at June 30, 2004 and 2003, we have classified the outstanding borrowings under the former Working Capital Credit Facility as a current liability because we have pledged our current assets as security for the facility.

Our inventories—discretionary volumes are presented in the accompanying consolidated balance sheet as current assets and are carried at the lower of cost or market. Inventories—discretionary volumes are as follows (in thousands):

	June 30, 2004			June 30, 2003
	Amount		Bbls	Amount		Bbls

Volumes held for immediate sale or exchange	$	55,298	1,304	$	130,492	3,890
Volumes held for base operations		181,412	4,050		96,426	2,922

Inventories—discretionary volumes	$	236,710	5,354	$	226,918	6,812

Our volumes held for immediate sale or exchange generally are subject to price risk management. Inventories—discretionary volumes held for immediate sale or exchange are as follows (in thousands):

	June 30, 2004			June 30, 2003
	Amount		Bbls	Amount		Bbls

Gasolines	$	13,343	226	$	71,147	2,007
Distillates		35,937	843		53,495	1,683
No. 6 oil		6,018	235		5,850	200

Volumes held for immediate sale or exchange	$	55,298	1,304	$	130,492	3,890

Our base operating inventory volumes, representing in-transit volumes principally on common carrier pipelines, generally are not subject to price risk management. Based on the level of our operations at June 30, 2004, we have established our base operating inventory volumes, exclusive of product linefill and tank bottom volumes, at approximately 4.0 million barrels. Changes in our operation, such as the acquisition of additional terminals or increases in our contract sales volumes, may result in changes in the volume of our base operating inventory volumes. Inventories—base operating inventory volumes are as follows (in thousands):

	June 30, 2004			June 30, 2003
	Amount		Bbls	Amount		Bbls

Gasolines	$	117,679	2,416	$	58,145	1,653
Distillates		56,268	1,346		31,050	981
No. 6 oil		7,465	288		7,231	288

Volumes held for base operations	$	181,412	4,050	$	96,426	2,922

The activity in our base operating inventory volumes is summarized as follows (in thousands):

	Amount			Barrels

As of June 30, 2002	$	—		—
Transfer from product linefill and tank bottom volumes		28,959		1,280
Cumulative effect adjustment for adoption of EITF 02-03		10,552		—
Expansion of existing operations		38,873		875
Acquisition of Coastal Fuels assets		30,062		767
Change in FIFO cost basis		415		—
Lower of cost or market write-down		(12,435	)	—

As of June 30, 2003		96,426		2,922
Expansion of existing operations		51,442		1,128
Change in FIFO cost basis		38,878		—
Lower of cost or market write-down		(5,334	)	—

As of June 30, 2004	$	181,412		4,050

Our product linefill and tank bottom volumes are not held for sale or exchange in the ordinary course of business and, therefore, we do not manage the commodity price risks associated with these volumes. Our product linefill and tank bottom volumes consist of refined products held in our proprietary terminal pipeline connects and tank bottoms. Our product linefill and tank bottom volumes are presented in the accompanying consolidated balance sheet as non-current assets and are carried at original cost adjusted for impairment write-downs to current market values. Product linefill and tank bottom volumes consist of the following (in thousands):

	June 30, 2004			June 30, 2003
	Amount		Bbls	Amount		Bbls

Gasolines	$	14,641	533	$	13,020	497
Distillates		8,881	356		7,449	319
No. 6 oil		1,514	61		1,548	61

Product linefill and tank bottom volumes	$	25,036	950	$	22,017	877

The activity in our product linefill and tank bottom volumes is summarized as follows (in thousands):

	Amount			Barrels

As of June 30, 2002	$	45,298		2,000
Transfer to base operating inventory volumes		(28,959	)	(1,280	)
Acquisition of Coastal Fuels assets		6,311		157
Lower of cost or market write-down		(633	)	—

As of June 30, 2003		22,017		877
Expansion of existing operations		3,079		73
Lower of cost or market write-down		(60	)	—

As of June 30, 2004	$	25,036		950

The following table indicates the maturities of our derivative contracts, including the credit quality of our counterparties to those contracts with unrealized gains at June 30, 2004.

		Fair value of contracts (in thousands)
		Maturity less than 1 year			Maturity 1-3 years			Maturity in excess of 3 years		Total

Unrealized gain position—asset
	Investment grade	$	1,869		$	—		$	—	$	1,869
	Non-investment grade		817			—			—		817
	No external rating		8,385			—			—		8,385

			11,071			—			—		11,071
Unrealized loss position—liability			(33,689	)		(909	)		—		(34,598	)

Net unrealized loss position—liability		$	(22,618	)	$	(909	)	$	—	$	(23,527	)

At June 30, 2004, the unrealized gain on our derivative contracts with non-investment grade counterparties was approximately $0.8 million. A single customer represented approximately $0.1 million of that unrealized gain. At June 30, 2004, we also had derivative contracts with that customer that were in an unrealized loss position of approximately $(16.2) million. Therefore, the net unrealized loss on all our derivative contracts with that customer was approximately $(16.1) million at June 30, 2004.

The following table includes information about the changes in the fair value of our derivative contracts with that customer for the year ended June 30, 2004 (in thousands):



Fair value at June 30, 2003	$	(1,682	)
Amounts realized or otherwise settled during the year		9,102
Change in fair value attributable to change in commodity prices		(23,492	)

Fair value at June 30, 2004	$	(16,072	)

Capital expenditures for the year ended June 30, 2004, were $17.1 million for terminal and pipeline facilities and assets to support these facilities. Excluding acquisitions, capital expenditures for the year ending June 30, 2005, are estimated to be approximately $10.0 million, which includes approximately $6.0 million of capital expenditures to maintain our existing facilities. Future capital expenditures will depend on numerous factors, including the availability, economics and cost of appropriate acquisitions which we identify and evaluate; the economics, cost and required regulatory approvals with respect to

the expansion and enhancement of existing systems and facilities; customer demand for the services we provide; local, state and federal governmental regulations; environmental compliance requirements; and the availability of debt financing and equity capital on acceptable terms.

Our former Working Capital Credit Facility as in effect at June 30, 2004 provided for a maximum borrowing line of credit that was the lesser of (i) $275 million and (ii) the borrowing base (as defined; $364 million at June 30, 2004). The maximum borrowing amount was reduced by the amount of letters of credit that were outstanding. The borrowing base was a function of our cash, accounts receivable, inventory, exchanges, margin deposits, open positions of derivative contracts, outstanding letters of credit, and outstanding indebtedness as defined in the facility. At June 30, 2004, we had borrowings of $110 million outstanding and letters of credit of $38.6 million outstanding under the former Working Capital Credit Facility. We also had the ability to borrow an additional $126.4 million under the facility based on the borrowing base computation at June 30, 2004. On September 13, 2004, we repaid all outstanding borrowings under the former Working Capital Credit Facility with proceeds from our new $400 million Senior Secured Working Capital Credit Facility.

The Senior Secured Working Capital Credit Facility provides for a maximum borrowing line of credit, including outstanding letters of credit, equal to the lesser of (i) $400 million and (ii) the borrowing base which is a function, among other things, of our cash, accounts receivable, refined petroleum product inventory, exchanges, margin deposits and open positions of derivative contracts. The borrowing base is also subject to reduction for certain reserves and, until certain fixed assets satisfying the requirements of the Senior Secured Working Capital Credit Facility have been granted as security for our obligations, the borrowing base will be subject to a further reduction of $50 million. At September 13, 2004, we had the ability to borrow $247.7 million under the Senior Secured Working Capital Credit Facility based on the borrowing base at that date. We may elect to have loans outstanding under the Senior Secured Working Capital Credit Facility bear interest either (1) at a Eurodollar rate based on LIBOR, plus an applicable margin ranging from 1.5% to 2.25% depending on the excess of the borrowing base over the amount of borrowings outstanding, or (2) at a base rate equal to the greater of (a) the federal funds rate plus 0.5% and (b) the rate announced from time to time by Wachovia Bank as its prime rate, in either case, plus an applicable margin ranging up to 0.75%, depending on the excess of the borrowing base over the amount of borrowings outstanding. In addition, we will pay a commitment fee ranging from 0.25% to 0.50% per annum on the total amount of the unused commitments. The principal balance of loans and any accrued and unpaid interest will be due and payable in full on the maturity date, September 13, 2009, or the date on which all of the lenders' commitments are terminated by us, if earlier. Upon the occurrence of certain events of default, and subject to the passage of time or cure periods under certain circumstances, the lenders may accelerate and declare all or a portion of the obligations under the Senior Secured Working Capital Credit Facility to be immediately due and payable.

As with our former credit facility, the new Senior Secured Working Capital Credit Facility is our primary means of short-term liquidity to finance working capital requirements. The Senior Secured Working Capital Credit Facility contains affirmative and negative covenants (including limitations on indebtedness, limitations on dividends and other distributions, limitations on certain inter-company transactions, limitations on mergers, consolidation and the disposition of assets, limitations on investments and acquisitions and limitations on liens) that are customary for a facility of this nature. The Senior Secured Working Capital Credit Facility also contains customary representations and warranties (including those relating to corporate organization and authorization, compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults, covenant defaults, cross defaults and bankruptcy events). The only financial covenant contained in the new Senior Secured Working Capital Credit Facility is a minimum

fixed charge coverage ratio test that is tested on a quarterly basis whenever the average minimum unused credit line falls below $75 million for the last month of any quarter. In that event, we must satisfy a minimum fixed charge coverage ratio requirement of 110%. The fixed charge coverage ratio is based on a defined financial performance measure within the Senior Secured Working Capital Credit Facility known as "fixed charges EBITDA."

The proforma computation of the fixed charge coverage ratio, as if the Senior Secured Working Capital Credit Facility had been in effect for the year ended June 30, 2004, is as follows:

	Three Months Ended
	Three Months Ended												Year Ended June 30, 2004
	September 30, 2003			December 31, 2003			March 31, 2004			June 30, 2004			Year Ended June 30, 2004

Financial performance debt covenant test:
Consolidated adjusted EBITDA	$	15,132		$	19,793		$	13,091		$	9,773		$	57,789
Maintenance capital expenditures		(1,478	)		(1,238	)		(880	)		(1,522	)		(5,118	)
Cash (paid for) refund of income taxes		(4	)		(4	)		17			19			28
Preferred stock dividends paid in cash		(1,093	)		(1,093	)		(1,093	)		—			(3,279	)

Fixed charges EBITDA	$	12,557		$	17,458		$	11,135		$	8,270		$	49,420

Fixed charges for the period	$	6,396		$	6,623		$	6,697		$	6,557		$	26,273

Fixed charge coverage ratio based on rolling four consecutive quarters														188	%
Reconciliation of consolidated adjusted EBITDA to cash flows provided by (used in) operating activities:
Consolidated adjusted EBITDA	$	15,132		$	19,793		$	13,091		$	9,773		$	57,789
One-time adjustment, per Senior Secured Working Capital Credit Facility		—			—			—			(10,475	)		(10,475	)
Inventory adjustments		940			(7,169	)		30,796			12,502			37,069
Interest expense, net		(6,396	)		(6,623	)		(6,697	)		(6,556	)		(26,272	)
Cash (paid for) refund of income taxes		(4	)		(4	)		17			19			28
Amortization of deferred revenue		(1,212	)		(1,315	)		(1,044	)		(1,412	)		(4,983	)
Amortization of deferred stock-based compensation		604			662			696			698			2,660
Net change in unrealized gains/losses on long-term derivative contracts		1,389			876			233			867			3,365
Change in operating assets and liabilities		(27,327	)		(29,308	)		(10,773	)		77,931			10,523

Cash flows provided by (used in) operating activities	$	(16,874	)	$	(23,088	)	$	26,319		$	83,347		$	69,704

If we were to fail the fixed charge ratio covenant, or any other covenant contained in the Senior Secured Working Capital Credit Facility, we would seek a waiver from our lenders under such facility. If we were unable to obtain a waiver from our lenders, we would be in breach of the Senior Secured Working Capital Credit Facility and the lenders would be entitled to declare all outstanding borrowings immediately due and payable. In addition, a default under the Senior Secured Working Capital Credit Facility would trigger a cross-default provision in the indenture covering our Senior Subordinated Notes.

On May 30, 2003, we consummated the sale and issuance of $200 million aggregate principal amount of 9¹/8% Senior Subordinated Notes due 2010 and received proceeds of $194.5 million (net of

underwriters' discounts of $5.5 million). We used the net proceeds from the offering of the Senior Subordinated Notes to repay the Term Loan. The Senior Subordinated Notes mature on June 1, 2010 and interest is payable semi-annually in arrears on each June 1 and December 1 commencing on December 1, 2003. The Senior Subordinated Notes are unsecured and subordinated to all of our existing and future senior debt. Upon certain change of control events, each holder of the Senior Subordinated Notes may require us to repurchase all or a portion of its notes at a purchase price equal to 101% of the principal amount thereof, plus accrued interest.

We have contractual obligations that are required to be settled in cash. The amounts of our contractual obligations at June 30, 2004 are as follows (in thousands):

			Years ending June 30,
			2005		2006		2007		2008		2009		Thereafter

Debt			$	1,923	$	110,000	$	—	$	—	$	—	$	200,000
Series B Redeemable Convertible Preferred stock				—		—		72,890		—		—		—
Transportation and deficiency agreements				465		456		—		—		—		—
Additions to property, plant and equipment under contract				6,370		—		—		—		—		—
Operating leases, net of contracted sublease rentals:
	Existing office space			1,516		1,530		1,576		1,535		1,516		3,963
	Vacated office space			1,287		1,108		928		370		378		385
	Vessel charters			7,978		—		—		—		—		—
	Terminal and pipeline capacity			4,135		2,133		1,511		1,082		117		88
	Property and equipment			284		189		116		47		—		—

		Total contractual obligations to be settled in cash	$	23,958	$	115,416	$	77,021	$	3,034	$	2,011	$	204,436

See Notes 9, 11, 12 and 17 of Notes to consolidated financial statements.

We have outstanding letters of credit with third parties in the amount of $38.6 million, which expire within one year.

We believe that our current working capital position; future cash expected to be provided by operating activities; available borrowing capacity under our Senior Secured Working Capital Credit Facility and commodity margin loan; and our relationship with institutional lenders and equity investors should enable us to meet our planned capital and liquidity requirements through at least the maturity date of our Senior Secured Working Capital Credit Facility (September 2009).

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Risk policies

We are exposed to market risk through changes in commodity prices and interest rates as discussed below. We have no foreign currency exchange risks. Risk management policies have been established by our Risk Management Committee ("RMC") to monitor and control these market risks. Our RMC is composed primarily of our senior executives. Our RMC has responsibility for oversight with respect to our risk management policies and our Audit Committee of the Board of Directors approves the financial exposure limits.

Commodity risk

Our earnings, cash flow and liquidity may be affected by a variety of factors beyond our control, including the supply of, and demand for refined petroleum products. Demand for refined petroleum products depends on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and the extent of government regulation. As a result, refined petroleum products experience price volatility, which directly impacts our revenues and net operating margins. Our net operating margins are not impacted as much by the absolute price of the commodities as they are by the impact that the absolute price has upon supply and demand of refined petroleum products and the related local market supply and demand imbalances.

Relative month-end commodity prices from June 30, 2001 to June 30, 2004 (near-month NYMEX close on the last day of the month) are as follows ($/gallon):

The value of petroleum products in any U.S. metropolitan area is the sum of the commodity price as reflected on the NYMEX and the basis differential for that city-specific delivery location. The objective of our risk management strategy is to minimize the financial impact on TransMontaigne from changes

in petroleum commodity prices affected by world-wide crude oil and petroleum products supply and demand disruptions (e.g., Middle East war, OPEC production quotas, foreign import disruptions due to hurricanes and other weather-related occurrences, foreign country work stoppages, and major refinery outages). We generally do not manage the financial impact on us from changes in basis differentials affected by local market supply and demand disruptions (e.g., local pipeline delivery disruptions (such as the August 2003 pipeline disruption that affected Arizona markets), local refinery outages, periodic change in local government specifications for gasolines and distillates, local seasonality in product demand, and disruptions due to local weather related occurrences).

