Transmontaigne Product Services S-4 Registration of securities issued in business combination transactions

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TABLE OF CONTENTS
Index to consolidated financial statements

As Filed with the Securities and Exchange Commission on July 22, 2003

Registration No. 333-            

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

FORM S-4
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

TRANSMONTAIGNE INC.
(Exact name of registrant as specified in its charter)

Delaware	5171	06-1052062
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

1670 Broadway, Suite 3100
Denver, Colorado 80202
(303) 626-8200
(Name, address, including zip code, and telephone number, including area code, of registrant's principal executive offices)

Erik B. Carlson, Esq.
Senior Vice President, Corporate Secretary and General Counsel
1670 Broadway, Suite 3100
Denver, Colorado 80202
(303) 626-8200
(Name, address, including zip code, and telephone number, including area code, of agent for service)

With copies to:
Whitney Holmes, Esq.
Michael Stefanoudakis, Esq.
Hogan & Hartson L.L.P.
1200 Seventeenth Street, Suite 1500
Denver, Colorado 80202
(303) 899-7300

Approximate Date Of Commencement Of Proposed Sale To The Public:As soon as practicable after the effective date of this Registration Statement.

        If the securities being registered on this Form are to be offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box. o

        If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

        If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

CALCULATION OF REGISTRATION FEE

Title of Each Class of Securities to be Registered	Amount to be Registered	Proposed Maximum Offering Price Per Unit	Proposed Maximum Aggregate Offering Price	Amount of Registration Fee
91/8% Series B Senior Subordinated Notes Due 2010	$200,000,000	100%	$200,000,000	$16,180(1)
Guarantee of 91/8% Series B Senior Subordinated Notes	—	—	—	(2)

(1)

Estimated solely for purposes of calculating the registration fee pursuant to Rule 457(f)(2) under the Securities Act of 1933, as amended (the "Securities Act").

(2)

Pursuant to Section 457(n) of the Securities Act, no separate registration fee for the guarantees is payable.

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment that specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

TABLE OF ADDITIONAL REGISTRANTS

Exact Name of Registrant as Specified in its Charter	State or Other Jurisdiction of Incorporation or Organization	Primary Standard Industrial Classified Code Number		I.R.S. Employer Identification Number	Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant's Primary Executive Offices
TransMontaigne Transport Inc.	Delaware	(1	)	03-0405433	(2	)
TransMontaigne Product Services Inc.	Delaware	(1	)	84-1477374	(2	)
Coastal Fuels Marketing, Inc.	Florida	(1	)	59-0159916	(2	)
Coastal Tug and Barge, Inc.	Florida	(1	)	59-0159916	(2	)

(1)

5171

(2)

1670 Broadway, Suite 3100, Denver, Colorado 80202

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and we are not soliciting an offer to buy these securities in any state where the offer is not permitted.

SUBJECT TO COMPLETION, DATED JULY 22, 2003

PROSPECTUS

$200,000,000

TRANSMONTAIGNE INC.
OFFER TO EXCHANGE ALL OF THE OUTSTANDING
$200,000,000 9¹/8% SENIOR SUBORDINATED NOTES DUE 2010
FOR
$200,000,000 9¹/8% SERIES B SENIOR SUBORDINATED NOTES DUE 2010
THAT HAVE BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933

        We are offering to exchange all of our outstanding 9¹/8% senior subordinated notes due 2010, which we refer to as the old notes, for our registered 9¹/8% series B senior subordinated notes due 2010, which we refer to as the exchange notes. We refer to the old notes and the exchange notes, collectively as the notes. The terms of the exchange notes are substantially identical to the terms of the old notes to be exchanged, except that the exchange notes have been registered under the Securities Act of 1933, as amended, which we refer to as the Securities Act, and will not bear any legend restricting their transfer.

Material Terms of the Exchange Offer

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The exchange offer will expire at 5:00 p.m., New York City time, on                        , 2003, unless extended.



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All old notes that are validly tendered and not validly withdrawn will be exchanged.



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You may withdraw tenders of old notes at any time prior to the expiration of the exchange offer.



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If you fail to tender your old notes, you will continue to hold unregistered notes that you will not be able to transfer freely.



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We will not receive any cash proceeds from the exchange offer.



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There is no established trading market for the exchange notes or the old notes. We do not intend to list the exchange notes on any securities exchange, and therefore no active public market is anticipated.

Participating in this exchange offer involves risks. See "Risk Factors" beginning on page 18.

        Each broker-dealer that receives exchange notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such exchange notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of exchange notes received in exchange for old notes where such old notes were acquired by that broker-dealer as a result of market-making activities or other trading activities. We have agreed that, for a period of 180 days after the expiration date of the exchange offer, we will make copies of this prospectus available to any broker-dealer for use in connection with any such resale. See "Plan of Distribution."

We are not making this exchange offer in any state or jurisdiction where it is not permitted.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. any representation to the contrary is a criminal offense.

The date of this prospectus is                        , 2003

TABLE OF CONTENTS

You should rely only on the information contained in this document or to which we have referred you. We have not authorized anyone to provide you with information that is different. This document may only be used where it is legal to sell these securities. The information in this document may only be accurate on the date of this document.

MARKET AND INDUSTRY DATA

        Market and industry data and other statistical information used throughout this prospectus 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 and cannot guarantee its accuracy and completeness.

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

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PROSPECTUS SUMMARY

This summary highlights basic information about us and the exchange notes that we are offering. You should read this entire prospectus carefully, including the "Risk factors" section, the consolidated financial statements and the notes to those consolidated financial statements. As used in this prospectus, unless the context otherwise requires, the terms "TransMontaigne," "we," "our" and "us" refer to TransMontaigne Inc. and its consolidated subsidiaries. References to "barrels" refer to the United States customary measurement of liquid volume equal to 42 gallons.

THE COMPANY

General

        We are 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. Our principal activities consist of (i) terminal, pipeline, and tug and barge operations, (ii) supply, distribution and marketing and (iii) supply management services. Our customers include refiners, wholesalers, distributors, marketers, and industrial and commercial end-users of refined petroleum products.

        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 recent 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 storage of jet fuel, crude oil and asphalt.

Terminals, pipelines, and tugs and barges

        The U.S. refined petroleum product distribution system links refineries to end-users of gasoline and other refined petroleum products through a network of terminals, pipelines, tankers, barges, rail cars and trucks. Terminals play a key role in the delivery of product to the end-user by providing storage, distribution, blending, injection and other ancillary services. The two basic types of terminals are inland terminals, which are supplied primarily by pipelines, and marine terminals, which are supplied primarily by ships and barges.

        We own and operate a terminal infrastructure that handles refined petroleum products and other commercial liquids. At March 31, 2003, we owned and operated 55 terminals with an aggregate capacity of approximately 22.0 million barrels.

        We generate revenues in our terminal operations from throughput fees and storage fees. 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. For the twelve-month period ended March 31, 2003, we averaged approximately 338,000 barrels per day of throughput volume at our terminals. Approximately 75% 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. We earn storage fees by leasing storage capacity at our terminals to third parties and earn a monthly fee based on the volume of storage capacity leased.

        Of our 55 terminals, we own and operate 31 terminals at various points along the Plantation and Colonial pipeline corridor, which extends from the Gulf Coast through the Southeast, Mid-Atlantic and Northeast regions. We own and operate 15 terminals in the Midwest and the upper and lower Mississippi River areas, eight terminals at various locations in Florida and a large terminal complex in

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Brownsville, Texas. Our network of terminals is geographically diverse with our largest terminal, the Brownsville complex, accounting for approximately 10% of our total capacity.

        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 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. We have a significant shipping history on the Colonial, Plantation, Explorer and TEPPCO pipelines that allows us to ship products through these pipelines to our and third-party terminals, even during periods of high demand. For the twelve-month period ended March 31, 2003, we shipped approximately 215,000 barrels per day of product through these pipelines.

        In addition to shipping product we sell to customers, we use exchange agreements to both increase throughput at our terminals and to establish greater shipping history on the common carrier pipelines. Under an exchange agreement, we agree to receive product in one location in exchange for delivering product in another location, together with a fee reflecting transportation, throughput and related costs.

        We also own and operate an interstate refined petroleum products pipeline operating from Mt. Vernon, Missouri to Rogers, Arkansas, known as the Razorback Pipeline, and associated terminals at Mt. Vernon and Rogers. We generate revenues in our pipeline operations from transportation fees. For the twelve-month period ended March 31, 2003, we transported an average of approximately 12,000 barrels per day of products through this pipeline.

        In Florida, we own and operate nine tugboats and 13 barges and a proprietary pipeline in Port Everglades, which we use to deliver 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 our customers' facilities in Florida and to transport our product among our Florida terminals when needed to augment our capacity. In addition, our tugboats earn fees for providing docking and other ship-assist services to vessel traffic throughout our Florida port locations.

        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, and serves as an injection point into the Colonial Pipeline for product unloaded from barges transporting it down the Mississippi River.

Supply, distribution and marketing

        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 others, in the Gulf Coast, Midwest and East Coast regions of the U.S. We then sell our products primarily through three types of arrangements: rack sales, bulk sales, and contract sales. For the twelve-month period ended March 31, 2003, we sold an average of 635,000 barrels per day of product through these arrangements.

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Rack sales are sales that do not involve continuing contractual obligations to purchase or deliver product. Rack 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 announce, via fax, website, e-mail and telephone, the rack sale price of various products for the following morning.



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Bulk sales are spot sales of large quantities of product to wholesalers, distributors and marketers in major cash markets. Bulk sales also may be made while the product is being transported in the major refined petroleum product pipelines. Because of supply and demand imbalances that occur from time to time in major cash markets around the country, the market price of product varies from location to location. We take advantage of these variations, commonly referred to as

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"basis differentials," 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.

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Contract sales are made pursuant to contracts, ranging from one month to six months in duration, in which we agree to deliver product to cruise ship operators, local market wholesalers, independent gasoline station chains and heating oil suppliers. The product delivered under a contract sale generally is priced at prevailing market rates, although occasionally we enter into fixed-price contracts.

Supply management services

        We provide supply management services to industrial, commercial and governmental ground fleet customers. We often combine these services with price management solutions to provide our customers an assured source of fuel at a predictable price. We have a growing customer base for our supply management services. Our fleet customers include waste disposal firms, retail consumer products companies, freight and delivery service providers, cable and communication companies, car rental firms, and city and state government agencies.

        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.

        Furthermore, using our supply management services, tax-exempt government fleet customers can purchase fuel and receive billing net of federal excise tax, eliminating the need for these customers to file for refunds. We believe that this additional service will allow us to attract additional governmental fleet customers.

        We currently offer three types of supply management services: delivered fuel price management, retail price management and logistical supply management. For the nine-month period ended March 31, 2003, we managed approximately 15,200 barrels of fuel per day under these arrangements.

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Delivered fuel price management contracts involve the sales of committed quantities of specific motor fuels delivered to a customer's proprietary vehicle fleet refueling locations at fixed prices for terms of up to three years. On a daily basis, for the customer's facilities, we procure product, schedule delivery, manage local inventory quantities and summarize the customer's fuel use by location and vehicle.



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Retail price management contracts, typically entered into for a period of up to 18 months, allow our customers to effectively fix the price they pay for motor fuel within a metropolitan area and reduce their exposure to retail price fluctuations. Under these arrangements, a customer's drivers will purchase fuel at any retail gasoline station within a metropolitan area and we settle the net financial difference between a stipulated retail price index for that metropolitan area and the customer's contract price on a monthly basis. We do not deliver physical product under these arrangements.



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Logistical supply management contracts allow our customers to use our proprietary web-based refined petroleum product procurement, inventory management, scheduling, routing, excise tax and consolidated billing services without any physical product delivery or price management services. These services allow our customers to operate more efficiently and reduce their overhead costs. Customers often initially contract for logistical supply management services and later expand the relationship to include a price management solution.

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RECENT DEVELOPMENTS

Acquisitions

Coastal Fuels assets

        On February 28, 2003, we acquired five Florida terminals, with an aggregate capacity of approximately 4.9 million barrels, and a related tug and barge operation, which we refer to collectively as the Coastal Fuels assets, from El Paso Corporation. The purchase price for the transaction was approximately $157 million, including approximately $37 million of product 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. For the twelve-month period ended December 31, 2002, these facilities sold an average of 29,000 barrels per day of bunker fuel, primarily to the cruise ship industry, and supplied approximately 28,000 barrels per day of gasoline and distillates. In addition, the Coastal Fuels assets allow us to lease capacity to the asphalt, commercial and government jet fuel, power generation and crude oil industries.

Fairfax, Virginia terminal

        On January 31, 2003, we acquired a 500,000 barrel terminal in Fairfax, Virginia, which increased our supply, distribution and marketing presence in the Mid-Atlantic market. The Fairfax terminal supplies refined petroleum products to the Washington, D.C. market which it receives off the Colonial Pipeline.

INDUSTRY TRENDS

Supply and demand

        The U.S. Department of Energy divides the United States into five geographic regions 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 56 refineries responsible for approximately 46% of total U.S. daily refining capacity. The Gulf Coast region historically has been a large shipper of petroleum products to PADD II, which is the Midwest region, and PADD I, which is the East Coast region. For the period 1991 to 2001, the amount of petroleum products shipped from the Gulf Coast region increased by approximately 28% to approximately 4.2 million barrels per day. The concentration of refining capacity and increased product flow in the Gulf Coast region has created an increasing need for transportation, storage and distribution facilities both in the Gulf Coast, as well as in the Midwest and East Coast regions. Furthermore, competition among refiners resulting from industry consolidation, combined with continued environmental pressures, government regulations and market conditions, increasingly is resulting in the closing of smaller, less economical inland refineries. This is creating even greater demand for petroleum products refined in the Gulf Coast region and increased opportunities for distribution and storage companies that transport refined petroleum products from the Gulf Coast to other regions.

Consolidation and specialization

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

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

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Major oil companies 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 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. In addition, we expect that acquisition opportunities will be available.

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 will allow us to benefit from the industry trends outlined above:

Significant asset base and shipping history

        The Gulf Coast region 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 in supply in the Gulf Coast and demand in the Midwest and East Coast regions. To purchase products in the Gulf Coast and sell the products in the Midwest or the East Coast regions, it is necessary to have a shipping history on common carrier pipelines and a network of terminals. We have a shipping history on four major refined petroleum product pipelines that provides us the benefit of allocated space on these common carrier pipelines during high demand periods to transport our product from the Gulf Coast to the Midwest and East Coast regions, which is an advantage over competitors that do not have as significant a shipping history.

        Supply disruptions, extreme weather, and other unforeseen factors may cause supply and demand imbalances in local markets resulting in larger basis differentials between local markets. Our geographically diverse network of terminals allows us to capitalize on the basis differentials by acquiring, transporting or storing product, using our assets, as well as those of third parties, in the locations that maximize the value of the product to 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, pipeline and tug and barge infrastructure to market various products and provide specialized supply, logistical and price management services to our customers. For the twelve-month period ended December 31, 2002, approximately 75% of the throughput on our terminal and pipeline infrastructure was driven by our

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own supply, distribution and marketing business. As a result, we do not rely primarily on third parties for our throughput activity.

        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.

Supply 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 management functions from a single source. We believe that we are the only significant independent fuel supply management services provider in the United States offering this extensive menu of services.

Acquisition of Coastal Fuels assets

        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:

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we have established a leading presence in key bunkering locations in various Florida ports, including the Port of Miami, Port Everglades, Cape Canaveral and Tampa;



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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;



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the terminals are located primarily in areas with limited opportunity for new terminal expansion because of zoning, land values and environmental considerations;



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no refineries exist in Florida and the major Florida markets are served by waterborne vessels due to the absence of major product supply pipelines;



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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;



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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



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a number of opportunities to increase operational efficiency exist with our current operations in Florida.

Strong management team

        Our executive management team has extensive industry experience and several members of the team have worked together for over 20 years. Several members of executive management were instrumental in building Associated Natural Gas Corporation, a natural gas gathering, processing and marketing company, into a company with an enterprise value of over $800 million at the time of its 1994 sale to Panhandle Eastern Corporation.

Technology and back-office infrastructure

        We have developed monitoring equipment and software to create an integrated, flexible system that allows us to effectively manage petroleum products throughout our terminal, pipeline and water-

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borne infrastructure on a real time basis. We also use a proprietary web-based system in our supply 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, while allowing our customers to closely monitor fuel usage and costs 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, which we have developed to administer excise taxes on product that is handled at our terminals. For the twelve-month period ended December 31, 2002, we remitted over $1 billion in excise taxes to taxing authorities.

        We also have substantial experience in managing complex petroleum product supply and demand arrangements. Our extensive back office and technology infrastructure has been established through significant time and capital commitments and which we believe gives us an advantage over competitors.

Risk management strategy and policy

        The market value of our inventory changes on a daily basis. We employ risk management policies and procedures to reduce commodity price risks with respect to our discretionary product inventories and obligations. We hedge our discretionary inventory, net of firm commitments, with New York Mercantile Exchange, or NYMEX, futures contracts. Our inventory and firm commitment position is reconciled daily and the commodity price exposure of the net position is managed with NYMEX futures contracts. As a result of this strategy, we reduce exposure to commodity price risk, but not to basis differentials. Our hedging 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 during adverse commodity market conditions.

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:

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Capitalize on the acquisition of the Coastal Fuels assets.



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We intend to take advantage of the steady year-round demand in the ports we serve.



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We intend to pursue growth opportunities in both the cruise ship bunkering and light oil businesses.



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We intend to expand our bunkering service to shipping markets outside of the cruise ship industry.



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Capitalize on our infrastructure by linking our significant asset base to our supply, distribution and marketing business.



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We intend to take advantage of our extensive network of terminals, as well as our shipping history on common carrier pipelines, to capitalize on supply and demand variations and basis differentials among the Gulf Coast, Midwest and East Coast regions.



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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.



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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,

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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.

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We intend to capitalize on the favorable location of, and significant capacity at, our Brownsville terminal complex. The Brownsville terminal complex is the primary provider for its area. A pipeline is scheduled to be completed in 2003 that will carry product between Mexico and the United States and will terminate at the Brownsville terminal complex.



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Pursue attractive acquisitions.



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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 of large energy companies divesting their distribution and terminal operations, we believe there will continue to be significant acquisition opportunities.



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Actively pursue new sales and distribution opportunities by marketing our services to hypermarkets and unbranded retailers of gasoline.



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Expand our supply management services.



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We intend to expand our existing supply management team and equipment to enable us to provide supply management services to additional customers with large ground transportation fleets.



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We intend to actively market our supply management solutions for managing and obtaining excise tax exemptions on fuel purchases to government fleet customers.



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Continue to manage our exposure to commodity price volatility.



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Our hedging 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.



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Our hedging strategy also allows us to concentrate on maximizing the value of our physical assets and expanding our supply management services business.

Other information

        Our principal executive offices are located at 1670 Broadway, Suite 3100, Denver, Colorado 80202. Our telephone number is (303) 626-8200.

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SUMMARY OF THE TERMS OF THE EXCHANGE OFFER

Issuer	$1,000 principal amount of exchange notes will be issued in exchange for each $1,000 principal amount of old notes validly tendered.
Resale	Based upon interpretations by the staff of the Securities and Exchange Commission set forth in no-action letters of Exxon Capital Holdings Corporation (available April 13, 1988), Morgan Stanley & Co. Incorporated (available June 5, 1991) and Shearman & Sterling (available July 2, 1993), we believe that exchange notes may be offered for resale, resold or otherwise transferred to you without compliance with the registration and prospectus delivery requirements of the Securities Act, unless you:
	•	are an "affiliate" of ours within the meaning of Rule 405 under the Securities Act;
	•	are a broker-dealer who purchased the old notes directly from us for resale under Rule 144A or any other available exemption under the Securities Act of 1933;
	•	acquired the exchange notes other than in the ordinary course of your business; or
	•	have an arrangement with any person to engage in the distribution of exchange notes.
	However, we have not submitted a no-action letter and there can be no assurance that the SEC will make a similar determination with respect to the exchange offer. Furthermore, in order to participate in the exchange offer, you must make the representations set forth in the letter of transmittal that we are sending you with this prospectus.
Expiration Date	The exchange offer will expire at 5:00 p.m., New York City time, on                        , 2003, unless we in our sole discretion extend it. We refer to this date, as it may be extended, as the expiration date.
Conditions to the Exchange Offer	The exchange offer is subject to certain customary conditions, some of which may be waived by us. See "The Exchange Offer—Conditions to the Exchange Offer."

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Procedure for Tendering Old Notes	If you wish to accept the exchange offer, you must complete, sign and date the letter of transmittal, or a copy of the letter of transmittal, in accordance with the instructions contained in this prospectus and in the letter of transmittal, and mail or otherwise deliver the letter of transmittal, or the copy, together with the old notes and any other required documentation, to the exchange agent at the address set forth in this prospectus. If you are a person holding the old notes through The Depository Trust Company and wish to accept the exchange offer, you must do so through The Depository Trust Company's Automated Tender Offer Program, by which you will agree to be bound by the letter of transmittal. By executing or agreeing to be bound by the letter of transmittal, you will be making a number of important representations to us as described under "The Exchange Offer—Purpose and Effect."
	We will accept for exchange any and all old notes that are properly tendered in the exchange offer prior to the expiration date. The exchange notes issued in the exchange offer will be delivered promptly following the expiration date. See "The Exchange Offer—Terms of the Exchange Offer."
Special Procedures for Beneficial Owners	If you are the beneficial owner of old notes registered in the name of a broker, dealer, commercial bank, trust company or other nominee and wish to tender in the exchange offer, you should contact the person in whose name your notes are registered and promptly instruct the person to tender on your behalf.
Guaranteed Delivery Procedures	If you wish to tender your old notes and time will not permit your required documents to reach the exchange agent by the expiration date, or the procedure for book-entry transfer cannot be completed on time, you may tender your notes according to the guaranteed delivery procedures. For additional information, you should read the discussion under "Exchange Offer—Guaranteed Delivery Procedures."
Withdrawal Rights	The tender of the old notes pursuant to the exchange offer may be withdrawn at any time prior to the expiration date.
Acceptance of Old Notes and Delivery of Exchange Notes	Subject to customary conditions, we will accept old notes that are properly tendered in the exchange offer and not withdrawn prior to the expiration date. The exchange notes will be delivered as promptly as practicable following the expiration date.

10

Consequence of Failure to Exchange	Old notes that are not tendered, or that are tendered but not accepted, will be subject to their existing transfer restrictions. Unless we are required by the registration rights agreements to register the notes pursuant to Rule 415 of the Securities Act on a "shelf" registration statement, generally we will have no further obligation to provide for registration under the Securities Act of such old notes.
Registration Rights Agreement; Effect on Holders	We sold the old notes in a private placement in reliance on Section 4(2) of the Securities Act. The old notes were immediately resold by the initial purchasers in reliance on Rule 144A and Regulation S under the Securities Act. On May 30, 2003, we entered into a registration rights agreement with the initial purchasers of the old notes requiring us to make this exchange offer. The registration rights agreement also requires 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
	•	consummate the exchange offer no later than December 26, 2003.
	See "The Exchange Offer—Purpose and Effect." If we do not do so, additional interest payments will be payable on the old notes.
Certain U.S. Federal Income Tax Considerations	The exchange of old notes for exchange notes by tendering holders will not be a taxable exchange for federal income tax purposes, and such holders will not recognize any taxable gain or loss or any interest income for federal income tax purposes as a result of such exchange. See "Certain United States Federal Income Tax Consequences."
Exchange Agent	Wells Fargo Bank Minnesota, National Association is serving as exchange agent in connection with the exchange offer.
Use of Proceeds	We will not receive any proceeds from the exchange offer.

11

SUMMARY OF THE TERMS OF THE EXCHANGE NOTES

        The exchange offer relates to the exchange of up to $200 million principal amount of exchange notes for up to an equal principal amount of old notes. The form and terms of the exchange notes are substantially identical to the form and terms of the old notes, except the exchange notes will be registered under the Securities Act. Therefore, the exchange notes will not bear legends restricting their transfer. The exchange notes will evidence the same debt as the old notes (which they replace). The old notes and the exchange notes are governed by the same indenture. The summary below describes the principal terms of the exchange notes. Certain of the terms and conditions described below are subject to important limitations and exceptions. The "Description of the Exchange Notes" section of this prospectus contains a more detailed description of the terms and conditions of the exchange notes.

Issuer	TransMontaigne Inc.
Notes Offered	We are offering $200,000,000 aggregate principal amount of our 91/8% Series B Senior Subordinated Notes due 2010, issued under an indenture dated as of May 30, 2003.
Interest	The exchange notes will accrue interest from the date of their issuance at the rate of 91/8% per year. Interest on the exchange notes will be payable semi-annually in arrears on each June 1 and December 1 commencing on December 1, 2003.
Maturity Date	June 1, 2010.
Guarantees	Certain of our existing subsidiaries and certain of our future domestic subsidiaries will guarantee jointly and severally the exchange notes on an unsecured, full and unconditional senior subordinated basis. See "Description of the Exchange Notes—Note guarantees."
Ranking	The exchange notes will be unsecured senior subordinated obligations and will be subordinated to all of our existing and future senior debt. The notes will rank equal in right of payment with all our other existing and future senior subordinated debt and will rank senior in right of payment to all of our subordinated debt.
	The exchange notes will be guaranteed by our subsidiaries, other than our minor subsidiaries that are inactive and have no assets or operations. Our subsidiaries' guarantees with respect to the exchange notes will be full and unconditional, joint and several general unsecured senior subordinated obligations of such guarantor subsidiaries and will be subordinated to all of such guarantor subsidiaries' existing and future senior debt. The guarantees will rank equal in right of payment with any senior subordinated indebtedness of the guarantor subsidiaries and will rank senior in right of payment to such guarantor subsidiaries' subordinated debt, if any. Because the exchange notes are subordinated, in the event of bankruptcy, liquidation or dissolution, or certain other events, including certain defaults on senior debt, we may be prevented from making payments on the exchange notes. The term "senior debt" is defined in the "Description of the Exchange Notes" section of this prospectus.

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	The notes will be structurally subordinated to the liabilities of any subsidiary that is not a guarantor to the extent of such subsidiary's assets, if any.
	At March 31, 2003, after giving effect to the offering and the application of the net proceeds for the offering of the old notes as described under "Use of proceeds," we and our guarantor subsidiaries would have had approximately $65.0 million of senior debt outstanding on a consolidated basis.
Optional Redemption	Prior to June 1, 2007, the exchange notes may be redeemed at our option, in whole or in part, at a make-whole price described under "Description of the Exchange Notes—Optional redemption." We may redeem the exchange notes, in whole or in part, at any time on or after June 1, 2007 at a redemption price equal to 104.563% of the principal amount thereof plus a premium declining ratably to par by 2010 plus accrued and unpaid interest and additional interest, if any. In addition, at any time on or prior to June 1, 2006, we may redeem up to 35% of the aggregate principal amount of the exchange notes and any additional notes issued under the indenture with the net cash proceeds of certain equity offerings at a redemption price equal to 109.125% of the principal amount thereof, plus accrued and unpaid interest and additional interest, if any, provided that:
	•	at least 65% of the principal amount of the exchange notes and any such additional notes remain(s) outstanding immediately after the occurrence of such redemption; and
	•	such redemption occurs within 90 days of the date of the initial receipt of the proceeds of any such equity offering.
Change of Control	Upon certain change of control events, each holder of the exchange notes may require us to repurchase all or a portion of their notes at a purchase price equal to 101% of the principal amount thereof, plus accrued and unpaid interest and additional interest, if any. Our ability to repurchase the notes upon a change of control event will be limited by the terms of our debt agreements, including our working capital facility. We may not have the financial resources to repurchase the notes. See "Description of the Exchange Notes—Change of control."
Registration Rights; Additional Payments	In connection with the offering of the old notes, we granted registration rights to holders of the old notes. We agreed to consummate an offer to exchange the old notes for the related series of exchange notes and to take other actions in connection with the exchange offer by the dates specified in the registration rights agreements. In addition, under certain circumstances, we may be required to file a shelf registration statement to cover resales of the old notes held by you.

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	We have agreed to make additional interest payments to holders of the notes under certain circumstances if we do not comply with our obligations under the registration rights agreement. See "Description of the Exchange Notes."
Form of Notes	The exchange notes to be issued in the exchange offer will be represented by one or more global securities deposited with Wells Fargo Bank Minnesota, National Association for the benefit of Depository Trust Company, or DTC. You will not receive exchange notes in certificated form unless one of the events set forth under the heading "Description of the Exchange Notes—Form of Exchange Notes" occurs. Instead, beneficial interests in the exchange notes to be issued in the exchange offer will be shown on, and transfer of these interests will be effected only through, records maintained in book-entry form by DTC with respect to its participants.
Certain Covenants	We will issue the exchange notes under an indenture with Wells Fargo Bank Minnesota, National Association, as trustee. The indenture governing the exchange notes will, among other things, restrict our ability to:
	•	incur additional indebtedness;
	•	pay dividends on, redeem or repurchase our capital 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 our assets and the assets of our subsidiaries on a consolidated basis.
	These covenants are subject to important exceptions and qualifications, which are described in the "Description of the Exchange Notes—Certain covenants" section of this registration statement.
	As to our restricted subsidiaries, the indenture governing the exchange notes also will limit their ability to enter into or become subject to arrangements that would restrict or limit their ability to:
	•	pay dividends or make other distributions to us or other restricted subsidiaries;
	•	make loans or advances to us;
	•	and transfer any assets to us.
Use of Proceeds	We will not receive any cash proceeds upon completion of the exchange offer.
Risk Factors	Investing in the exchange notes involves risks. You should refer to the section entitled "Risk Factors" for an explanation of the material risks of participating in the exchange offer and investing in the exchange notes.

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SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA

        You should read the following summary historical and pro forma financial data in conjunction with the historical consolidated financial statements and related notes and "Management's discussion and analysis of financial condition and results of operations" included elsewhere in this prospectus.

        The summary historical consolidated financial data for TransMontaigne Inc. as of and for each of the years ended June 30, 2002, 2001 and 2000 have been derived from our audited consolidated financial statements. The summary historical consolidated financial data as of and for the nine months ended March 31, 2003 have been derived from our unaudited consolidated financial statements. In the opinion of management, the unaudited consolidated financial statements from which the data below is derived contain all adjustments, which consist only of normal recurring adjustments, necessary to present fairly our financial position and results of operations as of the applicable dates and for the applicable periods. Historical results are not necessarily indicative of the results to be expected in the future.

        The summary pro forma financial data for the nine months ended March 31, 2003 and the year ended June 30, 2002, has been prepared to give pro forma effect to the Coastal Fuels assets acquisition as if it had occurred on July 1, 2001, as adjusted to reflect pro forma interest expense assuming the net proceeds from the offering of the old notes were used to repay our senior secured term loan. The summary pro forma financial data is for informational purposes only and should not be considered indicative of the actual results that would have been achieved had the transaction actually been consummated on the date indicated. The pro forma results are not necessarily indicative of results to be expected in future periods.

	Pro Forma As Adjusted						Historical
							Nine Months Ended March 31,						Years Ended June 30,
	Nine Months Ended March 31, 2003			Year Ended June 30, 2002
							2003			2002			2002			2001			2000
	(dollars in thousands)
Statement of Operations Data:
Supply, distribution and marketing:
Revenues	$	6,356,653		$	6,489,196		$	5,949,896		$	4,001,858		$	6,001,170		$	5,182,492		$	5,014,752
Less costs of product sold		(6,290,535	)		(6,414,736	)		(5,896,329	)		(3,953,387	)		(5,945,386	)		(5,154,492	)		(4,995,899	)
Net operating margin(1)		66,118			74,460			53,567			48,471			55,784			28,000			18,853
Terminals, pipelines, and tugs and barges:
Revenues		84,013			93,926			56,204			46,455			63,386			82,305			78,522
Direct operating costs and expenses		(41,865	)		(59,108	)		(21,981	)		(20,005	)		(27,668	)		(36,415	)		(34,268	)
Net operating margin(1)		42,148			34,818			34,223			26,450			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)	$	108,266		$	109,278		$	87,790		$	74,921		$	91,502		$	73,890		$	73,597

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Total net operating margins		$	108,266		$	109,278		$	87,790		$	74,921		$	91,502		$	73,890		$	73,597
Costs and expenses:
Selling, general and administrative			(29,957	)		(38,996	)		(28,547	)		(25,605	)		(35,211	)		(34,072	)		(41,680	)
Depreciation and amortization			(16,067	)		(20,556	)		(13,400	)		(12,449	)		(16,556	)		(19,510	)		(22,344	)
Corporate relocation and transition			(1,449	)		(6,316	)		(1,449	)		(315	)		(6,316	)		—			—
Impairment of long-lived assets			—			—			—			—			—			—			(50,136	)
	Operating income (loss)		60,793			43,410			44,394			36,552			33,419			20,308			(40,563	)
Interest expense, net			(21,984	)		(27,881	)		(9,950	)		(9,125	)		(11,837	)		(15,215	)		(25,121	)
Other expense, net			(717	)		(7,339	)		(538	)		(1,251	)		(7,546	)		(9,235	)		(5,350	)
Gain (loss) on disposition of assets, net			—			(13	)		—			(1,295	)		(13	)		22,146			13,930
	Earnings (loss) before income taxes		38,092			8,177			33,906			24,881			14,023			18,004			(57,104	)
Income (taxes) benefit			(14,475	)		(3,189	)		(12,888	)		(9,455	)		(5,465	)		(6,666	)		19,167
	Net earnings (loss) before cumulative effect of a change in accounting principle	$	23,617		$	4,988		$	21,018		$	15,426		$	8,558		$	11,338		$	(37,937	)
Other Financial Data:
EBITDA(2)		$	77,055		$	65,610		$	58,168		$	49,156		$	51,412		$	65,024		$	(2,699	)
Operating results for debt covenant compliance(3)		$	58,602		$	78,586		$	39,715		$	63,414		$	64,388		$	61,196		$	33,507
Net cash provided (used) by operating activities		$	—		$	—		$	73,770		$	(93,660	)	$	(101,512	)	$	51,936		$	267,526
Net cash provided (used) by investing activities		$	—		$	—		$	(129,753	)	$	104,599		$	102,778		$	(18,969	)	$	77,902
Net cash provided (used) by financing activities		$	—		$	—		$	51,445		$	(24,553	)	$	3,811		$	(61,130	)	$	(305,417	)
Total debt to total capital			—			—			45.2	%		25.9	%		39.0	%		30.5	%		38.4	%
Total debt to EBITDA			—			—			—			—			3.9	x		2.3	x		—
Total debt to operating results for debt covenant compliance			—			—			—			—			3.1	x		2.5	x		6.2	x
EBITDA to interest expense, net			3.5	x		2.4	x		5.8	x		5.4	x		4.3	x		4.3	x		(0.1)	x
Operating results for debt covenant compliance to interest expense, net			2.7	x		2.8	x		4.0	x		7.0	x		5.4	x		4.0	x		1.3	x
Ratio of earnings to fixed charges			2.6	x		1.3	x		4.0	x		—			1.9	x		1.9	x		—	(4)

	Pro Forma As Adjusted		Historical
			March 31,				June 30,
	March 31, 2003	June 30, 2002
			2003		2002		2002		2001		2000
	(dollars in thousands)
Balance Sheet Data:
Cash and cash equivalents	—	—	$	26,314	$	12,161	$	30,852	$	25,775	$	53,938
Working capital(5)	—	—	$	91,515	$	160,354	$	168,092	$	31,934	$	134,807
Total assets	—	—	$	927,883	$	683,930	$	735,328	$	712,365	$	834,572
Total debt	—	—	$	265,000	$	125,500	$	198,312	$	150,000	$	206,995
Total preferred stock	—	—	$	104,153	$	182,136	$	105,360	$	174,825	$	170,115
Total common stockholders' equity	—	—	$	217,017	$	176,746	$	205,350	$	167,550	$	161,983

(1)

Net operating margins represent revenues, less direct operating costs and expenses.