We utilize NYMEX futures contracts to manage the financial impact on us from changes in commodity prices due to "world-wide" events. We believe that the utilization of NYMEX futures contracts to manage commodity price risk minimizes the financial impact on TransMontaigne from changes in "world-wide" commodity prices. Except for the lack of correlation between the cash and futures markets that we experienced during the three months ended June 30, 2004, we believe that the historical results of our risk management strategies generally produce the financial outcomes we expect. During periods of rising commodity prices, we expect to recognize significant net margin before other direct costs and expenses from the sale of the physical product offset by significant net losses on risk management activities resulting in overall net operating margins that are in line with expectations. Conversely, during periods of declining commodity prices, we expect to recognize minimal, if any, net margin before other direct costs and expenses from the sale of the physical product offset by significant net gains on risk management activities resulting in overall net operating margins that are, again, in line with expectations. For the years ended June 30, 2004, 2003 and 2002, we recognized net losses on risk management activities of approximately $(54.7) million, $(84.1) million and $(56.8) million, respectively, due principally to rising commodity prices.

Our risk management strategies are designed to manage the commodity price risk associated with our discretionary inventories held for immediate sale or exchange and derivative contracts. Our risk management strategies generally are intended to maintain a balanced position of forward sale and purchase commitments, discretionary inventories held for immediate sale or exchange and risk management contracts, thereby reducing exposure to commodity price fluctuations. We evaluate our exposure to commodity price risk from an overall portfolio basis that considers the continuous movement of discretionary inventory volumes held for immediate sale or exchange and our obligations to deliver and receive products at fixed prices through our derivative sales and purchase contracts. Our physical position, which includes physical inventory volumes and firm commitments to buy and sell product, is reconciled daily and offset with NYMEX futures contracts. To the extent that we do not manage the commodity price risk relating to a portion of our inventory and commodity prices move adversely, we could suffer losses on that inventory. If, however, prices move favorably, we would realize a gain on the sale of the inventory that we would not realize if substantially all of our inventory was managed. At June 30, 2004, we were subject to commodity price risk on approximately 290,000 barrels of discretionary inventories held for immediate sale or exchange because those barrels were not offset with risk management contracts or future contractual delivery obligations.

Our risk management strategies and practices currently do not qualify for "hedge accounting" for financial reporting purposes.

When we purchase refined petroleum products, we generally enter into NYMEX futures contracts to protect against price fluctuations for the underlying commodity. Futures contracts are obligations to purchase or sell a specific volume of inventory at a fixed price at a future date. The NYMEX requires an initial margin deposit to open a futures contract. At June 30, 2004 and 2003, we had approximately $3.5 million and $5.2 million, respectively, on deposit to cover our initial margin

requirements on open NYMEX futures contracts. NYMEX futures contracts also require daily settlements for changes in commodity prices. Unfavorable commodity price changes subject us to variation margin calls that require us to make cash payments to the NYMEX in amounts that may be material. At June 30, 2004, a $0.05 per gallon unfavorable change in commodity prices would have required us to make a cash payment of approximately $1.8 million to cover the variation margin. Conversely, a $0.05 per gallon favorable change in commodity prices would have permitted us to receive approximately $1.8 million. We use our credit lines to fund these margin calls, but such funding requirements could exceed our ability to access capital. We have the contractual right to request that the counter-parties to our supply chain management services contracts post additional letters of credit or make additional cash deposits with us to assist us in meeting our obligations to cover our margin requirements.

When we ultimately sell the underlying inventory to a customer, we unwind the related futures contract. If there is correlation in price changes between the forward price curve in the futures market and the value of physical products in the cash market, the net changes in our variation margin position should be offset by the net operating margins we receive when we sell the underlying discretionary inventory. Therefore, in order to effectively manage commodity price risk, we must predict when we will sell the underlying product. If we fail to accurately predict the timing of those future sales, and the product remains in our inventory longer than the expiration date of the futures contract, we must settle the old futures contract and enter into a new futures contract to sell the product to manage the commodity price risk against the same inventory. We refer to this as "rolling" the risk management contracts. Furthermore, we may be unable to precisely match the underlying product in our futures contracts with the exact type of product in our physical inventory. To the extent that price fluctuations of the product covered by the NYMEX futures contract does not match the price fluctuations of the product in our physical inventory, our exposure may not be mitigated.

During the three months ended June 30, 2004, we reviewed our risk management strategies in light of the increase in the product volumes being delivered in our supply, marketing and distribution activities, and the significance of the overall losses we were incurring on our NYMEX futures contracts. Upon completion of our analysis, we concluded that our "minimum volumes," which are composed of the base operating inventory volumes and product linefill and tank bottom volumes to support our operations, would be increased from approximately 3.8 million barrels to approximately 5.0 million barrels. We generally do not manage the commodity price risk associated with our "minimum volumes."

However, our risk management policy allows our management team the discretion to manage the commodity price risk relating to up to 500,000 barrels of our base operating inventory volumes, which would reduce the total unmanaged inventory (base operating volumes and product linefill and tank bottom volumes) to approximately 4.5 million barrels, or to leave unmanaged up to 500,000 barrels of our discretionary inventory held for immediate sale or exchange, which would increase our total unmanaged inventory to approximately 5.5 million barrels. The principal objective of this aspect of our risk management policy is to allow management discretion to capture financial gains, or prevent financial losses, on predictable commodity price movements with respect to up to 500,000 barrels of physical product. We decide whether to manage the commodity price risk relating to a portion of our base operating inventory or to leave a portion of our discretionary inventory held for immediate sale or exchange unmanaged depending on our expectations of future market changes.

Our RMC reviews our discretionary inventory volumes held for immediate sale or exchange, open positions in fixed-price forward sale and purchase commitments, and risk management contracts on a regular basis in order to ensure compliance with our risk management policies. Fixed-price forward

sale and purchase commitments are subject to risks relating to market value fluctuations, as well as counter-party credit and liquidity risk. We have established procedures to continually monitor these contracts in order to minimize credit risk, including the establishment and review of credit limits, margin requirements, master net-out arrangements, letters of credit and other guarantees.

At June 30, 2004, a $0.05 per gallon unfavorable change in commodity prices relative to our open positions in derivative sales and purchase contracts and risk management contracts would have resulted in the recognition of a loss (realized and unrealized) of approximately $0.6 million. However, the fair value of our discretionary inventory held for immediate sale or exchange would have increased by approximately $1.2 million. The gain from the increase in the fair value of our discretionary inventory volumes held for immediate sale or exchange may not be recognized for financial reporting purposes until those volumes have been sold to customers, which may be in an accounting period subsequent to the accounting period in which the losses on derivative contracts and risk management contracts are recognized.

Interest rate risk

At June 30, 2004, we had outstanding borrowings of $110.0 million under our former Working Capital Credit Facility. We are exposed to interest rate risk because the former Working Capital Credit Facility was a variable-rate-based credit facility. Our new Senior Secured Working Capital Credit Facility is a variable-rate-based credit facility. The interest rate is based on the lender's alternate base rate plus a spread, or LIBOR plus a spread, in effect at the time of the borrowings and is adjusted monthly, bi-monthly, quarterly or semi-annually. Based on the outstanding balance of our variable-interest-rate debt at June 30, 2004, and assuming market interest rates increase or decrease by 100 basis points, the potential annual increase or decrease in interest expense is approximately $1.1 million.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The following consolidated financial statements should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" included elsewhere in this annual report.

TransMontaigne Inc. and Subsidiaries:

Report of Independent Registered Public Accounting Firm

Consolidated balance sheets as of June 30, 2004 and 2003

Consolidated statements of operations for the years ended June 30, 2004, 2003 and 2002

Consolidated statements of preferred stock and common stockholders' equity for the years ended June 30, 2004, 2003 and 2002

Consolidated statements of cash flows for the years ended June 30, 2004, 2003 and 2002

Notes to consolidated financial statements

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders
TransMontaigne Inc.:

We have audited the accompanying consolidated balance sheets of TransMontaigne Inc. and subsidiaries as of June 30, 2004 and 2003, and the related consolidated statements of operations, preferred stock and common stockholders' equity, and cash flows for each of the years in the three-year period ended June 30, 2004. These consolidated financial statements are the responsibility of TransMontaigne Inc.'s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of TransMontaigne Inc. and subsidiaries as of June 30, 2004 and 2003, and the results of their operations and their cash flows for each of the years in the three-year period ended June 30, 2004, in conformity with U.S. generally accepted accounting principles.

As discussed in note 1(i) to the consolidated financial statements, the Company changed its method of accounting for inventories—discretionary volumes in 2003.

		KPMG LLP
Denver, Colorado September 13, 2004

TransMontaigne Inc. and subsidiaries
Consolidated balance sheets
(In thousands)

			June 30, 2004			June 30, 2003

ASSETS
Current assets:
	Cash and cash equivalents		$	6,158		$	27,969
	Restricted cash held by commodity broker			3,468			5,155
	Trade accounts receivable, net			282,298			290,007
	Inventories—discretionary volumes			236,710			226,918
	Unrealized gains on derivative contracts			11,071			16,817
	Deferred tax assets			11,862			15,379
	Prepaid expenses and other			3,768			5,775

				555,335			588,020
Property, plant and equipment, net				362,265			371,735
Product linefill and tank bottom volumes				25,036			22,017
Unrealized gains on derivative contracts				—			1,885
Investments in petroleum related assets				10,131			10,131
Deferred debt issuance costs, net				10,383			12,908
Other assets, net				11,206			13,770

			$	974,356		$	1,020,466

LIABILITIES, PREFERRED STOCK, AND COMMON STOCKHOLDERS' EQUITY
Current liabilities:
	Commodity margin loan		$	1,923		$	4,534
	Working capital credit facility			110,000			175,000
	Trade accounts payable			142,395			144,443
	Unrealized losses on derivative contracts			33,689			20,151
	Inventory due to others under exchange agreements			32,390			35,121
	Excise taxes payable			93,702			99,068
	Other accrued liabilities			19,414			25,562
	Deferred revenue—supply chain management services			3,502			4,816

				437,015			508,695
Other liabilities:
	Long-term debt			200,000			200,000
	Deferred tax liabilities			30,424			21,750
	Unrealized losses on derivative contracts			909			423

		Total liabilities		668,348			730,868

Series B Redeemable Convertible Preferred stock				77,719			79,329

Common stockholders' equity:
	Common stock			411			407
	Capital in excess of par value			251,775			249,339
	Deferred stock-based compensation			(4,129	)		(3,943	)
	Accumulated deficit			(19,768	)		(35,534	)

				228,289			210,269

			$	974,356		$	1,020,466

See accompanying notes to consolidated financial statements.

TransMontaigne Inc. and subsidiaries
Consolidated statements of operations
(In thousands, except per share amounts)

				Year ended June 30, 2004			Year ended June 30, 2003			Year ended June 30, 2002

Supply, distribution and marketing:
	Revenues			$	11,215,351		$	8,241,001		$	6,001,170
	Cost of product sold and other direct costs and expenses				(11,145,501	)		(8,190,918	)		(5,932,423	)

			Net operating margins		69,850			50,083			68,747

Terminals, pipelines, and tugs and barges:
	Revenues				109,240			86,967			68,285
	Direct operating costs and expenses				(53,966	)		(39,175	)		(32,567	)

			Net operating margins		55,274			47,792			35,718

			Total net operating margins		125,124			97,875			104,465

Costs and expenses:
	Selling, general and administrative				(40,747	)		(40,491	)		(35,211	)
	Depreciation and amortization				(23,015	)		(19,371	)		(16,556	)
	Lower of cost or market write-downs on product linefill and tank bottom volumes				(60	)		(633	)		(12,963	)
	Corporate relocation and transition:
		Severance, transition, and relocation benefits			—			(1,449	)		(2,138	)
		Abandonment of office leases and leasehold improvements			—			—			(4,178	)
	Loss on disposition of assets, net				(978	)		—			(13	)

			Total costs and expenses		(64,800	)		(61,944	)		(71,059	)

			Operating income		60,324			35,931			33,406

Other income (expenses):
	Dividend income				6			374			1,450
	Interest income				205			286			599
	Interest expense				(26,477	)		(14,705	)		(12,436	)
	Other financing costs:
			Early payment penalty on retirement of long-term debt		—			—			(1,943	)
			Amortization of deferred debt issuance costs		(3,469	)		(1,725	)		(1,744	)
			Write-off of debt issuance costs		—			(5,775	)		(2,987	)
			Gain (loss) on interest rate swap		—			2,224			(2,322	)

			Total other expenses		(29,735	)		(19,321	)		(19,383	)

			Earnings before income taxes and cumulative effect of a change in accounting principle		30,589			16,610			14,023
Income tax expense					(12,060	)		(8,510	)		(5,465	)

			Earnings before cumulative effect of a change in accounting principle		18,529			8,100			8,558
Cumulative effect of a change in accounting principle of $2,092, net of income tax benefit of $795					—			(1,297	)		—

			Net earnings	$	18,529		$	6,803		$	8,558

TransMontaigne Inc. and subsidiaries
Consolidated statements of operations—(Continued)
(In thousands, except per share amounts)

			Year ended June 30, 2004			Year ended June 30, 2003			Year ended June 30, 2002

Computation of earnings (loss) per share:
	Net earnings before cumulative effect of a change in accounting principle		$	18,529		$	8,100		$	8,558
	Earnings allocable to preferred stock			(4,373	)		(3,984	)		(11,351	)
	Cumulative effect of a change in accounting principle			—			(1,297	)		—

		Net earnings (loss) attributable to common stockholders	$	14,156		$	2,819		$	(2,793	)

Basic net earnings (loss) per common share:
	Net earnings (loss) after amounts allocable to preferred stock and before cumulative effect of a change in accounting principle		$	0.36		$	0.10		$	(0.09	)
	Cumulative effect of a change in accounting principle			—			(0.03	)		—

			$	0.36		$	0.07		$	(0.09	)

Diluted net earnings (loss) per common share:
	Net earnings (loss) after amounts allocable to preferred stock and before cumulative effect of a change in accounting principle		$	0.36		$	0.10		$	(0.09	)
	Cumulative effect of a change in accounting principle			—			(0.03	)		—

			$	0.36		$	0.07		$	(0.09	)

Weighted average common shares outstanding:
	Basic			39,355			39,116			31,267

	Diluted			51,008			39,263			31,267

See accompanying notes to consolidated financial statements.

TransMontaigne Inc. and subsidiaries
Consolidated statements of preferred stock and common stockholders' equity
Years ended June 30, 2004, 2003 and 2002
(in thousands)

	Preferred stock									Capital in excess of par value			Deferred stock-based compensation						Total common stockholders' equity
	Preferred stock						Common stock									Accumulated deficit
	Series A			Series B			Common stock									Accumulated deficit

Balance at June 30, 2001	$	174,825		$	—		$	318		$	205,256		$	(2,465	)	$	(35,559	)	$	167,550
Common stock issued for options exercised		—			—			—			151			—			—			151
Common stock repurchased from employees for withholding taxes		—			—			—			(112	)		—			—			(112	)
Net tax effect arising from stock-based compensation		—			—			—			(24	)		—			—			(24	)
Forfeiture of restricted stock awards prior to vesting		—			—			(1	)		(501	)		502			—			—
Deferred compensation related to restricted stock awards		—			—			4			2,085			(2,089	)		—			—
Amortization of deferred stock-based compensation		—			—			—			—			1,512			—			1,512
Preferred stock dividends paid-in-kind		9,816			—			—			—			—			(9,816	)		(9,816	)
Recapitalization of Series A Convertible Preferred stock		(160,220	)		80,939			119			59,394			—			(1,536	)		57,977
Common stock repurchased and retired		—			—			(41	)		(20,405	)		—			—			(20,446	)
Net earnings		—			—			—			—			—			8,558			8,558

Balance at June 30, 2002	$	24,421		$	80,939		$	399		$	245,844		$	(2,540	)	$	(38,353	)	$	205,350
Common stock issued for options exercised		—			—			—			12			—			—			12
Common stock repurchased from employees for withholding taxes		—			—			—			(214	)		—			—			(214	)
Net tax effect arising from stock-based compensation		—			—			—			70			—			—			70
Forfeiture of restricted stock awards prior to vesting		—			—			—			(238	)		238			—			—
Deferred compensation related to restricted stock awards		—			—			8			3,605			(3,613	)		—			—
Deferred compensation related to non-employee stock options		—			—			—			260			(260	)		—			—
Amortization of deferred stock-based compensation		—			—			—			—			2,232			—			2,232
Preferred stock dividends		—			—			—			—			—			(5,594	)		(5,594	)
Amortization of premium on Series B Redeemable Convertible Preferred stock		—			(1,610	)		—			—			—			1,610			1,610
Repurchase of Series A Convertible Preferred stock		(24,421	)		—			—			—			—			—			—
Net earnings		—			—			—			—			—			6,803			6,803

Balance at June 30, 2003	$	—		$	79,329		$	407		$	249,339		$	(3,943	)	$	(35,534	)	$	210,269
Common stock issued for options exercised		—			—			1			317			—			—			318
Common stock repurchased from employees for withholding taxes		—			—			(1	)		(620	)		—			—			(621	)
Net tax effect arising from stock-based compensation		—			—			—			(103	)		—			—			(103	)
Forfeiture of restricted stock awards prior to vesting		—			—			(1	)		(336	)		337			—			—
Deferred compensation related to restricted stock awards		—			—			5			3,178			(3,183	)		—			—
Amortization of deferred stock-based compensation		—			—			—			—			2,660			—			2,660
Preferred stock dividends		—			—			—			—			—			(4,373	)		(4,373	)
Amortization of premium on Series B Redeemable Convertible Preferred stock		—			(1,610	)		—			—			—			1,610			1,610
Net earnings		—			—			—			—			—			18,529			18,529

Balance at June 30, 2004	$	—		$	77,719		$	411		$	251,775		$	(4,129	)	$	(19,768	)	$	228,289

See accompanying notes to consolidated financial statements.