(2)

EBITDA is defined as earnings before income taxes, interest expense, net, other financing costs, net, and depreciation and amortization. We believe that, in addition to cash flow from operating activities and net earnings (loss), EBITDA is a useful financial performance measurement for assessing operating performance since it provides an additional basis to evaluate our ability to incur and service debt and to fund capital expenditures. To evaluate EBITDA, the components of EBITDA such as net operating margin and direct operating expenses and the variability of such components over time, also should be considered. EBITDA should not be construed, however, as an alternative to operating income (loss) (as determined in

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accordance with generally accepted accounting principles ("GAAP")) as an indicator of our operating performance, or to cash flows from operating activities (as determined in accordance with GAAP) as a measure of liquidity.

(3)

We believe that operating results for debt covenant compliance is a useful measure in evaluating our performance because it eliminates the impact on our operating results from gains recognized and deferred on discretionary inventory volumes and the impairment of our inventories—minimum volumes. We believe that, in addition to operating income, cash flow from operating activities and EBITDA, operating results for debt covenant compliance is a useful financial performance measurement reflecting our ability to incur and service debt and to fund capital expenditures. In evaluating operating results for debt covenant compliance, we believe that consideration should be given, among other things, to the amount by which operating results for debt covenant compliance exceeds interest costs for the period; how operating results for debt covenant compliance compares to principal repayments on debt for the period; and how operating results for debt covenant compliance compares to capital expenditures for the period. As a result of the implementation of EITF 02-03, our inventories—minimum volumes and —discretionary volumes are carried at the lower of cost (first in, first out) or market, while our risk management contracts are carried at market. As a result, if market prices are increasing during the end of one quarter and into the beginning of the next quarter, we may show significant losses on risk management contracts at the end of the prior quarter and significant gains recognized on our beginning inventories—discretionary volumes in the following quarter. While this volatility tends to offset over several quarters, it can result in significant volatility in our reported operating income and EBITDA between any two quarters. Because the inventory adjustments that affect operating income can be volatile on a quarterly basis, management uses operating results for debt covenant compliance to monitor and manage the operations of our business segments. Management believes that operating results for debt covenant compliance provides an appropriate measure of our debt service capabilities and, as a result, this measure is used as a measure of our financial performance in our borrowing arrangements. Under Financial Accounting Standards Board Statement of Financial Accounting Standards No. 131,Disclosures About Segments of an Enterprise and Related Information, we are required to report measures of profit and loss that are used by our chief operating decision maker in assessing financial performance for each of our reportable segments in the footnotes to our consolidated financial statements and, accordingly, we report operating results for debt covenant compliance in connection with our operating segment disclosures.

Operating results for debt covenant compliance and EBITDA should not be construed as alternatives to operating income as determined in accordance with generally accepted accounting principles as indicators of our operating performance, or to cash flows from operating activities, as determined in accordance with generally accepted accounting principles as a measure of liquidity. The following table reconciles our operating results for debt covenant compliance to EBITDA and EBITDA to net earnings.

								Historical
		Pro Forma As Adjusted
								Nine Months Ended March 31,						Years Ended June 30,
		Nine Months Ended March 31, 2003
					Year Ended June 30, 2002
								2003			2002			2002			2001			2000
		(in thousands)
Operating results for debt covenant compliance		$	58,602		$	78,586		$	39,715		$	63,414		$	64,388		$	61,196		$	33,507
Gains recognized on beginning inventories—discretionary volumes			12,644			—			12,644			—			—			—			—
Net operating margin recognized on sale of inventories—minimum volumes			18,854			—			18,854			—			—			—			—
Lower of cost or market write down on base operating inventory volumes			(12,412	)		—			(12,412	)		—			—			—			—
Lower of cost or market writedowns on minimum inventory volumes			(633	)		(12,963	)		(633	)		(12,963	)		(12,963	)		(18,318	)		—
Impairment of long lived assets			—			—			—			—			—			—			(50,136	)
Gain (loss) on disposition of assets, net			—			(13	)		—			(1,295	)		(13	)		22,146			13,930
EBITDA			77,055			65,610			58,168			49,156			51,412			65,024			(2,699	)
Depreciation and amortization			(16,067	)		(20,556	)		(13,400	)		(12,449	)		(16,556	)		(19,510	)		(22,344	)
Interest expense, net			(21,984	)		(27,881	)		(9,950	)		(9,125	)		(11,837	)		(15,215	)		(25,121	)
Other financing costs, net			(912	)		(8,996	)		(912	)		(2,701	)		(8,996	)		(12,295	)		(6,940	)
Income tax (expense) benefit			(14,475	)		(3,189	)		(12,888	)		(9,455	)		(5,465	)		(6,666	)		19,167
	Net earnings before cumulative effect of a change in accounting principle	$	23,617		$	4,988		$	21,018		$	15,426		$	8,558		$	11,338		$	(37,937	)

(4)

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. Earnings for such year were insufficient to cover fixed charges by approximately $57.1 million.

(5)

Working capital is defined as current assets less current liabilities.

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RISK FACTORS

Our business, operations and financial condition are subject to various risks. You should consider carefully the following risk factors, in addition to the other information set forth in this prospectus, before deciding to participate in the exchange offer. The factors set forth below, however, are generally applicable to the old notes as well as the exchange notes. This section does not describe all risks applicable to us, our industry or our business, and it is intended only as a summary of certain material risk factors.

RISKS RELATED TO OUR BUSINESS

The profitability of our operations depends on the availability to us of supplies of petroleum products. A significant decrease in available supplies for any reason could adversely affect our sales and results of operations.

        The availability of supplies of refined petroleum product is essential to our operations. A material decline in refined petroleum product supplies could adversely affect our revenues from throughput and storage fees and from bulk, contract and rack product sales. Such a material decline in product supplies may be caused by natural disasters, adverse weather conditions, terrorist attacks and other events beyond our control. Furthermore, we do not have long-term supply contracts with refiners and our suppliers could cease selling product to us for any one of several reasons, including a lack of crude oil supplies, price or volume competition and external economic or political events. For example, a crude oil supply disruption in the Middle East or South America could lead the major oil companies and the independent refining and marketing companies to retain all of their refined petroleum product supplies for their own distribution operations, thus creating a shortage of supply available to us. Such a shortage could have a material adverse effect on our supplies of product and hinder our ability to earn throughput fees or sales revenues.

We are subject to the risk of contract non-performance by our customers.

        We have contract sales agreements, fuel supply management agreements, storage agreements and other contractual relationships with our customers. We therefore could be exposed to unplanned expenses and losses if any of those parties fails to honor its contractual commitments or files for bankruptcy. Accordingly, we are exposed to an increased level of direct and indirect counter-party credit and performance risk. For example, when we enter into long-term sale contracts with our customers, the contract sets a fixed price for our sale of product to the customer. In accordance with our risk management policies and practices, we enter into futures contracts to protect against price fluctuations. However, if the customer with whom we have entered into the long-term sale contract then fails to honor its contractual commitments or files for bankruptcy, we would remain liable for the obligations under the long-term futures contract that we would need to unwind. If the price of product has changed adversely since we entered into the futures contract, we could be forced to make a substantial payment to settle the futures contract that would not be offset by corresponding income and our operations could suffer. There can be no assurance that we have adequately assessed the creditworthiness of our existing or future customers or that there will not be an unanticipated deterioration in their creditworthiness.

We face intense competition in our supply, distribution and marketing activities, as well as in our terminal and pipeline activities.

        We compete with other petroleum companies, national, regional and local pipeline and terminal companies, the major integrated oil companies, their marketing affiliates, and independent brokers and

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marketers of widely varying sizes, financial resources and experience. In particular, our ability to compete could be harmed by factors we cannot control, including:

•

price competition from major oil companies or other independent refined product companies, some of which are substantially larger than we are, have greater financial resources and control substantially greater supplies of petroleum products than we do;



•

abundance of supply of petroleum products keeping petroleum prices low or unchanging;



•

the perception that another company can provide better service; and



•

the availability of alternative supply points, or supply points located closer to our customers' operations.

        If we are unable to compete with services offered by other petroleum enterprises, our results of operations may be adversely affected.

Potential customers of our supply management services may be unwilling to outsource this important function.

        Because the provision of supply management services is a relatively new industry, potential customers may not realize that they can outsource their fuel supply management functions in a cost effective manner. Furthermore, our supply management services require the companies we service to outsource a vital part of their operational activities to us which requires trust in our ability to fulfill their product needs. These potential customers may consider this function too important to their operations to outsource. Because we may have less name recognition than some of our competitors in the petroleum products industry, it may be difficult for us to obtain additional contracts for supply management services.

A portion of our revenues is generated under contracts that must be renegotiated periodically. The failure to successfully renew significant contracts, or renewals on less favorable terms, could adversely affect our revenues and results of operations.

        Much of our contract-based revenues are generated under contracts generally having a duration of one year or less. As these contracts expire periodically, they must be renegotiated and extended or replaced. Although we actively pursue the renegotiation, extension and/or replacement of these contracts, we cannot be certain that we will be able to extend or replace these contracts when they expire or that the terms of any renegotiated contracts will be as favorable as the existing contracts.

        In particular, our ability to extend or replace sales contracts could be harmed by competitive factors we cannot control, such as those described above under "We face intense competition in our supply, distribution and marketing activities, as well as in our terminal and pipeline activities" and such as the following:

•

the abundance of storage capacity in the markets we serve;



•

the failure of our technologies that support our performance under our contracts; and



•

the election by a customer to provide the services for themselves, eliminating the need for a contract with us.

If we cannot successfully renew significant contracts or have to renew them on less favorable terms, our revenues from these arrangements could decline and our results of operations could suffer.

        Our business involves many hazards and operational risks, some of which may not be covered by insurance. Our operations are subject to the many hazards inherent in the transportation and storage of volatile and toxic petroleum products, including explosions, pollution, release of toxic substances, fires,

19

accidents on rivers or at sea and other hazards that could result in environmental damages, personal injuries, loss of life and suspension of operations. Our operations also are subject to risks associated with natural disasters, adverse weather conditions, terrorist attacks and other events beyond our control. If any of these events were to occur, we could suffer substantial losses because of personal injury or loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental damage resulting in curtailment or suspension of our related operations. Although we maintain insurance against these types of risks to the extent and in amounts that we believe are reasonable, our financial condition and operations could be adversely affected if a significant event occurs that is not fully covered by insurance.

Our hedging activities may not precisely match our sales of physical inventory and therefore expose us to financial risks and reduce our opportunity to benefit from price increases.

        In order to protect against price volatility with respect to our refined petroleum product inventories, we enter into NYMEX futures contracts. These contracts reduce exposure to subsequent price drops, but also can result in financial risk if the expiration dates of the futures contracts do not precisely match the timing of the sales of the underlying inventory. In addition, while futures contracts reduce our exposure to subsequent price drops, they also reduce the opportunity to benefit when commodity prices rise.

        When we purchase refined petroleum products without a corresponding firm sale commitment, 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 hedging arrangement. In order to accurately hedge against price fluctuations, we must attempt to 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 hedge against the same inventory. We refer to this as "rolling" the hedges. While these conditions frequently exist on a small scale, if market conditions are adverse for an extended period, we can suffer financial losses.

        Our existing operations require us to maintain a base operating inventory of approximately 3.8 million barrels, consisting primarily of tank bottoms, product in transit and pipeline fill. We generally do not hedge our base operating inventory because the base operating inventory is not available for immediate sale. As a result, any futures contracts used to hedge the base operating inventory 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. Our risk policy, however, allows our management team the discretion under certain market conditions to hedge up to 500,000 barrels of our base operating inventory, which would reduce the unhedged inventory to approximately 3.3 million barrels, or to leave up to 500,000 barrels of our discretionary inventory unhedged, which would increase our unhedged inventory to approximately 4.3 million barrels. We decide whether to hedge a portion of our base operating inventory or to leave a portion of our discretionary inventory unhedged depending on our expectations of future market changes. To the extent that we do not hedge a portion of our inventory and commodity prices move adversely, we could suffer losses on that inventory.

        We maintain a system of internal controls to assure there is no unauthorized trading or speculation on commodity prices. However, unauthorized speculative trades could occur that may expose us to substantial losses to cover a position in the futures contract, which may in turn have a material adverse effect on our revenues, cash flows and results of operations.

20

Changes in commodity prices subject us to margin calls which may adversely affect our liquidity.

        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 NYMEX in amounts that may be material. For example, we may enter into a futures contract to hedge against a fixed-price firm sales commitment to sell and deliver product on a future date. If commodity prices fall 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 decrease in the commodity price. If our obligation to sell and deliver product under a fixed-price firm sales commitment extends over a period of several months, we would be required to fund significant margin deposits which would decrease our available cash balances until we receive payment from our customer for delivery of the underlying physical product. If commodity prices rise before the expiration date of the futures contract, a portion of our margin call deposits with the NYMEX will be returned to us. 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.

A sustained failure of the complex, proprietary technology, including computer software, that we use to link our facilities and to purchase and sell refined petroleum products could reduce our revenues, cause us to suffer increased expenses and adversely affect our business.

        We use complex, proprietary computer software and techniques to purchase refined petroleum product and to market, transport and distribute product to our facilities and customers. A sustained outage could significantly adversely affect our business by preventing us from:

•

acquiring adequate supplies and delivering them to our terminals and customers;



•

transporting product on a timely basis to locations and facilities where we have delivery obligations;



•

transporting product to markets in which we can profit from basis differentials;



•

marketing and selling product on a timely basis or at the best available prices; and



•

being able to properly manage the needs of customers for which we provide supply management services.

        In addition, refiners could elect to reduce their supply of product to us or stop supplying us altogether if they were injured by a failure of our systems or determined that we had become an unreliable customer. Similarly, our customers could elect to cease purchasing from us or reduce the volumes of product they purchase from us. In each case, we could lose revenue and suffer increased expenses that would adversely affect our results of operations.

Our operations and sales volumes are dependent upon demand for petroleum products by distributors, marketers, wholesalers and commercial end users in the Gulf Coast, Midwest and East Coast regions of the United States. Any decrease in this demand could adversely affect our business.

        Our business depends in large part on the demand for refined petroleum products in the markets served by our transportation and storage network. Our earnings and cash flow are dependent on high sales volumes. The volumes of our sales can be adversely affected by the prices of refined products, which are subject to significant fluctuation depending upon numerous factors beyond our control, including the supply of and demand for gasoline and other refined products. The supply of and demand

21

for refined products can be affected by, among other things, changes in domestic and foreign economies, political affairs, terrorism and the threat of terrorism, production levels, industry-wide inventory levels, the availability of imports, the marketing of gasoline and other refined products by competitors, the marketing of competitive fuels, the impact of energy conservation efforts and government regulation.

        Sales volumes also are affected by regional factors, such as local market conditions, the availability of transportation systems with adequate capacity, transportation costs, fluctuating and seasonal demands for products, changes in transportation and travel patterns, variations in weather patterns from year to year and the operations of companies providing competing services.

We may not be successful in growing through acquisitions or integrating effectively and efficiently any businesses and operations we may acquire. Any future acquisitions may substantially increase the levels of our indebtedness.

        Part of our business strategy includes acquiring additional terminal and storage facilities that complement our existing asset base and distribution capabilities. In order to expand our business through the selective acquisitions of new or expanded facilities, we must identify those opportunities. We cannot be certain that we will be able to identify appropriate opportunities for expansion which will satisfy our target rates of return, obtain financing on acceptable terms, negotiate satisfactory terms of such acquisitions, or that any such acquisitions will improve our operating results.

        Acquisitions may require substantial capital or the incurrence of substantial indebtedness. As a result, our capitalization and results of operations may change significantly as a result of future acquisitions. Any additional debt financing could significantly increase our interest expense and involve restrictive covenants. Furthermore, you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in connection with any future acquisitions.

        Unexpected costs or challenges may arise whenever businesses with different operations and management are combined. Inefficiencies and difficulties may arise because of unfamiliarity with new assets and new geographic areas of any acquired businesses. Successful business combinations will require our management and other personnel to devote significant amounts of time to integrating the acquired businesses with our existing operations. These efforts may temporarily distract their attention from day-to-day business and other business opportunities. In addition, the management of the acquired business may not join our management team. Any change in management may make it more difficult to integrate an acquired business with our existing operations. Following an acquisition, we may discover previously unknown liabilities associated with the acquired business for which we may have no recourse under applicable indemnification provisions.

        In February 2003, we acquired the Coastal Fuels assets. This acquisition was significant in relation to the size and scope of our existing terminaling operations. We also have had no prior experience in tug and barge operations. If we do not successfully integrate the Coastal Fuels assets and our other acquisitions, or if there is any significant delay in achieving such integration, our business and financial condition could be adversely affected.

        Furthermore, pursuant to the terms of the purchase, certain of El Paso's subsidiaries, including El Paso CGP Company, formerly The Coastal Corporation, made representations and warranties to us on which we relied when completing the purchase, agreed to indemnify us for certain losses under the purchase agreement, and entered into certain long-term contracts with us for storage of petroleum products and other services. El Paso Corporation also guaranteed certain of the obligations of its subsidiaries to us. If El Paso Corporation and El Paso CGP Company are unable to satisfy their obligations under the purchase agreement and related contracts or file for bankruptcy, we could suffer financial losses, incur expenses or lose revenues.

22

Our operations are subject to governmental laws and regulations relating to the protection of the environment that may expose us to significant costs and liabilities.

        The risk of substantial environmental costs and liabilities is inherent in pipeline, transport and terminal operations and we may incur substantial environmental costs and liabilities. Our operations and activities are subject to significant federal, state and local laws and regulations relating to the protection of the environment. These include, for example, the Federal Clean Air Act and analogous state laws, which impose obligations related to air emissions and the Federal Water Pollution Control Act, commonly referred to as the Clean Water Act, and analogous state laws, which regulate discharge of wastewaters from our facilities to state and federal waters. In addition, our operations are also subject to the federal Comprehensive Environmental Response, Compensation, and Liability Act, also known as CERCLA or the Superfund law, the Resource Conservation and Recovery Act, also known as RCRA, and analogous state laws in connection with the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal. Various governmental authorities including the U.S. Environmental Protection Agency, or the EPA, have the power to enforce compliance with these regulations and the permits issued under them, and violators are subject to administrative, civil and criminal penalties, including civil fines, injunctions or both. Liability may be incurred without regard to fault under CERCLA, RCRA, and analogous state laws for the remediation of contaminated areas. Private parties, including the owners of properties located near our terminal facilities or through which our pipeline systems pass, also may have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage.

        In addition, the possibility exists that new, stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary, some of which may be material. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage in the event an environmental claim is made against us. Our business may be adversely affected by increased costs because of stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. New environmental regulations might adversely affect our products and activities, including processing, storage and transportation, as well as waste management and air emissions. Federal and state agencies also could impose additional safety requirements, any of which could affect our profitability.

        We currently own or lease, and have owned or leased, many properties that have been used for many years to terminal or store refined petroleum products or other chemicals. Owners, tenants or users of these properties have disposed of or released hydrocarbons or solid wastes on or under them. Additionally, some sites we operate are located near current or former refining and terminal operations. There is a risk that contamination has migrated from those sites to ours. Increasingly strict environmental laws, regulations and enforcement policies and claims for damages and other similar developments could result in substantial costs and liabilities.

Federal Energy Regulatory Commission and Department of Transportation regulations may change important aspects of our industry and could reduce our ability to compete and impose significant costs on us or affect our ability to ship product in the quantities we need, which could adversely affect our revenues.

        The Federal Energy Regulatory Commission, or FERC, regulates the tariff rates for interstate common carrier operations. Tariff rates are subject to periodic changes and the FERC may approve higher tariff rates for transport of product on the principal pipelines we utilize. The FERC also may change the manner in which tariffs apply, such as changing from tariffs based on shipping history to tariffs based on competitive bidding or some other methodology. Substantial increases or changes in the tariff rates on the principal pipelines we utilize could adversely affect our ability to ship the quantities

23

of product we need or to ship product at economical rates. As a result, we could lose sales or suffer higher transportation expenses, which could adversely affect our results of operations.

        In addition, refined petroleum product pipeline operations are subject to regulation by the Department of Transportation. These regulations require, among other things, that pipeline operators engage in a regular program of pipeline integrity testing to assess, evaluate, repair and validate the integrity of their pipelines, which could result in service interruptions or significant and unexpected expenditures either with respect to pipelines we own or on pipelines owned by others that we use. We may have to bear those interruptions and expenses through the prices we pay to transport product, and the prices we charge when selling product that we purchase and market. Although we generally seek to pass those costs on to our customers, the resulting price increases might not be entirely recoverable or could lower demand for product. We transport a large amount of product on common carrier pipelines that we do not own, and spurs of those pipelines supply our terminals. If the Department of Transportation determines that a spur of a common carrier pipeline that supplies our terminals requires repair to maintain its integrity, the owner of the pipeline may decide to abandon the spur to our terminal instead of completing the repair work, or could require us to pay for the repair work, either of which would adversely affect our operations at that terminal or force us to close the terminal.

We are subject to strict regulations at many of our facilities regarding employee safety, and failure to comply with these regulations could adversely affect us.

        The workplaces associated with the processing and storage facilities and the pipelines we operate are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that we maintain information about hazardous materials used or produced in our operations and that we provide this information to our employees, state and local government authorities, and local residents. We believe that we have conducted our operations in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances. Failure to comply with OSHA requirements could adversely affect our results of operations if we are subjected to fines or significant additional compliance costs.

The departure of any of our key executive officers could harm our business.

        Our future success depends largely on the efforts of our executive management team, which consists of Cortlandt Dietler, Chairman and Director; Donald H. Anderson, Vice-Chairman, Chief Executive Officer, President and Director; William S. Dickey, Executive Vice President and Chief Operating Officer; Randall J. Larson, Executive Vice President and Chief Financial Officer; and Erik B. Carlson, Senior Vice President, Corporate Secretary and General Counsel. The loss of any of these individuals could have a material adverse effect on our business. If we experience vacancies in any of these key roles, it could have a material adverse impact on our ability to properly conduct our business operations and pursue our growth initiatives and, as a result, could have a material adverse impact on our overall business, financial condition and results of operations.

RISKS RELATED TO THE EXCHANGE NOTES AND OUR STRUCTURE

The exchange notes and the guarantees are subordinated obligations.

        The exchange notes are subordinate in right of payment to all of our current and future senior indebtedness. Senior indebtedness includes indebtedness under our bank credit facilities and all of our other indebtedness that is not expressly made subordinate to, or equal in right of payment to, the exchange notes. The full and unconditional, joint and several guarantees will be subordinated to all of the guarantors' existing and future senior debt. Subject to certain limitations in the indenture, we may

24

incur additional indebtedness in the future, including senior indebtedness. By reason of the subordination of the exchange notes, in the event of our insolvency, bankruptcy, liquidation, reorganization, dissolution or winding up of our business or upon default in payment with respect to any of our senior indebtedness, or an event of default with respect to such indebtedness resulting in the acceleration thereof, our assets will be available to pay the amounts due on the exchange notes only after all of our senior indebtedness has been paid in full. In these cases, we and the guarantors may not have sufficient funds to pay all of our creditors, and holders of the notes may receive proportionately less than the holders of senior debt. Furthermore, under certain circumstances, no cash payments with respect to the notes may be made for a period of up to 180 days (during each period of 360 days) if a non-payment default exists with respect to designated senior debt. At March 31, 2003, after giving effect to the offering of the old notes and the application of the net proceeds from the offering of the old notes we and our guarantor subsidiaries had $65.0 million of senior debt outstanding on a consolidated basis.

We may not be able to satisfy our obligations to holders of the notes upon a change of control.

        Upon the occurrence of a "Change of Control," as defined in the indenture, you will have the right to require us to purchase the notes at a price equal to 101% of the principal amount, together with any accrued and unpaid interest and additional interest, if any, to the date of purchase. We may not have the funds available to make the offer to purchase your notes upon a Change of Control. Our failure to purchase, or give notice of purchase of, the notes would be a default under the indenture, which would in turn be a default under the notes.

Our indebtedness could adversely restrict our ability to operate, affect our financial condition and prevent us from fulfilling our obligations under our debt securities.

        We have a significant amount of indebtedness outstanding and the ability to incur substantially more indebtedness. As of March 31, 2003, after giving effect to the offering of the old notes, our total debt would have been $265.0 million.

        In addition, our Series B Preferred Stock is subject to mandatory redemption between June 30 and December 31, 2007. As of March 31, 2003, 72,890 shares of Series B Preferred Stock, having an aggregate redemption value of $72.9 million, were outstanding. When redeemed, we can pay the redemption price of the Series B Preferred in cash, or subject to certain conditions, in common stock, or a combination of cash and common stock, at our option. To the extent that we redeem the Series B Preferred in cash, it could affect our ability to repay the notes.

        We and certain of our subsidiaries must comply with various affirmative and negative covenants contained in the documents related to the notes and our senior credit facility. Among other things, these covenants limit the ability of us and those subsidiaries to:

•

incur additional indebtedness or liens;



•

make payments in respect of or redeem or acquire any debt or equity issued by us;



•

sell assets;



•

make certain loans or investments;



•

acquire or be acquired by other companies;



•

enter into transactions with affiliates; and



•

amend some of our contracts.

25

        In addition, our senior credit facility requires us to maintain certain financial ratios and satisfy certain financial condition tests and may require us to take action to reduce our debt or take some other action to comply with them.

        The restrictions under our indebtedness may prevent us from engaging in certain transactions that might otherwise be considered beneficial to us and could have other important consequences to you. For example, they could:

•

increase our vulnerability to general adverse economic and industry conditions;



•

limit our ability to fund future working capital and capital expenditures, to engage in future acquisitions, construction or development activities, or to otherwise fully realize the value of our assets and opportunities because of the need to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness or to comply with any restrictive terms of our indebtedness;



•

limit our flexibility in planning for, or reacting to, changes in our businesses and the industries in which we operate; and



•

place us at a competitive disadvantage as compared to our competitors that have less debt.

        We may incur additional indebtedness (public or private) in the future, either under our existing senior credit facility, by issuing debt securities, under our new working capital credit facility or other new credit agreements, under capital leases or a combination of any of these. If we incur additional indebtedness in the future, it would be under our new working capital credit facility or under arrangements which may have terms and conditions at least as restrictive as those contained in our existing senior credit facility. Failure to comply with the terms and conditions of any existing or future indebtedness would constitute an event of default. If an event of default occurs, the lenders will have the right to accelerate the maturity of such indebtedness and foreclose upon the collateral, if any, securing that indebtedness. Any such an event could limit our ability to fulfill our obligations under the notes.

        We cannot assure you that our business will generate sufficient cash flow from operations or that future borrowings will be available to us under credit facilities in amounts sufficient to pay our debt, including the notes, or to fund our other liquidity needs. We may need to refinance all or a portion of our debt, including the notes, on or before maturity, and such refinancing may be costly under the terms of the notes. We cannot assure you that we would be able to refinance any of our debt, including any credit facilities or the notes, on commercially reasonable terms or at all.

The guarantees may be voided under specific legal circumstances.

        The notes will be guaranteed on a full and unconditional, joint and several basis by all of our subsidiaries, other than our minor subsidiaries that are inactive and have no assets or operations. The guarantees may be subject to review under U.S. federal bankruptcy law and comparable provisions of state fraudulent conveyance laws if a bankruptcy or reorganization case or lawsuit is commenced by or on behalf of our or one of the guarantor's unpaid creditors. Under these laws, if a court were to find in such a bankruptcy or reorganization case or lawsuit that, at the time any guarantor issued a guarantee of the notes, the guarantor:

•

incurred the guarantee of the notes with the intent of hindering, delaying or defrauding current or future creditors;



•

was a defendant in an action for money damages, or had a judgment for money damages docketed against it if, in either case, after final judgment, the judgment is unsatisfied; or

26

•

received less than reasonably equivalent value or fair consideration for incurring the guarantee of the notes, and such guarantor (a) was insolvent or was rendered insolvent by reason of issuing the guarantee, (b) was engaged, or about to engage, in a business or transaction for which its remaining assets constituted unreasonably small capital, or (c) intended to incur, or believed that it would incur, debts beyond its ability to pay as such debts matured,

then such a court could void the guarantee of such guarantor or subordinate the amounts owing under such guarantee to such guarantor's presently existing or future debt or take other actions detrimental to you.

        The measure of insolvency for purposes of the foregoing considerations will vary depending upon the law of the jurisdiction that is being applied in any such proceeding. Generally, a company would be considered insolvent if, at any time it incurred the debt or issued the guarantee, either:

•

the sum of its debts (including contingent liabilities) was greater than its assets, at fair valuation; or



•

the present fair saleable value of its assets was less than the amount required to pay the probable liability on its total existing debts and liabilities (including contingent liabilities) as they become absolute and matured.

        If the guarantees of the notes were challenged, we cannot be sure as to the standard a court would use to determine whether any of our guarantors was solvent at the relevant time. If such a case were to occur, the guarantee could also be subject to the claim that, since the guarantee was incurred for the benefit of TransMontaigne and only indirectly for the benefit of the guarantor, the obligations of the applicable guarantor were incurred for less than fair consideration. If a guarantor were also found to be insolvent, a court could thus void the obligations under the guarantee, subordinate the guarantee to the applicable guarantor's other debt or take other action detrimental to the holders of the notes. If a guarantee is voided as a fraudulent conveyance or found to be unenforceable for any other reason, you will not have a claim against that guarantor and will only be a creditor of TransMontaigne or any guarantor whose obligation was not set aside or found to be unenforceable.

Our ability to repay the notes and our other debt depends on cash flow from our subsidiaries.

        We are a holding company whose only material assets are its ownership interests in its subsidiaries. Consequently, we depend on distributions or other inter-company transfers of funds from our subsidiaries to meet our debt service and other obligations, including with respect to the notes.

If you fail to exchange your old notes, they will continue to be restricted securities and may become less liquid.

        Old notes that you do not tender or we do not accept will, following the exchange offer, continue to be restricted securities. You may not offer or sell untendered old notes except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. We will issue exchange notes in exchange for the old notes pursuant to the exchange offer only following the satisfaction of procedures and conditions described elsewhere in this prospectus. These procedures and conditions include timely receipt by the exchange agent of the old notes and of a properly completed and duly executed letter of transmittal.

        Because we anticipate that most holders of old notes will elect to exchange their old notes, we expect that the liquidity of the market for any old notes remaining after the completion of the exchange offer may be substantially limited. Any old note tendered and exchanged in the exchange offer will reduce the aggregate principal amount of the old notes outstanding. Following the exchange offer, if you did not tender your old notes you generally will not have any further registration rights

27

and your old notes will continue to be subject to transfer restrictions. Accordingly, the liquidity of the market for any old notes could be adversely affected.

There may be no active trading market for the exchange notes to be issued in the exchange offer.

        The exchange notes are a new issue of securities for which there is not an established market. We cannot assure you with respect to:

•

the liquidity of any market for the exchange notes that may develop,



•

your ability to sell exchange notes, or



•

the price at which you will be able to sell the exchange notes.

        If a public market were to exist, the exchange notes could trade at prices that may be higher or lower than their principal amount or purchase price, depending on many factors, including prevailing interest rates, the market for similar notes, and our financial performance. We do not intend to list the exchange notes to be issued to you in the exchange offer on any securities exchange or to seek approval for quotations through any automated quotation system. No active market for the exchange notes is currently anticipated.

Broker-dealers or holders of the notes may become subject to the registration and prospectus delivery requirements of the Securities Act.

        Any broker-dealer that:

•

exchanges its old notes in the exchange offer for the purpose of participating in a distribution of the exchange notes, or



•

resells exchange notes that were received by it for its own account in the exchange offer,

may be deemed to have received restricted securities and may be required to comply with the registration and prospectus delivery provisions of the Securities Act in connection with any resale transaction by that broker-dealer. Any profit on the resale of the exchange notes and any commission or concessions received by a broker-dealer may be deemed to be underwriting compensation under the Securities Act.