TransMontaigne Inc. and subsidiaries
Consolidated statements of cash flows
(In thousands)

					Year ended June 30, 2004			Year ended June 30, 2003			Year ended June 30, 2002

Cash flows from operating activities:
	Net earnings				$	18,529		$	6,803		$	8,558
	Adjustments to reconcile net earnings to net cash provided (used) by operating activities:
		Amortization of deferred revenue				(4,983	)		(2,485	)		(100	)
		Depreciation and amortization				23,015			19,371			16,556
		Deferred tax expense				12,191			7,400			5,062
		Net tax effect arising from stock-based compensation				(103	)		70			(24	)
		Loss on disposition of assets, net				978			—			13
		Abandonment of office leases and leasehold improvements				—			—			4,178
		Amortization of deferred stock-based compensation				2,660			2,232			1,512
		Amortization of debt issuance costs				3,469			1,725			1,744
		Repayment of interest rate swap				—			(3,205	)		—
		Write-off of debt issuance costs				—			5,775			2,987
		Unrealized loss (gain) on interest rate swap				—			(2,224	)		2,322
		Net change in unrealized (gains)/losses on long-term derivative contracts				3,365			6,678			1,716
		Lower of cost or market write-downs on product linefill and tank bottom volumes				60			633			12,963
		Amortization of prepaid transportation costs				2,159			—			—
		Other				—			—			538
		Changes in operating assets and liabilities, net of effects from acquisitions:
			Trade accounts receivable, net			7,709			(116,271	)		(94,686	)
			Inventories—discretionary volumes			(8,236	)		7,836			(78,182	)
			Prepaid expenses and other			(252	)		(918	)		1,533
			Trade accounts payable			1,801			40,313			30,609
			Unrealized (gain)/loss on derivative contracts			21,959			14,782			(1,910	)
			Inventory due to others under exchange agreements, net			(2,731	)		18,213			(59,845	)
			Excise taxes payable and other accrued liabilities			(11,886	)		26,595			42,944

				Net cash provided (used) by operating activities		69,704			33,323			(101,512	)

Cash flows from investing activities:
	Acquisition of Coastal Fuels assets					—			(155,968	)		—
	Acquisition of terminals, pipelines, tugs and barges					(3,070	)		(6,983	)		(7,115	)
	Additions to property, plant and equipment—expansion of facilities					(10,049	)		(7,170	)		(6,503	)
	Additions to property, plant and equipment—maintain existing facilities					(5,118	)		(3,649	)		(2,191	)
	Proceeds from sale of assets					501			—			120,510
	Additions to product linefill and tank bottom volumes					(3,079	)		—			—
	Decrease (increase) in restricted cash held by commodity broker					1,687			3,466			(637	)
	Decrease (increase) in other assets					845			(321	)		(1,286	)

				Net cash provided (used) by investing activities		(18,283	)		(170,625	)		102,778

Cash flows from financing activities:
	Net borrowings (repayments) of debt					(65,000	)		188,000			57,000
	Net borrowings (repayments) of commodity margin loan					(2,612	)		(6,778	)		(8,688	)
	Deferred debt issuance costs					(944	)		(17,679	)		(2,791	)
	Common stock issued for options and warrants exercised					318			12			151
	Common stock repurchased from employees for withholding taxes					(621	)		(214	)		(112	)
	Common stock repurchased and retired					—			—			(20,446	)
	Cash paid to redeem Series A Convertible Preferred stock					—			(24,421	)		(21,303	)
	Preferred stock dividends paid in cash					(4,373	)		(4,501	)		—

				Net cash provided (used) by financing activities		(73,232	)		134,419			3,811

				Increase (decrease) in cash and cash equivalents		(21,811	)		(2,883	)		5,077
Cash and cash equivalents at beginning of year						27,969			30,852			25,775

Cash and cash equivalents at end of year					$	6,158		$	27,969		$	30,852

TransMontaigne Inc. and subsidiaries
Consolidated statements of cash flows (continued)
(In thousands)

			Year ended June 30, 2004			Year ended June 30, 2003		Year ended June 30, 2002

Supplemental disclosures of cash flow information:
Cash paid for (refund of) income taxes			$	(28	)	$	310	$	600

Cash paid for interest expense			$	26,028		$	13,050	$	12,240

Cash received from sale of Little Rock facilities			$	—		$	—	$	29,033

Sale of West Shore shares on July 27, 2001 and October 29, 2001:
	Investment in West Shore		$	—		$	—	$	(35,952	)
	Loss on disposition			—			—		9,896

	Cash received from sale		$	—		$	—	$	26,056

Sale of NORCO system on July 31, 2001:
	Assets disposed		$	—		$	—	$	(49,733	)
	Liabilities recorded upon sale:
		Accrued environmental obligations		—			—		(2,000	)
		Accrued indemnities		—			—		(1,300	)
		Other		—			—		(116	)
	Gain on disposition			—			—		(8,601	)

	Cash received from sale		$	—		$	—	$	61,750

Sale of ST Oil Company on May 31, 2002:
	Investment in ST Oil Company		$	—		$	—	$	(1,677	)
	Gain on disposition			—			—		(1,363	)

	Cash received from sale		$	—		$	—	$	3,040

Other cash sales—cash received from sales of other assets			$	501		$	—	$	631

Total cash received from sales of assets			$	501		$	—	$	120,510

See accompanying notes to consolidated financial statements.

Notes to consolidated financial statements
Years ended June 30, 2004, 2003 and 2002

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a) Principles of Consolidation and Use of Estimates

Our accounting and financial reporting policies conform to accounting principles and practices generally accepted in the United States of America. The accompanying consolidated financial statements include the accounts of TransMontaigne Inc. and its majority-owned subsidiaries. All significant inter-company accounts and transactions have been eliminated in consolidation, except for throughput fees, storage fees, pipeline transportation fees, tug and barge fees and other fees charged to our supply, distribution and marketing operations by our terminals, pipelines, and tugs and barges. The related inter-company revenues and costs offset within total net operating margins in the accompanying consolidated statement of operations.

The preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. The following estimates, in our opinion, are subjective in nature, require the exercise of judgment, and involve complex analysis: allowance for doubtful accounts; fair value of inventories—discretionary volumes held for immediate sale or exchange (used to evaluate the financial performance of our business segments); fair value of derivative contracts; accrued lease abandonment costs; accrued transportation and deficiency obligations; and accrued environmental obligations. Changes in these estimates and assumptions will occur as a result of the passage of time and the occurrence of future events. Actual results could differ from these estimates.

(b) Nature of Business and Basis of Presentation

TransMontaigne Inc., a Delaware corporation ("TransMontaigne") based in Denver, Colorado, was formed in 1995 to create an independent refined petroleum products distribution and supply company. We are a holding company that conducts operations in the United States primarily in the Gulf Coast, Midwest, and East Coast regions. We provide integrated terminal, transportation, storage, supply, distribution, and marketing services to refiners, wholesalers, distributors, marketers, and industrial and commercial end-users of refined petroleum products. Our principal activities consist of (i) terminal, pipeline, and tug and barge operations, (ii) supply, distribution, and marketing, and (iii) supply chain management services.

On February 28, 2003, we acquired all of the outstanding shares of capital stock of Coastal Fuels Marketing, Inc. and its subsidiary, Coastal Tug and Barge, Inc., from a wholly-owned subsidiary of El Paso Merchant Energy Petroleum Company ("EPME-PC"), along with the rights to and operations of the southeast marketing division of EPME-PC (see Note 2 of Notes to consolidated financial statements).

(c) Accounting for Terminal, Pipeline, and Tug and Barge Activities

In connection with our terminal, pipeline, and tug and barge operations, we utilize the accrual method of accounting for revenue and expenses. We generate revenues in our terminal, pipeline, and tug and

barge operations from throughput fees, storage fees, transportation fees, ship-assist fees, management fees and cost reimbursements, and fees from other ancillary services. Throughput revenue is recognized when the product is delivered to the customer; storage revenue is recognized ratably over the term of the storage contract; transportation revenue is recognized when the product has been delivered to the customer at the specified delivery location; ship-assist revenue is recognized when docking and other services are provided to marine vessels; management fees and cost reimbursements are recognized as the services are performed; and other service revenue is recognized as the services are performed.

Shipping and handling costs attributable to our terminal, pipeline, and tug and barge operations are included in direct operating costs and expenses in the accompanying consolidated statement of operations.

(d) Accounting for Supply, Distribution, and Marketing Activities

In our supply, distribution and marketing operations, we purchase refined petroleum products primarily from refineries, schedule them for delivery to our terminals, as well as terminals owned by third parties, and then sell those products to our customers through rack spot sales, contract sales, and bulk sales. Revenue from our sales of physical inventory is recognized pursuant to the accrual method of accounting (i.e., when cash becomes due and payable to us pursuant to the terms of the sales contracts). Revenue from rack spot sales and contract sales is recognized when the product is delivered to the customer through a truck loading rack or marine fueling equipment. Revenue from bulk sales is recognized when the title to the product is transferred to the customer, which generally occurs upon confirmation of the terms of the sale.

Shipping and handling costs attributable to our supply, distribution, and marketing operations are included in cost of product sold in the accompanying consolidated statement of operations.

(e) Accounting for Supply Chain Management Services Activities

We provide supply chain management services to companies and governmental entities that desire to outsource their fuel supply function and to reduce the price volatility associated with their fuel supplies. We offer three types of supply chain management services: delivered fuel price management, retail price management, and logistical supply chain management services.

Delivered fuel price management contracts involve the sales of committed quantities of specific motor fuels delivered to our customer's proprietary fleet refueling locations, at fixed prices for terms up to three years. Under retail price management contracts, customers commit for terms up to 18 months to a specific monthly quantity of product within one or more metropolitan areas and agree to a net settlement with us for the difference between a stipulated retail price index and our fixed contract price. Our logistical supply chain management arrangements permit our customers to use our proprietary web-based inventory management system for a fee, which typically is charged on a per gallon basis.

Revenue from sales made pursuant to delivered fuel price management contracts is recognized when title to the product is transferred to the customer, which generally occurs upon delivery of the product at the customer's proprietary fleet refueling location. Revenue from sales made pursuant to retail price management contracts is recognized when title to the product is transferred to the customer, which generally occurs upon lifting of the product by the customer at the retail gasoline station. Revenue from logistical supply chain management services fees is recognized on a straight-line basis over the term of the contract.

(f) Accounting for Risk Management Activities

We enter into risk management contracts, principally NYMEX futures contracts, to manage our exposure to changes in commodity prices. We evaluate our market risk exposure from an overall portfolio basis that considers changes in physical inventories—discretionary volumes held for immediate sale or exchange, open positions in derivative contracts, and open positions in risk management contracts. We enter into risk management contracts that are intended to offset the changes in the values of our inventories—discretionary volumes held for immediate sale or exchange and derivative contracts. At June 30, 2004 and 2003, our open positions in risk management contracts were NYMEX futures contracts (purchases and sales).

(g) Accounting for Derivative Contracts

Our contract sales, bulk sales, delivered fuel price management, retail price management and risk management contracts qualify as derivative instruments pursuant to the requirements of Statement of Financial Accounting Standards No. 133 ("SFAS No. 133"), Accounting for Derivative Instruments and Hedging Activities. All derivative contracts are required to be reported as assets and liabilities at fair value in the accompanying consolidated balance sheet in accordance with SFAS No. 133. The fair value of our derivative contracts is included in "Unrealized gains or losses on derivative contracts" in the accompanying consolidated balance sheet. At June 30, 2004 and 2003, there were no unrealized gains or losses on risk management contracts because NYMEX futures contracts require daily settlement for changes in commodity prices on open futures contracts. The net changes in the fair value of our derivative contracts are included in net operating margins attributable to our supply, distribution and marketing operations.

For the year ended June 30, 2002, we recognized net operating margins of approximately $8.2 million attributable to our supply, distribution and marketing operations, representing the estimated fair value of our delivered fuel price management and retail price management contracts at origination. Effective April 1, 2002, the estimated fair value of our delivered fuel price management and retail price management contracts at origination is deferred because our estimate of the fair value is not evidenced by quoted market prices or current market transactions for the contracts in their entirety. The deferred revenue is amortized into income over the respective terms of the contracts as the products are delivered to the ground fleet customers. Subsequent changes in the fair value of our delivered fuel price management and retail price management contracts are included in net operating margins attributable to our supply, distribution, and marketing operations.

(h) Presentation of Revenues from Energy-Related and Risk Management Activities

We present revenue from our rack spot sales, contract sales, bulk sales, and delivered fuel price management on a gross basis in the accompanying consolidated statement of operations because our obligations under these arrangements are settled via transfer of title and risk of loss of the product to the customer. Revenue from our retail price management contracts and risk management contracts are presented on a net basis (i.e., product costs are required to be netted directly against gross revenues to arrive at net revenues) in the accompanying consolidated statement of operations because our obligations under these arrangements are settled on a net cash basis. The logistical supply chain management services fees do not involve the sale of inventory and, therefore, only the service fee is presented in the accompanying consolidated statement of operations.

(i) Accounting for Inventories—Discretionary Volumes

Our inventories—discretionary volumes consist of refined petroleum products, primarily gasolines, distillates, and No. 6 oil. At June 30, 2004 and 2003, our inventories—discretionary volumes are composed of volumes held for immediate sale or exchange and volumes held for base operations. Volumes held for immediate sale or exchange generally are subject to price risk management activities. Volumes held for base operations generally are not subject to price risk management activities. Inventories—discretionary volumes are presented in the accompanying consolidated balance sheet as current assets and are carried at the lower of cost (first-in, first-out) or market (replacement cost) for periods subsequent to September 30, 2002. Prior to October 1, 2002, our inventories—discretionary volumes held for immediate sale or exchange were carried at fair value and our volumes held for base operations, representing minimum volumes in-transit principally in common carrier pipelines, were carried at original cost adjusted for impairment write-downs (see Note 1(k) of Notes to consolidated financial statements). Inventories—discretionary volumes are as follows (in thousands):

	June 30, 2004			June 30, 2003
	Amount		Bbls	Amount		Bbls

Volumes held for immediate sale or exchange	$	55,298	1,304	$	130,492	3,890
Volumes held for base operations		181,412	4,050		96,426	2,922

Inventories—discretionary volumes	$	236,710	5,354	$	226,918	6,812

At June 30, 2004 and 2003, the market value of our volumes held for immediate sale or exchange exceeded their cost basis by approximately $2.3 million and $5.9 million, respectively. During the quarter ended June 30, 2004 we increased our volumes held for base operations, exclusive of product linefill and tank bottom volumes, by approximately 1.1 million barrels as a result of our increased supply, distribution and marketing activities. At June 30, 2004 and 2003, the market value of our volumes held for base operations exceeded their cost basis by approximately $1.4 million and $4.3 million, respectively. During the years ended June 30, 2004 and 2003, we recognized an impairment loss of approximately $5.3 million and $12.4 million, respectively, due to lower of cost or market write-downs on certain of our base operating inventory volumes.

Through September 30, 2002, we marked to market our energy trading and risk management activities, including physical inventories held for immediate sale or exchange, pursuant to the guidance in Issue No. 98-10 ("EITF 98-10"), Accounting for Contracts Involved in Energy Trading and Risk Management Activities. The mark-to-market method of accounting requires that the effect of changes in the fair value of our energy trading and risk management activities be recognized as assets and liabilities and included in net operating margins attributable to supply, distribution, and marketing in the period of the change in value. On October 25, 2002, the Emerging Issues Task Force reached a consensus on Issue No. 02-03 ("EITF 02-03"), Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities, that eliminated mark-to-market accounting for energy trading and risk management activities that are not derivative contracts. EITF 02-03 also concluded that all physical inventories, including inventory volumes associated with energy trading activities, be carried at the lower of cost or market pursuant to Accounting Research Bulletin ("ARB") No. 43, Chapter 4—Inventory Pricing. As a result, we are no longer permitted to carry our inventories—discretionary volumes held for immediate sale or exchange at fair value effective October 1, 2002. Therefore, we adjusted the carrying amount of our inventories—discretionary volumes to the lower of cost (first-in, first-out) or market pursuant to the requirements of EITF 02-03 through a cumulative effect adjustment for a change in accounting

principle. The cumulative effect adjustment is presented in the accompanying consolidated statement of operations for the year ended June 30, 2003, and is calculated as follows (in thousands):

Inventories—discretionary volumes:

Volumes held for immediate sale or exchange:
	Fair value at October 1, 2002		$	(180,241	)
	Cost basis at October 1, 2002			167,597

		Excess of fair value over cost basis		(12,644	)

Base operating volumes:
	Original cost basis—original cost as adjusted at October 1, 2002			(28,959	)
	New cost basis—first-in, first-out at October 1, 2002			39,511

		Excess of new cost basis over original cost basis		10,552

		Change in carrying amount of inventories—discretionary volumes		(2,092	)
Income tax effects at 38%				795

Cumulative effect of a change in accounting principle			$	(1,297	)

(j) Inventory Due to Others Under Exchange Agreements

We enter into exchange agreements with major oil companies. Exchange agreements generally are fixed term agreements that involve our receipt of a specified volume of product at one location in exchange for delivery by us of product at a different location. At June 30, 2004 and 2003, current liabilities include inventory due to others under exchange agreements of approximately 0.7 million barrels and 1.0 million barrels, respectively, with a fair value of approximately $32.4 million and $35.1 million, respectively. The amount recorded represents the fair value of inventory due to others under exchange agreements at the balance sheet date.

(k) Accounting for Product Linefill and Tank Bottom Volumes

Our product linefill and tank bottom volumes are required to be held for operating balances in the conduct of our overall operating activities. We do not intend to sell or exchange these volumes in the ordinary course of business and, therefore, we do not hedge the commodity price risks associated with these volumes.

Prior to October 1, 2002, our product linefill and tank bottom volumes aggregated approximately 2.0 million barrels of product reflecting tank bottoms, line fill in our proprietary pipelines, and in-transit volumes principally on common carrier pipelines. On October 1, 2002, in connection with the adoption of EITF 02-03, we transferred to inventories—discretionary volumes approximately 1.3 million barrels of product linefill and tank bottom volumes representing the volumes associated with our in-transit volumes. As of June 30, 2004 and 2003, we have approximately 950,000 barrels and 877,000 barrels, respectively, of product reflecting tank bottoms and line fill in our proprietary terminal connections with an adjusted cost basis of $25.0 million and $22.0 million, respectively.

At June 30, 2004 and 2003, our product linefill and tank bottom volumes are presented in the accompanying consolidated balance sheet as non-current assets and are carried at the lower of cost (weighted average) or market (replacement cost). The replacement cost of our product linefill and tank bottom volumes is based on the nearest quoted wholesale market price. At June 30, 2004 and 2003, the market value of our product linefill and tank bottom volumes exceeded their costs basis by approximately $17.9 million and $8.3 million, respectively. During the years ended June 30, 2004,

2003 and 2002, we recognized impairment losses of approximately $60,000, $0.6 million and $13.0 million, respectively, due to lower of cost or market write-downs on certain of our product linefill and tank bottom volumes.

(l) Cash and Cash Equivalents

We consider all short-term investments with a remaining maturity of three months or less at the date of purchase to be cash equivalents.

Restricted cash represents cash deposits held by our commodity broker to cover initial margin requirements related to open NYMEX futures contracts.

(m) Property, Plant and Equipment

Depreciation is computed using the straight-line and double-declining balance methods. Estimated useful lives are 20 to 25 years for plant, which includes buildings, storage tanks, and pipelines, and 3 to 20 years for equipment. All items of property, plant and equipment are carried at cost. Expenditures that increase capacity, or extend useful lives are capitalized. Routine repairs and maintenance are expensed as incurred.

We expense as incurred the costs related to the planning and preliminary project stage of our internal-use software and website development efforts. Direct costs incurred in the development stage are capitalized as property, plant and equipment and amortized over their estimated useful lives not to exceed five years as depreciation and amortization expense. The costs of installing certain enterprise-wide information systems are amortized over periods not exceeding 10 years. Costs associated with minor upgrades, enhancements and maintenance are expensed as incurred and included in selling, general and administrative expenses in the accompanying consolidated statement of operations.

We evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable based on expected undiscounted cash flows attributable to that asset. If an asset is impaired, the impairment loss to be recognized is the excess of the carrying amount of the asset over its estimated fair value.

(n) Deferred Debt Issuance Costs

Deferred debt issuance costs are amortized using the interest method over the term of the underlying debt instrument. Deferred debt issuance costs are as follows (in thousands):

	June 30, 2003		Additions		Amortization			June 30, 2004

Working capital credit facility	$	5,941	$	124	$	(2,296	)	$	3,769
Senior subordinated notes		6,967		820		(1,173	)		6,614

	$	12,908	$	944	$	(3,469	)	$	10,383

(o) Goodwill

Goodwill represents the excess of the aggregate purchase price over the fair value of the identifiable assets acquired. Pursuant to Statement of Financial Accounting Standards ("SFAS") No. 142, goodwill

and intangible assets acquired in a purchase business combination that have an indefinite useful life are not amortized, but instead tested for impairment in accordance with the provisions of SFAS No. 142. At June 30, 2004 and 2003, the carrying amount of goodwill was $6.9 million and $6.9 million, respectively, related to our November 1997 acquisition of the ITAPCO terminals. During the years ended June 30, 2004 and 2003, we performed an impairment review for goodwill during the three months ended June 30, and concluded that goodwill was not impaired.

(p) Environmental Obligations

We accrue for environmental costs that relate to existing conditions caused by past operations when estimable. Environmental costs include initial site surveys and environmental studies of potentially contaminated sites, costs for remediation and restoration of sites determined to be contaminated and ongoing monitoring costs, as well as fines, damages and other costs, including direct internal and legal costs. Liabilities for environmental costs at a specific site are initially recorded, on an undiscounted basis, when it is probable that we will be liable for such costs, and a reasonable estimate of the associated costs can be made based on available information. Such an estimate includes our share of the liability for each specific site and the sharing of the amounts related to each site that will not be paid by other potentially responsible parties, based on enacted laws and adopted/regulations and policies. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods. Estimates of our ultimate liabilities associated with environmental costs are particularly difficult to make with certainty due to the number of variables involved, including the early stage of investigation at certain sites, the lengthy time frames required to complete remediation, technology changes, alternatives available and the evolving nature of environmental laws and regulations. We periodically file claims for insurance recoveries of certain environmental remediation costs with our insurance carriers under our comprehensive liability policies. Due to the uncertainty of obtaining recoveries from our insurance carriers, we recognize our insurance recoveries as a credit to income in the period the insurance recoveries are received.

At June 30, 2004 and 2003, we have accrued environmental obligations of approximately $5.3 million and $5.6 million, respectively, representing our best estimate of our remediation obligations (see Note 9 of Notes to consolidated financial statements). During the years ended June 30, 2004 and 2003, we made payments of approximately $1.0 million and $0.4 million, respectively, towards our environmental remediation obligations. During the years ended June 30, 2004 and 2003, we charged to income approximately $0.7 million and $0.8 million, respectively, to increase our estimate of our future environmental remediation obligations. During the years ended June 30, 2004, 2003 and 2002, we received insurance recoveries of approximately $1.1 million, $0.2 million and $0.3 million, respectively.

(q) Income Taxes

We utilize the asset and liability method of accounting for income taxes. Under this 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 enacted tax rates expected to apply in the years in which these temporary differences are expected to be recovered or settled. Changes in tax rates are recognized in income in the period that includes the enactment date.

(r) Equity-Based Compensation Plans

We account for our employee stock option plans and restricted stock awards using the intrinsic value method pursuant to APB Opinion No. 25, Accounting for Stock Issued to Employees. We recognize deferred compensation on the date of grant if the quoted market price of the underlying common stock exceeds the exercise price (zero exercise price in the case of an award of restricted common stock). Accordingly, no compensation cost has been recognized for the granting of stock options to employees because the exercise price was equal to the quoted market price of the underlying common stock on the date of grant. If compensation cost for our stock-based compensation plans had been determined based on the fair value at the grant dates for awards under those plans pursuant to SFAS 123, Accounting for Stock-Based Compensation, our net earnings and earnings per common share would have been reduced to the pro forma amounts indicated below (in thousands, except for per share amounts):

			Years ended June 30,
			2004			2003			2002

Net earnings (loss) attributable to common stockholders:
	As reported		$	14,156		$	2,819		$	(2,793	)
	Amortization of the fair value of stock options granted to employees			(223	)		(379	)		(491	)

	Pro forma		$	13,933		$	2,440		$	(3,284	)

Earnings (loss) per common share
	As reported
		Basic	$	0.36		$	0.07		$	(0.09	)
		Diluted	$	0.36		$	0.07		$	(0.09	)
	Pro forma
		Basic	$	0.35		$	0.06		$	(0.11	)
		Diluted	$	0.36		$	0.06		$	(0.11	)

There were no options granted during the years ended June 30, 2004 and 2003. The weighted average fair value at grant dates for options granted during the year ended June 30, 2002, was $3.08. The primary assumptions used to estimate the fair value of options granted on the date of grant using the Black-Scholes option-pricing model during the year ended June 30, 2002, were as follows: no dividend yield, expected volatility of 79%, risk-free rates of 4.49%, and expected lives of 4 years.

Deferred compensation is amortized to income over the related vesting period on an accelerated basis pursuant to FASB Interpretation No. 28.

(s) Earnings (Loss) Per Common Share

In March 2004, the Emerging Issues Task Force ("EITF") reached a consensus on Issue No. 03-6, "Participating Securities and the Two-Class Method under FASB Statement No. 128, Earnings Per Share." EITF 03-6 provides guidance about how to determine whether a security should be considered a "participating" security for purposes of computing earnings per share and how earnings or losses should be allocated to a participating security when using the two-class method for computing basic earnings per share. The provisions of EITF 03-6 were effective for reporting periods beginning after March 31, 2004, and must be applied by recasting previously reported earnings per share amounts. We adopted the provisions of EITF 03-6 for all periods presented.

Our Series B Reedemable Convertible Preferred stock bears dividends at the rate of 6% per annum of the liquidation value. Dividends are cumulative and payable quarterly. In the event dividends are

declared on our common stock in excess of the dividends declared on the Series B Reedemable Convertible Preferred stock, the Series B Reedemable Convertible Preferred stock will participate as if the Series B Reedemable Convertible Preferred stock was converted to common stock. Accordingly, Series B Reedemable Convertible Preferred stock has been determined to be a "participating" security for purposes of computing earnings per share.

Basic earnings (loss) per common share is calculated based on the weighted average number of common shares outstanding during the period, excluding restricted common stock subject to continuing vesting requirements. Diluted earnings (loss) per share is calculated based on the weighted average number of common shares outstanding during the period and, when dilutive, potential common shares from the exercise of stock options and warrants to purchase common stock and restricted common stock subject to continuing vesting requirements pursuant to the treasury stock method. Diluted earnings (loss) per share also gives effect, when dilutive, to the conversion of the preferred stock pursuant to the if-converted method.

(t) Adoption of New Accounting Pronouncements

In June 2001, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 143, Accounting for Asset Retirement Obligations, which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for other than the carrying amount of the liability, a gain or loss is recognized on settlement. We adopted the provisions of SFAS No. 143 effective July 1, 2002. In connection with the adoption of SFAS No. 143, we reviewed current laws and regulations governing obligations for asset retirements. Based on that review we did not identify any significant legal obligations associated with the retirement of our tangible long-lived assets. Therefore, the adoption of SFAS No. 143 did not have an impact on our consolidated financial statements.

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity,which addresses the classification and measurement of certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 requires, among other things, a financial instrument issued in the form of shares that is mandatorily redeemable due to an unconditional obligation of the issuer to redeem the shares by transferring its assets at a specified date be classified as a liability on the balance sheet. We were required to adopt the provisions of SFAS No. 150 in our interim financial statements for the quarter ended September 30, 2003. The adoption of SFAS No. 150 did not have an impact on our consolidated financial statements. Pursuant to SFAS No. 150, our Series B Redeemable Convertible Preferred stock is not required to be presented as a liability in the accompanying consolidated balance sheet because holders of our Series B Redeemable Convertible Preferred stock have the right, at the holder's option, to convert the preferred shares into common shares.

(u) Reclassifications

Certain amounts in the prior years have been reclassified to conform to the current year's presentation. Net earnings and stockholders' equity have not been affected by these reclassifications.

(2) ACQUISITIONS

On October 1, 2003, we acquired for cash consideration of approximately $3.1 million a products terminal in Norfolk, Virginia. The terminal increases our presence in the Mid-Atlantic market and includes a docking facility that permits us to receive shipments off and deliver shipments to the water.

On February 28, 2003, we acquired all of the outstanding shares of capital stock of Coastal Fuels Marketing, Inc. and its subsidiary, Coastal Tug and Barge, Inc., from El Paso CGP Company ("CGP") along with the rights to and operations of the southeast marketing division of El Paso Merchant Energy Petroleum Company ("EPME-PC"). The acquisition included five Florida terminals, with aggregate capacity of approximately 4.9 million barrels, and a related tug and barge operation (collectively, the "Coastal Fuels assets"). The Coastal Fuels assets primarily provide sales and storage of bunker fuel, No. 6 oil, diesel fuel and gasoline at Cape Canaveral, Port Manatee/Tampa, Port Everglades/Ft. Lauderdale and Fisher Island/Miami, and storage of asphalt at Jacksonville, Florida. The adjusted purchase price for the acquisition was approximately $156.0 million, including approximately $37.0 million of product inventory. The consolidated financial statements include the results of operations of the Coastal Fuels assets from the closing date of the transaction (February 28, 2003).

On January 31, 2003, we acquired for cash consideration of approximately $6.4 million a products terminal in Fairfax, Virginia. The terminal supplies product to the Washington, D.C. market and increases our presence in the Mid-Atlantic market.

On July 31, 2002, we acquired for cash consideration of approximately $0.6 million a products terminal in Brownsville, Texas. The terminal provides us with additional storage and rail car handling facilities in Brownsville, Texas.

The purchase price of each transaction was allocated to the assets and liabilities acquired based upon the estimated fair value of the assets and liabilities as of the acquisition date. The purchase price was allocated as follows (in thousands):

		Norfolk			Coastal Fuels			Fairfax			Brownsville

Discretionary inventory volumes		$	698		$	30,625		$	—		$	—
Prepaid expenses and other current assets			—			2,259			—			—
Property, plant and equipment			1,906			118,787			6,773			630
Other assets—acquired intangible			—			2,500			—			—
Product linefill and tank bottom volumes			859			6,311			—			—
Trade accounts payable—due diligence costs			—			(1,350	)		—			—
Acquisition related liabilities			(393	)		(3,164	)		(420	)		—

	Cash paid, net of cash acquired of $0, $0, $0 and $85, respectively	$	3,070		$	155,968		$	6,353		$	630

Norfolk acquisition related liabilities include approximately $0.4 million of estimated environmental remediation costs. Coastal Fuels acquisition related liabilities of approximately $3.2 million represent an estimate of the fair value of certain assumed obligations that existed at the date of the Coastal Fuels assets acquisition, including estimated environmental remediation costs of approximately $2.5 million, estimated litigation costs of approximately $0.4 million, lease abandonment costs of

approximately $130,000 and property taxes of approximately $140,000. Fairfax acquisition related liabilities include approximately $0.4 million of estimated environmental remediation costs.

(3) DISPOSITIONS

On December 30, 2003, we sold our CETEX pipeline system for approximately $0.4 million, resulting in a loss on disposition of assets of approximately $0.7 million. For the six months ended December 31, 2003, we recognized net revenues of approximately $0.4 million, direct operating costs and expenses of approximately $0.3 million, and depreciation and amortization expense of approximately $34,000 related to the operations of the CETEX pipeline system. For the years ended June 30, 2003 and 2002, we recognized net revenues of approximately $0.5 million and $0.6 million, direct operating costs and expenses of approximately $0.7 million and $0.7 million, and depreciation and amortization of approximately $0.1 million and $0.1 million, respectively, related to the operations of the CETEX pipeline system.