        In addition to broker-dealers, any holder of old notes that exchanges its old notes in the exchange offer for the purpose of participating in a distribution of the exchange notes may be deemed to have received restricted securities and may be required to comply with the registration and prospectus delivery provisions of the Securities Act in connection with any resale transaction by that holder.

28

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

        This prospectus and the documents incorporated herein by reference contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934:

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," "will," "seeks," "believes," "expects," "anticipates," "intends," "continues," "estimates," "plans" 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.

        In addition to the specific risk factors described in the section entitled "Risk factors," important factors that could cause actual results to differ materially from our expectations and may affect our ability to pay timely amounts due under the notes or that may affect the value of the notes, 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;



•

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;



•

the impact of the departure of any key officers; and



•

general economic, market or business conditions.

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

29

THE EXCHANGE OFFER

Purpose and Effect

        Concurrently with the sale of the old notes on May 30, 2003, we entered into a registration rights agreement with the initial purchasers of the old notes, which requires us to file the registration statement under the Securities Act with respect to the exchange notes and, upon the effectiveness of the registration statement, offer to the holders of the old notes the opportunity to exchange their old notes for a like principal amount of exchange notes. The exchange notes will be issued without a restrictive legend and generally may be reoffered and resold without registration under the Securities Act. The registration rights agreement further provides that we must cause the registration statement to be declared effective by October 27, 2003 and must consummate the exchange offer no later than December 26, 2003.

        Except as described below, upon the completion of the exchange offer, our obligations with respect to the registration of the old notes and the exchange notes will terminate. A copy of the registration rights agreement has been filed as an exhibit to the registration statement of which this prospectus is a part. This summary of the material provisions of the registration rights agreement does not purport to be complete and is qualified in its entirety by reference to the complete registration rights agreement. As a result of the timely filing and the effectiveness of the registration statement, we will not have to pay certain additional interest on the old notes provided in the registration rights agreements. Following the completion of the exchange offer, holders of old notes not tendered will not have any further registration rights other than as set forth in the paragraphs below, and the old notes will continue to be subject to certain restrictions on transfer. Additionally, the liquidity of the market for the old notes could be adversely affected upon consummation of the exchange offer.

        In order to participate in the exchange offer, a holder must represent to us, among other things, that:

•

the exchange notes acquired pursuant to the exchange offer are being obtained in the ordinary course of business of the holder;



•

the holder is not engaging in and does not intend to engage in a distribution of the exchange notes;



•

the holder does not have an arrangement or understanding with any person to participate in the distribution of the exchange notes; and



•

the holder is not an "affiliate" of ours, as defined under Rule 405 under the Securities Act.

        Under certain circumstances specified in the registration rights agreement, we may be required to file a "shelf" registration statement for a continuous offer in connection with the old notes pursuant to Rule 415 under the Securities Act.

        Based on an interpretation by the staff of the SEC set forth in no-action letters of Exxon Capital Holdings Corporation (available April 13, 1988), Morgan Stanley & Co. Incorporated (available June 5, 1991) and Shearman & Sterling (available July 2, 1993), we believe that, with the exceptions set forth below, exchange notes issued in the exchange offer may be offered for resale, resold and otherwise transferred by the holder of exchange notes without compliance with the registration and prospectus delivery requirements of the Securities Act, unless the holder:

•

is our "affiliate" within the meaning of Rule 405 under the Securities Act;



•

is a broker-dealer who purchased old notes directly from us for resale under Rule 144A or any other available exemption under the Securities Act;



•

acquired the exchange notes other than in the ordinary course of the holder's business; or

30

•

the holder has an arrangement with any person to engage in the distribution of the exchange notes.

        Any holder who tenders in the exchange offer for the purpose of participating in a distribution of the exchange notes cannot rely on this interpretation by the staff of the SEC and must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a secondary resale transaction. Each broker-dealer that receives exchange notes for its own account in exchange for old notes, where such old notes were acquired by such broker-dealer as a result of market making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such exchange notes. See "Plan of Distribution." Broker-dealers who acquired old notes directly from us and not as a result of market making activities or other trading activities may not rely on the SEC staff's interpretations discussed above or participate in the exchange offer, and must comply with the prospectus delivery requirements of the Securities Act in order to sell the old notes.

Terms of the Exchange Offer

        Upon the terms and subject to the conditions set forth in this prospectus and in the letter of transmittal, we will accept any and all old notes validly tendered and not withdrawn prior to 5:00 p.m., New York City time, on the expiration date,                        , 2003 or such date and time to which we extend the offer. We will issue $1,000 in principal amount of exchange notes in exchange for each $1,000 principal amount of outstanding old notes accepted in the exchange offer. Holders may tender some or all of their old notes pursuant to the exchange offer. However, old notes may be tendered only in integral multiples of $1,000 in principal amount.

        The exchange notes will evidence the same debt as the old notes and will be issued under the terms of, and entitled to the benefits of, the indenture relating to the old notes.

        This prospectus, together with the letter of transmittal, is being sent to the registered holder and to others believed to have beneficial interests in the old notes. We intend to conduct the exchange offer in accordance with the applicable requirements of the Securities Exchange Act of 1934 and the rules and regulations of the SEC promulgated under the Securities Exchange Act of 1934. You do not have any appraisal or dissenters' rights in connection with the exchange offer under the Delaware General Corporation Law or the indenture.

        We will be deemed to have accepted validly tendered old notes when, as and if we have given oral or written notice thereof to Wells Fargo Bank Minnesota, National Association, the exchange agent. The exchange agent will act as agent for the tendering holders for the purpose of receiving the exchange notes from us. If any tendered old notes are not accepted for exchange because of an invalid tender, the occurrence of certain other events set forth under the heading "—Conditions to the Exchange Offer" or otherwise, certificates for any such unaccepted old notes will be returned, without expense, to the tendering holder of those old notes as promptly as practicable after the expiration date unless the exchange offer is extended.

        Holders who tender old notes in the exchange offer will not be required to pay brokerage commissions or fees or, subject to the instructions in the letter of transmittal, transfer taxes with respect to the exchange of old notes in the exchange offer. We will pay all charges and expenses, other than certain applicable taxes, applicable to the exchange offer. See "—Fees and Expenses."

Expiration date; Extensions; Amendments

        The expiration date shall be 5:00 p.m., New York City time, on                        , 2003, unless we, in our sole discretion, extend the exchange offer, in which case the expiration date shall be the latest date and time to which the exchange offer is extended. We refer to this date, as it may be extended, as the expiration date. In order to extend the exchange offer, we will notify the exchange agent and each

31

registered holder of any extension by oral or written notice prior to 9:00 a.m., New York City time, on the next business day after the previously scheduled expiration date. We reserve the right, in our sole discretion:

•

to delay accepting any old notes, to extend the exchange offer or, if any of the conditions set forth under "—Conditions to Exchange Offer" shall not have been satisfied, to terminate the exchange offer, by giving oral or written notice of that delay, extension or termination to the exchange agent; or



•

to amend the terms of the exchange offer in any manner.

        In the event that we make a fundamental change to the terms of the exchange offer, we will file a post-effective amendment to the registration statement.

Procedures for Tendering

        Only a holder of old notes may tender the old notes in the exchange offer. Except as set forth under "—Book-Entry Transfer," to tender in the exchange offer a holder must complete, sign and date the letter of transmittal, or a copy of the letter of transmittal, have the signatures on the letter of transmittal guaranteed if required by the letter of transmittal and mail or otherwise deliver the letter of transmittal or copy to the exchange agent prior to the expiration date. In addition:

•

certificates for the old notes must be received by the exchange agent along with the letter of transmittal prior to the expiration date;



•

a timely confirmation of a book-entry transfer, or a Book-Entry Confirmation, of the old notes, if that procedure is available, into the exchange agent's account at The Depository Trust Company, which we refer to as the Book-Entry Transfer Facility, following the procedure for book-entry transfer described below, must be received by the exchange agent prior to the expiration date; or



•

you must comply with the guaranteed delivery procedures described below.

        To be tendered effectively, the letter of transmittal and other required documents must be received by the exchange agent at the address set forth under "—Exchange Agent" prior to the expiration date.

        Your tender, if not withdrawn prior to 5:00 p.m., New York City time, on the expiration date, will constitute an agreement between you and us in accordance with the terms and subject to the conditions set forth herein and in the letter of transmittal.

The method of delivery of old notes and the letter of transmittal and all other required documents to the exchange agent is at your election and risk. Instead of delivery by mail, it is recommended that you use an overnight or hand delivery service. In all cases, sufficient time should be allowed to assure delivery to the exchange agent before the expiration date. No letter of transmittal or old notes should be sent to us. You may request your broker, dealer, commercial bank, trust company or nominee to effect these transactions for you.

        Any beneficial owner whose old notes are registered in the name of a broker, dealer, commercial bank, trust company, or other nominee and who wishes to tender should contact the registered holder promptly and instruct the registered holder to tender on the beneficial owner's behalf. If the beneficial owner wishes to tender on its own behalf, the beneficial owner must, prior to completing and executing the letter of transmittal and delivering the owner's old notes, either make appropriate arrangements to register ownership of the old notes in the beneficial owner's name or obtain a properly completed bond power from the registered holder. The transfer of registered ownership may take considerable time.

32

        Signatures on a letter of transmittal or a notice of withdrawal, as the case may be, must be guaranteed by an "eligible guarantor institution" within the meaning of Rule 17Ad-15 under the Securities Exchange Act of 1934 unless old notes tendered pursuant thereto are tendered:

•

by a registered holder who has not completed the box entitled "Special Registration Instruction" or "Special Delivery Instructions" on the letter of transmittal; or



•

for the account of an eligible guarantor institution.

        If signatures on a letter of transmittal or a notice of withdrawal, as the case may be, are required to be guaranteed, the guarantee must be by any eligible guarantor institution that is a member of or participant in the Securities Transfer Agents Medallion Program, the New York Stock Exchange Medallion Signature Program or an eligible guarantor institution.

        If the letter of transmittal is signed by a person other than the registered holder of any old notes listed in the letter of transmittal, the old notes must be endorsed or accompanied by a properly completed bond power, signed by the registered holder as that registered holder's name appears on the old notes.

        If the letter of transmittal or any old notes or bond powers are signed by trustees, executors, administrators, guardians, attorneys-in-fact, officers of corporations or others acting in a fiduciary or representative capacity, such persons should so indicate when signing, and evidence satisfactory to us of their authority to so act must be submitted with the letter of transmittal unless waived by us.

        All questions as to the validity, form, eligibility, including time of receipt, acceptance, and withdrawal of tendered old notes will be determined by us in our sole discretion, which determination will be final and binding. We reserve the absolute right to reject any and all old notes not properly tendered or any old notes our acceptance of which would, in the opinion of our counsel, be unlawful. We also reserve the right to waive any defects, irregularities or conditions of tender as to particular old notes. Our interpretation of the terms and conditions of the exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of old notes must be cured within such time as we shall determine. Although we intend to notify holders of defects or irregularities with respect to tenders of old notes, neither we, the exchange agent, nor any other person shall incur any liability for failure to give that notification. Tenders of old notes will not be deemed to have been made until such defects or irregularities have been cured or waived. Any old notes received by the exchange agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned by the exchange agent to the tendering holders, unless otherwise provided in the letter of transmittal, as soon as practicable following the expiration date, unless the exchange offer is extended.

        In addition, we reserve the right in our sole discretion to purchase or make offers for any old notes that remain outstanding after the expiration date or, as set forth under "—Conditions to the Exchange Offer," to terminate the exchange offer and, to the extent permitted by applicable law, purchase old notes in the open market, in privately negotiated transactions, or otherwise. The terms of any such purchases or offers could differ from the terms of the exchange offer.

        By tendering, you will be representing to us that, among other things:

•

the exchange notes acquired in the exchange offer are being obtained in the ordinary course of business of the person receiving such exchange notes, whether or not such person is the registered holder;



•

you are not engaging in and do not intend to engage in a distribution of the exchange notes;



•

you do not have an arrangement or understanding with any person to participate in the distribution of such exchange notes; and

33

•

you are not our "affiliate," as defined under Rule 405 of the Securities Act.

        In all cases, issuance of exchange notes for old notes that are accepted for exchange in the exchange offer will be made only after timely receipt by the exchange agent of certificates for such old notes or a timely Book-Entry Confirmation of such old notes into the exchange agent's account at the Book-Entry Transfer Facility, a properly completed and duly executed letter of transmittal or, with respect to The Depository Trust Company and its participants, electronic instructions in which the tendering holder acknowledges its receipt of and agreement to be bound by the letter of transmittal, and all other required documents. If any tendered old notes are not accepted for any reason set forth in the terms and conditions of the exchange offer or if old notes are submitted for a greater principal amount than the holder desires to exchange, such unaccepted or non-exchanged old notes will be returned without expense to the tendering holder or, in the case of old notes tendered by book-entry transfer into the exchange agent's account at the Book-Entry Transfer Facility according to the book-entry transfer procedures described below, those nonexchanged old notes will be credited to an account maintained with that Book-Entry Transfer Facility, in each case, as promptly as practicable after the expiration or termination of the exchange offer.

        Each broker-dealer that receives exchange notes for its own account in exchange for old notes, where those old notes were acquired by such broker-dealer as a result of market making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of those exchange notes. See "Plan of Distribution."

Book-Entry Transfer

        The exchange agent will make a request to establish an account with respect to the old notes at the Book-Entry Transfer Facility for purposes of the exchange offer within two business days after the date of this prospectus, and any financial institution that is a participant in the Book-Entry Transfer Facility's systems may make book-entry delivery of old notes being tendered by causing the Book-Entry Transfer Facility to transfer such old notes into the exchange agent's account at the Book-Entry Transfer Facility in accordance with that Book-Entry Transfer Facility's procedures for transfer. However, although delivery of old notes may be effected through book-entry transfer at the Book-Entry Transfer Facility, the letter of transmittal or copy of the letter of transmittal, with any required signature guarantees and any other required documents, must, in any case other than as set forth in the following paragraph, be transmitted to and received by the exchange agent at the address set forth under "—Exchange Agent" on or prior to the expiration date or the guaranteed delivery procedures described below must be complied with.

        The Depository Trust Company's Automated Tender Offer Program, or ATOP, is the only method of processing exchange offers through The Depository Trust Company. To accept the exchange offer through ATOP, participants in The Depository Trust Company must send electronic instructions to The Depository Trust Company through The Depository Trust Company's communication system instead of sending a signed, hard copy letter of transmittal. The Depository Trust Company is obligated to communicate those electronic instructions to the exchange agent. To tender old notes through ATOP, the electronic instructions sent to The Depository Trust Company and transmitted by The Depository Trust Company to the exchange agent must contain the character by which the participant acknowledges its receipt of and agrees to be bound by the letter of transmittal.

Guaranteed Delivery Procedures

        If a registered holder of the old notes desires to tender old notes and the old notes are not immediately available, or time will not permit that holder's old notes or other required documents to

34

reach the exchange agent prior to 5:00 p.m., New York City time, on the expiration date, or the procedure for book-entry transfer cannot be completed on a timely basis, a tender may be effected if:

•

the tender is made through an eligible guarantor institution;



•

prior to 5:00 p.m., New York City time, on the expiration date, the exchange agent receives from that eligible guarantor institution a properly completed and duly executed letter of transmittal or a facsimile of duly executed letter of transmittal and notice of guaranteed delivery, substantially in the form provided by us, by telegram, telex, fax transmission, mail or hand delivery, setting forth the name and address of the holder of old notes and the amount of the old notes tendered and stating that the tender is being made by guaranteed delivery and guaranteeing that within three New York Stock Exchange, Inc., or NYSE, trading days after the date of execution of the notice of guaranteed delivery, the certificates for all physically tendered old notes, in proper form for transfer, or a Book-Entry Confirmation, as the case may be, will be deposited by the eligible guarantor institution with the exchange agent; and



•

the certificates for all physically tendered old notes, in proper form for transfer, or a Book-Entry Confirmation, as the case may be, are received by the exchange agent within three NYSE trading days after the date of execution of the notice of guaranteed delivery.

Withdrawal Rights

        Tenders of old notes may be withdrawn at any time prior to 5:00 p.m., New York City time, on the expiration date.

        For a withdrawal of a tender of old notes to be effective, a written or, for The Depository Trust Company participants, electronic ATOP transmission notice of withdrawal, must be received by the exchange agent at its address set forth under "—Exchange Agent" prior to 5:00 p.m., New York City time, on the expiration date. Any such notice of withdrawal must:

•

specify the name of the person having deposited the old notes to be withdrawn;



•

identify the old notes to be withdrawn, including the certificate number or numbers and principal amount of such old notes;



•

be signed by the holder in the same manner as the original signature on the letter of transmittal by which such old notes were tendered, including any required signature guarantees, or be accompanied by documents of transfer sufficient to have the trustee register the transfer of such old notes into the name of the person withdrawing the tender; and



•

specify the name in which any such old notes are to be registered, if different from that of the person having deposited the old notes to be withdrawn.

        All questions as to the validity, form, eligibility and time of receipt of such notices will be determined by us, whose determination shall be final and binding on all parties. Any old notes so withdrawn will be deemed not to have been validly tendered for exchange for purposes of the exchange offer. Any old notes which have been tendered for exchange, but which are not exchanged for any reason, will be returned to the holder of those old notes without cost to that holder as soon as practicable after withdrawal, rejection of tender, or termination of the exchange offer. Properly withdrawn old notes may be retendered by following one of the procedures under "—Procedures for Tendering" at any time on or prior to the expiration date.

Conditions to the Exchange Offer

        Notwithstanding any other provision of the exchange offer, we will not be required to accept for exchange, or to issue exchange notes in exchange for, any old notes and may terminate or amend the

35

exchange offer if at any time before the acceptance of those old notes for exchange or the exchange of the exchange notes for those old notes, we determine that the exchange offer violates applicable law, any applicable interpretation of the staff of the SEC or any order of any governmental agency or court of competent jurisdiction.

        The foregoing conditions are for our sole benefit and may be asserted by us regardless of the circumstances giving rise to any such condition or may be waived by us in whole or in part at any time and from time to time in our sole discretion. The failure by us at any time to exercise any of the foregoing rights shall not be deemed a waiver of any of those rights and each of those rights shall be deemed an ongoing right which may be asserted at any time and from time to time.

        In addition, we will not accept for exchange any old notes tendered, and no exchange notes will be issued in exchange for those old notes, if at such time any stop order shall be threatened or in effect with respect to the registration statement of which this prospectus constitutes a part or the qualification of the indenture under the Trust Indenture Act of 1939. In any of those events we are required to use every reasonable effort to obtain the withdrawal of any stop order at the earliest possible time.

Exchange Agent

        All executed letters of transmittal should be directed to the exchange agent. Wells Fargo Bank Minnesota, National Association has been appointed as exchange agent for the exchange offer. Questions, requests for assistance and requests for additional copies of this prospectus or of the letter of transmittal should be directed to the exchange agent addressed as follows:

By Registered or Certified Mail: Wells Fargo Bank Minnesota, NA MAC# N9303-120 Corporate Trust Operations P.O. Box 1517 Minneapolis, MN 55480-1517	By Regular Mail or Overnight Courier: Wells Fargo Bank Minnesota, NA MAC# N9303-121 Corporate Trust Operations 6th & Marquette Avenue Minneapolis, MN 55479
In Person by Hand Only:   Wells Fargo Bank Minnesota, NA 608 Second Avenue South Corporate Trust Operations, 12th Floor Minneapolis, MN 55402	By Facsimile: (Eligible Institutions Only) (612) 667-4927 For Information or Confirmation by Telephone: (800) 344-5128

        Originals of all documents sent by facsimile should be sent promptly by registered or certified mail, by hand or by overnight delivery service.

Fees And Expenses

        We will not make any payments to brokers, dealers or others soliciting acceptances of the exchange offer. The principal solicitation is being made by mail; however, additional solicitations may be made in person or by telephone by our officers and employees. The estimated cash expenses to be incurred in connection with the exchange offer will be paid by us and will include fees and expenses of the exchange agent, accounting, legal, printing and related fees and expenses.

Transfer Taxes

        Holders who tender their old notes for exchange will not be obligated to pay any transfer taxes in connection with that tender or exchange, except that holders who instruct us to register exchange notes

36

in the name of, or request that old notes not tendered or not accepted in the exchange offer be returned to, a person other than the registered tendering holder will be responsible for the payment of any applicable transfer tax on those old notes.

Accounting Treatment

        We will not recognize any gain or loss for accounting purposes upon consummation of the exchange offer. We will amortize the expense of the exchange offer over the term of the exchange notes under generally accepted accounting principles.

USE OF PROCEEDS

        The exchange offer is intended to satisfy our obligations under the registration rights agreements. We will not receive any cash proceeds from the issuance of the exchange notes. In consideration for issuing the exchange notes as contemplated in this prospectus, we will receive, in exchange, an equal number of outstanding old notes in like principal amount. The form and terms of the exchange notes are identical in all material respects to the form and terms of the old notes. The outstanding old notes surrendered in exchange for the exchange notes will be retired and marked as cancelled and cannot be reissued. The net proceeds from the offering of the old notes of approximately $193.5 million were used to repay the senior secured term loan.

37

CAPITALIZATION

        This table sets forth our consolidated capitalization at March 31, 2003:

•

on an historical basis;



•

on an as adjusted basis to reflect the sale of the old notes and the application of the net proceeds from the offering of the old notes to repay outstanding indebtedness.

        You should read the table together with our financial statements and other information included in this prospectus.

			As of March 31, 2003
			Historical			As Adjusted(3)
			(dollars in thousands)
Debt(1):
	Working capital credit facility(2)		$	65,000		$	65,000
	Senior Secured Term Loan due 2006			200,000			—
	91/8% Senior Subordinated Notes due 2010			—			200,000
		Total debt	$	265,000		$	265,000
Preferred stock:
	Series A Convertible Preferred Stock ($0.01 par value; 250,000 shares authorized; 24,421 shares issued and outstanding)		$	24,421		$	24,421
	Series B Redeemable Convertible Preferred Stock ($0.01 par value; 100,000 shares authorized; 72,890 shares issued and outstanding)			79,732			79,732
		Total preferred stock		104,153			104,153
Common stockholders' equity:
	Common stock ($0.01 par value; 80,000,000 shares authorized; 40,663,447 shares issued and outstanding)			407			407
	Capital in excess of par value			249,258			249,258
	Deferred stock-based compensation			(4,489	)		(4,489	)
	Accumulated deficit			(28,159	)		(28,159	)
		Total common stockholders' equity		217,017			217,017
		Total capitalization	$	586,170		$	586,170

(1)

Please read "Description of other indebtedness" in this prospectus for additional information regarding our existing indebtedness.

(2)

Does not include $25.0 million of indebtedness incurred under the working capital credit facility on April 30, 2003 upon payment of the contingent portion of the purchase price with respect to the acquisition of the Coastal Fuels assets.

(3)

The initial purchasers' discount and other expenses of the offering of the old notes was approximately $6.5 million and was paid out of cash.

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UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

        The unaudited pro forma condensed consolidated statements of operations of TransMontaigne for the year ended June 30, 2002 and the nine months ended March 31, 2003 give effect to the acquisition of the Coastal Fuels assets as if it had occurred on July 1, 2001 using the purchase method of accounting, as adjusted to reflect pro forma interest expense assuming the net proceeds from the issuance of the old notes are used to repay our senior secured term loan. The pro forma adjustments are based on estimates and assumptions explained in further detail in the accompanying notes to unaudited pro forma condensed consolidated financial statements.

        The historical statements of operations of Coastal Fuels Marketing, Inc. have been adjusted from a calendar year presentation to match our fiscal year end of June 30^th. The historical statements of operations of Coastal Fuels Marketing, Inc. have been adjusted further to eliminate operating results related to assets formerly owned by Coastal Fuels Marketing, Inc., but disposed of prior to our acquisition of the Coastal Fuels assets.

        The historical income statement information for the year ended June 30, 2002 is derived from the audited financial statements of TransMontaigne for the year ended June 30, 2002 and the unaudited financial statements of Coastal Fuels Marketing, Inc. for the twelve months ended June 30, 2002. The historical income statement information for the nine-month period ended March 31, 2003 is derived from the unaudited financial statements of TransMontaigne and Coastal Fuels Marketing, Inc. We have provided all the historical information set forth herein regarding us and our subsidiaries and the assumptions and adjustments for the pro forma information, and El Paso CGP Company has provided all the historical information set forth herein regarding Coastal Fuels Marketing, Inc.

        The unaudited pro forma condensed consolidated statements of operations are presented for illustrative purposes only. The pro forma financial results may have been different if the companies had always been combined as of the date indicated above, nor do they purport to indicate the future results that we will experience.

        The following information should be read together with the historical financial statements and related notes of TransMontaigne and Coastal Fuels Marketing, Inc. included elsewhere in this prospectus.

39

TransMontaigne Inc. and subsidiaries

Pro forma condensed consolidated statements of operations

Nine months ended March 31, 2003

(In thousands)

		TransMontaigne Nine Months Ended March 31, 2003 (1)			Coastal Eight Months Ended February 28, 2003 (3)			Pro Forma Acquisition Adjustments			Pro Forma Combined Nine Months Ended March 31, 2003			Pro Forma Financing Adjustments			Pro Forma As Adjusted Combined Nine Months Ended March 31, 2003
Supply, distribution and marketing:
Revenues		$	5,949,896		$	406,757					$	6,356,653					$	6,356,653
Less cost of products sold			(5,817,624	)		(394,206	)					(6,211,830	)					(6,211,830	)
Other direct costs and expenses			(78,705	)		—						(78,705	)					(78,705	)
Net operating margins			53,567			12,551						66,118						66,118
Terminals, pipelines and tugs and barges:
Revenues			56,204			27,809						84,013						84,013
Direct operating costs and expenses			(21,981	)		(19,884	)					(41,865	)					(41,865	)
Net operating margins			34,223			7,925						42,148						42,148
Total net operating margins			87,790			20,476						108,266						108,266
Costs and expenses:
Selling, general and administrative			(28,547	)		(1,410	)					(29,957	)					(29,957	)
Depreciation and amortization			(13,400	)		(1,355	)		(1,312	)(4)		(16,067	)					(16,067	)
Corporate relocation and transition			(1,449	)		—						(1,449	)					(1,449	)
			(43,396	)		(2,765	)		(1,312	)		(47,473	)					(47,473	)
	Operating income		44,394			17,711			(1,312	)		60,793						60,793
Other income (expense):
Dividend income from and equity in earnings of petroleum related investments			374			—						374						374
Interest income			231			—						231						231
Interest expense			(10,181	)		(52	)		(5,836	)(5)		(16,069	)		(6,146	)(6)		(22,215	)
Other financing costs:
Amortization of debt issuance costs			(948	)		—						(948	)					(948	)
Write-off of debt issuance costs			(2,188	)		—						(2,188	)					(2,188	)
Unrealized gain on interest rate swap			2,224			—						2,224						2,224
Other income (expense)			—			(179	)					(179	)					(179	)
Earnings before income taxes			33,906			17,480			(7,148	)		44,238			(6,146	)		38,092
Income tax expense			(12,888	)		(7,418	)		3,496	(7)		(16,810	)		2,335	(7)		(14,475	)
	Net earnings	$	21,018		$	10,062		$	(3,652	)	$	27,428		$	(3,811	)	$	23,617
Earnings per common share(2):
	Basic	$	.46								$	.63					$	.53
	Diluted	$	.40								$	.53					$	.41
Weighted average common shares outstanding:
	Basic		39,101									39,101						39,101
	Diluted		50,288									51,916						50,288

See accompanying notes to unaudited pro forma condensed consolidated financial statements.

40

TransMontaigne Inc. and subsidiaries

Unaudited pro forma condensed consolidated statements of operations

Year ended June 30, 2002

(In thousands)

		TransMontaigne Year Ended June 30, 2002 (1)			Coastal As Adjusted Twelve Months Ended June 30, 2002 (8)			Pro Forma Acquisition Adjustments			Pro Forma Combined Year Ended June 30, 2002			Pro Forma Financing Adjustments			Pro Forma As Adjusted Combined Year Ended June 30, 2002
Supply, distribution, and marketing:
Revenues		$	6,001,170		$	488,026					$	6,489,196					$	6,489,196
Less cost of product sold			(5,932,423	)		(469,350	)					(6,401,773	)					(6,401,773	)
Lower of cost or market write-downs on minimum inventory volumes			(12,963	)		—						(12,963	)					(12,963	)
Net operating margins			55,784			18,676						74,460						74,460
Terminals and pipelines:
Revenues			63,386			30,540						93,926						93,926
Less direct operating costs and expenses			(27,668	)		(31,440	)					(59,108	)					(59,108	)
Net operating margins			35,718			(900	)					34,818						34,818
Total net operating margins			91,502			17,776						109,278						109,278
Costs and expenses:
Selling, general and administrative			(35,211	)		(3,785	)					(38,996	)					(38,996	)
Depreciation and amortization			(16,556	)		(2,222	)		(1,778	)(4)		(20,556	)					(20,556	)
Corporate relocation and transition			(6,316	)		—						(6,316	)					(6,316	)
			(58,083	)		(6,007	)		(1,778	)		(65,868	)					(65,868	)
	Operating income		33,419			11,769			(1,778	)		43,410						43,410
Other income (expense):
Dividend income from and equity in earnings of petroleum related investments			1,450			—						1,450						1,450
Interest income			599			812			(812	)(5)		599						599
Interest expense			(12,436	)		(2,031	)		(5,819	)(5)		(20,286	)		(8,194	)(6)		(28,480	)
Other financing costs:
Early payment penalty on senior notes			(1,943	)		—						(1,943	)					(1,943	)
Amortization of debt issuance costs			(1,744	)		—						(1,744	)					(1,744	)
Write-off of debt issuance costs			(2,987	)		—						(2,987	)					(2,987	)
Unrealized loss on interest rate swap			(2,322	)		—						(2,322	)					(2,322	)
Other income (expense)			(13	)		207						194						194
Earnings before income taxes			14,023			10,757			(8,409	)		16,371			(8,194	)		8,177
Income tax expense			(5,465	)		(4,112	)		3,197	(7)		(6,380	)		3,191(7	)		(3,189	)
	Net earnings	$	8,558		$	6,645		$	(5,212	)	$	9,991		$	(5,003	)	$	4,988
Earnings (loss) per common share(2):
	Basic	$	(.09	)							$	(.04	)				$	(.20	)
	Diluted	$	(.09	)							$	(.04	)				$	(.20	)
Weighted average common shares outstanding
	Basic		31,267									31,267						31,267
	Diluted		31,267									31,267						31,267

See accompanying notes to unaudited pro forma condensed consolidated financial statements.

41

TransMontaigne Inc. and Subsidiaries

Notes to Unaudited Pro Forma Condensed

Consolidated Financial Statements

(1)

The amounts presented for TransMontaigne represent historical amounts from (a) TransMontaigne's Quarterly Report on Form 10-Q for the nine months ended March 31, 2003 and (b) TransMontaigne's June 30, 2002 Consolidated Financial Statements contained in our Current Report on Form 8-K filed on May 13, 2003.

(2)

Earnings (loss) per common share is presented before the cumulative effect of a change in accounting principle and where applicable reflects the dilutive impact of potential common shares.

(3)

Because the most recent fiscal year end of Coastal Fuels Marketing, Inc. differs from TransMontaigne's most recent fiscal year end by more than 93 days, the income statement of Coastal Fuels Marketing, Inc. was adjusted to present a period consistent with TransMontaigne's fiscal year end. As a result, amounts in this column represent the results of operations attributable to the Coastal Fuels assets acquired by TransMontaigne for the eight-month period ended February 28, 2003 (i.e., the period from July 1, 2002 through the date of acquisition of the Coastal Fuels assets by TransMontaigne).

		Six Months Ended December 31, 2002			Adjustments to Add Two Months Ended February 28, 2003			As Adjusted Eight Months ended February 28, 2003
Supply, distribution, and marketing:
Revenues		$	282,771		$	123,986		$	406,757
Less cost of product sold			(275,297	)		(118,909	)		(394,206	)
Net operating margins			7,474			5,077			12,551
Terminals and pipelines:
Revenues			20,427			7,382			27,809
Less direct operating costs and expenses			(14,130	)		(5,754	)		(19,884	)
Net operating margins			6,297			1,628			7,925
Total net operating margins			13,771			6,705			20,476
Costs and expenses:
Selling, general and administrative			(1,117	)		(293	)		(1,410	)
Depreciation and amortization			(1,237	)		(118	)		(1,355	)
Corporate relocation and transition			—			—			—
			(2,354	)		(411	)		(2,765	)
	Operating income		11,417			6,294			17,711
Other income (expense):
Dividend income from and equity in earnings of petroleum related investments			—			—			—
Interest income			—			—			—
Interest expense			(50	)		(2	)		(52	)
Other financing costs:
Early payment penalty on senior notes			—			—			—
Amortization of debt issuance costs			—			—			—
Write-off of debt issuance costs			—			—			—
Unrealized loss on interest rate swap			—			—			—
Other income (expense)			(44	)		(135	)		(179	)
Earnings before income taxes			11,323			6,157			17,480
Income tax expense			(4,805	)		(2,613	)		(7,418	)
	Net earnings	$	6,518		$	3,544		$	10,062

(4)

Represents a net increase in depreciation expense resulting from the elimination of the historical depreciation expense of the Coastal Fuels assets and the recording of depreciation expense based on a preliminary allocation of the purchase price of the Coastal Fuels assets of $120 million (net of the working capital), including $40 million allocated to the value of land and $80 million allocated to plant and equipment, with a weighted average life for depreciation of 20 years (resulting in annual depreciation expense of $4 million per year).

42

(5)

Represents the elimination of historical interest expenses and historical interest income attributable to the Coastal Fuels assets and the recognition of interest expense at an interest rate of 5.0% on amounts borrowed under TransMontaigne's term loan to finance the acquisition of the Coastal Fuels assets.