On May 31, 2002, our investment in ST Oil Company was reacquired by ST Oil Company for cash consideration of approximately $3.0 million, resulting in a net gain of approximately $1.4 million on the sale. For the year ended June 30, 2002, we recorded equity in earnings from our investment in ST Oil Company of less than $0.1 million.

On July 27, 2001, we sold a portion of our investment in the common stock of West Shore Pipeline Company ("West Shore") for cash consideration of approximately $2.9 million. We recognized a net loss of approximately $1.1 million on this sale. We also recognized an impairment loss on our remaining investment in West Shore of approximately $8.8 million. On October 29, 2001, we sold our remaining investment in West Shore for cash consideration of approximately $23.1 million, which approximated our adjusted cost basis. For the year ended June 30, 2002, we recognized $0.7 million of dividend income from West Shore.

On July 31, 2001, we sold the NORCO Pipeline system and related terminals ("NORCO") for cash consideration of approximately $62.0 million and recognized a net gain of approximately $8.6 million on the sale. For the month ended July 31, 2001, we recognized net revenues of approximately $1.3 million, direct operating costs and expenses of approximately $0.6 million, and depreciation and amortization expense of approximately $0.3 million related to the operations of the NORCO system.

Effective June 30, 2001, we sold two petroleum distribution facilities in Little Rock, Arkansas. The cash proceeds of approximately $29.0 million from the sale transaction were received on July 3, 2001.

(4) CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE

Our primary market areas are located in the Northeast, Midwest and Southeast regions of the United States. We have a concentration of trade receivable balances due from major integrated oil companies, independent oil companies, other wholesalers, waste management companies, cruise-ship operators and transportation companies. These concentrations of customers may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. Our customers' historical and future credit positions are analyzed prior to extending credit. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions we may request letters of credit, prepayments or guarantees. We maintain allowances for potentially uncollectible accounts receivable. During the years ended June 30, 2004, 2003 and 2002, we increased the allowance for doubtful accounts through a charge to income of approximately $0.1 million, $0.7 million and $0.2 million, respectively.

Trade accounts receivable, net consists of the following (in thousands):

	June 30, 2004			June 30, 2003

Trade accounts receivable	$	282,889		$	291,929
Less allowance for doubtful accounts		(591	)		(1,922	)

	$	282,298		$	290,007

No single customer accounted for 10% or more of total revenues for the years ended June 30, 2004, 2003 or 2002.

(5) UNREALIZED GAINS AND LOSSES ON DERIVATIVE CONTRACTS

Unrealized gains and losses on derivative contracts are as follows (in thousands):

			June 30, 2004			June 30, 2003

Unrealized gains—current			$	11,071		$	16,817
Unrealized gains—long-term				—			1,885

	Unrealized gains—asset			11,071			18,702

Unrealized losses—current				(33,689	)		(20,151	)
Unrealized losses—long-term				(909	)		(423	)

	Unrealized losses—liability			(34,598	)		(20,574	)

		Net liability position	$	(23,527	)	$	(1,872	)

At June 30, 2004 and 2003, there were no unrealized gains or losses on risk management contracts because NYMEX futures contracts require daily settlement for changes in commodity prices on open futures contracts.

(6) PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment, net is as follows (in thousands):

	June 30, 2004			June 30, 2003

Land	$	42,886		$	46,477
Terminals, pipelines and equipment		378,258			365,379
Technology and equipment		14,586			13,426
Tugs and barges		18,790			15,914
Furniture, fixtures and equipment		6,747			6,539
Construction in progress		2,561			4,125

		463,828			451,860
Less accumulated depreciation		(101,563	)		(80,125	)

	$	362,265		$	371,735

(7) INVESTMENT IN PETROLEUM RELATED ASSETS

We own 18.04% of the common stock of Lion Oil Company ("Lion"), an Arkansas-based refinery. For financial reporting purposes, we carry our investment in Lion at the lower of cost or net realizable value. At June 30, 2004 and 2003, the carrying amount of our investment in Lion is approximately $10.1 million. For the years ended June 30, 2004, 2003, and 2002, we recognized dividend income from Lion of approximately $nil, $0.4 million, and $0.7 million, respectively.

(8) OTHER ASSETS

Other assets are as follows (in thousands):

	June 30, 2004		June 30, 2003

Prepaid transportation	$	862	$	3,021
Goodwill		6,853		6,853
Acquired intangible, net of accumulated amortization of $667 and $167, respectively		1,833		2,333
Commodity trading membership		1,500		1,500
Deposits and other assets		158		63

	$	11,206	$	13,770

Prepaid transportation relates to our contractual transportation and deficiency agreements with three interstate product pipelines (see Note 17 of Notes to consolidated financial statements).

Acquired intangible represents the right to use the Coastal Fuels trade name for a period of five years. The cost of the acquired intangible is being amortized on a straight-line basis over five years.

Commodity trading membership represents the purchase price we paid to acquire two seats on the NYMEX.

(9) OTHER ACCRUED LIABILITIES

Other accrued liabilities are as follows (in thousands):

	June 30, 2004		June 30, 2003

Accrued environmental obligations	$	5,278	$	5,577
Accrued lease abandonment		2,468		3,178
Accrued indemnities—NORCO		1,300		1,300
Accrued transportation and deficiency obligations		921		2,013
Accrued property taxes		2,013		1,876
Assumed litigation costs—Coastal Fuels assets		400		2,900
Dividend payable—preferred stock		1,093		1,093
Interest payable		1,903		1,788
Accrued expenses and other		4,038		5,837

	$	19,414	$	25,562

Accrued Lease Abandonment. We vacated certain office space in Denver, Colorado during June 2003 and we vacated our excess space in Atlanta, Georgia during October 2002. In connection with our acquisition of the Coastal Fuels assets, we vacated a sales office in Coral Gables, Florida (see Note 2

of Notes to consolidated financial statements). The accrual for the abandonment of the office leases represents the excess of the remaining lease payments subsequent to vacancy of the space by us over the estimated sublease rentals to be received based on current market conditions. At June 30, 2004 and 2003, the accrued liability for lease abandonment costs was approximately $2.5 million and $3.2 million, respectively.

(in thousands)	Accrued liability at June 30, 2003		Change in estimate charged to expense		Amounts paid during the period			Accrued liability at June 30, 2004

Accrued lease abandonment	$	3,178	$	234	$	(944	)	$	2,468

We expect to pay the accrued liability of approximately $2.5 million, net of estimated sublease rentals, as follows (in thousands):

Years ending June 30:	Lease payments		Estimated sublease rentals			Accrued liability

2005	$	1,287	$	(305	)	$	982
2006		1,108		(567	)		541
2007		928		(472	)		456
2008		370		(209	)		161
2009		378		(215	)		163
Thereafter		385		(220	)		165

	$	4,456	$	(1,988	)	$	2,468

Accrued indemnities—NORCO. In connection with our sale of the NORCO system on July 31, 2001, we accrued approximately $1.3 million for the estimated costs that we expect to incur in connection with satisfying certain covenants and undertakings set forth in the sales agreement.

Assumed litigation costs—Coastal Fuels assets. During the year ended June 30, 2004, we concluded our analysis regarding the estimated fair value of the expected litigation costs we assumed in connection with our acquisition of the Coastal Fuels assets. As a result, we reduced the amount recorded for accrued litigation costs by approximately $2.5 million through a reduction of the purchase price allocated to property, plant and equipment (see Note 2 of Notes to consolidated financial statements).

(10) DEFERRED REVENUE—SUPPLY CHAIN MANAGEMENT SERVICES

In connection with providing delivered fuel price management to ground fleet customers, we commit to provide our customers with logistical supply chain management services over the term of their respective supply contracts. At June 30, 2004 and 2003, our deferred revenue associated with logistical supply chain management contracts entered into prior to April 1, 2002, was approximately $0.4 million and $1.0 million, respectively. We amortize the deferred revenue from these contracts into revenues attributable to our supply, distribution, and marketing operations over the respective terms of the contracts as the products are delivered to the ground fleet customers. During the years ended June 30, 2004 and 2003, we recognized approximately $600,000 and $600,000, respectively, in revenues attributable to our supply, distribution and marketing operations from the amortization of these contracts.

We enter into price management contracts with ground fleet customers that permit these customers to fix the price of their fuel purchases. During the years ended June 30, 2004 and 2003, we originated retail price management contracts with estimated fair values of approximately $1.5 million and $2.9 million, respectively, and delivered fuel price management contracts with estimated fair values of approximately $2.1 million and $2.8 million, respectively, representing the excess of the amounts we expect to receive from the ground fleet customers over our estimate of the forward price curve of the underlying commodity adjusted for basis differentials. We have deferred the estimated fair value of these contracts at origination because our estimate of the fair value is not evidenced by quoted market prices or current market transactions for the contracts in their entirety. We amortize the deferred revenue from these contracts into revenues attributable to our supply, distribution, and marketing operations over the respective terms of the contracts as the products are delivered to the ground fleet customers. During the years ended June 30, 2004 and 2003, we recognized approximately $4.4 million and $1.9 million, respectively, in revenues attributable to our supply, distribution and marketing operations from the amortization of the deferred revenue from these contracts.

(in thousands)	Deferred revenue at June 30, 2003		Additions during the period		Amounts amortized during the period			Deferred revenue at June 30, 2004

Logistical supply chain management services	$	1,000	$	—	$	(600	)	$	400
Retail price management contracts		2,047		1,544		(2,259	)		1,332
Delivered fuel price management contracts		1,769		2,125		(2,124	)		1,770

	$	4,816	$	3,669	$	(4,983	)	$	3,502

(11) DEBT

Debt is as follows (in thousands):

	June 30, 2004			June 30, 2003

Commodity margin loan	$	1,923		$	4,534
Working capital credit facility		110,000			175,000
Senior subordinated notes		200,000			200,000

		311,923			379,534
Less debt classified as current		(111,923	)		(179,534	)

Long-term debt	$	200,000		$	200,000

Commodity Margin Loan. We currently have a commodity margin loan agreement with a commodity broker that allows us to borrow up to $20.0 million to fund certain initial and variation margin requirements in commodities accounts maintained by us with the commodity broker. The entire unpaid principal amount of the loan, together with accrued interest, is due and payable on demand. Outstanding loans bear interest at the average 90-day Treasury Bill rate plus 1.75% (3.08% at June 30, 2004).

Working Capital Credit Agreement. On February 28, 2003, we executed a Credit Agreement with UBS AG that initially provided for a $250 million revolving line of credit ("Working Capital Credit Facility") and a $200 million senior secured term loan ("Term Loan"). The former Working Capital Credit Facility provided for a maximum borrowing line of credit that was the lesser of (i) $275 million

and (ii) the borrowing base (as defined; $364 million at June 30, 2004). The maximum borrowing amount was reduced by the amount of letters of credit that are outstanding ($38.6 million at June 30, 2004). Borrowings under the former Working Capital Credit Facility bore interest (at our option) based on a base rate plus a specified margin, or LIBOR plus a specified margin; the specified margins were a function of our leverage ratio (as defined). Accrued interest on the outstanding borrowings was due monthly. The weighted average interest rate on borrowings under the former Working Capital Credit Facility was 3.9% during the year ended June 30, 2004. Borrowings under the former Working Capital Credit Facility were secured by substantially all of our current assets. The terms of the former Working Capital Credit Facility included financial covenants relating to fixed charge coverage, current ratio, consolidated tangible net worth, capital expenditures, cash distributions and open inventory positions that were tested on a quarterly and annual basis. As of June 30, 2004, we were in compliance with all covenants included in the former Working Capital Credit Facility. In the accompanying consolidated balance sheet at June 30, 2004, we have classified the outstanding borrowings under the former Working Capital Credit Facility as a current liability because we have pledged our current assets as security for the facility. On September 13, 2004, we repaid all outstanding borrowings under the former Working Capital Credit Facility with proceeds from our new $400 million Senior Secured Working Capital Credit Facility.

Senior Secured Working Capital Credit Agreement. On September 13, 2004, we entered into a new $400 million Senior Secured Working Capital Credit Facility. The Senior Secured Working Capital Credit Facility provides for a maximum borrowing line of credit equal to the lesser of (i) $400 million and (ii) the borrowing base, which is a function, among other things, of our cash, accounts receivable, refined petroleum product inventory, exchanges, margin deposits and open positions of derivative contracts. The borrowing base is also subject to reduction for certain reserves and, until certain fixed assets satisfying the requirements of the Senior Secured Working Capital Credit Facility have been granted as security for our obligations, the borrowing base will be subject to a further reduction of $50 million. In addition, outstanding letters of credit are counted against the maximum borrowing capacity available at any time. Borrowings under the Senior Secured Working Capital Credit Facility bear interest (at our option) based on a base rate plus an applicable margin, or LIBOR plus an applicable margin; the applicable margins are a function of the average excess borrowing base availability (as defined). Interest on loans under the Senior Secured Working Capital Credit Facility will be due and payable periodically, based on the applicable interest rate and related interest period, generally each one, two or three months. In addition, we will pay a commitment fee ranging from 0.25% to 0.50% per annum on the total amount of the unused commitments. Borrowings under the Senior Secured Working Capital Credit Facility are secured by our cash, accounts receivable, refined petroleum product inventory and, upon the satisfaction of certain conditions, a portion of our real estate and fixed assets, among other things. The only financial covenant contained in the new Senior Secured Working Capital Credit Facility is a minimum fixed charge coverage ratio test that is tested on a quarterly basis whenever the average minimum unused credit line falls below $75 million for the last month of any quarter. In that event, we must satisfy a minimum fixed charge coverage ratio requirement of 110%. The principal balance of loans and any accrued and unpaid interest will be due and payable in full on the maturity date, September 13, 2009.

Senior Subordinated Notes. On May 30, 2003, we consummated the sale and issuance of $200 million aggregate principal amount of 9¹/8% Senior Subordinated Notes due 2010 and received proceeds of $194.5 million (net of underwriters' discounts of $5.5 million). The Senior Subordinated Notes mature on June 1, 2010 and interest is payable semi-annually in arrears on each June 1 and December 1 commencing on December 1, 2003. The Senior Subordinated Notes are unsecured and subordinated to all of our existing and future senior debt. Upon certain change of control events, each

holder of the Senior Subordinated Notes may require us to repurchase all or a portion of its notes at a purchase price equal to 101% of the principal amount thereof, plus accrued interest. The indenture governing the Senior Subordinated Notes contains covenants that, among other things, limit our ability to incur additional indebtedness, pay dividends on, redeem or repurchase our common stock, make investments, make certain dispositions of assets, engage in transactions with affiliates, create certain liens, and consolidate, merge, or transfer all or substantially all of our assets. The Senior Subordinated Notes are fully and unconditionally guaranteed on a joint and several basis by our subsidiaries other than minor subsidiaries that are inactive and have no assets or operations.

We are a holding company for our subsidiaries, with no independent assets or operations. Accordingly, we are dependent upon the distribution of the earnings of our subsidiaries, whether in the form of dividends, advances or payments on account of inter-company obligations, to service our debt obligations. There are no restrictions on our ability or any subsidiary guarantor to obtain funds from our subsidiaries.

Scheduled maturities of debt at June 30, 2004 are as follows (in thousands):

Years ending:

June 30, 2005	$	1,923
June 30, 2006		110,000
June 30, 2007		—
June 30, 2008		—
June 30, 2009		—
Thereafter		200,000

	$	311,923

(12) PREFERRED STOCK

At June 30, 2004 and 2003, we have authorized the issuance of up to 2,000,000 shares of preferred stock. Preferred stock outstanding is as follows (in thousands, except share data):

	June 30, 2004		June 30, 2003

Series B Redeemable Convertible Preferred stock, par value $0.01 per share, 100,000 shares authorized, 72,890 shares issued and outstanding, liquidation preference of $72,890	$	77,719	$	79,329

At June 30, 2004 and 2003, there are 72,890 shares of Series B Redeemable Convertible Preferred Stock outstanding. The Series B Redeemable Convertible Preferred Stock has a liquidation value of $1,000 per share, bears dividends at the rate of 6% per annum of the liquidation value, and is mandatorily redeemable between June 30, 2007 and December 31, 2007 for shares of common stock and/or cash at our option, subject to limitations on the total number of common shares permitted to be used in the exchange and issued to any shareholder. Dividends are cumulative and payable quarterly. The dividends are payable in cash, unless precluded by contract or by restrictions under the Senior Secured Working Capital Credit Facility, in which case dividends are payable in additional shares of Series B Redeemable Convertible Preferred Stock. The Series B Redeemable Convertible Preferred Stock may be put to us, at the option of the holder, for cash equal to the greater of its liquidation value or conversion value upon the future occurrence of a fundamental change (including those relating to sale of substantially of the assets, delisting of our common stock from a national exchange, change in control, bankruptcy filing, and an event of default that accelerates the repayment

of our debt). We may call the outstanding shares of Series B Redeemable Convertible Preferred Stock after June 30, 2005 if certain specified conditions are met. The Series B Redeemable Convertible Preferred Stock is convertible, at the option of the holder, into common stock at $6.60 per share, subject to adjustment upon the occurrence of specified future events. The holders of the Series B Redeemable Convertible Preferred Stock have the right to vote on all matters (except the election of directors) with the holders of the common stock (voting collectively as a single class).