(6)

Represents the elimination of pro forma interest expense at an interest rate of 5.0% on amounts borrowed under TransMontaigne's Term Loan to fund the $157 million purchase price of the Coastal Fuels assets and the elimination of pro forma interest expenses, at a rate of 5.13% on a $43 million reduction in borrowings under the Working Capital Credit Facility and recognition of interest expense on the $200 million of senior subordinated notes offered hereby at an interest rate of 9.125%.

(7)

Adjustment to reflect provision for income taxes resulting from pro forma income before income taxes, assuming an effective tax rate of 38% and 39% for the nine months ended March 31, 2003, and for the year ended June 30, 2002, respectively.

(8)

Because certain Coastal Fuels Marketing, Inc. assets were disposed of by Coastal Fuels prior to the TransMontaigne acquisition, the historical Coastal Fuels Marketing, Inc. income statement has been adjusted to eliminate amounts attributable to assets of Coastal Fuels Marketing, Inc. that were not acquired by TransMontaigne. Further, because the most recent fiscal year end of Coastal Fuels Marketing, Inc. differs from TransMontaigne's most recent fiscal year end by more than 93 days, the income statement of Coastal Fuels Marketing, Inc. was adjusted to present a twelve-month period consistent with TransMontaigne's fiscal year.

43

        The following table reconciles the historical Coastal Fuels Marketing, Inc. statement of operations for the year ended December 31, 2002 to a statement of operations for the Coastal Fuels assets for the twelve months ended June 30, 2002 (in thousands):

		Historical Year Ended December 31, 2002			Adjustments to Eliminate Assets Not Acquired			Adjustments to Eliminate Six Months Ended December 31, 2002			Adjustments to Add Six Months Ended December 31, 2001			As Adjusted Twelve Months Ended June 30, 2002
Supply, distribution, and marketing:
Revenues		$	820,046		$	(281,739	)	$	(282,771	)	$	232,490		$	488,026
Less cost of product sold			(802,755	)		283,685			275,297			(225,577	)		(469,350	)
Net operating margins			17,291			1,946			(7,474	)		6,913			18,676
Terminals and pipelines:
Revenues			38,975			(5,626	)		(20,427	)		17,618			30,540
Less direct operating costs and expenses			(31,912	)		4,260			14,130			(17,918	)		(31,440	)
Net operating margins			7,063			(1,366	)		(6,297	)		(300	)		(900	)
Total net operating margins			24,354			580			(13,771	)		6,613			17,776
Costs and expenses:
Selling, general and administrative			(3,146	)		196			1,117			(1,952	)		(3,785	)
Depreciation and amortization			(2,728	)		408			1,237			(1,139	)		(2,222	)
Corporate relocation and transition			—			—			—			—			—
			(5,874	)		604			2,354			(3,091	)		(6,007	)
	Operating income		18,480			1,184			(11,417	)		3,522			11,769
Other income (expense):
Dividend income from and equity in earnings of petroleum related investments			—			—			—			—			—
Interest income			812			—			—			—			812
Interest expense			(1,430	)		—			50			(651	)		(2,031	)
Other financing costs:
Early payment penalty on senior notes			—			—			—			—			—
Amortization of debt issuance costs			—			—			—			—			—
Write-off of debt issuance costs			—			—			—			—			—
Unrealized loss on interest rate swap			—			—			—			—			—
Other income (expense)			30			—			44			133			207
Earnings before income taxes			17,892			1,184			(11,323	)		3,004			10,757
Income tax expense			(7,593	)		(502	)		4,805			(822	)		(4,112	)
	Net earnings	$	10,299		$	682		$	(6,518	)	$	2,182		$	6,645

44

SELECTED CONSOLIDATED FINANCIAL DATA

        The following selected financial data for the years ended June 30, 2002, 2001, 2000 and 1999 and for the year ended April 30, 1998 and the two months ended June 30, 1998 have been derived from our audited consolidated financial statements. The selected financial data as of March 31, 2003 and for the nine months ended March 31, 2003 and 2002 have been derived from our unaudited consolidated financial statements. The unaudited consolidated financial statements include all adjustments that we consider necessary for a fair presentation of the financial position and results of operations for those periods. Net operating margin data by segment for the two months ended June 30, 1998 is not available. You should not expect the results for any prior or interim periods to be indicative of the results that may be achieved in future periods. You should read the following information together with our historical financial statements and related notes and with "Management's discussion and analysis of financial condition and results of operations" included elsewhere in this prospectus.

	Historical
	Nine Months Ended March 31,						Years Ended June 30,
																			Two Months Ended June 30, 1998		Year Ended April 30, 1998
	2003			2002			2002			2001			2000			1999
	(dollars in thousands)
Statement of Operations Data:
Supply, distribution and marketing:
Revenues	$	5,949,896		$	4,001,858		$	6,001,170		$	5,182,492		$	5,014,752		$	2,935,550				$	1,879,350
Less costs of products sold		(5,896,329	)		(3,953,387	)		(5,945,386	)		(5,154,492	)		(4,995,899	)		(2,914,272	)				(1,872,305	)
Net operating margin(1)		53,567			48,471			55,784			28,000			18,853			21,278			N/A		7,045
Terminals, pipelines, and tugs and barges:
Revenues		56,204			46,455			63,386			82,305			78,522			56,374					27,134
Direct operating costs and expenses		(21,981	)		(20,005	)		(27,668	)		(36,415	)		(34,268	)		(24,678	)				(11,398	)
Net operating margin(1)		34,223			26,450			35,718			45,890			44,254			31,696			N/A		15,736
Natural gas services:
Revenues		—			—			—			—			18,249			55,137					61,022
Direct operating costs and expenses		—			—			—			—			(7,759	)		(43,167	)				(47,914	)
Net operating margin(1)		—			—			—			—			10,490			11,970			N/A		13,108
Total net operating margins(1)	$	87,790		$	74,921		$	91,502		$	73,890		$	73,597		$	64,944		$	1,125	$	35,889

45

Total net operating margins(1)		$	87,790		$	74,921		$	91,502		$	73,890		$	73,597		$	64,944		$	1,125		$	35,889
Costs and expenses:
Selling, general and administrative			(28,547	)		(25,605	)		(35,211	)		(34,072	)		(41,680	)		(17,990	)		(1,938	)		(8,438	)
Depreciation and amortization			(13,400	)		(12,449	)		(16,556	)		(19,510	)		(22,344	)		(16,775	)		(1,773	)		(8,217	)
Corporate relocation and transition			(1,449	)		(315	)		(6,316	)		—			—			—			—			—
Impairment of long-lived assets			—			—			—			—			(50,136	)		—			—			—
	Operating income (loss)		44,394			36,552			33,419			20,308			(40,563	)		30,179			(2,586	)		19,234
Interest expense, net			(9,950	)		(9,125	)		(11,837	)		(15,215	)		(25,121	)		(23,575	)		(1,327	)		(5,532	)
Other income (expense)			(538	)		(1,251	)		(7,546	)		(9,235	)		(5,350	)		(3,210	)		(153	)		(572	)
Gain (loss) on disposition of assets, net			—			(1,295	)		(13	)		22,146			13,930			—			—			—
	Earnings (loss) before income taxes		33,906			24,881			14,023			18,004			(57,104	)		3,394			(4,066	)		13,130
Income (taxes) benefit			(12,888	)		(9,455	)		(5,465	)		(6,666	)		19,167			(1,455	)		1,403			(5,492	)
	Net earnings (loss) before cumulative effect of a change in accounting principle	$	21,018		$	15,426		$	8,558		$	11,338		$	(37,937	)	$	1,939		$	(2,663	)	$	7,638
Earnings (loss) per common share:
Common Share:
	Basic		.46			.26			(.09	)		.08			(1.52	)		(.01	)		(.10	)		.30
	Diluted		.40			.26			(.09	)		.08			(1.52	)		(.01	)		(.10	)		.29

46

Other Financial Data:
EBITDA(2)	$	58,168		$	49,156		$	51,412		$	65,024		$	(2,699	)	$	48,703		$	(813	)	$	27,451
Operating results for debt covenant compliance(3)	$	39,715		$	63,414		$	64,388		$	61,196		$	33,507		$	48,703		$	(813	)	$	27,451
Net cash provided (used) by operating activities	$	73,770		$	(93,660	)	$	(101,512	)	$	51,936		$	267,526		$	(68,861	)	$	3,673		$	(4,570	)
Net cash provided (used) by investing activities	$	(129,753	)	$	104,599		$	102,778		$	(18,969	)	$	77,902		$	(467,040	)	$	(6,277	)	$	(66,131	)
Net cash provided (used) by financing activities	$	51,445		$	(24,553	)	$	3,811		$	(61,130	)	$	(305,417	)	$	522,613		$	12		$	64,124
Total debt to total capital		45.2	%		25.9	%		39.0	%		30.5	%		38.4	%		57.0	%		47.0	%		46.6	%
Total debt to EBITDA		—			—			3.9	x		2.3	x		—			10.2	x		—			4.7	x
Total debt to operating results for debt covenant compliance		—			—			3.1	x		2.5	x		6.2	x		10.2	x		—			4.7	x
EBITDA to interest expense, net		5.8	x		5.4	x		4.3	x		4.3	x		(0.1	)x		2.1	x		(0.6	)x		5.0	x
Operating results for debt covenant compliance to interest expense, net		4.0	x		7.0	x		5.4	x		4.0	x		1.3	x		2.1	x		(0.6	)x		5.0	x
Ratio of earnings to fixed charges		4.0	x		—			1.9	x		1.9	x		—	(4)		1.1	x		—	(4)		2.8	x

	March 31,				June 30,
															April 30, 1998
	2003		2002		2002		2001		2000		1999		1998
Balance Sheet Data:
Cash and cash equivalents	$	26,314	$	12,161	$	30,852	$	25,775	$	53,938	$	13,927	$	27,215	$	29,807
Working capital(5)	$	91,515	$	160,354	$	168,092	$	31,934	$	134,807	$	356,602	$	86,467	$	94,393
Total assets	$	927,883	$	683,930	$	735,328	$	712,365	$	834,572	$	1,106,009	$	318,215	$	323,305
Total debt	$	265,000	$	125,500	$	198,312	$	150,000	$	206,995	$	497,672	$	128,971	$	128,970
Total preferred stock	$	104,153	$	182,136	$	105,360	$	174,825	$	170,115	$	170,115	$	—	$	—
Total common stockholders' equity	$	217,017	$	176,746	$	205,350	$	167,550	$	161,983	$	205,936	$	145,266	$	147,804

(1)

Net operating margins represents revenues, less direct operating costs and expenses.

(2)

EBITDA is defined as earnings before income taxes, interest expense, net, other financing costs, net, and depreciation and amortization. We believe that, in addition to cash flow from operating activities and net earnings (loss), EBITDA is a useful financial performance measurement for assessing operating performance since it provides an additional basis to evaluate our ability to incur and service debt and to fund capital expenditures. To evaluate EBITDA, the components of EBITDA such as net operating margin and direct operating expenses and the variability of such components over time, also should be considered. EBITDA should not be construed, however, as an alternative to operating income (loss) (as determined in accordance with generally accepted accounting principles ("GAAP")) as an indicator of our operating performance, or to cash flows from operating activities (as determined in accordance with GAAP) as a measure of liquidity.

(3)

We believe that operating results for debt covenant compliance is a useful measure in evaluating our performance because it eliminates the impact on our operating results from gains recognized and deferred on discretionary inventory volumes and the impairment of our inventories—minimum volumes. We believe that, in addition to operating income, cash flow from operating activities and EBITDA, operating results for debt covenant compliance is a useful financial performance measurement reflecting our ability to incur and service debt and to fund capital expenditures. In evaluating operating results for debt covenant compliance, we believe that consideration should be given, among other things, to the amount by which operating results for debt covenant compliance exceeds interest costs for the period; how operating results for debt covenant compliance compares to principal repayments on debt for the period; and how operating results for debt covenant compliance compares to capital expenditures for the period. As a result of the implementation of EITF 02-03, our inventories—minimum volumes and —discretionary volumes are carried at the lower of cost (first in, first out) or market,

47

while our risk management contracts are carried at market. As a result, if market prices are increasing during the end of one quarter and into the beginning of the next quarter, we may show significant losses on risk management contracts at the end of the prior quarter and significant gains recognized on our beginning inventories—discretionary volumes in the following quarter. While this volatility tends to offset over several quarters, it can result in significant volatility in our reported operating income and EBITDA between any two quarters. Because the inventory adjustments that affect operating income can be volatile on a quarterly basis, management uses operating results for debt covenant compliance to monitor and manage the operations of our business segments. Management believes that operating results for debt covenant compliance provides an appropriate measure of our debt service capabilities and, as a result, the measure is used as a measure of our financial performance in our borrowing arrangements. Under Financial Accounting Standards Board Statement of Financial Accounting Standards No. 131,Disclosures About Segments of an Enterprise and Related Information, we are required to report measures of profit and loss that are used by our chief operating decision maker in assessing financial performance for each of our reportable segments in the footnotes to our consolidated financial statements and, accordingly, we report operating results for debt covenant compliance in connection with our operating segment disclosures.

Operating results for debt covenant compliance and EBITDA should not be construed as alternatives to operating income as determined in accordance with generally accepted accounting principles as indicators of our operating performance, or to cash flows from operating activities, as determined in accordance with generally accepted accounting principles as a measure of liquidity. The following table reconciles our operating results for debt covenant compliance to EBITDA and EBITDA to net earnings.

	Historical
	Nine Months Ended March 31,						Year Ended June 30,												Two Months Ended June 30, 1998
																						Year Ended April 30, 1998
	2003			2002			2002			2001			2000		��	1999
	(in thousands)
Operating results for debt covenant compliance	$	39,715		$	63,414		$	64,388		$	61,196		$	33,507		$	48,703		$	(813	)	$	27,451
Gains recognized on beginning inventories—discretionary volumes		12,644			—			—			—			—			—			—			—
Net margin recognized on sale of inventories—minimum volumes		18,854			—			—			—			—			—			—			—
Lower of cost or market write down on base operating inventory volumes		(12,412	)		—			—			—			—			—			—			—
Lower of cost or market writedowns on minimum inventory volumes		(633	)		(12,963	)		(12,963	)		(18,318	)		—			—			—			—
Impairment of long lived assets		—			—			—			—			(50,136	)		—			—			—
Gain (loss) on disposition of Assets		—			(1,295	)		(13	)		22,146			13,930			—			—			—
EBITDA		58,168			49,156			51,412			65,024			(2,699	)		48,703			(813	)		27,451
Depreciation and amortization		(13,400	)		(12,449	)		(16,556	)		(19,510	)		(22,344	)		(16,775	)		(1,773	)		(8,217	)
Interest expense, net		(9,950	)		(9,125	)		(11,837	)		(15,215	)		(25,121	)		(23,575	)		(1,327	)		(5,532	)
Other financing costs, net		(912	)		(2,701	)		(8,996	)		(12,295	)		(6,940	)		(4,959	)		(153	)		(572	)
Income tax (expense) benefit		(12,888	)		(9,455	)		(5,465	)		(6,666	)		19,167			(1,455	)		1,403			(5,492	)
Net earnings	$	21,018		$	15,426		$	8,558		$	11,338		$	(37,937	)	$	1,939		$	(2,663	)	$	7,638

(4)

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 two months ended June 30, 1998. Earnings for such periods were insufficient to cover fixed charges by approximately $57.1 million and $4.1 million, respectively.

(5)

Working capital is defined as current assets less current liabilities.

48

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS; THREE AND NINE MONTHS ENDED MARCH 31, 2003

GENERAL

        The following discussion and analysis of the results of operations, liquidity, capital resources and commodity price risk should be read in conjunction with the accompanying consolidated financial statements.

CRITICAL ACCOUNTING 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 our consolidated financial statements for the year ended June 30, 2002 (see Note 1 of Notes to the Consolidated Financial Statements). Certain of these accounting policies require the use of estimates. 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 (for periods as of and prior to October 1, 2002); fair value of supply management services contracts; accrued lease abandonment costs; accrued transportation and deficiency obligations; and accrued environmental obligations. These estimates are based on our knowledge and understanding of current conditions and actions 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.

SIGNIFICANT DEVELOPMENTS

        On July 31, 2002, we closed on the purchase of a 25,000-barrel terminal in Brownsville, Texas. The terminal provides us with additional storage and rail car handling facilities and operating synergies with our main facility in Brownsville, Texas.

        On August 23, 2002, we announced the signing of a long-term terminaling agreement with P.M.I. Trading Limited to provide distribution related services and a related pipeline construction assistance agreement with P.M.I. Services North America, Inc., both affiliates of Petroleos Mexicanos, for the construction of a new 17-mile U.S. products pipeline from the U.S./Mexican border to our terminaling facility located at the port of Brownsville, Texas.

        During the three months ended September 30, 2002, we relocated our supply, distribution and marketing operations from Atlanta, Georgia to our existing office space at 370 17th Street in Denver, Colorado. During October and November 2002, our supply, distribution and marketing operations moved into our new office space at 1670 Broadway in Denver, Colorado. Our executive and administrative operations vacated our office space at 370 17th Street and joined our supply, distribution, and marketing operations at 1670 Broadway during June 2003.

        On February 4, 2003, we announced the purchase of a 500,000-barrel terminal in Fairfax, Virginia that supplies products in the Washington, D.C. market, including Dulles Airport. The transaction closed on January 31, 2003.

        On February 28, 2003, we closed on the purchase 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, or EPME-PC, along with the rights to and operations of the southeast marketing division of EPME-PC. The acquisition includes five Florida terminals, with aggregate capacity of approximately 4.9 million barrels, and a related tug and barge operation, or 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. For

49

the twelve months ended December 31, 2002, these facilities delivered an average of 29,000 barrels per day of bunker fuel, primarily to the cruise-ship industry, utilizing its tug and barge and hydrant delivery systems, and delivered approximately 28,000 barrels per day of gasoline and distillates over its petroleum products racks. In addition, Coastal Fuels provides storage services to the asphalt, jet fuel, power generation and crude oil industries. The purchase price for the acquisition was approximately $157 million, including approximately $37 million of product inventory. The purchase price includes contingent consideration of approximately $25.0 million due and payable to EPME-PC upon the delivery by EPME-PC of audited financial statements of the Coastal Fuels assets. On April 25, 2003, EPME-PC delivered to us the audited financial statements of the Coastal Fuels assets and EPME-PC was paid $25 million on April 30, 2003.

        On February 28, 2003, we executed a Credit Agreement with UBS AG that provided for a $250 million revolving line of credit, or the Working Capital Credit Facility, and a $200 million senior secured term loan, or the Term Loan, and, together with the Working Capital Credit Facility, these are called the Senior Credit Facility. TransMontaigne utilized funds available under the Credit Agreement to consummate the acquisition of the Coastal Fuels assets.

        On May 30, 2003, we consummated the sale and issuance of $200 million aggregate principal amount of 9¹/8% Senior Subordinated Notes ("Old Notes") 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 Old Notes to repay the Term Loan. The indenture governing the Old Notes contains covenants that, among other things, limits our ability to incur additional indebtedness, pay dividends on, redeem or repurchase our common stock, make investments, make certain dispositions of assets, engage in transaction with affiliates, create certain liens, and consolidate, merge, or transfer all or substantially all of our assets. See "Description of the Exchange Notes—Certain Covenants."

        On June 25, 2003, we amended and restated the Working Capital Credit Facility in connection with the syndication of the facility. All outstanding borrowings under the Working Capital Credit Facility are due and payable on February 28, 2006. The Working Capital Credit Facility contains affirmative and negative covenants (including limitations on indebtedness, limitations on dividends and other distributions, limitations on certain intercompany transactions, limitations on mergers, consolidation and the disposition of assets, limitations on investments and acquisitions and limitations on liens) as well as customary representations and warranties and events of default. It also contains certain financial covenants that are tested on a quarterly basis including a minimum fixed charge coverage ratio of 150%, a maximum funded senior debt leverage ratio of 4.5 times the last twelve months' EBITDA (as defined in the credit agreement), a minimum current ratio of 120% and a minimum consolidated tangible net worth test. In addition, we may not make aggregate expenditures in excess of $80.0 million with respect to general corporate purposes over the term of the agreement (however, such amount shall be increased by certain cash flow amounts generated after February 28, 2003). See "Description of Other Indebtedness."

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QUARTERLY RESULTS OF OPERATIONS

        Selected financial data regarding our quarterly results of operations is summarized below (in thousands):

			Three Months Ended
			March 31, 2003			December 31, 2002			September 30, 2002			June 30, 2002			March 31, 2002			December 31, 2001			September 30, 2001
Net operating margins(1):
	Supply, distribution, and marketing		$	53,457		$	(7,503	)	$	7,612		$	7,313		$	20,106		$	1,615		$	26,750
	Terminals, pipelines, and tug and barges			12,550			10,745			10,928			9,268			9,596			8,513			8,341
		Total net operating margins		66,007			3,242			18,540			16,581			29,702			10,128			35,091
Costs and expenses:
	Selling, general and administrative			(10,440	)		(8,775	)		(9,331	)		(9,606	)		(8,955	)		(8,185	)		(8,465	)
	Depreciation and amortization			(4,851	)		(4,293	)		(4,256	)		(4,107	)		(4,143	)		(4,024	)		(4,282	)
	Corporate relocation and transition			—			(365	)		(1,084	)		(6,001	)		(315	)		—			—
				(15,291	)		(13,433	)		(14,671	)		(19,714	)		(13,413	)		(12,209	)		(12,747	)
		Operating income (loss)	$	50,716		$	(10,191	)	$	3,869		$	(3,133	)	$	16,289		$	(2,081	)	$	22,344

(1)

Net operating margins represent revenues, less direct operating costs and expenses.

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        The following summary reflects our comparative EBITDA, operating results for debt covenant compliance, operating income, and net cash flows for the three months and nine months ended March 31, 2003 and 2002 (in thousands):

	Three Months Ended March 31,						Nine Months Ended March 31,
	2003			2002			2003			2002
EBITDA(1)	$	55,567		$	20,425		$	58,168		$	49,156
Operating results for debt covenant compliance(2)	$	16,268		$	20,425		$	39,715		$	63,414
Operating income	$	50,716		$	16,289		$	44,394		$	36,552
Net cash provided (used) by operating activities	$	92,013		$	28,654		$	73,770		$	(93,660	)
Net cash provided (used) by investing activities	$	(113,504	)	$	(17,885	)	$	(129,753	)	$	104,599
Net cash provided (used) by financing activities	$	41,841		$	(20,512	)	$	51,445		$	(24,553	)
Reconciliation of EBITDA and Operating Results for Debt Covenant Compliance to Net Earnings:
Operating results for debt covenant compliance	$	16,268		$	20,425		$	39,715		$	63,414
Gains recognized on beginning inventories—discretionary volumes		33,490			—			12,644			—
Net operating margins recognized on sale of inventories—minimum volumes		18,854			—			18,854			—
Lower of cost or market write-down on base operating inventory volumes		(12,412	)		—			(12,412	)		—
Lower of cost or market write-down on inventories—minimum volumes		(633	)		—			(633	)		(12,963	)
Loss on disposition of assets		—			—			—			(1,295	)
EBITDA		55,567			20,425			58,168			49,156
Depreciation and amortization		(4,851	)		(4,143	)		(13,400	)		(12,449	)
Interest expense, net		(3,759	)		(3,577	)		(9,950	)		(9,125	)
Other financing costs, net		(1,725	)		1,384			(912	)		(2,701	)
Income tax expense		(17,192	)		(5,354	)		(12,888	)		(9,455	)
Net earnings before cumulative effect of a change in accounting principle	$	28,040		$	8,735		$	21,018		$	15,426

(1)

EBITDA is defined as earnings before income taxes, interest expense, net, other financing costs, net, depreciation and amortization. We believe that, in addition to cash flow from operating activities and net earnings (loss), EBITDA is a useful financial performance measurement for assessing operating performance since it provides an additional basis to evaluate our ability to incur and service debt and to fund capital expenditures. To evaluate EBITDA, the components of EBITDA such as net operating margin and direct operating expenses and the variability of such components over time, also should be considered. EBITDA should not be construed, however, as an alternative to operating income (loss) (as determined in accordance with generally accepted accounting principles, or GAAP) as an indicator of our operating performance, or to cash flows from operating activities (as determined in accordance with GAAP) as a measure of liquidity.

(2)

We believe that operating results for debt covenant compliance is a useful measure in evaluating our performance because it eliminates the impact on our operating results from gains recognized and deferred on discretionary inventory volumes and the impairment of our inventories—minimum volumes. We believe that, in addition to operating income, cash flow from operating activities and EBITDA, operating results for debt covenant compliance is a useful financial performance measurement reflecting our ability to incur and service debt and to fund capital expenditures. In

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evaluating operating results for debt covenant compliance, we believe that consideration should be given, among other things, to the amount by which operating results for debt covenant compliance exceeds interest costs for the period; how operating results for debt covenant compliance compares to principal repayments on debt for the period; and how operating results for debt covenant compliance compares to capital expenditures for the period. As a result of the implementation of EITF 02-03, our inventories—minimum volumes and —discretionary volumes are carried at the lower of cost (first in, first out) or market, while our risk management contracts are carried at market. As a result, if market prices are increasing during the end of one quarter and into the beginning of the next quarter, we may show significant losses on risk management contracts at the end of the prior quarter and significant gains recognized on our beginning inventories—discretionary volumes in the following quarter. While this volatility tends to offset over several quarters, it can result in significant volatility in our reported operating income and EBITDA between any two quarters. Because the inventory adjustments that affect operating income can be volatile on a quarterly basis, management uses operating results for debt covenant compliance to monitor and manage the operations of our business segments. Management believes that operating results for debt covenant compliance provides an appropriate measure of our debt service capabilities and, as a result, this measure is used as a measure of our financial performance in our borrowing arrangements. Under Financial Accounting Standards Board Statement of Financial Accounting Standards No. 131,Disclosures About Segments of an Enterprise and Related Information, we are required to report measures of profit and loss that are used by our chief operating decision maker in assessing financial performance for each of our reportable segments in the footnotes to our consolidated financial statements and, accordingly, we report operating results for debt covenant compliance in connection with our operating segment disclosures.

        Operating results for debt covenant compliance and EBITDA should not be construed as alternatives to operating income as determined in accordance with generally accepted accounting principles as indicators of our operating performance, or to cash flows from operating activities, as determined in accordance with generally accepted accounting principles as a measure of liquidity.

THREE MONTHS ENDED MARCH 31, 2003 COMPARED TO THREE MONTHS ENDED MARCH 31, 2002

        We reported net earnings of $28.0 million for the three months ended March 31, 2003, compared to net earnings of $8.7 million for the three months ended March 31, 2002. After preferred stock dividends, the net earnings attributable to common stockholders was $27.0 million for the three months ended March 31, 2003, compared to net earnings of $6.3 million for the three months ended March 31, 2002. Basic earnings per common share for the three months ended March 31, 2003 and 2002, was $0.69 and $0.20, respectively, based on 39.1 million and 31.2 million weighted average common shares outstanding, respectively. Diluted earnings per share for the three months ended March 31, 2003 and 2002, was $0.54 and $0.20, respectively, based upon 51.9 million and 31.5 million weighted average diluted shares outstanding, respectively.

Terminals, pipelines, and tugs and barges

        The net operating margins from our terminals, pipelines, and tugs and barges operations for the three months ended March 31, 2003 were $12.6 million, compared to $9.6 million for the three months ended March 31, 2002. On February 28, 2003, we acquired the Coastal Fuels assets, which include five

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terminals, a hydrant delivery system, and a tug and barge operation. The net operating margins from our terminals, pipelines, and tugs and barges operations are as follows (in thousands):

			Three Months Ended March 31,
			2003			2002
Throughput fees			$	7,635		6,744
Storage fees				6,694		4,427
Additive injection fees, net				1,995		1,714
Pipeline transportation fees				1,479		1,750
Tugs and barges				1,318		—
Other				2,423		1,129
	Revenue			21,544		15,764
	Less direct operating costs and expenses			(8,994	)	(6,168	)
		Net operating margins	$	12,550		9,596

        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 success of our terminals, pipelines, and tugs and barges operations depends in large part on the level of demand for products by customers in the geographic locations served by such facilities and the ability and willingness of our customers to utilize our terminals and pipelines as opposed to the terminals, pipelines, and tugs and barges of other companies. We cannot predict the impact of future fuel conservation measures, alternate fuel requirements, governmental regulation, technological advances in fuel economy, demographic changes, weather conditions and energy-generation devices, among other factors, all of which could reduce the demand for products in the areas we serve.

        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 three months ended March 31, 2003 and 2002, we averaged approximately 39,000 and 54,000 barrels per day, respectively, of delivered volumes under exchange agreements.

        Terminal throughput fees were approximately $7.6 million and $6.7 million for the three months ended March 31, 2003 and 2002, respectively. For the three months ended March 31, 2003 and 2002, we averaged approximately 340,000 barrels and 335,000 barrels per day of throughput volumes at our terminals, including volumes under exchange agreements. The increase of $0.9 million in throughput fees was due principally to increases in throughput volumes from our supply, distribution and marketing operations. Specifically, throughput fees increased approximately $0.2 million as a result of our acquisition of the Coastal Fuels assets, and approximately $0.7 million at our Southeast facilities.

        Included in the terminal throughput fees for the three months ended March 31, 2003 and 2002 are fees charged to TransMontaigne's supply, distribution and marketing segment of approximately $5.8 million and $5.1 million, respectively.

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        Storage Fees.    We lease storage capacity at our terminals to third parties. 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 $6.7 million and $4.4 million for the three months ended March 31, 2003 and 2002, respectively. The increase of $2.3 million in storage fees was due principally to an increase of approximately $1.5 million from our acquisition of the Coastal Fuels assets, approximately $0.5 million at our Brownsville, Texas facilities, and approximately $0.3 million at our Selma, North Carolina facilities.

        Included in the terminal storage fees for the three months ended March 31, 2003 and 2002 are fees charged to TransMontaigne's supply, distribution and marketing segment of approximately $0.9 million and $0.9 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 $2.0 million and $1.7 million for the three months ended March 31, 2003 and 2002, respectively. The increase of $0.3 million in additive injection fees, net was due principally to increases in throughput volumes at our Southeast facilities.

        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 also own and operate a proprietary pipeline in Port Everglades/Ft. Lauderdale, or the hydrant system, which we use to deliver our product to cruise ships and other marine vessels for refueling, and a small intrastate crude oil gathering pipeline system, located in east Texas, or the CETEX pipeline. We earn pipeline transportation fees based on the volume of product transported and the distance from the origin point to the delivery point.

        For the three months ended March 31, 2003 and 2002, we earned pipeline transportation fees of approximately $1.5 million and $1.8 million, respectively. For the three months ended March 31, 2003 and 2002, the Razorback Pipeline averaged approximately 13,000 barrels and 14,000 barrels per day, respectively, of transported volumes.

        Included in the pipeline transportation fees for the three months ended March 31, 2003 and 2002 are fees charged to TransMontaigne's supply, distribution and marketing segment of approximately $1.5 million and $1.8 million, respectively.

        Tugs and Barges.    In Florida, we own and operate nine tugboats and 13 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 three months ended March 31, 2003, we earned bunkering fees, transportation fees, and other ship-assist services fees of approximately $1.3 million. 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 three and nine months ended March 31, 2003 are fees charged to TransMontaigne's supply, distribution and marketing segment of approximately $0.9 million.

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        Direct Operating Costs and Expenses.    The direct operating costs and expenses of the 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 three months ended March 31, 2003 and 2002, the direct operating costs and expenses of the terminals, pipelines, and tugs and barges were approximately $9.0 million and $6.2 million, respectively. The increase of $2.8 million in direct operating costs and expenses was due principally to the addition of the Coastal Fuels assets which resulted in approximately $1.8 million of additional direct operating costs and expenses. The remainder of the increase resulted from increases of approximately $0.4 million in wages and employee benefits, $0.4 million in maintenance and repairs, $0.2 million in property taxes and $0.1 million in materials and supplies offset by a decrease of approximately $0.1 million in rent expense.

Supply, distribution and marketing

        The net operating margins from our supply, distribution and marketing operations for the three months ended March 31, 2003 were $53.5 million, compared to $20.1 million for the three months ended March 31, 2002. The increase in net operating margins for the three months ended March 31, 2003 is due principally to three items that generated approximately $40.0 million in net operating margins. At December 31, 2002, the fair value of our inventories—discretionary volumes exceed their cost basis by approximately $33.5 million. During the three months ended March 31, 2003, we sold to customers those discretionary inventory volumes and recognized approximately $33.5 million in net operating margins. At March 31, 2003 the fair value of our inventories—discretionary volumes approximate their cost basis. For the three months ended March 31, 2003, we also recognized approximately $18.9 million in net operating margins from the transfer of minimum inventory volumes to discretionary inventory volumes and their subsequent sale to customers. That increase in net operating margins was offset by a lower of cost or market write-down of approximately $12.4 million. The net operating margins from our supply, distribution and marketing operations are as follows (in thousands):

			Three Months Ended March 31,
			2003			2002
Rack sales			$	502,318		295,113
Bulk sales				1,279,582		761,215
Contract sales				494,693		223,354
Supply management services (net in 2003; gross in 2002)				3,522		30,252
		Total revenue		2,280,115		1,309,934
Cost of product sold				(2,180,441	)	(1,227,309	)
Lower of cost or market write-downs on base operating volumes				(12,412	)	—
		Net margin before other direct costs and expenses		87,262		82,625
Other direct costs and expenses:
	Losses on NYMEX futures contracts			(33,172	)	(15,631	)
	Change in unrealized gains (losses) on supply management services contracts			—		(46,888	)
	Lower of cost or market write-downs on minimum volumes			(633	)	—
		Net operating margins	$	53,457		20,106

        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

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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 sales, bulk sales and contract sales.

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

        Rack sales were approximately $502.3 million and $295.1 million for the three months ended March 31, 2003 and 2002, respectively. For the three months ended March 31, 2003 and 2002, we averaged approximately 137,000 and 130,000 barrels per day, respectively, of delivered volumes under rack sales.