On June 28, 2002, we consummated an agreement with the holders of the Series A Convertible Preferred stock (the "Preferred Stock Recapitalization Agreement") to redeem a portion of the outstanding Series A Convertible Preferred stock and warrants in exchange for cash, shares of common stock, and shares of the Series B Redeemable Convertible Preferred Stock. The Preferred Stock Recapitalization Agreement resulted in the redemption of 157,715 shares of Series A Convertible Preferred stock and warrants to purchase 9,841,493 shares of common stock in exchange for the (i) issuance of 72,890 shares of Series B Redeemable Convertible Preferred Stock with a fair value of approximately $80.9 million, (ii) issuance of 11,902,705 shares of common stock with a fair value of approximately $59.5 million, and (iii) a cash payment of approximately $21.3 million. The initial carrying amount of the Series B Redeemable Convertible Preferred Stock of approximately $80.9 million will be decreased ratably over its 5-year term until it equals its liquidation value of approximately $72.9 million with an equal reduction in the amount of preferred stock dividends recorded for financial reporting purposes. The fair value of the consideration paid to the holders of the Series A Convertible Preferred Stock and warrants exceeded their financial statement carrying amount by approximately $1.5 million, which has been treated in a manner similar to preferred stock dividends in the accompanying consolidated financial statements.

On June 30, 2003, we redeemed the remaining outstanding shares of Series A Convertible Preferred stock and warrants for approximately $24.4 million in cash.

Preferred stock dividends on the Series A Convertible Preferred stock were $nil, $1.2 million, and $11.4 million for the years ended June 30, 2004, 2003 and 2002, respectively. Preferred Stock dividends on the Series B Redeemable Convertible Preferred Stock were $2.8 million for each of the years ended June 30, 2004 and 2003. The amount of the Series B Redeemable Convertible Preferred Stock dividend recognized for financial reporting purposes is composed of the amount of the dividend payable and paid to the holders of the Series B Redeemable Convertible Preferred Stock of $4.4 million offset by the amortization of the premium on the carrying amount of the Series B Redeemable Convertible Preferred Stock of $1.6 million.

(13) COMMON STOCK

At June 30, 2004, we were authorized to issue up to 150,000,000 shares of common stock with a par value of $0.01 per share. At June 30, 2004 and 2003, there were 41,114,494 shares and 40,685,690 shares issued and outstanding, respectively. Our Senior Secured Working Capital Credit Facility, Senior Subordinated Notes and the certificate of designation of our Series B Redeemable Convertible Preferred stock contain restrictions on the payment of dividends on our common stock.

We have a restricted stock plan that provides for awards of common stock to certain employees, subject to forfeiture if employment terminates prior to the vesting dates. Upon a change in control, all unvested shares become immediately vested shares. At the date of grant, the market value of shares awarded under the plan is recorded in common stockholders' equity as deferred stock-based

compensation. Information about restricted common stock activity for the years ended June 30, 2004, 2003 and 2002 is as follows:

	Total shares		Vested shares		Unvested shares

Outstanding at June 30, 2001	778,959		90,549		688,410
Granted	420,500		—		420,500
Cancelled	(104,170	)	—		(104,170	)
Repurchased	(20,573	)	(20,573	)	—
Vested	—		90,772		(90,772	)

Outstanding at June 30, 2002	1,074,716		160,748		913,968
Granted	840,500		—		840,500
Cancelled	(51,080	)	—		(51,080	)
Repurchased	(49,437	)	(49,437	)	—
Vested	—		187,209		(187,209	)

Outstanding at June 30, 2003	1,814,699		298,520		1,516,179
Granted	536,000		—		536,000
Cancelled	(71,095	)	—		(71,095	)
Repurchased	(101,601	)	(101,601	)	—
Vested	—		356,876		(356,876	)

Outstanding at June 30, 2004	2,178,003		553,795		1,624,208

During the years ended June 30, 2004, 2003 and 2002, we recognized deferred-stock based compensation associated with restricted common stock granted to employees of approximately $3.2 million, $3.6 million, and $2.1 million, respectively, which is being amortized to income over their respective four-year vesting period.

Amortization of deferred compensation of approximately $2.7 million, $2.2 million and $1.5 million is included in selling, general and administrative expense for the years ended June 30, 2004, 2003 and 2002, respectively.

(14) STOCK OPTIONS

We had three stock option plans (the "1991 Plan", the "1995 Plan" and the "1997 Plan") under which stock options had been granted to employees. The 1991 Plan and the 1995 Plan have been terminated as all previously granted stock options have been exercised or cancelled. There were no options granted during the years ended June 30, 2004 and 2003. Options previously granted under the 1997 Plan expire no later than ten years from the date of grant. Options granted under the 1997 Plan vest 100% upon a change in control or, alternatively, 10% after the end of the first year, 20% after the end of the second year, 30% after the end of the third year, and 40% after the end of the fourth year.

Information about stock option activity for the years ended June 30, 2004, 2003 and 2002, is as follows:

	Terminated Plans			1997 Plan
	Shares		Weighted average exercise price	Shares		Weighted average exercise price

Outstanding at June 30, 2001	298,450		5.28	1,168,830		4.81
Granted	—		—	75,000		5.05
Cancelled	(35,000	)	5.50	(174,050	)	6.68
Exercised	(33,000	)	3.50	(7,000	)	5.13

Outstanding at June 30, 2002	230,450		5.50	1,062,780		4.52
Granted	—		—	—		—
Cancelled	(230,450	)	5.50	(55,080	)	4.69
Exercised	—		—	(3,200	)	3.75

Outstanding at June 30, 2003	—		—	1,004,500		4.51
Granted	—		—	—		—
Cancelled	—		—	(53,500	)	4.73
Exercised	—		—	(65,500	)	4.85

Outstanding at June 30, 2004	—		—	885,500		4.48

Exercisable at June 30, 2004	—		—	608,000		4.69

Information about stock options outstanding at June 30, 2004 is as follows:

					Options exercisable
	Range of exercise prices	Number outstanding	Weighted average remaining life in years	Weighted average exercise prices	Number exercisable	Weighted average exercise prices

1997 Plan	3.75 - 7.25	873,000	6.6	4.37	595,500	4.54
	11.00 - 13.50	11,500	4.5	11.65	11,500	11.65
	17.25	1,000	3.2	17.25	1,000	17.25

		885,500			608,000

(15) EMPLOYEE BENEFIT PLAN

We have a 401(k) retirement savings plan for all employees. The plan allows participants to contribute a percentage of their compensation ranging from 1% to a maximum of 15%, subject to the maximum salary deferral allowed by the Internal Revenue Service. Employees vest 25% per year in our discretionary contributions, as determined by management based upon our financial performance. Our discretionary contributions for the years ended June 30, 2004, 2003 and 2002, were approximately $0.8 million, $0.6 million and $0.5 million, respectively.

(16) INCOME TAXES

Total income tax expense (benefit) consists of the following (in thousands):

		Years ended June 30,
		2004		2003			2002

Continuing operations		$	12,060	$	8,510		$	5,465
Cumulative effect of a change in accounting principle			—		(795	)		—

	Total income tax expense	$	12,060	$	7,715		$	5,465

Income tax expense (benefit) from continuing operations consists of the following (in thousands):

				Years ended June 30,
				2004			2003		2002

Current:
	Federal income taxes			$	—		$	—	$	(240	)
	State income taxes				(28	)		315		643

		Current income taxes			(28	)		315		403

Deferred:
	Federal income taxes				11,138			7,805		4,483
	State income taxes				950			390		579

		Deferred income taxes			12,088			8,195		5,062

			Income tax expense	$	12,060		$	8,510	$	5,465

Income tax expense differs from the amount computed by applying the federal corporate income tax rate of 35% to pretax earnings as a result of the following (in thousands):

		Years ended June 30,
		2004		2003		2002

Computed "expected" tax expense		$	10,706	$	5,814	$	4,908
Increase (reduction) in income taxes resulting from:
	Change in prior years' estimates		660		1,700		(273	)
	State income taxes, net of federal income tax benefit		572		452		387
	Other, net		122		544		443

	Income tax expense	$	12,060	$	8,510	$	5,465

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are as follows (in thousands):

			June 30, 2004			June 30, 2003

Deferred tax assets:
	Net operating loss and tax credit carry forwards		$	32,923		$	31,354
	Allowance for doubtful accounts			226			220
	Accrual for lease abandonment, corporate relocation and transition plan			938			1,243
	Other non-deductible accruals			763			3,881
	Intangible assets, principally due to differences in amortization methods and impairment allowances			4,459			4,937
	Deferred compensation			1,410			1,444
	Inventories—discretionary and minimum volumes, principally due to differences in accounting methods			8,224			8,652
	Accrued environmental obligations			2,006			2,120
	Other intangibles			169			—

		Deferred tax assets		51,118			53,851

Deferred tax liabilities:
	Plant and equipment, principally due to differences in depreciation methods and impairment allowances			(68,381	)		(58,481	)
	Deferred revenue—supply chain management services			(295	)		(737	)
	Investments in affiliated companies, principally due to undistributed earnings			(1,004	)		(1,004	)

		Deferred tax liabilities		(69,680	)		(60,222	)

		Net deferred tax liabilities	$	(18,562	)	$	(6,371	)

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment.

Based upon projections of future taxable income including the expected timing of the reversal of taxable temporary differences over the periods in which the deferred tax assets are deductible, management believes the "more likely than not" criterion has been satisfied as of June 30, 2004 and 2003, and that the benefits of future deductible differences will be realized.

At June 30, 2004, we have net operating loss carry forwards for federal income tax purposes of approximately $86.5 million which are available to offset future federal taxable income, if any, through 2024. The amount and expiration date of the net operating loss carry forwards for federal income tax purposes are as follows: $2.3 million—2018, $27.9 million—2019, $39.5 million—2020, $14.0 million—2021, $2.3 million—2023, and $0.5 million—2024.

(17) COMMITMENTS AND CONTINGENCIES

Transportation and Deficiency Agreements. In connection with our sale of two product distribution facilities in Little Rock, Arkansas, we are potentially liable for payments of up to $725,000 per year for a five-year period through June 30, 2006. The potential liability for each year is based on the

actual throughput volumes of the facility for each year as compared to the contractual thresholds of 20,000 and 32,500 barrels per day ("BPD"). If actual volumes exceed 32,500 BPD, we will not be obligated to pay any of the $725,000 for that given year. If actual volumes are between 20,000 and 32,500 BPD, we will be obligated to pay a prorated portion of the $725,000 for that given year. If actual volumes are less than 20,000 BPD, we are obligated to pay the entire $725,000 for that given year. At June 30, 2003, we recognized an accrued liability of approximately $0.8 million representing our estimate of the future amounts we expect to pay for the shortfall in our actual volumes and our estimated shortfall in volumes for the remainder of the term of the agreement. During the year ended June 30, 2004, we paid approximately $0.2 million as settlement for our shortfall in volumes for the year ended June 30, 2003. Based on actual throughput volumes for the year ended June 30, 2004, we decreased our accrued liability by $0.2 million resulting in a remaining accrued liability of $0.4 million at June 30, 2004.

We also are subject to three transportation and deficiency agreements ("T&D's") with three separate interstate pipeline companies. Each agreement calls for guaranteed minimum shipping volumes over the term of the agreements. If actual volumes shipped are less than the guaranteed minimum volumes, we must make payment to the interstate pipeline company for any shortfall at the contracted pipeline tariff. Such payments are accounted for as prepaid transportation, since we have a contractual timeframe, after the end of the term of the T&D, to apply the amounts to charges for using the interstate pipeline in the future. We monitor the actual volumes shipped against our obligations to determine if the T&D payments made will ultimately be recovered. In order to do this, we have to estimate our future shipping volumes. At June 30, 2003, we recognized an accrued liability of approximately $1.2 million representing our estimate of the future amounts we expect to pay for our estimated shortfall in volumes for the remainder of the term of the agreements. During the year ended June 30, 2004, we paid approximately $0.3 million pursuant to the T&D agreements because our actual volumes shipped during the year were less than the guaranteed minimum volumes for the year and we recognized a reduction in our accrued liability of approximately $0.4 million representing a change in our estimate of the future amounts we expect to pay for the estimated shortfall in volumes for the remainder of the terms of the T&D agreements resulting in a remaining accrued liability of $0.5 million at June 30, 2004.

At June 30, 2004 and 2003, we included approximately $0.9 million and $3.0 million, respectively, of prepaid transportation in other assets since we have a contractual right, after the end of the term of the T&D agreements, to apply the amounts to charges for using the interstate pipelines in the future (see Note 8 of Notes to consolidated financial statements). During the year ended June 30, 2004, we applied approximately $2.2 million of our prepaid transportation to charges for using the interstate pipelines during the year.

(in thousands)	June 30, 2003			Payments during the period		Amounts applied during the period			Change in estimate during the period		June 30, 2004

Other assets—prepaid transportation	$	3,021		$	—	$	(2,159	)	$	—	$	862

Accrued liability—T&D obligations	$	(2,013	)	$	544	$	—		$	548	$	(921	)

Operating Leases. On April 19, 2002, we executed a 10-year non-cancelable operating lease for new office space to accommodate our corporate headquarters. The lease commenced on October 1, 2002 and July 1, 2003 with respect to approximately one-half of the total leased square footage, respectively. We also lease office space in Atlanta, Georgia, vessel charters, pipeline and terminal

capacity, and property and equipment under non-cancelable operating leases that expire through June 2012. At June 30, 2004, future minimum lease payments under these non-cancelable operating leases are as follows (in thousands):

Years ending June 30:	Office space		Vessel charters		Terminal and pipeline capacity		Property and equipment

2005	$	1,516	$	7,978	$	4,135	$	284
2006		1,530		—		2,133		189
2007		1,576		—		1,511		116
2008		1,535		—		1,082		47
2009		1,516		—		117		—
Thereafter		3,963		—		88		—

	$	11,636	$	7,978	$	9,066	$	636

Rental expense under operating leases is as follows (in thousands):

	Years ended June 30,
	2004		2003		2002

Office space	$	2,106	$	1,724	$	1,771
Vessel charters		29,873		5,867		—
Terminal and pipeline capacity		13,645		7,331		2,316
Property and equipment		559		764		735

	$	46,183	$	15,686	$	4,822

(18) LITIGATION

We have been named as a defendant in various lawsuits and we are a party to various other legal proceedings, in the ordinary course of business, some of which are covered in whole or in part by insurance. We believe that the outcome of such lawsuits and other proceedings will not individually or in the aggregate have a material adverse effect on our consolidated financial condition, results of operations or cash flows. For the years ended June 30, 2004, 2003 and 2002, we incurred outside third-party legal and settlement expenses of approximately $0.8 million, $1.6 million and $0.7 million, respectively, that are included in selling, general and administrative expenses in the accompanying consolidated statement of operations.

(19) EARNINGS PER SHARE

The following tables reconcile the computation of basic EPS and diluted EPS (in thousands, except per share amounts).