        Bulk Sales.    Bulk sales are spot sales of large quantities of product to wholesalers, distributors, and marketers in major cash markets. We also make bulk sales of products prior to their scheduled delivery to us 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 $1,279.6 million and $761.2 million for the three months ended March 31, 2003 and 2002, respectively. For the three months ended March 31, 2003 and 2002, we averaged approximately 370,000 and 355,000 barrels per day, respectively, of delivered volumes under bulk 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 $494.7 million and $223.4 million for the three months ended March 31, 2003 and 2002, respectively. For the three months ended March 31, 2003 and 2002, we averaged approximately 132,000 and 95,000 barrels per day, respectively, of delivered volumes under contract sales.

        Supply Management Services Contracts, Net.    We provide supply 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 management services: delivered fuel price management, retail price management and logistical supply management services. Our delivered fuel price management and retail price management contracts are carried at fair value because these contracts qualify as derivative instruments pursuant to SFAS No. 133. Changes in the fair value of our delivered fuel price management and retail price management contracts are included in net margins attributable to our supply, distribution and marketing operations.

        For the three months ended March 31, 2003, our revenues from delivered fuel price management and retail price management contracts are presented in the accompanying consolidated statement of

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operations on a net basis (i.e., product costs are netted directly against gross revenues to arrive at net revenues) pursuant to EITF 02-03. The information necessary to present these revenues on a net basis for periods prior to July 1, 2002 is not readily available and it is impracticable to obtain. Net revenues attributable to our delivered fuel price management and retail price management contracts are as follows (in thousands):

			Three Months Ended March 31,
			2003			2002
Gross revenues			$	44,692		30,252
Less:
	Cost of revenues			(39,612	)
	Change in unrealized gains (losses) on contracts			(1,558	)
		Net revenues	$	3,522

        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.

        Lower of Cost or Market Write-Downs on Base Operating Volumes.    During the three months ended March 31, 2003 and 2002, we recognized impairment losses of approximately $12.4 million and $nil, respectively, due to lower of cost or market write-downs on the base operating volumes due principally to declining prices during March 2003.

        Losses on NYMEX Futures Contracts.    Our risk management strategy generally is intended to maintain a balanced position of forward sale and forward purchase commitments against our discretionary inventories held for immediate sale 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 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 protect against price fluctuations for the underlying commodity. When we ultimately sell the underlying inventory to a customer, we unwind the related hedging arrangement. In order to accurately hedge against price fluctuations, we must attempt to 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 hedge against the same inventory. We refer to this as "rolling" the hedges. During a period of rising prices, our risk management contracts (i.e., short futures) that reduce our risk to commodity price changes associated with our discretionary inventory volumes will decline in value resulting in a loss.

        Losses on NYMEX futures contracts were approximately $33.2 million and $15.6 million for the three months ended March 31, 2003 and 2002, respectively, due principally to rising commodity prices during these periods.

        Lower of Cost or Market Write-Downs on Inventories—Minimum Volumes.    During the three months ended March 31, 2003 and 2002, we recognized impairment losses of approximately $0.6 million and

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$nil, respectively, due to lower of cost or market write-downs on the minimum inventory volumes of No. 6 oil due to declining commodity prices subsequent to our acquisition of the Coastal Fuels assets.

Costs and expenses

        Selling, general and administrative expenses for the three months ended March 31, 2003 were $10.4 million, compared to $9.0 million for the three months ended March 31, 2002. The increase of $1.4 million was due principally to compensation incurred for redundant employees involved in our corporate relocation and transition of approximately $0.5 million and increases in relocation, compensation, accounting, legal and insurance costs of approximately $0.9 million as a result of the acquisition of the Coastal Fuels assets.

        Depreciation and amortization for the three months ended March 31, 2003 and 2002, was $4.9 million, compared to $4.1 million. The increase of $0.8 million in depreciation and amortization is principally related to depreciation and amortization on new additions to property, plant and equipment.

        During the three months ended March 31, 2003, we substantially completed the relocation of our employees from Atlanta, Georgia to Denver, Colorado and paid the remaining special termination benefits and transition bonuses. We expect to pay the remaining accrued liability before June 30, 2003.

Other income and expenses

        Dividend income from and equity in earnings (loss) of petroleum related investments for the three months ended March 31, 2003 was $nil, compared to $(7,000) for the three months ended March 31, 2002.

        Interest income for the three months ended March 31, 2003 was $0.1 million, as compared to $0.1 million for the three months ended March 31, 2002. Pursuant to our cash management practices, excess cash balances are used to pay down our outstanding borrowings under our bank credit facility and commodity margin loan.

        Interest expense for the three months ended March 31, 2003 was $3.8 million, compared to $3.6 million during the three months ended March 31, 2002. The increase of $0.2 million in interest expense was primarily attributable to an increase in the amount of debt outstanding during the current period, offset by lower interest rates during the three months ended March 31, 2003, as the average interest rate under our credit facility was 3.8% and 4.8% for the three months ended March 31, 2003 and 2002, respectively. For the three months ended March 31, 2003, our interest expense resulted from $2.6 million for outstanding borrowings under our credit facility, $0.1 million for outstanding letters of credit, $0.1 million for outstanding borrowings under our commodity margin loan, and $1.0 million in net payments for the interest rate swap. For the three months ended March 31, 2002, our interest expense resulted from $2.0 million for outstanding borrowings under our bank credit facility and Senior Notes, $0.1 million for outstanding letters of credit, $0.1 million for outstanding borrowings under our commodity margin loan, and $1.4 million in net payments for the interest rate swap.

        Other financing costs (income) for the three months ended March 31, 2003 were $1.7 million, compared to $(1.4) million for the three months ended March 31, 2002. During the three months ended March 31, 2003, we wrote-off the unamortized deferred debt issuance costs of approximately $2.2 million associated with the repayment of our former bank credit facility. The remaining increase in other financing costs was due principally to a decline of approximately $0.8 million in the unrealized gain on an interest rate swap. We recognized an unrealized gain of $1.0 million during the three months ended March 31, 2003, as compared to an unrealized gain of $1.8 million during the three months ended March 31, 2002. The swap agreement provides that we pay a fixed interest rate of 5.48% on the notional amount of $150 million in exchange for receiving a variable rate based on LIBOR so long as the one-month LIBOR interest rate does not rise above 6.75%. If the one-month

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LIBOR rate rises above 6.75%, the swap knocks out and we will receive no payments under the agreement until such time as the one-month LIBOR rate declines below 6.75%. At March 31, 2002, the one-month LIBOR rate was 1.9%. On February 28, 2003, we settled our obligations under the swap agreement when we repaid our former bank revolving credit facility.

Income taxes

        Income tax expense was $17.2 million for the three months ended March 31, 2003, which represents an effective combined federal and state income tax rate of 38.0%. Income tax expense was $5.4 million for the three months ended March 31, 2002, which represents an effective combined federal and state income tax rate of 38.0%.

Preferred stock dividends

        Preferred stock dividends on our Series A Convertible Preferred stock were $0.3 million and $2.5 million for the three months ended March 31, 2003 and 2002, respectively. The decrease in the current year dividend resulted from a reduction in the number of shares of Series A Convertible Preferred stock outstanding during the current period. 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. 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.

        Preferred stock dividends on our Series B Redeemable Convertible Preferred Stock were $0.7 million for the three months ended March 31, 2003. There were no shares of Series B Redeemable Convertible Preferred Stock outstanding during the three months ended March 31, 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 $1.1 million, offset by the amortization of the premium on the carrying amount of the Series B Redeemable Convertible Preferred Stock of $0.4 million.

NINE MONTHS ENDED MARCH 31, 2003 COMPARED TO NINE MONTHS ENDED MARCH 31, 2002

        We reported net earnings of $13.2 million for the nine months ended March 31, 2003, compared to net earnings of $15.4 million for the nine months ended March 31, 2002. After preferred stock dividends, the net earnings attributable to common stockholders was $10.2 million for the nine months ended March 31, 2003, compared to net earnings of $8.1 million for the nine months ended March 31, 2002. Basic earnings per common share for the nine months ended March 31, 2003 and 2002, was $0.26 and $0.26, respectively, based on 39.1 million and 31.2 million weighted average common shares outstanding, respectively. Diluted earnings per share for the nine months ended March 31, 2003 and 2002, was $0.24 and $0.26, respectively, based upon 50.3 million and 31.5 million weighted average diluted shares outstanding, respectively.

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Terminals, pipelines, and tugs and barges

        The net operating margins from our terminals, pipelines, and tugs and barges operations for the nine months ended March 31, 2003 were $34.2 million, compared to $26.5 million for the nine months ended March 31, 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 net operating margins from our terminals, pipelines, and tugs and barges operations are as follows (in thousands):

			Nine Months Ended March 31,
			2003			2002
Throughput fees			$	21,937		19,099
Storage fees				17,144		13,265
Additive injection fees, net				5,721		4,732
Pipeline transportation fees				4,184		5,784
Tugs and barges				1,318		—
Other				5,900		3,575
	Revenue			56,204		46,455
	Less direct operating costs and expenses			(21,981	)	(20,005	)
		Net operating margins	$	34,223		26,450

        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.

        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 nine months ended March 31, 2003 and 2002, we averaged approximately 43,000 and 73,000 barrels per day, respectively, of delivered volumes under exchange agreements.

        Terminal throughput fees were approximately $21.9 million and $19.1 million for the nine months ended March 31, 2003 and 2002, respectively. For the nine months ended March 31, 2003 and 2002, we averaged approximately 329,000 barrels and 322,000 barrels per day of throughput volumes at our terminals, including volumes under exchange agreements. The increase of $2.8 million in throughput fees was due principally to increases in throughput volumes from our supply, distribution and marketing operations of approximately $2.6 million and approximately $0.2 million as a result of our acquisition of the Coastal Fuels assets.

        Included in the terminal throughput fees for the nine months ended March 31, 2003 and 2002 are fees charged to TransMontaigne's supply, distribution and marketing segment of approximately $15.9 million and $13.4 million, respectively.

        Storage Fees.    We lease storage capacity at our terminals to third parties. 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.

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        Terminal storage fees were approximately $17.1 million and $13.3 million for the nine months ended March 31, 2003 and 2002, respectively. The increase of $3.8 million in storage fees was due principally to an increase of approximately $1.5 million from our acquisition of Coastal Fuels assets, approximately $2.0 million at our Brownsville, Texas facilities and approximately $0.6 million at our Selma, North Carolina facilities, offset by decreases at our Baton Rouge, Louisiana and Greenville, Mississippi facilities of $0.1 million and $0.2 million, respectively.

        Included in the terminal storage fees for the nine months ended March 31, 2003 and 2002 are fees charged to TransMontaigne's supply, distribution and marketing segment of approximately $2.6 million and $2.7 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 $5.7 million and $4.7 million for the nine months ended March 31, 2003 and 2002, respectively. The increase of $1.0 million in additive injection fees, net was due principally to increases in throughput volumes at our Southeast facilities.

        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 also own and operate a proprietary pipeline in Port Everglades/Ft. Lauderdale, or the hydrant system, which we use to deliver product to cruise ships and other marine vessels for refueling, and a small intrastate crude oil gathering pipeline system, located in east Texas, or the CETEX pipeline. We earn pipeline transportation fees based on the volume of product transported and the distance from the origin point to the delivery point.

        For the nine months ended March 31, 2003 and 2002, we earned pipeline transportation fees of approximately $4.2 million and $5.8 million, respectively. For the nine months ended March 31, 2003 and 2002, the Razorback Pipeline averaged approximately 12,000 barrels per day, of transported volumes.

        Included in the pipeline transportation fees for the nine months ended March 31, 2003 and 2002 are fees charged to TransMontaigne's supply, distribution and marketing segment of approximately $4.2 million and $5.8 million, respectively.

        Tugs and Barges.    In Florida, we own and operate nine tugboats and 13 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 nine months ended March 31, 2003, we earned bunkering fees, transportation fees, and other ship-assist services fees of approximately $1.3 million. 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 nine months ended March 31, 2003 are fees charged to TransMontaigne's supply, distribution and marketing segment of approximately $0.9 million.

        Direct Operating Costs and Expenses.    The direct operating costs and expenses of the terminals, pipelines, and tugs and barges operations include the directly related wages and employee benefits,

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utilities, communications, maintenance and repairs, property taxes, rent, vehicle expenses, environmental compliance costs, materials and supplies. For the nine months ended March 31, 2003 and 2002, the direct operating costs and expenses of the terminals, pipelines, and tugs and barges were approximately $22.0 million and $20.0 million, respectively. The increase of $2.0 million in direct operating costs and expenses was due principally to the addition of the Coastal Fuels assets which resulted in approximately $1.8 million of additional direct operating costs and expenses. The remainder of the increase resulted from increases of approximately $0.7 million in wages and employee benefits and $0.2 million in maintenance and repairs offset by decreases of approximately $0.5 million in rent expense, $0.1 million in property taxes and $0.1 million in materials and supplies.

Supply, distribution and marketing

        The net operating margins from our supply, distribution and marketing operations for the nine months ended March 31, 2003 were $53.6 million, compared to $48.5 million for the nine months ended March 31, 2002. For the nine months ended March 31, 2003, we recognized approximately $18.9 million in net operating margins from the transfer of minimum inventory volumes to discretionary inventory volumes and their subsequent sale to customers. That increase in net operating margins was offset by a lower of cost or market write-down of approximately $12.4 million. The net operating margins from our supply, distribution and marketing operations are as follows (in thousands):

			Nine Months Ended March 31,
			2003			2002
Rack sales			$	1,267,934		729,888
Bulk sales				3,536,712		2,544,730
Contract sales				1,134,188		632,127
Supply management services (net in 2003; gross in 2002)				11,062		95,113
		Gross sales		5,949,896		4,001,858
Cost of product sold				(5,805,212	)	(3,884,248	)
Lower of cost or market write-downs on base operating volumes				(12,412	)	—
		Net margin before other direct costs and expenses		132,272		117,610
Other direct costs and expenses:
	Losses on NYMEX futures contracts			(78,072	)	(55,173	)
	Change in unrealized gains (losses) on supply management services contracts			—		(1,003	)
	Lower of cost or market write-downs on inventories—minimum volumes			(633	)	(12,963	)
		Net operating margins	$	53,567		48,471

        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 sales, bulk sales and contract sales.

        Rack Sales.    Rack 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 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

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

        Rack sales were approximately $1,267.9 million and $729.9 million for the nine months ended March 31, 2003 and 2002, respectively. For the nine months ended March 31, 2003 and 2002, we averaged approximately 129,000 and 101,000 barrels per day, respectively, of delivered volumes under rack sales.

        Bulk Sales.    Bulk sales are spot sales of large quantities of product to wholesalers, distributors and marketers in major cash markets. We also may make a bulk sale of products prior to scheduled delivery to us 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 $3,536.7 million and $2,544.7 million for the nine months ended March 31, 2003 and 2002, respectively. For the nine months ended March 31, 2003 and 2002, we averaged approximately 374,000 and 338,000 barrels per day, respectively, of delivered volumes under bulk 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 $1,134.2 million and $632.1 million for the nine months ended March 31, 2003 and 2002, respectively. For the nine months ended March 31, 2003 and 2002, we averaged approximately 114,000 and 84,000 barrels per day, respectively, of delivered volumes under contract sales.

        Supply Management Services Contracts, Net.    We provide supply 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 management services: delivered fuel price management, retail price management, and logistical supply management services. Our delivered fuel price management and retail price management contracts are carried at fair value because these contracts qualify as derivative instruments pursuant to SFAS No. 133. Changes in the fair value of our delivered fuel price management and retail price management contracts are included in net margins attributable to our supply, distribution and marketing operations.

        For the nine months ended March 31, 2003, our revenues from delivered fuel price management and retail price management contracts are presented in the accompanying consolidated statement of operations on a net basis (i.e., product costs are netted directly against gross revenues to arrive at net revenues) pursuant to EITF 02-03. The information necessary to present these revenues on a net basis for periods prior to July 1, 2002 is not readily available and it is impracticable to obtain. Net revenues

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attributable to our delivered fuel price management and retail price management contracts are as follows (in thousands):

			Nine Months Ended March 31,
			2003			2002
Gross revenues			$	116,385		95,113
Less:
	Cost of revenues			(96,645	)
	Change in unrealized gains (losses) on contracts			(8,678	)
		Net revenues	$	11,062

        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.

        Lower of Cost or Market Write-Downs on Base Operating Volumes.    During the nine months ended March 31, 2003 and 2002, we recognized impairment losses of approximately $12.4 million and $nil, respectively, due to lower of cost or market write-downs on the base operating volumes due principally to declining prices during March 2003.

        Losses on NYMEX Futures Contracts.    Our risk management strategy generally is intended to maintain a balanced position of forward sale and forward purchase commitments against our discretionary inventories held for immediate sale 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 and our obligations to deliver products at fixed prices and through our sales contracts and supply 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 hedging arrangement. In order to accurately hedge against price fluctuations, we must attempt to 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 hedge against the same inventory. We refer to this as "rolling" the hedges. During a period of rising prices, our risk management contracts (i.e., short futures) that reduce our risk to commodity price changes associated with our discretionary inventory volumes will decline in value resulting in a loss.

        Losses on NYMEX futures contracts were approximately $78.1 million and $55.2 million for the nine months ended March 31, 2003 and 2002, respectively, due principally to rising commodity prices during these periods.

        Lower of Cost or Market Write-Downs on Inventories—Minimum Volumes.    During the nine months ended March 31, 2003 and 2002, we recognized impairment losses of approximately $0.6 million and $13.0 million, respectively, due to lower of cost or market write-downs on the minimum inventory volumes.

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Costs and expenses

        Selling, general and administrative expenses for the nine months ended March 31, 2003 were $28.5 million, compared to $25.6 million for the nine months ended March 31, 2002. The increase of $2.9 million was due principally to travel costs to investigate certain potential acquisition targets of approximately $0.5 million and increases in relocation, accounting, insurance and legal costs of approximately $2.4 million.

        Depreciation and amortization for the nine months ended March 31, 2003 and 2002, was $13.4 million, compared to $12.4 million. The increase of $1.0 million in depreciation and amortization is principally related to depreciation and amortization on new additions to property, plant, and equipment.

        We recognized special charges of $1.4 million during the nine months ended March 31, 2003 related to the corporate relocation and transition. During the nine months ended March 31, 2003 we substantially completed the relocation of our employees from Atlanta, Georgia to Denver, Colorado and paid the remaining special termination benefits and transition bonuses. We expect to pay the remaining accrued liability before June 30, 2003.

Other income and expenses

        Dividend income from and equity in earnings (loss) of petroleum related investments for the nine months ended March 31, 2003 was $0.4 million, compared to $1.5 million for the nine months ended March 31, 2002. The decrease of $1.1 million in dividend income 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 in the current period. 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 nine months ended March 31, 2003 was $0.2 million, as compared to $0.5 million for the nine months ended March 31, 2002. Pursuant to our cash management practices, excess cash balances are used to pay down our outstanding borrowings under our bank credit facility and commodity margin loan.

        Interest expense for the nine months ended March 31, 2003 was $10.2 million, compared to $9.6 million during the nine months ended March 31, 2002. The increase of $0.6 million in interest expense was primarily attributable to an increase in the amount of debt outstanding during the current period, offset by lower interest rates during the nine months ended March 31, 2003, as the average interest rate under our bank credit facility was 4.0% and 5.3% for the nine months ended March 31, 2003 and 2002, respectively. For the nine months ended March 31, 2003, our interest expense resulted from $5.8 million for outstanding borrowings under our bank credit facility, $0.3 million for outstanding letters of credit, $0.1 million for outstanding borrowings under our commodity margin loan, and $4.0 million in net monthly payments on the interest rate swap. For the nine months ended March 31, 2002, our interest expense resulted from $5.7 million for outstanding borrowings under our bank credit facility and Senior Notes, $0.2 million for outstanding letters of credit, $0.5 million for outstanding borrowings under our commodity margin loan, and $3.2 million in net payments for the interest rate swap.

        Other financing costs (income) for the nine months ended March 31, 2003 were $0.9 million, compared to $2.7 million for the nine months ended March 31, 2002. The decrease of $1.8 million in other financing costs was due principally to an unrealized gain on an interest rate swap of $2.2 million during the nine months ended March 31, 2003, as compared to an unrealized loss on an interest rate swap of $(1.3) million during the nine months ended March 31, 2002, and a decrease in the amortization of deferred financing costs of $0.4 million, offset by the write-off of debt issuance costs in the amount of $2.2 million related to the repayment of our former bank credit facility. The swap

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agreement provides that we pay a fixed interest rate of 5.48% on the notional amount of $150 million in exchange for receiving a variable rate based on LIBOR so long as the one-month LIBOR interest rate does not rise above 6.75%. If the one-month LIBOR rate rises above 6.75%, the swap knocks out and we will receive no payments under the agreement until such time as the one-month LIBOR rate declines below 6.75%. At March 31, 2002, the one-month LIBOR rate was 1.9%. On February 28, 2003, we settled our obligations under the swap agreement when we repaid our former bank revolving credit facility.

Income taxes

        Income tax expense was $12.9 million for the nine months ended March 31, 2003, which represents an effective combined federal and state income tax rate of 38.0%. Income tax expense was $9.5 million for the nine months ended March 31, 2002, which represents an effective combined federal and state income tax rate of 38.0%.

Cumulative effect adjustment for a change in accounting principle

        As a result of the guidance reached on EITF 02-03, we are no longer permitted to carry our inventories—discretionary volumes at fair value effective October 1, 2002. The excess of the fair value of our inventories—discretionary volumes over their cost basis as of October 1, 2002 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 $0.9 million and $7.3 million for the nine months ended March 31, 2003 and 2002, respectively. The decrease in the current year dividend resulted from a reduction in the number of shares of Series A Convertible Preferred stock outstanding during the current period. 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. 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.

        Preferred stock dividends on our Series B Redeemable Convertible Preferred Stock were $2.1 million for the nine months ended March 31, 2003. There were no shares of Series B Redeemable Convertible Preferred Stock outstanding during the nine months ended March 31, 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 $3.3 million, offset by the amortization of the premium on the carrying amount of the Series B Redeemable Convertible Preferred Stock of $1.2 million.

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LIQUIDITY, CAPITAL RESOURCES, AND COMMODITY PRICE RISK

        At March 31, 2003, our current assets exceeded our current liabilities by $91.5 million, compared to $168.1 million at June 30, 2002. The decrease of $76.6 million in working capital is due principally to the outstanding borrowings on the Working Capital Credit Facility.

        The increase in accounts receivable of $71.2 million is due principally to increased supply, distribution, and marketing volumes coupled with an increase in commodity prices. Our gross revenues for the supply, distribution and marketing operations were approximately $2.3 billion and $1.3 billion for the three months ended March 31, 2003 and 2002, respectively. Our gross revenues for the supply, distribution and marketing operations were approximately $5.9 billion and $4.0 billion for the nine months ended March 31, 2003 and 2002, respectively.

        Our Risk Management Committee reviews the discretionary inventory volumes and related open positions in risk management contracts on a regular basis in order to ensure compliance with our inventory and risk management policies. We have adopted policies under which changes to our net risk position, which is subject to commodity price risk, requires the prior approval of our Audit Committee of the Board of Directors.

        Our risk management strategy generally is intended to maintain a balanced position of forward sale and forward purchase commitments against our discretionary inventories and our 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 and our obligations to deliver products at fixed prices and through our sales contracts and supply management contracts. Our physical inventory position, which includes firm commitments to buy and sell product, is reconciled daily and that net position is offset with risk management contracts.

        In order to protect against price volatility with respect to our discretionary inventories and fixed-price delivery obligations, we enter into futures contracts. Futures contracts are obligations to purchase or sell a specific volume of inventory at a fixed price at a future date. All of our futures contracts are traded on the NYMEX and require an initial margin deposit to open a futures contract. At March 31, 2003 and June 30, 2002, we had approximately $23.4 million and $8.6 million 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 March 31, 2003, a $0.05 per gallon unfavorable change in commodity prices would have required us to make a cash payment of approximately $9.0 million to cover the variation margin. Conversely, a $0.05 per gallon favorable change in commodity prices would have permitted us to receive approximately $9.0 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 counterparties to our supply 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. For the three months ended March 31, 2003 and 2002, we recognized losses on NYMEX futures contracts of approximately $33.2 million and $15.6 million, respectively. For the nine months ended March 31, 2003 and 2002, we recognized losses on NYMEX futures contracts of approximately $78.1 million and $55.2 million, respectively.

        When we purchase refined petroleum products, we generally enter into NYMEX futures contracts to protect against price fluctuations for the underlying commodity. 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.

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        In order to accurately hedge against price fluctuations, we also must attempt to 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 hedge against the same inventory. We refer to this as "rolling" the hedges.

        Included in the recognized losses on NYMEX futures contracts for the three and nine months ended March 31, 2003, are losses of approximately $20.7 million and $26.8 million, respectively, from unwinding the original futures contract in an unfavorable futures market and rolling the hedges in an unfavorable futures market.

        During the three months ended March 31, 2003, we re-evaluated our risk management strategy in light of the acquisition of the Coastal Fuels assets, which expanded our product offering to include bunker fuel and No. 6 oil, the expansion of our supply, marketing and distribution activities along the Mississippi and Ohio rivers, and the significance of the overall losses we were incurring on our NYMEX futures contracts. Upon completion of our analysis, we concluded that our base inventory volumes and minimum inventory volumes, which are necessary to support our operations, would be increased in the aggregate from approximately 2.0 million barrels to approximately 3.8 million barrels, and that our risk management policy should permit discretion in determining the volume of inventories that would be hedged with NYMEX futures contracts at any particular point in time. Consequently, our risk management policy has been amended to allow our management team the discretion to hedge up to 500,000 barrels of our base operating inventory volumes, which would reduce the total unhedged inventory (base operating volumes and minimum volumes) to approximately 3.3 million barrels, or to leave unhedged up to 500,000 barrels of our discretionary inventory held for immediate sale or exchange, which would increase our total unhedged inventory to approximately 4.3 million barrels. We decide whether to hedge a portion of our base operating inventory or to leave a portion of our discretionary inventory unhedged depending on our expectations of future market changes. To the extent that we do not hedge 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 hedged.

        Prior to March 1, 2003, we treated inventories not held for sale or exchange in the ordinary course of business and not subject to price risk management as inventories—minimum volumes. Our minimum inventories consisted of tank bottoms, line fill in our proprietary pipelines, and in-transit volumes on common carrier pipelines. Our revised risk management policy now allows us the discretion to hedge up to 500,000 barrels of our base operating inventory volumes. The ability to hedge a portion of our base operating inventory volumes necessitated the transfer for financial reporting purposes of approximately 1.3 million barrels of our original inventories—minimum volumes to inventories—discretionary volumes, representing the in-transit volumes on common carriers. The weighted average cost basis of the transferred volumes was approximately $0.54 per gallon. For the three and nine months ended March 31, 2003, we recognized for financial reporting purposes an increase in net operating margins of approximately $18.9 million on the sale of the transferred volumes, which was offset by a lower of cost or market write-down of approximately $12.4 million.

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        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 at March 31, 2003, and at fair value at June 30, 2002. Inventories—discretionary volumes are as follows (in thousands):

	March 31, 2003			June 30, 2002
	Amount		Bbls	Amount		Bbls
Volumes held for immediate sale or exchange	$	74,045	2,099	$	175,169	5,749
Volumes held for base operations		104,339	2,922		—	—
Inventories—discretionary volumes	$	178,384	5,021	$	175,169	5,749

        Based on the level of our operations at March 1, 2003, we determined that we should establish a base operating inventory, exclusive of minimum volumes, of approximately 2.9 million barrels within inventories—discretionary volumes, consisting primarily of product in transit in common carrier pipelines. Changes in our operation, such as the acquisition of additional terminals, may result in changes in the volume of our base operating inventory. The activity in our volumes held for base operations, exclusive of minimum volumes, is summarized as follows (in thousands):

	Amount			Barrels
As of June 30, 2002	$	—		—
Transfer from minimum volumes		47,813		1,280
Expansion of existing operations		38,876		875
Acquisition of Coastal Fuels assets		30,062		767
Lower of cost or market write-down		(12,412	)	—
As of March 31, 2003	$	104,339		2,922

        Our inventories—minimum volumes, which are limited to tank bottoms and line fill in proprietary pipelines at March 31, 2003, are not held for sale or exchange in the ordinary course of business and, therefore, we do not hedge the market risks associated with this inventory. Our inventories—minimum volumes are presented in the accompanying consolidated balance sheet as non-current assets and are carried at the lower of cost or market. Inventories—minimum volumes are as follows (in thousands):

	March 31, 2003			June 30, 2002
	Amount		Bbls	Amount		Bbls
Gasolines	$	13,020	497	$	27,855	1,200
Distillates		7,449	319		17,443	800
No. 6 oil		1,548	61		—	—
Inventories—minimum volumes	$	22,017	877	$	45,298	2,000

        At March 31, 2003 and June 30, 2002, the weighted average adjusted cost basis of our inventories—minimum volumes was $0.60 and $0.54 per gallon, respectively. The activity in our inventories—minimum volumes is summarized as follows (in thousands):

	Amount			Barrels
As of June 30, 2002	$	45,298		2,000
Transfer to discretionary volumes		(28,959	)	(1,280	)
Acquisition of Coastal Fuels assets		6,311		157
Lower of cost or market write-down		(633	)	—
As of March 31, 2003	$	22,017		877

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        Relative month-end commodity prices from June 30, 2001 to March 31, 2003 (NYMEX close on the last day of the month) are as follows:

	Crude Oil		Heating Oil	Gasoline
6/30/01	$	26.25	.709	.721
7/31/01		26.35	.697	.732
8/31/01		27.20	.766	.806
9/30/01		23.43	.664	.680
10/31/01		21.18	.598	.552
11/30/01		19.44	.532	.534
12/31/01		19.84	.551	.573
1/31/02		19.48	.523	.559
2/28/02		21.74	.563	.581
3/31/02		26.31	.669	.825
4/30/02		27.29	.689	.823
5/31/02		25.31	.630	.738
6/30/02		26.86	.680	.794
7/31/02		27.02	.676	.830
8/31/02		28.98	.748	.814
9/30/02		30.45	.802	.814
10/31/02		27.22	.744	.864
11/30/02		26.89	.757	.734
12/31/02		31.20	.866	.865
1/31/03		33.51	.959	.976
2/28/03		36.60	1.256	1.038
3/31/03		31.04	.792	.944

        The following table indicates the maturities of our supply management services contracts, including the credit quality of our counterparties to those contracts with unrealized gains at March 31, 2003.

		Fair value of contracts (in thousands)
		Maturity less than 1 year			Maturity 1-3 years		Maturity 4-5 years	Maturity in excess of 5 years	Total
Unrealized gain position—asset
	Investment grade	$	3,164		333		—	—	$	3,497
	Non-investment grade		4,542		3,597		—	—		8,139
	No external rating		13,607		18		—	—		13,625
			21,313		3,948		—	—		25,261
Unrealized loss position—liability			(19,945	)	(107	)	—	—		(20,052	)
Net unrealized gain position—asset		$	1,368		3,841		—	—	$	5,209

        At March 31, 2003, the unrealized gain on our supply management services contracts with non-investment grade counterparties was approximately $8.1 million. A single customer represented approximately $4.3 million of that unrealized gain. At March 31, 2003, we also had supply management services contracts with that customer that were in an unrealized loss position of approximately $2.0 million. Therefore, the net fair value of all our supply management services contracts with that customer was approximately $2.3 million at March 31, 2003. The following table includes information

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about the changes in the fair value of our supply management services contracts with that customer for the nine months ended March 31, 2003 (in thousands):

Fair value at June 30, 2002	$	11,041
Amounts realized or otherwise settled during the year		(4,166	)
Change in fair value attributable to change in commodity prices		(7,968	)
Other changes in fair value		3,432
Fair value at March 31, 2003	$	2,339

        Excluding the acquisitions of Coastal Fuels assets and the products terminals in Brownsville, Texas and Fairfax, Virginia, capital expenditures for the three months and nine months ended March 31, 2003 were $3.1 million and $7.9 million, respectively, for terminal and pipeline facilities and assets to support these facilities. Excluding acquisitions, capital expenditures for the remainder of the year ending June 30, 2003, are estimated to be approximately $3.0 million. 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 Working Capital Credit Facility as in effect at March 31, 2003 provided for a maximum borrowing line of credit that was the lesser of (i) $250 million and (ii) the borrowing base (as defined; $389 million at March 28, 2003). The maximum borrowing amount is reduced by the amount of letters of credit that are outstanding. The borrowing base is a function of our cash, accounts receivable, inventory, exchanges, margin deposits, open positions of energy services and risk management contracts, outstanding letters of credit, and outstanding indebtedness as defined in the facility. At March 31, 2003, we had borrowings of $65.0 million outstanding and letters of credit of $30.7 million outstanding under the Working Capital Credit Facility. We also had the ability to borrow an additional $99.3 million under the facility based on the borrowing base computation at March 28, 2003. The terms of the Credit Agreement included financial covenants that are tested on a quarterly basis including: (i) a fixed charge coverage of 150%, (ii) a maximum funded debt leverage ratio of 4.5 times the last twelve months EBITDA (as defined), (iii) a minimum consolidated tangible net worth, including preferred stock, of at least $252.7 million, and (iv) an annual limitation of $50 million with respect to acquisitions, additions to property, plant, and equipment, and the redemption of TransMontaigne's Series A Preferred stock.

        On May 30, 2003, we consummated the sale and issuance of $200 million aggregate principal amount of 9¹/8% Senior Subordinated Notes ("Old Notes") 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 Old Notes to repay the Term Loan. The indenture governing the Old Notes contains covenants that, among other things, limits our ability to incur additional indebtedness, pay dividends on, redeem or repurchase our common stock, make investments, make certain dispositions of assets, engage in transaction with affiliates, create certain liens, and consolidate, merge, or transfer all or substantially all of our assets. See "Description of the Exchange Notes—Certain Covenants."

        On June 25, 2003, we amended and restated the Working Capital Credit Facility in connection with the syndication of the facility. All outstanding borrowings under the Working Capital Credit Facility are due and payable on February 28, 2006. The Working Capital Credit Facility contains affirmative and negative covenants (including limitations on indebtedness, limitations on dividends and other distributions, limitations on certain intercompany transactions, limitations on mergers, consolidation and the disposition of assets, limitations on investments and acquisitions and limitations on liens) as well as customary representations and warranties and events of default. It also contains certain financial covenants that are tested on a quarterly basis including a minimum fixed charge coverage ratio of

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150%, a maximum funded senior debt leverage ratio of 4.5 times the last twelve months' EBITDA (as defined in the credit agreement), a minimum current ratio of 120% and a minimum consolidated tangible net worth test. In addition, we may not make aggregate expenditures in excess of $80.0 million with respect to general corporate purposes over the term of the agreement (however, such amount shall be increased by certain cash flow amounts generated after February 28, 2003). See "Description of Other Indebtedness."

        We believe that our current working capital position; future cash expected to be provided by operating activities; available borrowing capacity under our bank 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.

        Net cash provided by operating activities of $92.0 million for the three months ended March 31, 2003, was due principally to net earnings adjusted for non-cash activities, decrease in inventories—discretionary volumes, increase in inventory due to others under exchange agreements and excise taxes payable and other accrued liabilities. The net cash provided by operating activities of $28.7 million for the three months ended March 31, 2002, was due principally to an increase in unrealized loss on supply management services contracts, inventory due to others under exchange agreements, and excise taxes payable and other accrued liabilities.

        Net cash provided by operating activities of $73.8 million for the nine months ended March 31, 2003 was due principally to net earnings adjusted for non-cash activities, increases in trade accounts payable, unrealized losses on supply management service contracts, inventory due to others under exchange agreements, excise taxes and other accrued liabilities. The net cash used by operating activities of $(93.7) million for the nine months ended March 31, 2002 was due principally to an increase in trade accounts receivable and inventories—discretionary volumes and decreases in inventory due to others under exchange agreements, offset by an increase in trade accounts payable and excise taxes payable and other accrued liabilities.

        Net cash used by investing activities of $(113.5) million for the three months ended March 31, 2003 was due principally to capital expended for additions to property, plant and equipment of approximately $8.4 million, acquisitions of approximately $95.0 million, additional restricted cash of $3.8 million to cover required margin deposits on risk management contracts and additional minimum inventory volumes of $6.3 million. Net cash used by investing activities of $(17.9) million during the three months ended March 31, 2002, was due principally to capital expended for construction and improvements to existing operating facilities and acquisitions of $3.3 million and an increase of $14.5 million in restricted cash held by commodity broker.

        Net cash used by investing activities of $(129.8) million for the nine months ended March 31, 2003 was due principally to additions to property, plant and equipment of $13.8 million, acquisitions of $95.0 million, additional restricted cash of $14.7 million to cover required margin deposits on risk management contracts and additional minimum inventory volumes of $6.3 million. Net cash provided by investing activities of $104.6 million during the nine months ended March 31, 2002 was due principally to proceeds received from the sale of assets of $117.2 million, offset by capital expended for construction and improvements to existing operating facilities and acquisitions of $4.5 million and an increase of $6.6 million in restricted cash held by commodity broker.

        Net cash provided by financing activities of $41.8 million for the three months ended March 31, 2003 was due principally to proceeds from borrowings under our Working Capital Credit Facility and term loan of $265.0 million offset by repayments of borrowings under our former bank credit facility of $200.0 million, repayments of borrowings under our commodity margin loan of $9.8 million, payment of debt issuance costs of $11.9 million in connection with the new Credit Agreement, and payment of preferred stock dividends of $1.4 million. Net cash used by financing activities of $(20.5) million for the

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three months ended March 31, 2002 was due principally to repayment of borrowings under our commodity margin loan of $20.0 million.

        Net cash provided by financing activities of $51.4 million for the nine months ended March 31, 2003 was due principally to proceeds from borrowings under our Working Capital Credit Facility and term loan of $265.0 million offset by repayments of borrowings under our former bank credit facility of $187.0 million, repayments of borrowings under our commodity margin loan of $11.3 million, payment of debt issuance costs of $12.0 million in connection with the new Credit Agreement, and payment of preferred stock dividends of $3.1 million. Net cash used by financing activities of $(24.6) million for the nine months ended March 31, 2002 was due principally to repayments of borrowings under our bank credit facility and master shelf facility of $4.5 million and repayment of borrowings under our commodity margin loan of $20.0 million.

NEW ACCOUNTING PRONOUNCEMENTS WITH DELAYED EFFECTIVE DATES

        In June 2002, the FASB issued SFAS No. 146,Accounting for Costs Associated with Exit or Disposal Activities, which addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies EITF Issue No. 94-3,Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). SFAS No. 146 applies to costs associated with an exit activity that does not involve an entity newly acquired in a business combination or with a disposal activity covered by SFAS No. 144. A liability for a cost associated with an exit or disposal activity generally shall be recognized and measured initially at its fair value in the period in which the liability is incurred. In periods subsequent to initial measurement, changes to the liability shall be measured using the credit-adjusted risk-free rate that was used to measure the liability initially. We are required to adopt the provisions of SFAS No. 146 for exit or disposal activities initiated after December 31, 2002. In connection with our corporate relocation and transition, we accrued our expected lease abandonment costs and severance costs. After its effective date, SFAS No. 146 does not permit the accrual of expected costs in advance of those costs being incurred. Had SFAS No. 146 been in effect as of July 1, 2001, we believe that approximately $3.1 million of accrued lease abandonment costs and approximately $0.7 million of accrued severance benefits would not have been recognized during the year ended June 30, 2002.

        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 are required to adopt the provisions of SFAS No. 150 in our interim financial statements for the three months ending September 30, 2003. We do not expect the adoption of SFAS No. 150 to have an impact on our consolidated financial statements. Our Series A and Series B preferred stock will continue to be presented between liabilities and common equity in our accompanying consolidated balance sheet. Pursuant to SFAS No. 150, our Series A and Series B preferred stock are not required to be presented as liabilities in the accompanying consolidated balance sheet because holders of our preferred stock have the right, at the holder's option, to convert the preferred shares into common shares.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS; THREE FISCAL YEARS ENDED JUNE 30, 2002

GENERAL

        The following discussion and analysis of the results of operations and financial condition should be read in conjunction with the consolidated financial statements. Material period-to-period variances in the consolidated statements of operations are discussed under "Results of Operations."

CRITICAL ACCOUNTING 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 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, 2002, our allowance for doubtful accounts was $1.25 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.

        Inventories—Discretionary Volumes.    At June 30, 2002, we held products for sale or exchange in the ordinary course of business with a value of $175.2 million. Our inventories—discretionary volumes are carried at fair value in the accompanying consolidated balance sheets. The valuation of our inventories—discretionary volumes 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 historical relationships between current and future prices and delivery locations.

        Supply Management Services Contracts.    At June 30, 2002, we are a party to supply management services contracts that require us to deliver physical quantities of refined petroleum products over a specified term at a specified price. Our supply management services contracts are carried at fair value in the accompanying consolidated balance sheets. At June 30, 2002, our net unrealized gains on supply management services contracts were approximately $13.9 million. The valuation of our supply management services 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 historical relationships between current and future prices and delivery locations.

        Accrued Lease Abandonment.    At June 30, 2002, we have an accrued liability of $3.1 million as our estimate of the future payments we expect to pay, net of sublease payments we expect to receive from subleasing our to-be-vacated office space in Denver, Colorado and Atlanta, Georgia. The valuation of our accrued lease abandonment is based on the timing and amount of sublease payments we expect to receive from subleasing our to-be-vacated office space. Our estimate of the timing and amount of sublease payments is based on information received from real estate brokers.

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        Accrued Transportation and Deficiency Agreements.    At June 30, 2002, we have an accrued liability of $2.8 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 accrued 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.

        Accrued Environmental Obligations.    At June 30, 2002, we have an accrued liability of $2.3 million as our estimate of the 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.

        Series B Redeemable Convertible Preferred Stock.    At June 30, 2002, the carrying amount of the Series B Redeemable Convertible Preferred Stock was $80.9 million. The carrying amount is based on our estimate of the fair value of the Series B Redeemable Preferred Stock at the date of issuance (June 28, 2002). We estimated the value of the Series B Redeemable Preferred Stock by adding together (i) the present value of the expected dividend payments and mandatory redemption value discounted at a risk-adjusted rate and (ii) the value of the embedded conversion option using an option pricing model.

SIGNIFICANT DEVELOPMENTS

        During the year ended June 30, 2002, we amended and restated our bank credit facility, or the New Facility, to provide us with financing to expand our petroleum products marketing and terminaling network, support our working capital requirements and general corporate needs, recapitalize our preferred stock, and repurchase shares of our common stock. The New Facility provides us with a revolving line of credit and the ability to issue letters of credit to support our supply, distribution, and marketing operations.

        We also announced our decision to relocate our supply, distribution and marketing operations from Roswell, Georgia to Denver, Colorado to join our corporate headquarters.

Extension of bank credit facility

        On June 28, 2002, we entered into the New Facility with a syndication of banks. The New Facility provides for a maximum borrowing under the revolving line of credit that is the lesser of (i) $300 million and (ii) the borrowing base. The borrowing base is a function of our accounts receivable, inventory, exchanges, margin deposits, open positions of supply management services and risk management contracts, outstanding letters of credit, and outstanding indebtedness as defined in the New Facility. Borrowings under the New Facility bear interest (at our option) based on the lender's base rate plus a specified margin, or LIBOR plus a specified margin; the specified margins are a function of our leverage ratio as defined in the New Facility. Borrowings under the New Facility are secured by substantially all of our assets. The New Facility matures on June 27, 2005. The terms of the New Facility include financial covenants relating to fixed charge coverage, current ratio, maximum leverage ratio, consolidated tangible net worth, capital expenditures, cash distributions and open

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inventory positions that are tested on a quarterly and annual basis. At June 30, 2002, we were in compliance with all covenants included in the New Facility.

Preferred stock recapitalization

        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.

        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 fair value of the consideration paid to the holders of the Series A Convertible Preferred Stock was in excess of the financial statement carrying amount of the Series A Convertible Preferred Stock that was redeemed. That excess of approximately $1.5 million has been treated in a manner similar to preferred stock dividends in the accompanying consolidated financial statements. At June 30, 2002, there were 24,421 shares of Series A Convertible Preferred Stock that remain outstanding.

        In connection with the Preferred Stock Recapitalization Agreement, we also agreed to repurchase approximately 4.1 million shares of our common stock from an institutional holder of the Series A Convertible Preferred Stock for cash consideration of approximately $20.4 million.

        We borrowed approximately $41.7 million under the New Facility to finance the redemption of the Series A Convertible Preferred Stock and the reacquisition of the common stock.

Corporate relocation and transition

        During the year ended June 30, 2002, we announced to our employees that our supply, distribution and marketing operations in Atlanta, Georgia would be relocated to Denver, Colorado. On March 19, 2002, we offered approximately 72 employees the opportunity to relocate to Denver, Colorado and we informed approximately 25 employees that they would not be offered the opportunity to relocate to Denver, Colorado. Ultimately, 36 employees chose to relocate to Denver, Colorado. Those employees are entitled to receive a transition bonus and a relocation package payable upon transfer to the Denver office. The transition bonus is being accrued over the period from date of acceptance by the employee to the expected date of arrival in Denver, Colorado. The relocation costs are being accrued as incurred/earned by the employee. Ultimately, 36 employees chose not to relocate and those employees are entitled to receive termination benefits on their termination date as determined by us. The special termination benefits were accrued upon receipt of the notification from the employee that they did not intend to accept the offer to relocate to Denver, Colorado. For the year ended June 30, 2002, we accrued approximately $2.1 million of benefits due to employees, of which approximately $2.0 million

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remains unpaid as of June 30, 2002. We expect to pay the accrued liability of approximately $2.0 million during the year ending June 30, 2003.

	Special charge		Amounts paid			Accrued liability at June 30, 2002
	(in thousands)
Accrued severance payable to employees not relocating to Denver, Colorado	$	1,512	$	(84	)	$	1,428
Accrued transition benefits payable to employees relocating to Denver, Colorado		501		—			501
Relocation costs incurred during the period		100		—			100
Other		25		(25	)		—
	$	2,138	$	(109	)	$	2,029

        In connection with our corporate relocation and transition, we entered into an operating lease for new office space in Denver, Colorado. The new lease was executed on April 19, 2002. Prior to June 30, 2002, we engaged commercial real estate agents to solicit prospective tenants to sublease our existing office space in Denver, Colorado and the vacated space in Roswell, Georgia. We expect to vacate our existing office space in Denver, Colorado during June 2003 and the space in Roswell, Georgia during September 2002. 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. The abandonment of leasehold improvements represents the carrying amount of those assets that are expected to be abandoned in connection with the abandonment of the office leases. For the year ended June 30, 2002, we charged to income approximately $4.2 million for abandonment of office leases and leasehold improvements.

		Special charge		Amounts paid or written-off			Accrued liability at June 30, 2002
		(in thousands)
Abandonment of office leases:
	Denver, Colorado	$	1,150	$	—		$	1,150
	Atlanta, Georgia		1,960		—			1,960
Abandonment of leasehold improvements:
	Denver, Colorado		550		(550	)		—
	Atlanta, Georgia		518		(518	)		—
		$	4,178	$	(1,068	)	$	3,110

        We expect to pay the accrued liability of approximately $3.1 million, net of estimated sublease rentals, as follows (in thousands):

Years ending June 30:	Lease payments		Estimated sublease rentals			Accrued liability at June 30, 2002
2003	$	745	$	(97	)	$	648
2004		991		(562	)		429
2005		1,020		(565	)		455
2006		1,045		(569	)		476
2007		948		(508	)		440
Thereafter		1,243		(581	)		662
	$	5,992	$	(2,882	)	$	3,110

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DISPOSITIONS

        On May 31, 2002, our 30.02% interest in ST Oil Company was reacquired by ST Oil Company for cash consideration of approximately $3.0 million and we recognized a net gain of approximately $1.4 million on the sale. The proceeds from the sale were used for general corporate purposes.

        On July 31, 2001, we sold the NORCO Pipeline system and related terminals, or NORCO, to Buckeye Partners L.P. for cash consideration of approximately $62.0 million and recognized a net gain of approximately $8.6 million on the sale. The proceeds from the sale were used to repay long-term debt and for general corporate purposes.

        On July 27, 2001, we sold 861 shares of the common stock of West Shore Pipeline Company, or West Shore, thereby reducing our ownership interest to 18.50%. The West Shore common stock was sold to Midwest Pipeline Company, LLC for cash consideration of approximately $2.9 million. We recognized a loss of approximately $1.1 million on this sale. As a result of this transaction, we also recognized a loss on our remaining investment in West Shore of approximately $8.8 million. We sold our remaining 18.50% interest on October 29, 2001 to Buckeye Partners L.P. for cash consideration of approximately $23.1 million, which approximated our adjusted book value. The cash proceeds from both sales were used to repay long-term debt and for general corporate purposes.

        Effective June 30, 2001, we sold two petroleum distribution facilities in Little Rock, Arkansas to Williams Energy Partners L.P. for $29.0 million. The cash proceeds from the sales transactions were received on July 3, 2001. We recognized a net gain in June 2001 of approximately $22.1 million on the sale. The proceeds from the sale were used to repay long-term debt and for general corporate purposes.

        Effective December 31, 1999, we sold our natural gas gathering subsidiary, Bear Paw Energy Inc., or BPEI, to BPE Acquisition LLC, a special purpose entity formed by Bear Paw's management in association with Thomas J. Edelman and Chase Capital Partners. The sale of BPEI was for cash consideration of $107.5 million, plus $23.7 million for reimbursement of the capital expenditures we made on BPEI's newly constructed Powder River coal seam gathering system from July 1, 1999 to December 31, 1999. This disposition resulted in an approximate $16.6 million gain. The sale proceeds were used to reduce long-term debt and for general corporate purposes.

ACQUISITIONS

        Effective June 30, 2002, we acquired for cash consideration of approximately $7.2 million the remaining 40% interest that we previously did not own in the Razorback Pipeline system, a 67 mile products pipeline between Mount Vernon, Missouri and Rogers, Arkansas with approximately 0.4 million barrels of storage capacity.

        On May 31, 2000, we acquired two products terminals located in Richmond and Montvale, Virginia for approximately $3.2 million. These facilities are interconnected to the Colonial and Plantation pipeline systems and include approximately 0.5 million barrels of storage capacity.

SUBSEQUENT EVENTS

        On August 23, 2002, we announced the signing of a long-term terminaling agreement with P.M.I. Trading Limited to provide Products terminaling services and a related pipeline construction assistance agreement with P.M.I. Services North America, Inc., both affiliates of Petroleos Mexicanos, for the construction of a new 17-mile U.S. Products pipeline from the U.S./Mexican border to our terminaling facility located at the port of Brownsville, Texas.

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        We also announced that on July 31, 2002, we closed on the purchase of a 25,000-barrel terminal in Brownsville, Texas. The terminal provides us with additional storage and rail car handling facilities and operating synergies with our main facility in Brownsville, Texas.

RESULTS OF OPERATIONS

        Selected annual results of operations data are summarized below:

			Years ended June 30,
			2002			2001			2000
			(in thousands)
Net operating margins(1):
	Supply, distribution and marketing		$	55,784		$	28,000		$	18,853
	Terminals and pipelines			35,718			45,890			44,254
	Natural gas services(2)			—			—			10,490
		Total net operating margins		91,502			73,890			73,597
Selling, general and administrative expenses				(35,211	)		(34,072	)		(41,680	)
Depreciation and amortization				(16,556	)		(19,510	)		(22,344	)
Impairment of long-lived assets				—			—			(50,136	)
Corporate relocation and transition				(6,316	)		—			—
		Operating income (loss)		33,419			20,308			(40,563	)
Dividend income from and equity in earnings of petroleum related investments				1,450			3,060			1,590
Interest income				599			2,914			3,419
Interest expense and other financing costs				(21,432	)		(30,424	)		(35,480	)
Gain (loss) on disposition of assets, net				(13	)		22,146			13,930
		Earnings (loss) before income taxes		14,023			18,004			(57,104	)
Income tax (expense) benefit				(5,465	)		(6,666	)		19,167
		Net earnings (loss)		8,558			11,338			(37,937	)
Preferred stock dividends				(11,351	)		(8,963	)		(8,506	)
		Net earnings (loss) attributable to common stockholders	$	(2,793	)	$	2,375		$	(46,443	)

(1)

Net operating margins represent net revenues, less direct operating costs and expenses.

(2)

Our natural gas services activities were divested as of December 31, 1999.

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        The following table summarizes our EBITDA, operating results for debt covenant compliance, operating income, and cash flows (in thousands):

		Years ended June 30,
		2002			2001			2000
EBITDA(1)		$	51,412		$	65,024		$	(2,699	)
Operating results for debt covenant compliance(2)		$	64,388		$	61,196		$	33,507
Operating income (loss)		$	33,419		$	20,308		$	(40,563	)
Net cash provided (used) by operating activities		$	(101,512	)	$	51,936		$	267,526
Net cash provided (used) by investing activities		$	102,778		$	(18,969	)	$	77,902
Net cash provided (used) by financing activities		$	3,811		$	(61,130	)	$	(305,417	)
Reconciliation of EBITDA and operating results for debt covenant compliance to net earnings:
Operating results for debt covenant compliance		$	64,388		$	61,196		$	33,507
Lower of cost or market write-downs on minimum inventory volumes			(12,963	)		(18,318	)		—
Impairment of long-lived assets			—			—			(50,136	)
Gain (loss) on disposition of assets			(13	)		22,146			13,930
EBITDA			51,412			65,024			(2,699	)
Depreciation and amortization			(16,556	)		(19,510	)		(22,344	)
Interest expense, net			(11,837	)		(15,215	)		(25,121	)
Other financing costs, net			(8,996	)		(12,295	)		(6,940	)
Income tax benefit (expense)			(5,465	)		(6,666	)		19,167
	Net earnings (loss)	$	8,558		$	11,338		$	(37,937	)

(1)

EBITDA is defined as earnings before income taxes, interest expense, net, other financing costs, net, depreciation and amortization. We believe that, in addition to cash flow from operating activities and net earnings (loss), EBITDA is a useful financial performance measurement for assessing operating performance since it provides an additional basis to evaluate our ability to incur and service debt and to fund capital expenditures. To evaluate EBITDA, the components of EBITDA such as net operating margin and direct operating expenses and the variability of such components over time, also should be considered. EBITDA should not be construed, however, as an alternative to operating income (loss) (as determined in accordance with generally accepted accounting principles ("GAAP")) as an indicator of our operating performance, or to cash flows from operating activities (as determined in accordance with GAAP) as a measure of liquidity.

(2)

We believe that operating results for debt covenant compliance is a useful measure in evaluating our performance because it eliminates the impact on our operating results from gains recognized and deferred on discretionary inventory volumes and the impairment of our inventories—minimum volumes. We believe that, in addition to operating income, cash flow from operating activities and EBITDA, operating results for debt covenant compliance is a useful financial performance measurement reflecting our ability to incur and service debt and to fund capital expenditures. In evaluating operating results for debt covenant compliance, we believe that consideration should be given, among other things, to the amount by which operating results for debt covenant compliance exceeds interest costs for the period; how operating results for debt covenant compliance compares to principal repayments on debt for the period; and how operating results for debt covenant compliance compares to capital expenditures for the period. As a result of the implementation of EITF 02-03, our inventories—minimum volumes and —discretionary volumes are carried at the lower of cost (first in, first out) or market, while our risk management contracts are carried at market. As a result, if market prices are increasing during the end of one quarter and into the

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beginning of the next quarter, we may show significant losses on risk management contracts at the end of the prior quarter and significant gains recognized on our beginning inventories—discretionary volumes in the following quarter. While this volatility tends to offset over several quarters, it can result in significant volatility in our reported operating income and EBITDA between any two quarters. Because the inventory adjustments that affect operating income can be volatile on a quarterly basis, management uses operating results for debt covenant compliance to monitor and manage the operations of our business segments. Management believes that operating results for debt covenant compliance provides an appropriate measure of our debt service capabilities and, as a result, this measure is used as a measure of our financial performance in our borrowing arrangements. Under Financial Accounting Standards Board Statement of Financial Accounting Standards No. 131,Disclosures About Segments of an Enterprise and Related Information, we are required to report measures of profit and loss that are used by our chief operating decision maker in assessing financial performance for each of our reportable segments in the footnotes to our consolidated financial statements and, accordingly, we report operating results for debt covenant compliance in connection with our operating segment disclosures.

        Operating results for debt covenant compliance and EBITDA should not be construed as alternatives to operating income as determined in accordance with generally accepted accounting principles as indicators of our operating performance, or to cash flows from operating activities, as determined in accordance with generally accepted accounting principles as a measure of liquidity.

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

			Three months ended
			September 30, 2001			December 31, 2001			March 31, 2002			June 30, 2002			Year ended June 30, 2002
Net operating margins:
Supply, distribution and marketing
		Net operating margins	$	26,750		$	1,615		$	20,106		$	7,313		$	55,784
Terminals and pipelines
		Net operating margins		8,341			8,513			9,596			9,268			35,718
		Total net operating margins		35,091			10,128			29,702			16,581			91,502
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	)
Corporate relocation and transition				—			—			(315	)		(6,001	)		(6,316	)
		Operating income (loss)		22,344			(2,081	)		16,289			(3,133	)		33,419
Other income (expense), net				(6,811	)		(2,660	)		(2,200	)		(7,725	)		(19,396	)
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
Reconciliation of EBITDA and operating results for debt covenant compliance to net earnings:
	Operating results for debt covenant compliance		$	28,824		$	14,165		$	20,425		$	974		$	64,388
	Lower of cost or market write-downs on minimum inventory volumes			(849	)		(12,114	)		—			—			(12,963	)
	Gain (loss) on disposition of assets			(1,295	)		—			—			1,282			(13	)
		EBITDA		26,680			2,051			20,425			2,256			51,412
	Depreciation and amortization			(4,282	)		(4,024	)		(4,143	)		(4,107	)		(16,556	)
	Interest expense, net			(2,789	)		(2,757	)		(3,577	)		(2,714	)		(11,837	)
	Other financing costs, net			(4,076	)		(11	)		1,384			(6,293	)		(8,996	)
	Income tax benefit (expense)			(5,902	)		1,801			(5,354	)		3,990			(5,465	)
		Net earnings (loss)	$	9,631		$	(2,940	)	$	8,735		$	(6,868	)	$	8,558

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			Three months ended
			September 30, 2000			December 31, 2000			March 31, 2001			June 30, 2001			Year ended June 30, 2001
			(in thousands)
Net operating margins:
Supply, distribution and marketing
		Net operating margins	$	3,782		$	8,512		$	12,700		$	3,006		$	28,000
Terminals and pipelines
		Net operating margins		12,352			12,031			10,220			11,287			45,890
		Total net operating margins		16,134			20,543			22,920			14,293			73,890
Selling, general, and administrative				(7,237	)		(8,157	)		(9,102	)		(9,576	)		(34,072	)
Depreciation and amortization				(4,847	)		(4,821	)		(4,927	)		(4,915	)		(19,510	)
		Operating income (loss)		4,050			7,565			8,891			(198	)		20,308
Other income (expense), net				(3,616	)		(4,754	)		(8,143	)		14,209			(2,304	)
Income tax (expense) benefit				(165	)		(1,068	)		(284	)		(5,149	)		(6,666	)
		Net earnings (loss)	$	269		$	1,743		$	464		$	8,862		$	11,338
Reconciliation of EBITDA and operating results for debt covenant compliance to net earnings:
	Operating results for debt covenant compliance		$	14,344		$	15,559		$	16,524		$	14,769		$	61,196
	Lower of cost or market writedowns on minimum inventory volumes			(4,528	)		(2,353	)		(1,940	)		(9,497	)		(18,318	)
	Gain (loss) on disposition of assets			—			8			—			22,138			22,146
	EBITDA			9,816			13,214			14,584			27,410			65,024
	Depreciation and amortization			(4,847	)		(4,821	)		(4,927	)		(4,915	)		(19,510	)
	Interest expense, net			(3,561	)		(3,795	)		(4,289	)		(3,570	)		(15,215	)
	Other financing costs, net			(974	)		(1,787	)		(4,620	)		(4,914	)		(12,295	)
	Income tax expense			(165	)		(1,068	)		(284	)		(5,149	)		(6,666	)
		Net earnings	$	269		$	1,743		$	464		$	8,862		$	11,338

YEAR ENDED JUNE 30, 2002 COMPARED TO YEAR ENDED JUNE 30, 2001

        We reported net earnings of $8.6 million for the year ended June 30, 2002, compared to net earnings of $11.3 million for the year ended June 30, 2001. After preferred stock dividends, the net earnings (loss) attributable to common stockholders was $(2.8) million for the year ended June 30, 2002, compared to net earnings of $2.4 million for the year ended June 30, 2001. Basic and diluted loss per common share for the year ended June 30, 2002 was $(0.09) based on 31.3 million weighted average common shares outstanding. Basic and diluted earnings per share for the year ended June 30, 2001 was $0.08 per share based upon 30.9 million weighted average common shares outstanding and 31.0 million weighted average diluted shares outstanding.

Supply, distribution and marketing

        Our supply, distribution and marketing operations include energy trading and risk management activities as defined by Emerging Issues Task Force Issue No. 98-10 ("EITF 98-10"),Accounting for Contracts Involved in Energy Trading and Risk Management Activities. In accordance with EITF 98-10, our energy trading and risk management activities are marked to market (i.e., recorded at fair value in the accompanying consolidated balance sheet). The mark-to-market method of accounting requires that

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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 revenues attributable to supply, distribution and marketing in the period of the change in value.

        We seek to maintain a balanced position of forward sale commitments against our discretionary inventories and forward purchase commitments, thereby minimizing or eliminating 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 and the open positions in supply management services and risk management contracts. However, there are certain risks that we do not attempt to hedge or eliminate. For example, we attempt to exploit the price relationships between various delivery locations, or basis (geographical location) differentials. These differentials create opportunities for increased operating margins when we predict the most beneficial location (highest value location) for sales of our discretionary inventories of refined products. However, the margins created from exploiting these market inefficiencies do not occur ratably over our reporting periods.

        During a "contango" or "carry" market structure, we utilize our and third-party terminals to store products to capture commodity price differentials between current and future months. Mark-to-market accounting will create volatility in our net operating margins due to either the widening or narrowing of these pricing spreads from the original spread relationship. If the spreads widen (narrow), marking these storage volumes and the related forward contracts to market will produce unrealized losses (gains) in interim reporting periods. These negative (positive) results will reverse and the originally anticipated spread will be recognized during the future periods when the physical product inventory is delivered against the short future position. At June 30, 2002, we held approximately 3.0 million barrels of distillates in our terminals for future delivery.

        The revenues reported for the supply, distribution and marketing operations include amounts realized on sales, exchanges and arbitrage. The revenues from our supply, distribution and marketing operations for the year ended June 30, 2002 were $6,001.2 million compared to $5,182.5 million for the year ended June 30, 2001. Cost of product sold was $5,932.4 million and $5,136.2 million for the years ended June 30, 2002 and 2001, respectively. The net operating margins from our supply, distribution, and marketing operations for the year ended June 30, 2002 were $55.8 million compared to $28.0 million for the year ended June 30, 2001. The increase of $27.8 million in net revenues is due principally to taking advantage of market opportunities that were caused by volatility in basis (geographical location) differentials. During the quarter ended September 30, 2001, a disruption at a Chicago refinery resulted in increased volatility in basis (geographical location) differentials. This disruption increased the basis (geographical location) differentials for both gasoline and distillates between the Gulf Coast, Chicago and Group (Mid-Continent) regions, which created significant margin opportunities in arbitraging the basis (geographical location) differentials between those markets. During the quarter ended March 31, 2002, we were able to increase our net operating margins by taking advantage of the price volatility in the gasoline market in the Gulf Coast region. That volatility also created significant arbitrage opportunities associated with basis (geographical location) differentials. In addition, during the quarter ended March 31, 2002, we renegotiated and extended for an additional year, a fixed-price supply contract with a large industrial/commercial end-user. We recognized approximately $3.0 million in net operating margins associated with this contract extension and we deferred approximately $1.7 million for the value of the supply logistical management services that we are committed to provide over the term of the supply contract. During the quarter ended June 30, 2002, we experienced a reduction in volatility in basis (geographical location) differentials combined with an unfavorable relationship between crude oil and refined product prices.

        During the years ended June 30, 2002 and 2001, we recognized impairment losses of approximately $13.0 million and $18.3 million, respectively, due to lower of cost or market write-downs on the minimum inventory volumes. These write-downs are included in net operating margins attributable to our supply, distribution and marketing operations.

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Terminals and pipelines

        The revenues from our terminal and pipeline operations for the years ended June 30, 2002 and 2001, were $63.4 million and $82.3 million, respectively. The direct operating costs were $27.7 million and $36.4 million for the years ended June 30, 2002 and 2001, respectively. The net operating margins from our terminal and pipeline operations for the year ended June 30, 2002 were $35.7 million compared to $45.9 million for the year ended June 30, 2001. The decrease of $10.2 million in net operating margins was due principally to the sale of our Little Rock facilities on June 30, 2001 and the NORCO system on July 31, 2001. For the year ended June 30, 2001, the net operating margins from the Little Rock facilities and the NORCO system were $10.4 million.

        Our pipeline net operating margins per barrel of transported volumes were approximately $0.42 and $0.21 for the years ended June 30, 2002 and 2001, respectively. The increase in net operating margins per barrel is due principally to the higher unit tariff being realized on one of our joint tariffs, as compared to the lower unit tariff associated with our NORCO system which was disposed of in July 2001.

Selling, general, and administrative

        Selling, general and administrative expenses for the year ended June 30, 2002 were $35.2 million, compared to $34.1 million for the year ended June 30, 2001. The increase of $1.1 million was due principally to increased compensation and travel expenses related to our corporate relocation and transition during the year ended June 30, 2002.

        Depreciation and amortization for the year ended June 30, 2002 was $16.6 million, compared to $19.5 million for the year ended June 30, 2001. The decrease of $2.9 million in depreciation and amortization was due primarily to the disposition of the NORCO system and Little Rock facilities.

        We recognized special charges of $6.3 million during the year ended June 30, 2002 related to the corporate relocation and transition. We expect to recognize an additional special charge of $2.1 million during the year ended June 30, 2003 to complete the corporate relocation and transition. The additional special charges will consist of $1.7 million in moving costs for employees relocating to Denver, Colorado, transition benefits of $0.3 million payable to employees relocating to Denver, Colorado, and moving costs of $0.1 million related to the relocation of the corporate headquarters.

Other income and expenses

        Dividend income and equity in earnings from petroleum related investments for the year ended June 30, 2002 was $1.5 million, compared to $3.1 million for the year ended June 30, 2001. The decrease of $1.6 million in dividend income was due principally to the decline in dividends received from West Shore. We sold our investment in West Shore on October 29, 2001.

        Interest income for the year ended June 30, 2002 was $0.6 million, compared to $2.9 million for the year ended June 30, 2001. The decrease of $2.3 million in interest income was due primarily to a decrease in interest bearing cash balances and lower interest rates during 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 bank credit facility and commodity margin loan.

        Interest expense for the year ended June 30, 2002 was $12.4 million, compared to $18.1 million during the year ended June 30, 2001. For the year ended June 30, 2002, our interest expense resulted from $7.0 million for outstanding borrowings under our bank credit facility and Senior Notes, $0.3 million for outstanding letters of credit, $0.5 million for outstanding borrowings under our commodity margin loan, and $4.6 million in net payments for the interest rate swap. The decrease of $5.7 million in interest expense was primarily attributable to a reduction in the amount of debt outstanding during the current year. We used a portion of the proceeds from the sale of the Little

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Rock facilities, NORCO system, and West Shore to repay our outstanding borrowings under our bank credit facility and commodity margin loan. We also benefited from lower interest rates during the year ended June 30, 2002, as the average interest rate under our bank credit facility was 5.13% and 6.6% for the years ended June 30, 2002 and 2001, respectively.