		Years ended June 30,
		2004			2003			2002

Net earnings before cumulative effect of a change in accounting principle		$	18,529		$	8,100		$	8,558
Earnings allocable to preferred stock			(4,373	)		(3,984	)		(11,351	)
Cumulative effect of a change in accounting principle			—			(1,297	)		—

Net earnings (loss) attributable to common stockholders		$	14,156		$	2,819		$	(2,793	)

Basic weighted average shares			39,355			39,116			31,267
Effect of dilutive securities:
	Restricted common stock subject to continuing vesting requirements		333			22			—
	Stock options		276			125			—
	Series B Redeemable Convertible Preferred stock		11,044			—			—

Diluted weighted average shares			51,008			39,263			31,267

Earnings (loss) per share:
	Basic	$	0.36		$	0.07		$	(0.09	)

	Diluted	$	0.36		$	0.07		$	(0.09	)

We exclude potentially dilutive securities from our computation of diluted earnings per share when their effect would be anti-dilutive. The following securities were excluded from the earnings per share computation, as their inclusion would have been anti-dilutive:

		June 30, 2004	June 30, 2003	June 30, 2002

Restricted common stock subject to continuing vesting requirements		—	693,179	913,968
Common stock issuable upon exercise of stock options		62,500	397,500	1,293,230
Common stock issuable upon exercise of stock purchase warrants		—	—	900,045
Common stock issuable upon conversion of:
	Series A Convertible Preferred Stock	—	—	1,628,083
	Series B Redeemable Convertible Preferred Stock	—	11,043,939	11,043,939

		62,500	12,134,618	15,779,265

For the year ended June 30, 2004, certain stock options were excluded because their exercise prices exceeded the average quoted market price of our common stock during the period. For the year ended June 30, 2004, the excluded stock options had a weighted average exercise price of $8.22 per share.

(20) DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS

The following methods and assumptions were used to estimate the fair value of financial instruments at June 30, 2004 and 2003.

Cash and Cash Equivalents, Trade Receivables and Trade Accounts Payable. The carrying amount approximates fair value because of the short-term maturity of these instruments.

Debt. The carrying values of the commodity margin loan and bank credit facility approximate fair value since they bear interest at current market interest rates. The fair value of the Senior Subordinated Notes was approximately $206 million based on quoted market prices.

(21) BUSINESS SEGMENTS

We provide integrated terminal, transportation, storage, supply, distribution and marketing services to refiners, wholesalers, distributors, marketers, and industrial and commercial end-users of refined petroleum products. We conduct business in the following business segments:

–>: Terminals, pipelines, and tugs and barges—consists of an extensive terminal and pipeline infrastructure that handles refined petroleum products with transportation connections via pipelines, barges, vessels, rail cars and trucks to our facilities or to third-party facilities with an emphasis on transportation connections primarily through the Colonial, Plantation, TEPPCO, Explorer and Magellan pipeline systems.
–>: Supply, distribution and marketing—consists of services for the supply and distribution of refined petroleum products through rack spot sales, contract sales, and bulk sales in the physical and derivative markets, with retail, wholesale, industrial and commercial customers using our terminal racks and marine refueling equipment, and providing related value-added fuel procurement and supply chain management services.

Our chief operating decision maker is our chief executive officer ("CEO"). Our CEO reviews the financial performance of our business segments using a financial performance measure that is referred to by us as "adjusted net operating margins" for purposes of making operating decisions and assessing financial performance. Accordingly, we present "adjusted net operating margins" for each of our two business segments: (i) terminals, pipelines, and tugs and barges and (ii) supply, distribution and marketing.

For the terminals, pipelines, and tugs and barges segment, "adjusted net operating margins" is composed of revenues less direct operating costs and expenses. There are no differences between "adjusted net operating margins" for our terminals, pipelines, and tugs and barges segment and the net operating margins reported for that segment in our accompanying historical financial statements.

For our supply, distribution and marketing segment, "adjusted net operating margins" is composed of revenues less cost of product sold and other direct costs and expenses. For purposes of computing our "adjusted net operating margins" for the supply, distribution and marketing segment, cost of product sold is reflected at fair value, which matches the treatment of our derivative and risk management contracts. Additionally, for purposes of computing our "adjusted net operating margins," our discretionary inventories—base operating inventory volumes are maintained at original cost. The differences between "adjusted net operating margins" for the supply, distribution and marketing segment and the net operating margins reported for that segment in our accompanying historical financial statements are presented as "Inventory Adjustments" in the accompanying "Reconciliation to Earnings Before Income Taxes."

The financial performance of our business segments is as follows (in thousands):

						Year ended June 30, 2004			Year ended June 30, 2003			Year ended June 30, 2002

Terminals, pipelines, and tugs and barges:
		Historical facilities				$	39,834		$	42,384		$	35,718
		Coastal facilities					15,440			5,408			—

			Adjusted net operating margins				55,274			47,792			35,718

Supply, distribution and marketing:
		Light oils:
			Rack spot margins				16,267			16,126			3,950
			Contract margins				14,047			18,228			3,658
		Inventory roll (cost) benefit					(6,404	)		(14,956	)		12,308
		Bulk activities and other margins					(12,586	)		17,739			34,887
		Heavy oils—contract margins					13,656			6,299			—
		Supply chain management services margins					8,624			13,017			13,888
		Trading activities, net					(823	)		(1,139	)		56

			Adjusted net operating margins				32,781			55,314			68,747

				Total adjusted net operating margins		$	88,055		$	103,106		$	104,465

Reconciliation to Earnings Before Income Taxes:
	Adjusted net operating margins					$	88,055		$	103,106		$	104,465
		Inventory Adjustments:
			Gains recognized on beginning inventories—discretionary volumes				5,855			12,644			—
			Gains deferred on ending inventories—discretionary volumes held for immediate sale or exchange				(2,330	)		(5,855	)		—
			Increase in FIFO cost basis of base operating inventory volumes				38,878			415			—
			Lower of cost or market write-downs on base operating inventory volumes				(5,334	)		(12,435	)		—

				Net operating margins			125,124			97,875			104,465
		Other Items:
			Selling, general and administrative expenses				(40,747	)		(41,940	)		(41,527	)
			Depreciation and amortization				(23,015	)		(19,371	)		(16,556	)
			Lower of cost or market write-downs on product linefill and tank bottom volumes				(60	)		(633	)		(12,963	)
			Loss on disposition of assets, net				(978	)		—			(13	)

					Operating income		60,324			35,931			33,406
			Other expense, net				(29,735	)		(19,321	)		(19,383	)

					Earnings before income taxes	$	30,589		$	16,610		$	14,023

Supplemental information about our business segments is summarized below (in thousands):

		Year ended June 30, 2004
		Supply, distribution and marketing		Terminals, pipelines, tugs and barges		Corporate		Total consolidated

Revenues from external customers		$	11,215,351	$	43,827	$	—	$	11,259,178
Inter-segment revenues			—		65,413		—		65,413

	Revenues	$	11,215,351	$	109,240	$	—	$	11,324,591

Identifiable assets		$	561,047	$	368,434	$	44,875	$	974,356

Capital expenditures		$	711	$	16,040	$	322	$	17,073

		Year ended June 30, 2003
		Supply, distribution and marketing		Terminals, pipelines, tugs and barges		Corporate		Total consolidated

Revenues from external customers		$	8,241,001	$	39,973	$	—	$	8,280,974
Inter-segment revenues			—		46,994		—		46,994

	Revenues	$	8,241,001	$	86,967	$	—	$	8,327,968

Identifiable assets		$	557,794	$	378,395	$	84,277	$	1,020,466

Capital expenditures		$	649	$	135,498	$	862	$	137,009

		Year ended June 30, 2002
		Supply, distribution and marketing		Terminals and pipelines		Corporate		Total consolidated

Revenues from external customers		$	6,001,170	$	32,289	$	—	$	6,033,459
Inter-segment revenues			—		35,996		—		35,996

	Revenues	$	6,001,170	$	68,285	$	—	$	6,069,455

Identifiable assets		$	447,761	$	248,871	$	38,696	$	735,328

Capital expenditures		$	62	$	13,592	$	2,155	$	15,809

100

(22) FINANCIAL RESULTS BY QUARTER (UNAUDITED)

(in thousands, except per share amounts)

		Three Months Ended
		Three Months Ended										Year Ended June 30, 2004
		September 30, 2003		December 31, 2003			March 31, 2004		June 30, 2004			Year Ended June 30, 2004

Revenues		$	2,551,545	$	2,175,154		$	3,134,346	$	3,463,546		$	11,324,591

Net operating margins		$	26,437	$	23,568		$	55,230	$	19,889		$	125,124

Net earnings (loss) attributable to common stockholders		$	883	$	(2,036	)	$	17,279	$	(1,970	)	$	14,156

Earnings (loss) per common share
	Basic	$	0.03	$	(0.04	)	$	0.36	$	(0.04	)	$	0.36

	Diluted	$	0.03	$	(0.04	)	$	0.36	$	(0.04	)	$	0.36

		Three Months Ended
		Three Months Ended											Year Ended June 30, 2003
		September 30, 2002			December 31, 2002			March 31, 2003		June 30, 2003			Year Ended June 30, 2003

Revenues		$	1,745,863		$	2,024,958		$	2,343,608	$	2,213,539		$	8,327,968

Net operating margins		$	18,540		$	1,821		$	57,509	$	20,005		$	97,875

Net earnings (loss) attributable to common stockholders		$	(459	)	$	(10,732	)	$	21,384	$	(7,374	)	$	2,819

Earnings (loss) per common share
	Basic	$	(0.01	)	$	(0.27	)	$	0.54	$	(0.19	)	$	0.07

	Diluted	$	(0.01	)	$	(0.27	)	$	0.54	$	(0.19	)	$	0.07

101

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES

There were no changes in and disagreements with accountants on accounting and financial disclosures during the year ended June 30, 2004.

ITEM 9A. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the Commission's rules and forms, and that information is accumulated and communicated to our management, including our principal executive and principal financial officers (whom we refer to as our Certifying Officers), as appropriate to allow timely decisions regarding required disclosure. Our management evaluated, with the participation of our Certifying Officers, the effectiveness of our disclosure controls and procedures as of June 30, 2004, pursuant to Rule 13a-15(b) under the Exchange Act. Based upon that evaluation, our Certifying Officers concluded that, as of June 30, 2004, our disclosure controls and procedures were effective.

There were no changes in our internal control over financial reporting that occurred during the fiscal quarter ended June 30, 2004 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

102

Part III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS

The information required by this item will be included in, and is incorporated herein by reference to, the Proxy Statement for the Annual Meeting of Stockholders or in a subsequent amendment to this Form 10-K.

ITEM 11. EXECUTIVE COMPENSATION

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by this item will be included in, and is incorporated herein by reference to, the Proxy Statement for the Annual Meeting of Stockholders, or in a subsequent amendment to this Form 10-K.

103

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a): The following documents are filed as a part of this report.
(1): Consolidated Financial Statements

TransMontaigne Inc.

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets as of June 30, 2004 and 2003

Consolidated Statements of Operations for the years ended June 30, 2004, 2003 and 2002

Consolidated Statements of Preferred Stock and Common Stockholders' Equity for the years ended June 30, 2004, 2003 and 2002

Consolidated Statements of Cash Flows for the years ended June 30, 2004, 2003 and 2002

Notes to Consolidated Financial Statements

(2): Financial Statement Schedules

Valuation and qualifying accounts.

(3): Exhibits:

A list of exhibits required by Item 601 of Regulation S-K to be filed as part of this report:

Exhibit Number		Description

2.1		Facilities Sale Agreement by and among TransMontaigne Inc., TransMontaigne Pipeline Inc., TransMontaigne Terminaling Inc. and NORCO Pipeline Company, LLC and Buckeye Terminals, LLC dated July 31, 2001 (incorporated by reference to Exhibit 2.1 of TransMontaigne Inc.'s Current Report on Form 8-K filed on August 15, 2001).
2.2		Stock Purchase Agreement by and between El Paso CGP Company and TransMontaigne Product Services Inc. dated January 13, 2003 (incorporated by reference to Exhibit 99.2 of TransMontaigne Inc.'s Current Report on Form 8-K filed on March 17, 2003).
2.3		First Amendment to Stock Purchase Agreement by and between El Paso CGP Company and TransMontaigne Product Services Inc. dated February 28, 2003 (incorporated by reference to Exhibit 99.3 of TransMontaigne Inc.'s Current Report on Form 8-K filed on March 17, 2003).
2.4		Second Amendment to Stock Purchase Agreement by and between El Paso CGP Company and TransMontaigne Product Services Inc., dated as of June 27, 2003 (incorporated by reference to Exhibit 2.3 of TransMontaigne Inc.'s Registration Statement on Form S-4 filed on July 22, 2003).
3.1A		Restated Articles of Incorporation and Certificate of Merger (incorporated by reference to Exhibit 3.1 of TransMontaigne Oil Company's Form 10-K for the year ended April 30, 1996).
3.1B		Certificate of Amendment of Restated Certificate of Incorporation of TransMontaigne Oil Company dated August 26, 1998 (incorporated by reference to Exhibit 3.1B of TransMontaigne Inc.'s Form 10-Q for the quarter ended September 30, 1998).

104

3.1C		Certificate of Amendment of Restated Certificate of Incorporation of TransMontaigne Inc. dated December 18, 1998 (incorporated by reference to Exhibit 3.1C of TransMontaigne Inc.'s Form 10-Q for the quarter ended December 31, 1998).
3.1D		Certificate of Designations of Series B Redeemable Convertible Preferred Stock (incorporated by reference to Exhibit 99.4 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002).
3.2		Amended and Restated Bylaws of TransMontaigne Inc. (incorporated by reference to Exhibit 3.2 of TransMontaigne Inc.'s Form 10-Q for the quarter ended September 30, 2002).
4.1		Indenture dated as of May 30, 2003 among TransMontaigne Inc., the Guarantors party thereto and Wells Fargo Bank Minnesota, National Association, as trustee, with respect to the 9¹/8% Series B Senior Subordinated Notes due 2010 (incorporated by reference to Exhibit 4.1 of TransMontaigne Inc.'s Current Report on Form 8-K filed June 3, 2003).
4.2		Form of 9¹/8% Series B Senior Subordinated Notes due 2010 (included in Exhibit 4.1 of TransMontaigne Inc.'s Current Report on Form 8-K filed June 3, 2003).
4.3		Registration Rights Agreement dated as of May 30, 2003 among TransMontaigne Inc., the Guarantors party thereto, UBS Warburg LLC, Wachovia Securities Inc., BNP Paribas Securities Corp. and SG Cowen Securities Corporation (incorporated by reference to Exhibit 4.2 of TransMontaigne Inc.'s Current Report on Form 8-K filed June 3, 2003).
10.1*		TransMontaigne Oil Company Equity Incentive Plan (incorporated by reference to Exhibit 10.2 TransMontaigne Oil Company's Definitive Proxy Statement filed in connection with the August 28, 1997 Annual Meeting of Shareholders).
10.1A*		Amendment to TransMontaigne Inc. Equity Incentive Plan, effective March 17, 1999 (incorporated by reference to Exhibit A of TransMontaigne Inc.'s Definitive Proxy Statement on Schedule 14A filed on October 26, 1999).
10.1B*		Amendment to TransMontaigne Inc. Equity Incentive Plan, effective March 17, 1999 (incorporated by reference to Exhibit 99.3 of TransMontaigne Inc.'s Registration Statement on Form S-8 filed on October 17, 2001).
10.1C*		Amendment to TransMontaigne Inc. Equity Incentive Plan, effective November 21, 2002 (incorporated by reference to Exhibit A of TransMontaigne Inc.'s Definitive Proxy Statement on Schedule 14A filed on October 16, 2002).
10.2		Anti-dilution Rights Agreement dated as of April 17, 1996 between TransMontaigne Oil Company and Waterwagon & Co., nominee for Merrill Lynch Growth Fund (incorporated by reference to Exhibit 10.7 of TransMontaigne Oil Company's Form 10-K for the year ended April 30, 1996).
10.3		Agreement to Elect Directors dated as of April 17, 1996 between TransMontaigne Oil Company and the First Reserve Investors named therein (incorporated by reference to Exhibit 10.8 of TransMontaigne Oil Company's Form 10-K for the year ended April 30, 1996).
10.4		Amendment to Agreement to Elect Directors dated as of April 17, 1996 dated June 26, 2002 between TransMontaigne Inc. and the First Reserve Investors named therein (incorporated by reference to Exhibit 10.6 of TransMontaigne Inc.'s Form 10-K for the year ended June 30, 2002).
10.5		Amended and Restated Institutional Investor Registration Rights Agreement dated June 27, 2002 by and among TransMontaigne Inc. and the entities listed on the signature pages thereof (incorporated by reference to Exhibit 99.6 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002).