        Other financing costs for the year ended June 30, 2002 were $9.0 million, compared to $12.3 million for the year ended June 30, 2001. The decrease of $3.3 million in other financing costs was due principally to a reduction in the amortization of deferred financing costs of $1.7 million and a lower unrealized loss on the interest rate swap of $1.3 million. The unrealized loss on the interest rate swap was $2.3 million and $3.6 million during the years ended June 30, 2002 and 2001, respectively. The swap agreement provides that we pay a fixed interest rate of 5.48% on the notional amount of $150 million in exchange for receiving a variable rate based on LIBOR so long as the one-month LIBOR interest rate does not rise above 6.75%. If the one-month LIBOR rate rises above 6.75%, the swap knocks out and we will receive no payments under the agreement until such time as the one-month LIBOR rate declines below 6.75%. At June 30, 2002 and 2001, the one-month LIBOR rate was 1.84% and 4.08%, respectively. This swap agreement expires in August 2003.

        Gain (loss) on the disposition of assets for the year ended June 30, 2002 consists of $(9.9) million loss on the sale of West Shore, $8.6 million gain on the sale of the NORCO system, $1.4 million gain on the sale of our investment in ST Oil Company, and $(0.1) million loss on the sale of other assets. Gain on the disposition of assets was $22.1 million for the year ended June 30, 2001 due to the sale of the Little Rock facilities.

Income taxes

        Income tax expense was $5.5 million for the year ended June 30, 2002, which represents an effective combined federal and state income tax rate of 39.0%. Income tax expense was $6.7 million for the year ended June 30, 2001, which represents an effective combined federal and state income tax rate of 37.0%.

Preferred stock dividends

        Preferred stock dividends on the Series A Convertible Preferred Stock were $9.8 million and $9.0 million for the years ended June 30, 2002 and 2001, respectively. The increase in the current year dividend resulted from our election to pay the preferred dividends "in-kind" by issuing additional shares of Series A Convertible Preferred Stock.

        The fair value of the consideration paid to the holders of the Series A Convertible Preferred Stock to affect the Preferred Stock Recapitalization was in excess of the financial statement carrying amount of the Series A Convertible Preferred Stock that was redeemed. That excess of approximately $1.5 million has been treated in a manner similar to preferred stock dividends in the accompanying consolidated financial statements.

YEAR ENDED JUNE 30, 2001 COMPARED TO YEAR ENDED JUNE 30, 2000

        We reported net earnings of $11.3 million for the year ended June 30, 2001, compared to a net loss of $(37.9) million for the year ended June 30, 2000. After preferred stock dividends, the net earnings attributable to common stockholders was $2.4 million for the year ended June 30, 2001, compared to a net loss of $(46.4) million for the year ended June 30, 2000. Basic and diluted earnings per common share for the year ended June 30, 2001 were $0.08 based on 30.9 million weighted average common shares outstanding and 31.0 million weighted average diluted shares outstanding. Basic and diluted loss per share for the year ended June 30, 2000 were $(1.52) based on 30.5 million weighted average common shares outstanding.

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        The increase in net earnings resulted primarily from the absence of an impairment charge in the year ended June 30, 2001, compared to a pre-tax $50.1 million impairment charge in fiscal 2000; increased net operating margins from the supply, distribution and marketing operations, offset by the net operating margins from the natural gas services activities which were sold; decreased selling, general and administrative expenses; decreased depreciation and amortization expenses attributable to the sale of the natural gas services activities; and decreased interest expense, attributable to a decrease in average interest rates for the current year, a reduction in the amount of outstanding debt resulting from the sale of the natural gas services activities, and a reduction in the amount of discretionary inventory being carried by us during the current year.

Supply, distribution and marketing

        The revenues reported for the supply, distribution and marketing operations include amounts realized on sales, exchanges and arbitrage transactions. The revenues from our supply, distribution and marketing operations for the year ended June 30, 2001 were $5,182.5 million compared to $5,014.8 million for the year ended June 30, 2000. The cost of product sold was $5,136.2 million and $4,995.9 million for the years ended June 30, 2001 and 2000, respectively. The net operating margins for the year ended June 30, 2001 were $28.0 million compared to $18.9 million for the year ended June 30, 2000. During the year ended June 30, 2001, we benefited from the following items: increased supply disruptions in the gasoline and distillate markets; concerns regarding the availability of distillate for the Northeastern region of the United States; the completion of our Baton Rouge dock facility which allowed us to arbitrage basis (geographical location) differentials between Colonial pipeline supplied barrels and Mississippi River based barrels; and an overall increase in the demand for Products from customers supplied by us. In the prior year, we experienced losses from liquidating a portion of our discretionary inventory position and an unfavorable impact from an abnormal price movement between crude oil and distillates. Subsequently, we amended our risk management policies to reduce the potential exposure from future abnormal commodity price movements of this nature by establishing daily reporting of our cumulative profit and loss positions to various levels of management, each of which has predetermined limits that escalate with the applicable level of authority.

        Our inventory consists primarily of gasoline and distillates, the majority of which is held for sale or exchange in the ordinary course of business. A portion of this inventory, based on line fill and tank bottoms, is required to be held for operating balances in the conduct of our daily supply, distribution and marketing operations, and is maintained both in tanks and pipelines owned by us and pipelines owned by third parties. During the quarter ended June 30, 2000, we embarked upon a thorough review of our inventory management strategies and customer contracts. As a result, we lowered our required minimum inventory from over 3.8 million barrels to the current level of 2.0 million barrels. We also changed our strategy regarding the risk management associated with this minimum inventory.

        Previously, we were hedging the minimum inventory in the futures market and we were renewing the hedges forward at the end of each month as the prior month's hedging contracts expired. In connection with our new risk management strategy, we removed the hedging contracts on our minimum inventory, thereby eliminating any future cash receipts or payments associated with rolling the hedging contracts on the inventory that was not being sold.

        During the year ended June 30, 2000, we experienced a cash loss of $12.4 million associated with rolling the hedges into a backwardated market (a market in which the current month commodity price is higher than the future price in succeeding periods) with respect to the minimum inventory. No loss of this type was realized in the year ended June 30, 2001 due to the change in the strategy associated with hedging the minimum inventory. The new policy has resulted in recording the minimum inventories at the lower of cost or market with the resulting non-cash write-downs recognized in net operating margins. We recognized a lower of cost or market write-down of $18.3 million during the year ended June 30, 2001 relating to our minimum inventories.

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Terminals and pipelines

        The revenues from our terminal and pipeline operations for the years ended June 30, 2001 and 2000, were $82.3 million and $78.5 million, respectively. The direct operating costs were $36.4 million and $34.3 million for the years ended June 30, 2001 and 2000, respectively. The net operating margins from our terminal and pipeline operations for the year ended June 30, 2001 was $45.9 million, compared to $44.3 million for the year ended June 30, 2000. The increase of $1.6 million in net operating margins is mostly attributable to increased utilization of our terminals during the current year which was offset somewhat by lower utilization of our pipeline systems. The total revenues recognized by our terminal and pipeline operations increased by approximately $3.8 million during the year ended 2001. The increase in net operating margins resulting from the increases in revenues was offset by an increase of approximately $2.1 million in operating expenses during the year ended June 30, 2001. In the year ended June 30, 2000, we recognized a loss of approximately $0.8 million for the write-off of a few small terminal customers' receivable balances.

Natural gas services

        Our natural gas services activities were divested effective December 31, 1999.

Selling, general, and administrative

        Selling, general and administrative expenses for the year ended June 30, 2001 were $34.1 million, compared to $41.7 million for the year ended June 30, 2000. The decrease of $7.6 million in selling, general, and administrative expenses is due principally to lease contract cancellation costs, additional personnel related costs related to separation and release agreements, non-cash stock compensation costs, and other personnel costs related to a corporate staff reduction and relocation plan, all of which amounted to approximately $5.0 million during the year ended June 30, 2000 that were not incurred during the current year. The sale of our natural gas services activities resulted in a reduction of approximately $0.5 million of employee costs in the current year. During the year ended June 30, 2001, travel and entertainment expenses decreased by approximately $0.6 million, and employee wage and benefit expenses decreased by approximately $3.1 million, offset by an increase in professional services and other costs of approximately $1.6 million.

        Depreciation and amortization for the year ended June 30, 2001 was $19.5 million, compared to $22.3 million for the year ended June 30, 2000. The decrease was due primarily to the disposition of our natural gas services activities.

        Non-cash impairment charges on long-lived assets for the fiscal year ended June 30, 2000 totaled $50.1 million, before income taxes. The charges include $31.9 million relating to certain of our product terminals acquired in the 1998 acquisition of Louis Dreyfus Energy Corp. and $18.2 million relating to certain intangible assets recorded as a result of the same acquisition. The impairment charges resulted from the change in the planned use of certain terminals and the abandonment of a pipeline that supplied one terminal, thereby significantly impacting the economic viability of the terminals. Each of these events significantly reduced or eliminated future cash flows related to these assets. The $31.9 million impairment charge for the terminals reduced the book value of the assets to their estimated fair value. The additional $18.2 million impairment charge for the intangible assets represented the unamortized balance of the intangible assets. Our review of the market location differentials associated with those assets showed that we received little or no value from those assets in the period ended June 30, 2000. There were no impairment charges on long-lived assets for the year ended June 30, 2001.

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Other income and expenses

        Dividend income and equity in earnings from petroleum related investments for the year ended June 30, 2001 were $3.1 million, compared to $1.6 million for the year ended June 30, 2000. The increase of $1.5 million in dividend income was due principally to dividends being received from West Shore and Lion Oil in the year ended June 30, 2001, compared to the prior year in which dividends were received only from West Shore. Additionally, we recorded $0.1 million of equity earnings in the year ended June 30, 2001 from our investment in ST Oil Company.

        Interest income for the year ended June 30, 2001 was $2.9 million, compared to $3.4 million for the year ended June 30, 2000. The decrease of $0.5 million in interest income was due primarily to a decrease in interest bearing cash balances and lower interest rates during the year ended June 30, 2001.

        Interest expense for the year ended June 30, 2001 was $18.1 million, compared to $28.5 million for the year ended June 30, 2000. The decrease of $10.4 million in interest expense was primarily attributable to a reduction in the amount of debt outstanding during the current year resulting from the sale of our natural gas services activities and the liquidation of our discretionary inventory in the prior year. We also benefited by an overall reduction in our borrowing rate under our bank credit facility due to declining LIBOR rates.

        Other financing costs for the year ended June 30, 2001 were $12.3 million, compared to $6.9 million for the year ended June 30, 2000. The unrealized loss on the interest rate swap was $3.6 million for the year ended June 30, 2001. In the year ended June 30, 2000, the unrealized gain on the interest rate swap was $1.6 million. The unrealized loss on the interest rate swap was due to a decline in the one-month LIBOR rates during the year ended June 30, 2001.

        Gain on the disposition of assets was $22.1 million for the year ended June 30, 2001, primarily due to the sale of the Little Rock facilities. Gain on the disposition of assets was $13.9 million for the year ended June 30, 2000 and was primarily due to the sale of our natural gas services activities, partially offset by losses on the disposition and retirement of other assets no longer used in our operations.

Income taxes

        Income tax expense was $6.7 million for the year ended June 30, 2001, which represents an effective combined federal and state income tax rate of 37.0%. Income tax benefit was $19.2 million for the year ended June 30, 2000, which represents an effective combined federal and state income tax rate of 33.6%. The effective tax rate for the year ended June 30, 2000 was lower than the effective tax rate for the year ended June 30, 2001 due to an adjustment in cumulative temporary differences recognized in the fiscal year ended June 30, 2000.

Preferred stock dividends

        Preferred stock dividends on the Series A Convertible Preferred Stock were $9.0 million and $8.5 million for the years ended June 30, 2001 and 2000, respectively. The increase in the current year dividend resulted from our election to pay the preferred dividends for the quarters ended March 31 and June 30, 2001 "in-kind" by issuing additional shares of Series A Convertible Preferred Stock.

FINANCIAL POSITION

        At June 30, 2002, our current assets exceeded our current liabilities by $168.1 million, compared to $31.9 million at June 30, 2001. The increase of $136.2 million in working capital is due principally to increases in accounts receivable of $94.7 million and inventories—discretionary volumes of $138.0 million, net of amounts due under exchange agreements, being offset by increases in accounts payable of $30.6 million and excise taxes payable of $40.0 million.

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        The increase in accounts receivable of $94.7 million is due principally to an increase in the volume of daily-priced rack sales, which are billed on a gross basis, compared to exchange transactions, which are billed on a net basis, and an increase in supply, distribution, and marketing volumes coupled with a corresponding increase in the price of gasoline. Our revenues for the supply, distribution and marketing operations were approximately $564.8 million for the month ended June 30, 2002, compared to approximately $391.6 million for the month ended June 30, 2001.

        Our inventories—discretionary volumes are held for sale or exchange in the ordinary course of business and consist of products, primarily gasolines and distillates. Our inventories—discretionary volumes are presented in the accompanying consolidated balance sheet as current assets and are carried at fair value. Inventories—discretionary volumes are as follows (in thousands):

	June 30, 2002			June 30, 2001
	Amount		Bbls	Amount		Bbls
Products held for sale or exchange	$	158,261	5,224	$	20,234	468
Products due to others under exchange agreements, net		16,908	525		76,754	2,778
Inventories—discretionary volumes	$	175,169	5,749	$	96,988	3,246

        During the last six months of the year ended June 30, 2002, we increased our discretionary inventory of distillates to capitalize on the "carry" or "contango" market structure. During a "contango" market, we utilize our and third-party terminals to store products to capture commodity price differentials between current and future months. At June 30, 2002, we held approximately 3.0 million barrels of distillates in our terminals for future delivery.

        Our inventories—discretionary volumes are an integral component of our overall energy trading and risk management activities. We evaluate the level of inventories—discretionary volumes in combination with energy trading and risk management disciplines, (including certain hedging strategies, forward purchases and sales, swaps and other financial instruments) to manage market exposure, primarily commodity price risk. We evaluate the market exposure from an overall portfolio basis that considers both continuous movement of physical inventory balances and related open positions in energy trading and risk management contracts.

        Our inventories—minimum 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 inventories in the ordinary course of business and, therefore, we do not hedge the market risks associated with this minimum inventory. Our inventories—minimum volumes are presented in the accompanying consolidated balance sheet as non-current assets and are carried at the lower of cost or market. Inventories—minimum volumes are as follows (in thousands):

	June 30, 2002			June 30, 2001
	Amount		Bbls	Amount		Bbls
Gasolines	$	27,855	1,200	$	33,831	1,200
Distillates		17,443	800		24,430	800
Inventories—minimum volumes	$	45,298	2,000	$	58,261	2,000

        During the years ended June 30, 2002 and 2001, we recognized impairment losses of approximately $13.0 million and $18.3 million, respectively, due to lower of cost or market write-downs on this minimum inventory. These write-downs are included in net operating margins attributable to our supply, distribution, and marketing operations. At June 30, 2002 and 2001, the weighted average adjusted cost basis of our inventories—minimum volumes was $0.54 and $0.69 per gallon, respectively.

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        During the three months ended June 30, 2000, we conducted a thorough review of our inventory management strategies and customer contracts. Effective July 1, 2000, we designated 2.0 million barrels of refined petroleum products as inventories—minimum volumes and we changed our risk management strategy associated with this minimum inventory. In accordance with our revised risk management strategy, we removed the hedging contracts on the minimum inventory volumes prior to July 1, 2002.

        Relative month-end commodity prices from June 30, 2001 to June 30, 2002 (NYMEX close on the last day of the month) are as follows:

	Crude		Heating oil	Gasoline
6/30/01	$	26.25	.709	.721
7/31/01		26.35	.697	.732
8/31/01		27.20	.766	.806
9/30/01		23.43	.664	.680
10/31/01		21.18	.598	.552
11/30/01		19.44	.532	.534
12/31/01		19.84	.551	.573
1/31/02		19.48	.523	.559
2/28/02		21.74	.563	.581
3/31/02		26.31	.669	.825
4/30/02		27.29	.689	.823
5/31/02		25.31	.630	.738
6/30/02		26.86	.680	.794

        The following table indicates the maturities of our supply management services contracts, including the credit quality of our counter parties to those contracts with unrealized gains at June 30, 2002.

			Fair value of contracts
			Maturity less than 1 year			Maturity 1–3 years			Maturity 4–5 years		Maturity in excess of 5 years		Total
			(in thousands)
Unrealized gain position—asset
	Supply management services contracts:
		Investment grade	$	3,651		$	—		$	—	$	—	$	3,651
		Non-investment grade		4,123			7,979			—		—		12,102
		No external rating		6,751			114			—		—		6,865
				14,525			8,093			—		—		22,618
Unrealized loss position—liability
	Supply management services contracts			(8,522	)		(209	)		—		—		(8,731	)
	Net unrealized gain position—asset		$	6,003		$	7,884		$	—	$	—	$	13,887

        At June 30, 2002, the unrealized gain on our supply management services contracts with non-investment grade counterparties was approximately $12.1 million. A single industrial/commercial end-user represented approximately $11.5 million of that unrealized gain. At June 30, 2002, we also had supply management services contracts with that end-user that were in an unrealized loss position of approximately $0.5 million. Therefore, the fair value of our supply management contracts with that industrial/commercial end-user was approximately $11.0 million at June 30, 2002. The following table

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includes information about the changes in the fair value of our supply management services contracts with that industrial/commercial end-user for the year ended June 30, 2002 (in thousands):

Fair value at June 30, 2001	$	11,401
Amounts realized or otherwise settled during the year		(3,461	)
Fair value of additional contracts entered into during the year(1)		4,689
Change in fair value attributable to change in commodity prices		(2,002	)
Other changes in fair value		414
Fair value at June 30, 2002	$	11,041

(1)

Approximately $3.0 million was included in net operating margins attributable to the supply, distribution and marketing activities and approximately $1.7 million was deferred for logistical supply management services to be provided over the term of the contract (see Note 11 of Notes to Consolidated Financial Statements).

        Our Risk Management Committee reviews the discretionary inventory and related open positions in energy services and risk management contracts on a regular basis in order to ensure compliance with our inventory and risk management policies. We have adopted policies under which changes to our net risk position, which is subject to commodity price risk, requires the prior approval of our Audit Committee of the Board of Directors.

        Our inventories—discretionary volumes, supply management services contracts, and risk management contracts are the integral components of our overall energy trading and risk management activities. We evaluate our market risk exposure from an overall portfolio basis that considers changes in physical inventories—discretionary volumes, open positions in energy services contracts, and open positions in risk management contracts. We have established risk management policies and procedures to monitor and control our market risk exposure. Our overall risk management objective is to minimize our exposure to changes in commodity prices. We accomplish this objective by entering into risk management contracts that offset the changes in the values of our inventories—discretionary volumes and supply management services contracts when there are changes in commodity prices. At June 30, 2002, our open positions in risk management contracts include forward contracts (purchases and sales), swaps, and other financial instruments to manage market exposure, primarily commodity price risk.

        We principally utilize exchange-traded risk management contracts to manage our commodity price risk. These contracts require us to maintain initial and variation margin deposits with a third party financial intermediary. At June 30, 2002, we had $8.6 million on deposit to cover our margin requirements on open risk management contracts, which consisted solely of an initial margin deposit. At June 30, 2002, a $0.05 per gallon unfavorable change in commodity prices would have required us to deposit approximately $1.6 million in variation margin. Conversely, a $0.05 per gallon favorable change in commodity prices would have permitted us to reduce the deposit in our margin account by approximately $1.6 million. We have the contractual right to request that the counterparties to our energy 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.

        Capital expenditures for the year ended June 30, 2002 were $15.8 million for terminal and pipeline facilities and assets to support these 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.

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        On June 28, 2002, we executed the New Facility with a syndication of banks. The New Facility provides for a maximum borrowing line of credit that is the lesser of (i) $300 million and (ii) the borrowing base. The borrowing base is a function of our accounts receivable, inventory, exchanges, margin deposits, open positions of energy services and risk management contracts, outstanding letters of credit, and outstanding indebtedness as defined in the New Facility. Borrowings under the New Facility are secured by substantially all of our assets. The New Facility matures on June 27, 2005. The terms of the New Facility include financial covenants relating to fixed charge coverage, current ratio, maximum leverage ratio, consolidated tangible net worth, capital expenditures, cash distributions and open inventory positions that are tested on a quarterly and annual basis. As of June 30, 2002, we were in compliance with all covenants included in the New Facility. At June 30, 2002, we had borrowings of $187.0 million outstanding under the New Facility. We also had the ability to borrow an additional $113.0 million under the New Facility based on the borrowing base computation at June 30, 2002.

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

			Years ending June 30,
			2003		2004		2005		2006		2007		Thereafter
Debt			$	11,312	$	—	$	187,000	$	—	$	—	$	—
Preferred stock				—		—		—		—		—		72,890
Transportation and deficiency agreements				779		786		786		489		—		—
Operating leases:
	New corporate headquarters			—		524		968		968		1,015		5,788
	Existing corporate headquarters (excluding estimated sublease rentals)			1,888		1,398		1,435		1,468		1,380		2,591
	Property and equipment			1,304		1,294		1,141		324		162		—
		Total contractual obligations to be settled in cash	$	15,283	$	4,002	$	191,330	$	3,249	$	2,557	$	81,269

        See Notes 11, 12, 14 and 19 of Notes to Consolidated Financial Statements.

        We have outstanding letters of credit with third parties in the amount of $11.5 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 New 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.

CASH FLOWS

        Net cash used by operating activities of $101.5 million for the fiscal year ended June 30, 2002 was due principally to increases in accounts receivable and inventories—discretionary volumes. The net cash provided by operating activities of $51.9 million for the year ended June 30, 2001 was due principally to decreases in accounts receivable and inventories—discretionary volumes, offset by an increase in net assets from price risk management activities and a decrease in trade accounts payable and inventory due under exchange agreements. The net cash provided by operating activities of $267.5 million for the year ended June 30, 2000 was due principally to a reduction in our physical inventory, an increase in the amount of inventory due under exchanges and a reduction of trade accounts receivable, offset by a reduction in trade accounts payable.

        Net cash provided by investing activities of $102.8 million for the year ended June 30, 2002 was due principally to proceeds received from the sale of assets of $120.5 million offset by capital expended

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for construction and improvements to existing operating facilities and acquisitions of $15.8 million. Net cash used by investing activities of $19.0 million during the year ended June 30, 2001 was due principally to capital expended for construction and improvements to existing operating facilities of $11.5 million and additional restricted cash of $8.0 million to cover required margin deposits on risk management contracts. Net cash provided by investing activities of $77.9 million during the year ended June 30, 2000 was due principally to proceeds from the sale of our natural gas services activities of $137.4 million offset by capital expended for construction and improvements to existing operating facilities and acquisitions of $61.3 million.

        Net cash provided by financing activities of $3.8 million for the year ended June 30, 2002 was due principally to proceeds from additional borrowings under our bank credit facility of $57.0 million offset by payments to retire common stock of $20.4 million, payments to retire preferred stock of $21.3 million, payments on our commodity margin loan of $8.7 million, and additional deferred debt issuance costs of $2.8 million. Net cash used by financing activities of $61.1 million for the year ended June 30, 2001 was due principally to repayments of borrowings under our bank credit facility and master shelf facility of $77.0 million and payments of preferred stock dividends of $4.3 million offset by borrowings under our commodity margin loan of $20.0 million. Net cash used by financing activities of $305.4 million for the year ended June 30, 2000 was due principally to repayments of borrowings under our bank credit facility and master shelf facility of $290.7 million and payments of preferred stock dividends of $8.5 million and additional deferred debt issuance costs of $6.4 million.

NEW ACCOUNTING STANDARDS

        In June 2001, the Financial Accounting Standards Board, or the FASB issued Statement of Financial Accounting Standards ("SFAS") No. 141,Business Combinations, and SFAS No. 142,Goodwill and Other Intangible Assets. SFAS No. 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30, 2001. SFAS No. 141 also specifies criteria intangible assets acquired in a purchase method business combination must meet to be recognized and reported apart from goodwill, and establishes that any purchase price allocable to an assembled workforce may not be accounted for separately. SFAS No. 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized, but instead tested for impairment at least annually in accordance with the provisions of SFAS No. 142. SFAS No. 142 also requires that intangible assets with definite useful lives be amortized over their respective estimated useful lives to their estimated residual values, and reviewed for impairment in accordance with SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets. We have adopted the provisions of SFAS No. 141 and we will adopt SFAS No. 142 effective July 1, 2002. The adoption of SFAS No. 141 did not have any impact on our financial statements, and we do not expect the adoption of SFAS No. 142 to have an impact on our financial statements.

        In June 2001, the FASB issued 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 are required to adopt the provisions of SFAS No. 143 effective July 1, 2002. To accomplish this, we must identify all legal obligations for asset retirement obligations, if any, and determine the fair value of these obligations on the date of adoption. The determination of fair value is complex and will

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require us to gather market information and develop cash flow models. Additionally, we will be required to develop processes to track and monitor these obligations. We currently are in the process of assessing the impact, if any, on our financial position, results of operations, and cash flows of adopting SFAS No. 143. However, we are unable to estimate the impact of adopting this statement at the date of this report.

        In August 2001, the FASB issued SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets, which is effective for fiscal years beginning after December 15, 2001. SFAS No. 144 establishes one accounting model to be used for long-lived assets to be disposed of by sale and broadens the presentation of discontinued operations to include more disposal transactions. SFAS No. 144 also provides guidance that will eliminate inconsistencies in accounting for the impairment or disposal of long-lived assets under existing accounting pronouncements. The new rule retains many of the fundamental recognition and measurement provisions provided for in SFAS No. 121,Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, but significantly changes the criteria for classifying an asset as held for sale. We do not expect the adoption of SFAS No. 144 to have an impact on our financial statements.

        The FASB issued Statement No. 145,Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections, on April 30, 2002. Statement No. 145 rescinds Statement No. 4, which required all gains and losses from extinguishments of debt to be aggregated and, if material, classified as an extraordinary item, net of related income tax effect. Upon adoption of Statement No. 145, companies will be required to apply the criteria in APB Opinion No. 30,Reporting the Results of Operations—reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions in determining the classification of gains and losses resulting from the extinguishments of debt. Statement No. 145 is effective for fiscal years beginning after May 15, 2002. We have adopted SFAS No. 145 as of July 1, 2001 (see Note 11 of Notes to Consolidated Financial Statements).

        In June 2002 the FASB issued SFAS No. 146,Accounting for Costs Associated with Exit or Disposal Activities, which addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force, or the EITF Issue No. 94-3,Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). SFAS No. 146 applies to costs associated with an exit activity that does not involve an entity newly acquired in a business combination or with a disposal activity covered by SFAS No. 144. A liability for a cost associated with an exit or disposal activity generally shall be recognized and measured initially at its fair value in the period in which the liability is incurred. In periods subsequent to initial measurement, changes to the liability shall be measured using the credit-adjusted risk-free rate that was used to measure the liability initially. We are required to adopt the provisions of SFAS No. 146 for exit or disposal activities initiated after December 31, 2002. In connection with our corporate relocation and transition, we accrued our expected lease abandonment costs and severance costs. It would appear that SFAS No. 146 would not permit the accrual of those expected costs in advance of those costs being incurred. Had SFAS No. 146 been in effect for the year ended June 30, 2002, we believe that approximately $3.1 million of accrued lease abandonment costs and approximately $0.7 million of accrued severance benefits would not have been recognized at June 30, 2002.

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

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comprised primarily of senior executives. Our RMC has responsibility for oversight with respect to all product risk management policies and our Audit Committee 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 products. Demand for 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, 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 and the related movement of products.

        We have developed risk management strategies to mitigate the risk associated with price volatility on our product inventories. We believe these strategies are integral to our risk policies since Product inventories are required to effectively operate our product supply, distribution and marketing operations and such inventories are expected to be purchased, sold and carried over extended periods of time in the ordinary course of business.

        We mitigate exposure to commodity price fluctuations by maintaining a balanced position of future commitments for product purchases and sales, either in the physical commodity market or the derivative commodity markets. Our strategies are intended to minimize the impact of product prices volatility on profitability and generally involve the purchase and sale of exchange-traded, energy futures and options. To a lesser extent, we enter into energy swap agreements, such as crack spreads, when they better match specific price movements in our markets. These strategies are designed to minimize, on a short-term basis, our exposure to the risk of fluctuations in product margins. The barrels of products covered by such contracts vary and are closely managed and subject to internally established risk guidelines.

        In connection with our supply, distribution and marketing operations, we engage in price risk management activities. Our price risk management activities are energy trading activities as defined by EITF 98-10,Accounting for Contracts Involved in Energy Trading and Risk Management Activities. As such, the financial instruments utilized are marked to market in accordance with the guidance set forth in EITF 98-10. Under the mark-to-market method of accounting, forwards, swaps, options and other financial instruments with third parties are reflected at market value, net of future physical delivery related costs, and are shown as "Unrealized gain or loss on supply management services contracts" in the accompanying consolidated balance sheets. Unrealized gains and losses from the impact of price movements are included in net operating margins. Changes in the assets and liabilities from price risk management activities result primarily from changes in the valuation of the portfolio of contracts, newly initiated transactions and the timing of settlement relative to the receipt of cash for certain contracts. The market prices used to value these transactions reflect management's best estimate considering various factors, including closing exchange and over-the-counter quotations, time value and volatility factors underlying the commitments. The values are adjusted to reflect the potential impact of liquidating our position in an orderly manner over a reasonable period of time under present market conditions.

        For certain of our supply management services contracts and contract locations, calculating fair value relies on a degree of estimation in calculating the basis (geographical location) differentials for deferred trading months and locations without an actively traded forward cash market. For these markets (in which we cannot secure a forward traded basis (geographical location) differential quote from a broker), our mark-to-market model estimates the basis (geographical location) differentials based on a rolling historical average. Currently, it is not practicable for us to estimate the effects on

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our financial condition, results of operations, or cash flows from an unfavorable change in basis (geographical location) differentials.

        Contractual commitments are subject to risks relating to market value fluctuations, as well as counterparty 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.

Interest rate risk

        At June 30, 2002, we had outstanding $187.0 million under the New Facility. We are exposed to risk resulting from changes in interest rates as a result of the variable-rate debt associated with the New 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, 2002, our interest rate swap, and assuming market interest rates increase or decrease 100 basis points, the potential annual increase or decrease in interest expense is approximately $0.4 million.

        In August 1999, we entered into two "periodic knock-out" swap agreements with money center banks to offset the exposure of an increase in variable interest rates on our debt. Each swap was for a notional value of $150 million and was for a term expiring in August 2003. The swaps settle monthly, contain a knockout level on the one-month LIBOR at or above 6.75%, and have a fixed interest rate of 5.48%. The swaps provide that we pay a fixed interest rate of 5.48% on $300 million notional amount in exchange for a variable rate based on LIBOR so long as the one-month LIBOR interest rate does not rise above 6.75%. If the one-month LIBOR rate rises above 6.75%, the swap knocks out and no payments are due under the agreements until such time as the one-month LIBOR rate declines below 6.75%. Prior to June 30, 2000, proceeds from the swap agreements were recorded as a reduction in interest expense, as the swaps were designated as hedges against the changes in interest rates.

        As a result of the significant reduction in the variable rate debt during the fiscal year ended June 30, 2000 and with the adoption of SFAS 133,Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138,Accounting for Derivative Instruments and Certain Hedging Activities, an amendment of FASB Statement No. 133, on June 30, 2000, the swaps were no longer designated as hedges. Any changes in the fair value of the interest rate swap are recognized immediately in earnings. As a result, at June 30, 2000, we recorded the fair value of the two swap agreements at $1.6 million in other assets, and a corresponding unrealized gain of $1.6 million. In August 2000, we settled one of the swap agreements, recognizing no gain or loss on the settlement. As of June 30, 2002, the fair market value of the remaining swap agreement is a liability of $5.4 million, which is recorded in accrued liabilities. For the years ended June 30, 2002 and 2001, we recorded an unrealized (non-cash) loss on the interest rate swap of $2.3 million and $3.6 million, respectively. For the years ended June 30, 2002, 2001 and 2000, we made (received) net payments of $4.6 million, $(0.7) million, and $(1.0) million, respectively, on the interest rate swap that are included in interest expense (income).

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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 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 recent 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 March 31, 2003, we owned and operated 55 terminals with an aggregate capacity of approximately 22.0 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 sales, bulk sales, and contract 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 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 ground fleet customers include waste disposal firms, retail consumer products companies, freight and delivery service providers, cable and communication companies, car rental firms, and city and state government agencies.

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. The crude oil refining process results in a slate of petroleum products that are all produced simultaneously. When produced at the refinery, refined products of a specific grade, such as unleaded

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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 56 refineries, responsible for approximately 46% 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 twelve-month period ended December 31, 2001, the Gulf Coast had average refined petroleum production of approximately 7.9 million barrels per day and average refined petroleum product consumption of approximately 3.8 million barrels per day. From 1991 to 2001, the amount of refined petroleum products shipped from the Gulf Coast region increased by approximately 28%, to approximately 4.1 million barrels per day. For the twelve-month period ended March 31, 2003, we purchased and scheduled for transportation out of the Gulf Coast approximately 215,000 barrels per day of refined petroleum products through pipelines and an additional 25,000 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 twelve-month period ended December 31, 2001, the Midwest region had average refined

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petroleum production of approximately 3.4 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 also imported from foreign producers directly into East Coast ports. For the twelve-month period ended December 31, 2001, 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 5.7 million barrels per day.

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

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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 fungible 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 transport product to its terminals, it must schedule its 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. 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. Because the refineries produce all of the various types of refined products simultaneously, and because the demand for various product types must be met on a continuous basis, product shipments through the common carrier pipelines must be alternated in batches.