105

10.6		Amended and Restated Louis Dreyfus Corporation Registration Rights Agreement dated June 27, 2002 between TransMontaigne Inc. and Louis Dreyfus Corporation (incorporated by reference to Exhibit 99.7 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002).
10.7		Amended and Restated Preferred Stock Investor Registration Rights Agreement dated June 27, 2002 between TransMontaigne Inc. and the entities listed on the signature pages thereof (incorporated by reference to Exhibit 99.5 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002).
10.8		Form of Preferred Stock Recapitalization Agreement dated as of June 27, 2002 (without exhibits) (incorporated by reference to Exhibit 99.3 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002).
10.9		Stockholders' Agreement dated as of June 28, 2002 among TransMontaigne Inc., Key Senior Executives, and the Investors listed on the signature pages thereof (incorporated by reference to Exhibit 99.8 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002).
10.10		Stock Purchase Agreement dated as of September 13, 1998, between Louis Dreyfus Corporation and TransMontaigne Inc. (incorporated by reference to Exhibit 2.1 of TransMontaigne Inc.'s Current Report on Form 8-K filed on November 13, 1998).
10.11		Amendment No. 1 to Stock Purchase Agreement dated as of October 30, 1998, between Louis Dreyfus Corporation and TransMontaigne Inc. (incorporated by reference to Exhibit 2.2 of TransMontaigne Inc.'s Current Report on Form 8-K filed on November 13, 1998).
10.12		Letter Agreement dated as of June 27, 2002 between First Reserve Fund VI, Limited Partnership and TransMontaigne Inc. (incorporated by reference to Exhibit 99.9 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002).
10.13*		Change in Control Agreement between TransMontaigne Inc. and Donald H. Anderson dated April 12, 2001 (incorporated by reference to Exhibit 10.1 of TransMontaigne Inc.'s Form 10-Q for the quarter ended September 30, 2002).
10.14*		Change in Control Agreement between TransMontaigne Inc. and Erik B. Carlson dated April 12, 2001 (incorporated by reference to Exhibit 10.2 of TransMontaigne Inc.'s Form 10-Q for the quarter ended September 30, 2002).
10.15*		Change in Control Agreement between TransMontaigne Inc. and William S. Dickey dated April 12, 2001 (incorporated by reference to Exhibit 10.4 of TransMontaigne Inc.'s Form 10-Q for the quarter ended September 30, 2002).
10.16*		Change in Control Agreement between TransMontaigne Inc. and Randall J. Larson dated May 1, 2002 (incorporated by reference to Exhibit 10.6 of TransMontaigne Inc.'s Form 10-Q for the quarter ended September 30, 2002).
10.17		Consulting Agreement by and between Harold R. Logan, Jr. and TransMontaigne Inc. effective as of January 1, 2003 (incorporated by reference to Exhibit 10.1 of TransMontaigne Inc.'s Form 10-Q for the quarter ended March 31, 2003).
10.18		First Amended and Restated Credit Agreement by and among TransMontaigne Inc., certain subsidiaries of TransMontaigne Inc., certain lenders, UBS AG, Cayman Islands Branch, as lender and UBS AG, Stamford Branch, in its capacities as Administrative and Collateral Agent for itself and the other lenders, dated as of June 25, 2003 (incorporated by reference to Exhibit 10.25 of TransMontaigne Inc.'s Registration Statement on Form S-4 filed on July 22, 2003).

106

10.19		First Amended and Restated Inventory and Accounts Security Agreement by and among TransMontaigne Inc., the Guarantors party thereto and UBS AG, Stamford Branch as Collateral Agent, dated as of June 25, 2003 (incorporated by reference to Exhibit 10.26 of TransMontaigne Inc.'s Registration Statement on Form S-4 filed on July 22, 2003).
10.20		Letter Agreement dated as of October 9, 2003 between LB I Group Inc. and TransMontaigne Inc. (incorporated by reference to Exhibit 10.1 of TransMontaigne Inc.'s Form 10-Q for the quarter ended September 30, 2003).
10.21		Letter Agreement dated as of October 8, 2003 between First Reserve Corporation and TransMontaigne Inc. (incorporated by reference to Exhibit 10.2 of TransMontaigne Inc.'s Form 10-Q for the quarter ended September 30, 2003).
10.22		$400,000,000 Senior Secured Working Capital Credit Facility, dated as of September 13, 2004, among TransMontaigne Inc., as Borrower, the several financial institutions initially signatory thereto, as Lenders, JPMorgan Chase Bank and UBS AG Stamford Branch, as Syndication Agents, Société Générale, New York Branch, and Wells Fargo Foothill, LLC, as the Documentation Agents, and Wachovia Bank, National Association, as Agent. FILED HEREWITH.
12.1		Statement of Computation of Ratios of Earnings to Fixed Charges. FILED HEREWITH.
21.1		List of Subsidiaries. FILED HEREWITH.
23.1		Audit Report on Schedule and Consent of Registered Public Accounting Firm. FILED HEREWITH.
31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. FILED HEREWITH.
31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. FILED HEREWITH.
32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. FILED HEREWITH.
32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. FILED HEREWITH.
99.1		Financial Statement Schedule. FILED HEREWITH.

*: Identifies each management compensation plan or arrangement
(b): Reports on Form 8-K:

A Current Report on Form 8-K was filed on May 18, 2004 under Item 7, Financial Statements, Pro Forma Financial Information and Exhibits, and furnished under Item 9, Regulation FD Disclosure, and Item 12, Results of Operations and Financial Condition, reporting the Company's May 12, 2004 earnings press release for its third fiscal quarter ended March 31, 2004.

107

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		TRANSMONTAIGNE INC.
		By:	/s/ CORTLANDT S. DIETLER Cortlandt S. Dietler Chairman

Date: September 23, 2004

Pursuant to the requirements of the Securities and Exchange Act of 1934, this report is signed below by the following persons on behalf of the Registrant and in the capacities indicated on September 23, 2004.

Name and Signature		Title

/s/ CORTLANDT S. DIETLER Cortlandt S. Dietler		Chairman and Director
/s/ DONALD H. ANDERSON Donald H. Anderson		President, Chief Executive Officer, Chief Operating Officer, Vice Chairman and Director
/s/ RANDALL J. LARSON Randall J. Larson		Executive Vice President, Chief Financial Officer and Chief Accounting Officer
/s/ JOHN A. HILL John A. Hill		Director
/s/ BRYAN H. LAWRENCE Bryan H. Lawrence		Director
/s/ HAROLD R. LOGAN, JR. Harold R. Logan, Jr.		Director
/s/ EDWIN H. MORGENS Edwin H. Morgens		Director

108

/s/ WAYNE W. MURDY Wayne W. Murdy		Director
/s/ WALTER P. SCHUETZE Walter P. Schuetze		Director

109

EXHIBIT INDEX

Exhibit Number		Description of Exhibits
2.1		Facilities Sale Agreement by and among TransMontaigne Inc., TransMontaigne Pipeline Inc., TransMontaigne Terminaling Inc. and NORCO Pipeline Company, LLC and Buckeye Terminals, LLC dated July 31, 2001 (incorporated by reference to Exhibit 2.1 of TransMontaigne Inc.'s Current Report on Form 8-K filed on August 15, 2001).
2.2		Stock Purchase Agreement by and between El Paso CGP Company and TransMontaigne Product Services Inc. dated January 13, 2003 (incorporated by reference to Exhibit 99.2 of TransMontaigne Inc.'s Current Report on Form 8-K filed on March 17, 2003).
2.3		First Amendment to Stock Purchase Agreement by and between El Paso CGP Company and TransMontaigne Product Services Inc. dated February 28, 2003 (incorporated by reference to Exhibit 99.3 of TransMontaigne Inc.'s Current Report on Form 8-K filed on March 17, 2003).
2.4		Second Amendment to Stock Purchase Agreement by and between El Paso CGP Company and TransMontaigne Product Services Inc., dated as of June 27, 2003 (incorporated by reference to Exhibit 2.3 of TransMontaigne Inc.'s Registration Statement on Form S-4 filed on July 22, 2003).
3.1A		Restated Articles of Incorporation and Certificate of Merger (incorporated by reference to Exhibit 3.1 of TransMontaigne Oil Company's Form 10-K for the year ended April 30, 1996).
3.1B		Certificate of Amendment of Restated Certificate of Incorporation of TransMontaigne Oil Company dated August 26, 1998 (incorporated by reference to Exhibit 3.1B of TransMontaigne Inc.'s Form 10-Q for the quarter ended September 30, 1998).
3.1C		Certificate of Amendment of Restated Certificate of Incorporation of TransMontaigne Inc. dated December 18, 1998 (incorporated by reference to Exhibit 3.1C of TransMontaigne Inc.'s Form 10-Q for the quarter ended December 31, 1998).
3.1D		Certificate of Designations of Series B Redeemable Convertible Preferred Stock (incorporated by reference to Exhibit 99.4 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002).
3.2		Amended and Restated Bylaws of TransMontaigne Inc. (incorporated by reference to Exhibit 3.2 of TransMontaigne Inc.'s Form 10-Q for the quarter ended September 30, 2002).
4.1		Indenture dated as of May 30, 2003 among TransMontaigne Inc., the Guarantors party thereto and Wells Fargo Bank Minnesota, National Association, as trustee, with respect to the 9¹/8% Series B Senior Subordinated Notes due 2010 (incorporated by reference to Exhibit 4.1 of TransMontaigne Inc.'s Current Report on Form 8-K filed June 3, 2003).
4.2		Form of 9¹/8% Series B Senior Subordinated Notes due 2010 (included in Exhibit 4.1 of TransMontaigne Inc.'s Current Report on Form 8-K filed June 3, 2003).
4.3		Registration Rights Agreement dated as of May 30, 2003 among TransMontaigne Inc., the Guarantors party thereto, UBS Warburg LLC, Wachovia Securities Inc., BNP Paribas Securities Corp. and SG Cowen Securities Corporation (incorporated by reference to Exhibit 4.2 of TransMontaigne Inc.'s Current Report on Form 8-K filed June 3, 2003).
10.1	*	TransMontaigne Oil Company Equity Incentive Plan (incorporated by reference to Exhibit 10.2 TransMontaigne Oil Company's Definitive Proxy Statement filed in connection with the August 28, 1997 Annual Meeting of Shareholders).

10.1A	*	Amendment to TransMontaigne Inc. Equity Incentive Plan, effective March 17, 1999 (incorporated by reference to Exhibit A of TransMontaigne Inc.'s Definitive Proxy Statement on Schedule 14A filed on October 26, 1999).
10.1B	*	Amendment to TransMontaigne Inc. Equity Incentive Plan, effective March 17, 1999 (incorporated by reference to Exhibit 99.3 of TransMontaigne Inc.'s Registration Statement on Form S-8 filed on October 17, 2001).
10.1C	*	Amendment to TransMontaigne Inc. Equity Incentive Plan, effective November 21, 2002 (incorporated by reference to Exhibit A of TransMontaigne Inc.'s Definitive Proxy Statement on Schedule 14A filed on October 16, 2002).
10.2		Anti-dilution Rights Agreement dated as of April 17, 1996 between TransMontaigne Oil Company and Waterwagon & Co., nominee for Merrill Lynch Growth Fund (incorporated by reference to Exhibit 10.7 of TransMontaigne Oil Company's Form 10-K for the year ended April 30, 1996).
10.3		Agreement to Elect Directors dated as of April 17, 1996 between TransMontaigne Oil Company and the First Reserve Investors named therein (incorporated by reference to Exhibit 10.8 of TransMontaigne Oil Company's Form 10-K for the year ended April 30, 1996).
10.4		Amendment to Agreement to Elect Directors dated as of April 17, 1996 dated June 26, 2002 between TransMontaigne Inc. and the First Reserve Investors named therein (incorporated by reference to Exhibit 10.6 of TransMontaigne Inc.'s Form 10-K for the year ended June 30, 2002).
10.5		Amended and Restated Institutional Investor Registration Rights Agreement dated June 27, 2002 by and among TransMontaigne Inc. and the entities listed on the signature pages thereof (incorporated by reference to Exhibit 99.6 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002).
10.6		Amended and Restated Louis Dreyfus Corporation Registration Rights Agreement dated June 27, 2002 between TransMontaigne Inc. and Louis Dreyfus Corporation (incorporated by reference to Exhibit 99.7 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002).
10.7		Amended and Restated Preferred Stock Investor Registration Rights Agreement dated June 27, 2002 between TransMontaigne Inc. and the entities listed on the signature pages thereof (incorporated by reference to Exhibit 99.5 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002).
10.8		Form of Preferred Stock Recapitalization Agreement dated as of June 27, 2002 (without exhibits) (incorporated by reference to Exhibit 99.3 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002).
10.9		Stockholders' Agreement dated as of June 28, 2002 among TransMontaigne Inc., Key Senior Executives, and the Investors listed on the signature pages thereof (incorporated by reference to Exhibit 99.8 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002).
10.10		Stock Purchase Agreement dated as of September 13, 1998, between Louis Dreyfus Corporation and TransMontaigne Inc. (incorporated by reference to Exhibit 2.1 of TransMontaigne Inc.'s Current Report on Form 8-K filed on November 13, 1998).

10.11		Amendment No. 1 to Stock Purchase Agreement dated as of October 30, 1998, between Louis Dreyfus Corporation and TransMontaigne Inc. (incorporated by reference to Exhibit 2.2 of TransMontaigne Inc.'s Current Report on Form 8-K filed on November 13, 1998).
10.12		Letter Agreement dated as of June 27, 2002 between First Reserve Fund VI, Limited Partnership and TransMontaigne Inc. (incorporated by reference to Exhibit 99.9 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002).
10.13	*	Change in Control Agreement between TransMontaigne Inc. and Donald H. Anderson dated April 12, 2001 (incorporated by reference to Exhibit 10.1 of TransMontaigne Inc.'s Form 10-Q for the quarter ended September 30, 2002).
10.14	*	Change in Control Agreement between TransMontaigne Inc. and Erik B. Carlson dated April 12, 2001 (incorporated by reference to Exhibit 10.2 of TransMontaigne Inc.'s Form 10-Q for the quarter ended September 30, 2002).
10.15	*	Change in Control Agreement between TransMontaigne Inc. and William S. Dickey dated April 12, 2001 (incorporated by reference to Exhibit 10.4 of TransMontaigne Inc.'s Form 10-Q for the quarter ended September 30, 2002).
10.16	*	Change in Control Agreement between TransMontaigne Inc. and Randall J. Larson dated May 1, 2002 (incorporated by reference to Exhibit 10.6 of TransMontaigne Inc.'s Form 10-Q for the quarter ended September 30, 2002).
10.17		Consulting Agreement by and between Harold R. Logan, Jr. and TransMontaigne Inc. effective as of January 1, 2003 (incorporated by reference to Exhibit 10.1 of TransMontaigne Inc.'s Form 10-Q for the quarter ended March 31, 2003).
10.18		First Amended and Restated Credit Agreement by and among TransMontaigne Inc., certain subsidiaries of TransMontaigne Inc., certain lenders, UBS AG, Cayman Islands Branch, as lender and UBS AG, Stamford Branch, in its capacities as Administrative and Collateral Agent for itself and the other lenders, dated as of June 25, 2003 (incorporated by reference to Exhibit 10.25 of TransMontaigne Inc.'s Registration Statement on Form S-4 filed on July 22, 2003).
10.19		First Amended and Restated Inventory and Accounts Security Agreement by and among TransMontaigne Inc., the Guarantors party thereto and UBS AG, Stamford Branch as Collateral Agent, dated as of June 25, 2003 (incorporated by reference to Exhibit 10.26 of TransMontaigne Inc.'s Registration Statement on Form S-4 filed on July 22, 2003).
10.20		Letter Agreement dated as of October 9, 2003 between LB I Group Inc. and TransMontaigne Inc. (incorporated by reference to Exhibit 10.1 of TransMontaigne Inc.'s Form 10-Q for the quarter ended September 30, 2003).
10.21		Letter Agreement dated as of October 8, 2003 between First Reserve Corporation and TransMontaigne Inc. (incorporated by reference to Exhibit 10.2 of TransMontaigne Inc.'s Form 10-Q for the quarter ended September 30, 2003).
10.22		$400,000,000 Senior Secured Working Capital Credit Facility, dated as of September 13, 2004, among TransMontaigne Inc., as Borrower, the several financial institutions initially signatory thereto, as Lenders, JPMorgan Chase Bank and UBS AG Stamford Branch, as Syndication Agents, Société Générale, New York Branch, and Wells Fargo Foothill, LLC, as the Documentation Agents, and Wachovia Bank, National Association, as Agent. FILED HEREWITH.
12.1		Statement of Computation of Ratios of Earnings to Fixed Charges. FILED HEREWITH.
21.1		List of Subsidiaries. FILED HEREWITH.

23.1		Audit Report on Schedule and Consent of KPMG LLP, Independent Auditors. FILED HEREWITH.
31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. FILED HEREWITH.
31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. FILED HEREWITH.
32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. FILED HEREWITH.
32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. FILED HEREWITH.
99.1		Financial Statement Schedule. FILED HEREWITH.

*: Identifies each management compensation plan or arrangement