        During periods of high demand for a particular product, companies may seek to schedule more product than the volume of the batch, in which case the common carrier pipelines will allocate volume based on the shipping history of each company seeking to ship in that batch. 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, specific volumes of product are loaded into tankers or barges at the ports connected to major refinery complexes and shipped to a marine terminal.

        At both inland and marine terminals, the various refined petroleum products are stored in tanks. While each type of product continues to be fungible, different products must be segregated by tank. For example, 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 1,000 to 300,000 barrels per tank.

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        Delivery.    Each inland terminal has a tanker truck loading facility 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. A truck scheduled to pick up product at a terminal will drive up to a rack. 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. Each truck holds an aggregate of approximately 8,000 gallons of various products in different compartments. Our computerized system also 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 added into certain 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 require approximately 8,000 barrels, the equivalent of 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

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. Terminals play a key role in the delivery of product to wholesalers, retailers and end-users by providing storage, distribution, blending, injection and other ancillary services. 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 own and operate terminal infrastructure of 55 terminals with approximately 22.0 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. We currently own and operate the following terminal facilities:

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31 terminals with approximately 10.4 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;



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15 terminals with approximately 3.4 million barrels of capacity, located in the Midwest and upper and lower Mississippi River areas;



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8 terminals with approximately 6.0 million barrels of capacity, at various locations in Florida; and

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1 terminal complex in Brownsville, Texas with approximately 2.2 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 is uniquely situated in that its size and scope of operations enable it to handle the large majority of liquid products movements in the geographic area 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 own and operate nine tugboats and 13 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 pipelines 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 also own and operate a small intrastate crude oil gathering pipeline system, located in east Texas known as the CETEX Pipeline.

        We generate revenues in our terminal, pipeline and tug and barge operations from throughput fees, storage fees, additization fees, transportation fees, ship-assist fees 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 through our supply and marketing efforts, through exchange agreements, or for third parties. 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. With respect to fungible products, we enter into throughput agreements with customers who provide product to our terminal and agree to draw co-mingled product from that terminal at a later date. These customers prefer to take delivery of co-mingled product from us at our terminals and pay a throughput fee with respect to that product rather than leasing storage capacity.

        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 Washington, D.C. 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

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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 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. 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 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, 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 2.2 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 and CETEX pipelines 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 FERC. Transportation fees for the CETEX Pipeline are not regulated by FERC and are based on negotiated rates.

        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.

        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

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resulting from the excess of product deposited by third parties into our terminals over the amount of product that is drawn by such parties from our terminals.

Supply, distribution and marketing

        We generally purchase our inventory of refined petroleum products at prevailing prices from refiners and producers 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 barges 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 sales, bulk sales and contract sales.

        Rack Sales.    Rack sales are sales that do not involve continuing contractual obligations to purchase or deliver product. Rack 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 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 sale price of various products for the following morning. Typical rack 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, our desire to reduce inventory levels at that particular location that day and other factors.

        We manage the physical quantity of our inventories of product through rack sales. Our rack sales volume for a particular product is sensitive to changes in price. If our objective is to increase rack 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.

        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 prior to scheduled delivery to us 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 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,

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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 located in a terminal 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.

        Contract Sales.    Contract sales are made pursuant to negotiated contracts, generally ranging from one to six months in duration, that we enter into with cruise ship operators, local market wholesalers, independent gasoline station chains, heating oil suppliers 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.

Supply 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 addition, companies that enter into their own hedging contracts to avoid fuel price volatility are subject to complex accounting of such transactions that can be avoided by entering into sales agreements with third party providers of price management services. In response to these market needs, we developed our supply management services business segment. We provide supply 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 fleet customers include, among others, PepsiCo, Sysco Corporation, FedEx Corporation, Waste Management, Inc., Allied Waste Industries, Waste Connections, Inc., the Indiana Department of Transportation, and the City of Raleigh, North Carolina.

        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 management services: delivered fuel price management, retail price management and logistical supply 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.

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        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 Management.    Under our logistical supply 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 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.

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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 return to obtain a refund of excise taxes paid. By using our supply 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 other 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.

Recent 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 $157 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 Costal Fuels assets provide the following benefits:

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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;



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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;



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the terminals are located primarily in areas with limited opportunity for new terminal expansion because of zoning, land values and environmental considerations;



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no refineries exist in Florida and the major Florida markets are served by waterborne vessels due to the absence of major product supply pipelines;



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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;



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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



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a number of opportunities to increase operational efficiency exist with our current operations in Florida.

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Fairfax, Virginia terminal

        On January 31, 2003, we acquired a 500,000 barrel 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:

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the attractive geographic location of the terminal:



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the terminal expands our delivery capabilities into and around Washington, D.C.;



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the terminal is located in an area with limited opportunity for new terminal expansion because of zoning, land values and environmental considerations; and



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the Washington, D.C. area is growing and provides future growth opportunities.



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potential synergies that would result with our existing terminal infrastructure along the Colonial Pipeline.

Risk management

        Our risk management committee, comprised of senior executives of TransMontaigne, has established risk management policies to monitor and manage price risks. Our risk management strategy generally is intended to maintain a balanced position of forward sale and forward purchase commitments against our discretionary inventories held for immediate sale or exchange and our 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 and our obligations to deliver products at fixed prices and through our sales contracts and supply 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 net position is offset with risk management contracts, principally futures contracts on the 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 without corresponding agreements to sell the product for physical delivery to third parties, 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.

        We also hedge our exposure to commodity price risks in our supply management services business. At the execution of each contract for which we provide price management solutions, we either purchase an appropriate supply of motor fuel or 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 our hedging activity to the exact type of product contemplated by our sales contract, delivered fuel price management contract or retail price management contract. To the extent that the price fluctuations of the product covered in our sales contracts do not match the price fluctuations of the product covered by the NYMEX futures contract that we use, our exposure will not be entirely mitigated.

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        There are certain risks that we either do not attempt to hedge or that cannot be completely hedged. For example, we do not hedge 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 a base operating inventory, including minimum inventory volumes, of approximately 3.8 million barrels, consisting primarily of tank bottoms, product in transit and pipeline fill. We generally do not hedge our base operating inventory, including minimum inventory volumes, because it is not available for immediate sale. As a result, any futures contracts used to hedge the base operating inventory 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, may result in changes in the volume of our base operating inventory. Our risk policy, however, allows our management team the discretion under certain market conditions to hedge up to 500,000 barrels of our base operating inventory, which would reduce the unhedged inventory to approximately 3.3 million barrels, or to leave unhedged up to 500,000 barrels of our discretionary inventory available for immediate sale or exchange, which would increase our unhedged inventory to approximately 4.3 million barrels. We decide whether to hedge a portion of our base operating inventory or to leave a portion of our discretionary inventory available for immediate sale or exchange unhedged depending on our expectations of future market changes. To the extent that we do not hedge 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 hedged.

        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 counterparties in amounts that may be material. For example, we may enter into a futures contract to hedge against discretionary inventory on hand. If commodity prices rise before the expiration date of the futures contract, it 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 between the futures market and the physical products market and in timing, 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 7.4 million barrels per day in 1991 to 5.9 million barrels per day in 2001. Imports of petroleum from the Middle East, South America and elsewhere have increased substantially over this period from 7.6 million barrels per day in 1991 to 11.6 million barrels per day in 2001. 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

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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, or 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.

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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.



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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.

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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.

        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. 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, 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.

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        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 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 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 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 management functions from a single source. We believe that we are the only significant independent fuel supply management services provider in the United States offering this extensive suite of services.

Technology and back-office infrastructure

        We have developed 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

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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 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 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 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.

        We also have substantial experience in managing complex petroleum product supply and demand arrangements. Our back office and technology infrastructure has been established through significant time and capital commitments and gives us an advantage over competitors.

Strong management team

        Our executive management team has extensive industry experience and several members of the team have worked together for over 20 years. Several members of executive management were instrumental in building Associated Natural Gas Corporation, a natural gas gathering, processing and marketing company, into a company with an enterprise value of over $800 million at the time of its 1994 sale to Panhandle Eastern Corporation.

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:

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Capitalize on the acquisition of the Coastal Fuels assets in Florida.



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We intend to take advantage of the steady year-round demand in the ports served.



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We intend to pursue growth opportunities in both the cruise ship bunkering and light oil businesses.



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We intend to expand our bunkering service to shipping markets outside of the cruise ship industry.

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Capitalize on our infrastructure by linking our significant asset base to our supply, distribution and marketing business.



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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.



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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.



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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.



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We intend to capitalize on the favorable location of, and significant capacity at, our Brownsville terminal complex. The Brownsville terminal complex is the primary provider for its area. A pipeline is scheduled for completion in 2003 that will carry product between Mexico and the United States and will terminate at the Brownsville terminal complex.



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Pursue Attractive Acquisitions.



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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.



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Actively pursue new sales and distribution opportunities by marketing our services to hypermarkets.



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Expand our supply management services.



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We intend to expand our existing supply management team and equipment to enable us to provide supply management services to additional customers with large ground transportation fleets.



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We intend to actively market our supply management solution for managing and obtaining excise tax exemptions on fuel purchases to government fleet customers.



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Continue to manage our exposure to commodity price volatility.



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Our hedging 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.



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Our hedging strategy also allows us to keep our efforts focused on maximizing the value of our physical assets and expanding our supply management services business.

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PROPERTIES

        The locations, manner of product receipt and distribution and approximate capacity of our terminals are as follows:

Locations	In/Out	Approximate Capacity (in barrels)	Locations	In/Out	Approximate Capacity (in barrels)
Colonial/Plantation Facilities:			Upper River Facilities:
Albany, GA	C/T	181,000	Evansville, IN	D/T	214,000
Americus, GA	C/T	83,000	Greater Cincinnati, KY	D/T	183,000
Athens, GA	CP/T	165,000	Henderson, KY	D/T	261,000
Atlanta, GA	CP/T	370,000	New Albany, IN	D/T	177,000
Bainbridge, GA	C/T	188,000	Louisville, KY	D/TR	172,000
Belton, SC	CP/T	204,000	Cape Girardeau, MO	D/T	131,000
Belton, SC	CP/T	258,000	East Liverpool, OH	D/T	206,000
Birmingham, AL	CP/T	533,000	Owensboro, KY	D/T	147,000
Charlotte, NC	CP/T	400,000	Paducah, KY Complex	D/T	297,000
Charlotte, NC	CP/T	290,000	Total		1,788,000
Collins, MS	CP/T	170,000
Collins, MS (Pipeline Injection Facility)	CP/CP	1,263,000	Lower River Facilities:
Doraville, GA	CP/T	394,000	Baton Rouge, LA—Dock facility	CD/DC	—
Fairfax, VA	C/T	500,000	Arkansas City, AR	D/T	633,000
Greensboro, NC	CP/T	422,000	Greenville, MS Complex	D/T	502,000
Greensboro, NC	CP/T	368,000	Total		1,135,000
Griffin, GA	C/T	93,000
Lookout Mountain, GA	C/T	195,000	Brownsville Facilities:
Macon, GA	C/T	164,000	Brownsville, TX Complex	DR/DRT	2,200,000
Meridian, MS	C/T	120,000	Total		2,200,000
Montgomery, AL	P/T	124,000
Montvale, VA	C/T	443,000	Florida Facilities:
Norfolk, VA	CD/TD	360,000	Pensacola, FL	D/DT	147,000
Purvis, MS	CP/CP	938,000	Port Everglades, FL	D/DT	422,000
Purvis, MS	CP/CP	124,000	Tampa, FL	D/DT	454,000
Rensselaer, NY	D/T	503,000	Total		1,023,000
Richmond, VA	CP/T	414,000
Rome, GA	CP/T	132,000	Coastal Fuels Terminals:
Selma, NC	C/RT	468,000	Jacksonville, FL	D/DT	385,000
Spartanburg, SC	CP/RT	286,000	Cape Canaveral, FL	D/DT	708,000
Spartanburg, SC	CP/T	260,000	Port Everglades, FL	D/DT	1,650,000
Total		10,413,000	Fisher Island, FL	D/D	670,000
			Port Manatee/Tampa, FL	D/DT	1,517,000
Midwest Facilities:			Total		4,930,000
Mount Vernon, MO	W/T	198,000
Rogers, AR	W/T	172,000
Chippewa Falls, WI	W/T	113,000
Total		483,000	TOTAL CAPACITY		21,972,000

C—Colonial Pipeline    P—Plantation Pipeline    W—Williams/Explorer Pipeline    D—Dock    T—Truck Rack    R—Rail

        The names, approximate length in miles and geographical locations of our pipelines are as follows:

Pipeline Name	Approximate Miles of Pipeline	Geographical Location
Razorback	67	Mt. Vernon, Missouri south to Rogers, Arkansas
CETEX	220	East Texas area—north of Tyler, Texas

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        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.

EMPLOYEES

        We had 637 employees at April 25, 2003. No employees are subject to representation by unions for collective bargaining purposes.

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.

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 it is possible that the costs of compliance with environmental laws and regulations will 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.

Water

        The Federal Water Pollution Control Act of 1972, as renamed and amended as the Clean Water Act or 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.

        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

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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, we cannot give any assurance that the effect will not be material in the aggregate.

        The primary federal law for oil spill liability is the Oil Pollution Act of 1990, or 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, or 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.

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.

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.

        The CETEX Pipeline, our intrastate crude oil pipeline located in east Texas, is subject to regulation by the Texas Railroad Commission. Texas regulations require that intrastate tariffs be filed with the Texas Railroad Commission and allows shippers to challenge such tariffs.

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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, or 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, or 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 are also subject to the requirements of the federal Occupational Safety and Health Act, or 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.

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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.

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MANAGEMENT

        The following table sets forth information with respect to our executive officers and directors.

Name	Age	Position
Cortlandt S. Dietler	81	Chairman and Director
Donald H. Anderson	54	Vice Chairman, Chief Executive Officer, President and Director
Randall J. Larson	45	Executive Vice President and Chief Financial Officer
William S. Dickey	45	Executive Vice President and Chief Operating Officer
Erik B. Carlson	55	Senior Vice President, Corporate Secretary and General Counsel
Peter B. Griffin	58	Director
Ben A. Guill	51	Director
John A. Hill	60	Director
Bryan H. Lawrence	60	Director
Harold R. Logan, Jr.	57	Director
Edwin H. Morgens	61	Director
Walter P. Schuetze	70	Director

Cortlandt S. Dietler has been the Chairman of TransMontaigne since April 1995, and served as Chief Executive Officer from April 1995 to September 1999. He was the founder, Chairman and Chief Executive Officer of Associated Natural Gas Corporation, a natural gas gathering, processing and marketing company, prior to its 1994 merger with PanEnergy Corporation. From 1994 to 1997, Mr. Dietler served as an Advisory Director to PanEnergy Corporation prior to its merger with Duke Energy Corporation in March 1997. Mr. Dietler currently serves as a Director of Hallador Petroleum Company, Cimarex Energy Co., Forest Oil Corporation and Carbon Energy Corporation. Industry affiliations include: Member, National Petroleum Council; Director, American Petroleum Institute; and past Director, Independent Petroleum Association of America.

Donald H. Anderson has been Director, Vice Chairman and Chief Executive Officer of TransMontaigne since September 1999, and has served as President since January 2000. Mr. Anderson is a director of Bear Paw Energy, LLC, which is an independent gatherer and processor of natural gas active in the Rocky Mountain Region of the United States. From 1997 through September 1999, Mr. Anderson was the Executive Director and a Principal of Western Growth Capital LLC, a Colorado-based private equity investment and consulting firm. From December 1994 until March 1997, Mr. Anderson was Chairman, President and Chief Executive Officer of PanEnergy Services, PanEnergy's non-jurisdictional operating subsidiary. From December 1994 until March 1997, Mr. Anderson also served as a Director of TEPPCO Partners, LLP. Mr. Anderson was previously President, Chief Operating Officer and Director of Associated Natural Gas Corporation until its merger with PanEnergy Corporation in 1994.

Randall J. Larson has been Executive Vice President and Chief Financial Officer of TransMontaigne since January 2003. Mr. Larson served as Executive Vice President, Chief Accounting Officer and Controller of TransMontaigne from May 2002 until January 2003. Prior to his employment with TransMontaigne, Mr. Larson was a partner with KPMG LLP, most recently in KPMG's San Jose, California office. Prior to joining the San Jose office in 1996, Mr. Larson was a partner in KPMG's Department of Professional Practice in the national office in New York City. From July 1992 to June 1994, Mr. Larson served as a Professional Accounting Fellow in the Office of Chief Accountant of the Securities and Exchange Commission. Mr. Larson began his accounting career with KPMG in 1981 in the Denver, Colorado office.

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     ��  William S. Dickey has been Executive Vice President and Chief Operating Officer of TransMontaigne since May 2000. From January 1999 until May 2000, Mr. Dickey was a Vice President of TEPPCO Partners, LLP. From 1994 to 1998, Mr. Dickey served as Vice President and Chief Financial Officer of Duke Energy Field Services.

Erik B. Carlson has been Senior Vice President, Corporate Secretary and General Counsel of TransMontaigne since January 1998. From February 1983 until January 1998, Mr. Carlson served as Senior Vice President, General Counsel and Corporate Secretary of Associated Natural Gas Corporation or its successor, Duke Energy Field Services.

Peter B. Griffin has been a Director of TransMontaigne since July 2000. Since 1998, Mr. Griffin has been President of Louis Dreyfus Corporation, and served as Executive Vice President of Louis Dreyfus Corporation from 1995 to 1998. Mr. Griffin joined Dreyfus in 1976 as Corporate Controller and subsequently held various administrative and financial positions in both the energy and agricultural business segments. Mr. Griffin is a director of Louis Dreyfus Holding Company Inc. and a member of its subsidiaries, including Dreyfus. Prior to joining Dreyfus, Mr. Griffin was an accountant with Arthur Young & Company.

Ben A. Guill has been a Director of TransMontaigne since March 2001. Since 1998, Mr. Guill has been President of First Reserve Corporation, a private equity fund sponsor specializing in management buyouts and acquisitions in the energy and energy-related industries. From 1980 to 1998, Mr. Guill served as Managing Director and Co-Head of Investment Banking of Simmons & Company International, an investment banking firm. Mr. Guill is a Director of National Oilwell, Inc., Superior Energy Services, Inc., Chicago Bridge & Iron Company, N.V., T3 Energy Services, Quanta Services, Inc. and Dresser, Inc.

John A. Hill has been a Director of TransMontaigne since April 1995. Mr. Hill is Vice Chairman of the Board, Managing Director and founder of First Reserve Corporation, a private equity fund sponsor specializing in management buyouts and acquisitions in the energy and energy-related industries. Mr. Hill is Chairman of the Board of Trustees of the Putnam Mutual Funds in Boston and serves as a Director of Devon Energy Corporation and various private companies owned by First Reserve and Continuum Health Partners.

Bryan H. Lawrence has been a Director of TransMontaigne since April 1995. From 1996 to 1997, Mr. Lawrence served as Managing Director of Dillon, Read & Co. Inc., an investment banking firm. In 1997, Mr. Lawrence established Yorktown Partners LLC to manage Yorktown Energy Partners III, L.P. and predecessor partnerships previously managed by Dillon, Read & Co. Inc. He is currently a member of Yorktown Partners LLC. Mr. Lawrence also serves as a Director of Vintage Petroleum, Inc., D&K Healthcare Services, Inc., Hallador Petroleum Company, Carbon Energy Corporation, Crosstex Energy L.P., Cavell Energy Corporation, and several privately-owned companies in which affiliates of Yorktown Partners LLC hold equity interests including PetroSantander Inc., Savoy Energy, L.P., Athanor B.V., Camden Resources, Inc., Ciweo Natural Resources Corporation, ESI Energy Services Inc., Ellora Energy Inc., Dernick Resources Inc., Peak Energy Resources, Inc. and Approach Resources Corporation.

Harold R. Logan, Jr. has been a Director of TransMontaigne since April 1995 and has provided consulting services to TransMontaigne on a contractual basis since January 2003. He served as Executive Vice President and Treasurer of TransMontaigne from April 1995 to December 2002 and as Chief Financial Officer of TransMontaigne from March 2000 to December 2002. From 1985 to 1994, Mr. Logan was Senior Vice President/Finance and a Director of Associated Natural Gas Corporation. Prior to joining Associated Natural Gas Corporation, Mr. Logan was with Dillon, Read & Co. Inc. and Rothschild, Inc. Mr. Logan also serves as Director of Suburban Propane Partners, L.P., Graphic Packaging Corporation, The Houston Exploration Company and Rivington Capital Advisors LLC.

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Edwin H. Morgens has been a Director of TransMontaigne since June 1996. Mr. Morgens has been Chairman of Morgens, Waterfall, Vintiadis & Company, Inc., an investment management firm, since 1970. Mr. Morgens serves as a Director of Programmer's Paradise, Inc.

Walter P. Schuetze has been a Director and Chairman of the Audit Committee of TransMontaigne since October 2002. Mr. Schuetze currently is an Executive in Residence in the College of Business at the University of Texas—San Antonio. From January 1992 to March 1995, Mr. Schuetze was the Chief Accountant to the U.S. Securities and Exchange Commission. From November 1997 to February 2000, he served as Chief Accountant of the Commission's Division of Enforcement, and served as a consultant to the Commission's Division of Enforcement from March 2000 to March 2002 on matters involving accounting and auditing. Mr. Schuetze began his accounting career in 1957 with the public accounting firm of Eaton & Huddle in San Antonio, Texas, which merged with Peat, Marwick, Mitchell & Co. (now KPMG LLP) in 1958. He was a partner with KPMG from 1965 to 1973, and again from 1976 to 1992. He served on the Financial Accounting Standards Board from 1973 to 1976. Mr. Schuetze is a member of the Board of Directors of Computer Associates International, Inc. and currently is chairman of that company's audit committee.

Composition of the Board of Directors

        Our board of directors currently consists of nine members. Our directors are elected annually to serve during the ensuing year or until their respective successors are duly elected and qualified.

Compensation of Directors

        Our directors who also are our employees receive no additional compensation for services on the board of directors or committees of the board. Directors who are not employees were paid an annual fee of $18,000 through June 30, 2002, payable quarterly. All directors are reimbursed for reasonable out-of-pocket expenses incurred in attending meetings of the board or any committee or otherwise by reason of their being a director. Due in part to the renewed focus on corporate governance issues and the passage of the Sarbanes-Oxley Act of 2002, which will require greater oversight by board members and board committees, we anticipate that the workload and number of meetings of the board will increase substantially. In order to retain, as well as to attract, qualified persons to serve on the board, as well as to chair its various committees, TransMontaigne has determined that a substantial increase in base annual compensation for non-employee directors is warranted, as well as additional compensation for those non-employee directors who chair those committees. Therefore, effective October 1, 2002, the base annual compensation for non-employee directors was increased from $18,000 per year to $30,000 per year, payable quarterly. Also effective October 1, 2002, an additional sum of $30,000 per year will be paid to the non-employee director serving as Chairman of the Audit Committee due to the increased responsibilities associated with that position under the Sarbanes-Oxley Act of 2002, while additional sums of $20,000 per year and $10,000 per year will be paid to the non-employee directors serving as Chairman of the Finance Committee and the Compensation Committee, respectively. In addition, discretionary grants of restricted stock, stock options or other stock—based awards also may be made to non-employee directors.

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Executive Compensation

        The following table sets forth certain information regarding compensation earned during each of our last three fiscal years by all individuals serving as the Company's Chief Executive Officer and each of our four other most highly compensated executive officers based on salary and bonus earned in the fiscal year ended June 30, 2002. These individuals are also referred to as our named executive officers.

Summary Compensation Table

	Annual Compensation							Long Term Compensation Awards
Name and Principal Position	Year	Salary(1)		Bonus		Other Annual Compensation		Securities Underlying Options(#)		Restricted Stock Awards($)			All Other Compensation(2)
Donald H. Anderson(3) Vice Chairman of the Board, Chief Executive Officer and President	2002 2001 2000	$	312,961 301,538 254,615	$	100,000 — —	$	— — —	— 50,000 330,000	(5)	$	49,500 142,500 1,202,500	(4) (5) (6)	$	5,325 4,500 1,177
Harold R. Logan, Jr.(7) Former Executive Vice President, Chief Financial Officer and Treasurer	2002 2001 2000		210,962 200,000 200,000		50,000 — —		— — —	— 30,000 —			37,125 95,000 102,500	(8) (9) (10)		5,325 5,250 4,800
William S. Dickey(11) Executive Vice President	2002 2001 2000		235,962 225,000 18,173		100,000 — —		— — —	— 50,000 50,000			123,750 47,500 362,500	(11) (11) (11)		5,325 3,375 —
Erik B. Carlson Senior Vice President, General Counsel and Secretary	2002 2001 2000		210,962 200,000 200,000		65,000 — —		— — —	— 30,000 — 7			49,500 133,475 76,875	(4) (12) (13)		5,325 4,519 4,800
Randall J. Larson(14) Executive Vice President and Chief Financial Officer	2002 2001 2000		36,538 — —		— — —		10,000 — —	75,000 — —			378,750 — —	(14)		— ��� —
Larry F. Clynch(15) Former Senior Vice President	2002 2001 2000		161,731 238,846 230,231		30,000 — —		415,648 14,922 31,866	— 25,000 30,000			24,750 95,000 —	(16) (16)		2,683 5,400 4,800

(1)

Amounts shown set forth all cash compensation earned by each of the named executive officers in the years shown, including salaries deferred under our savings and profit sharing plan, or the 401(k) Plan pursuant to Section 401(k) of the Internal Revenue Code.

(2)

Amounts shown set forth our matching contributions to our 401(k) Plan.

(3)

Mr. Anderson became our employee on September 28, 1999, became the Chief Executive Officer on October 1, 1999 and President on January 4, 2000.

(4)

Represents 10,000 shares of restricted stock granted on October 1, 2001 when the market price was $4.95. The restricted stock award vests 10% after the first year, 20% after the second year, 30% after the third year and 40% after the fourth year of continuous employment since the grant date.

(5)

Represents 30,000 shares of restricted stock on granted October 15, 2000 when the market price was $4.75. The grant of 30,000 shares was made in connection with the underwater stock option/restricted stock exchange program, or the exchange program. 250,000 of the 330,000 options granted during fiscal year 2000 were cancelled on October 15, 2000 in exchange for the 30,000 shares of restricted stock. The restricted stock award vests 10% after the first year, 20% after the second year, 30% after the third year and 40% after the fourth year of continuous employment since the grant date.

(6)

Represents two grants of restricted stock at the market price of the stock on the date of each grant: 100,000 shares granted on September 28, 1999 when the market price was $11.00, and 20,000 shares granted on February 16, 2000 when the market price was $5.125. Each restricted stock award vests 10% after the first year, 20% after the second year, 30% after the third year and 40% after the fourth year of continuous employment since each grant date.

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(7)

As of January 2003, Mr. Logan is no longer an executive officer of TransMontaigne, but he remains a director. Effective January 1, 2003, we entered into a consulting agreement with Mr. Logan, the material terms of which are described in "Certain Relationships and Related Transactions."

(8)

Represents 7,500 shares of restricted stock granted on October 1, 2001 when the market price was $4.95. The restricted stock award vests 10% after the first year, 20% after the second year, 30% after the third year and 40% after the fourth year of continuous employment since the grant date.

(9)

Represents 20,000 shares of restricted stock granted on October 15, 2000 when the market price was $4.75. 18,400 of the 20,000 shares were granted in connection with the exchange program to cancel 101,200 underwater options. The restricted stock award vests 10% after the first year, 20% after the second year, 30% after the third year and 40% after the fourth year of continuous employment since the grant date.

(10)

Represents 20,000 shares of restricted stock granted on February 16, 2000 when the market price was $5.125 on the date of the grant. The restricted stock award vests 10% after the first year, 20% after the second year, 30% after the third year and 40% after the fourth year of continuous employment since the grant date.

(11)

Mr. Dickey became an employee of TransMontaigne on May 26, 2000. The restricted stock award in fiscal year 2002 represents 25,000 shares of restricted stock granted on October 1, 2001 when the market price was $4.95. The restricted stock award in fiscal year 2001 represents 10,000 shares of restricted stock granted on October 15, 2000 when the market price was $4.75. The restricted stock award in fiscal year 2000 represents a grant of 50,000 shares of restricted stock when the market price was $7.25 on the date of the grant. The restricted stock awards vest 10% after the first year, 20% after the second year, 30% after the third year and 40% after the fourth year of continuous employment since each grant date.

(12)

The restricted stock award in fiscal year 2001 represents a grant of 28,100 shares of restricted stock on October 15, 2000 when the market price was $4.75. The 28,100 shares were granted in connection with the exchange program to cancel 166,900 underwater options. The restricted stock awards vest 10% after the first year, 20% after the second year, 30% after the third year and 40% after the fourth year of continuous employment since the grant date.

(13)

The restricted stock awards in fiscal year 2000 represent a grant of 15,000 shares of restricted stock on February 16, 2000 when the market price was $5.125 on the date of the grant. The restricted stock grants vest 10% after the first year, 20% after the second year, 30% after the third year and 40% after the fourth year of continuous employment since the grant date.

(14)

Mr. Larson became an employee of TransMontaigne on May 1, 2002 as Executive Vice President. As of January 2003, Mr. Larson was appointed the Chief Financial Officer of TransMontaigne. Other 2002 annual compensation for Mr. Larson consists of a $10,000 relocation bonus. The restricted stock award in fiscal year 2002 represents a grant of 75,000 shares of restricted stock on May 1, 2002 when the market price was $5.05. The restricted stock award vests 10% after the first year, 20% after the second year, 30% after the third year and 40% after the fourth year of continuous employment since the grant date.

(15)

Pursuant to a separation and release agreement, Mr. Clynch's employment with TransMontaigne terminated effective February 18, 2002. The other 2002 annual compensation for Mr. Clynch consists of costs incurred pursuant to his separation and release agreement, $400,000 severance payment and $14,423 accrued vacation. In addition, other 2002, 2001 and 2000 annual compensation for Mr. Clynch consists of reimbursement for certain relocation expenses of $1,225, $14,922 and $31,866, respectively.

(16)

The restricted stock award in fiscal year 2002 represents 5,000 shares of restricted stock granted on October 1, 2001 when the market price was $4.95. The restricted stock award in fiscal year 2001 represents 20,000 shares of restricted stock granted on October 15, 2000 when the market price was $4.75. 10,000 of the 20,000 shares were granted in connection with the Exchange Program to cancel 61,200 underwater options. The restricted stock awards vest 10% after the first year, 20% after the second year, 30% after the third year and 40% after the fourth year of continuous employment since the grant date. All unvested shares of restricted stock were forfeit effective February 18, 2002 when Mr. Clynch's employment with TransMontaigne terminated.

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Option Grants in Last Fiscal Year

        The following table contains information about stock options granted to our named executive officers under our 1997 incentive plan during the fiscal year ended June 30, 2002.

	Individual Grants							Potential Realizable Value at Assumed Annual Rates of Stock Price Appreciation for Option Term (10 Years)(1)
Name	Number of Securities Underlying Options Granted		% of Total Options Granted to Employees in Fiscal Year		Exercise or Base Price ($/Share)		Expiration Date	5% Aggregate Value(3)		10% Aggregate Value(3)
Donald H. Anderson	—		—			—	—		—		—
Harold R. Logan, Jr.	—		—			—	—		—		—
William S. Dickey	—		—			—	—		—		—
Randall J. Larson	75,000	(2)	100	%	$	5.05	05/01/2012	$	238,194	$	603,630
Erik B. Carlson	—		—			—	—		—		—
Larry F. Clynch	—		—			—	—		—		—

(1)

The dollar gains under these columns result from calculations assuming 5% and 10% growth rates as set by the SEC and are not intended to forecast future price appreciation of our Common Stock. The gains reflect a future value based upon growth at these prescribed rates. We did not use an alternative formula for a grant date valuation, an approach which would state gains at present, and therefore lower, value. We are not aware of any formula that will determine with reasonable accuracy a present value based on future unknown or volatile factors. It is important to note that options have value to recipients, including the named executive officers and to other option recipients, only if the stock price advances beyond the grant date price shown in the table during the effective option period.

(2)

This award was made pursuant to our 1997 incentive plan. Under the 1997 incentive plan, the option price must be not less than 100% of the fair market value of our common stock on the date the option is granted. The fair market value of a share of our common stock is the officially listed closing price of the our common stock on the American Stock Exchange on the date of grant. All unexercisable stock options granted under the 1997 incentive plan become exercisable upon a change in control. The stock options granted on May 1, 2002 have an exercise price equal to $5.05 per share and vest 10% on May 1, 2003; 20% on May 1, 2004; 30% on May 1, 2005, and 40% on May 1, 2006. The 1997 incentive plan allows shares of our common stock to be used to satisfy any resulting federal, state and local tax liabilities, but does not provide for a cash payment by TransMontaigne for income taxes payable as a result of the exercise of a stock option award.

(3)

Not discounted to present value.

Aggregated Option Exercises In Last Fiscal Year And Fiscal Year End Option Values

        The following table provides information with respect to the options that were exercised during fiscal year ended June 30, 2002 and the value as of June 30, 2002 of unexercised options held by the named executive officers. The value of unexercised options at the fiscal year end is calculated using the difference between the option exercise price and the fair market value of TransMontaigne's common stock at June 30, 2002, $6.05.

				Number of Securities Underlying Unexercised Options at Fiscal Year-End (#)
						Value of Unexercised Options At Fiscal Year-End ($)
Name	Shares Acquired on Exercise (#)	Value Realized ($)
				Exercisable	Unexercisable	Exercisable		Unexercisable
Donald H. Anderson	—		—	29,000	101,000	$	33,700	$	155,300
Harold R. Logan, Jr.	—		—	68,000	27,000		42,650		62,100
William S. Dickey	—		—	20,000	80,000		11,500		103,500
Randall J. Larson	—		—	—	75,000		—		75,000
Erik B. Carlson	—		—	3,000	27,000		6,900		62,100
	—		—	—	—		—		—
Larry F. Clynch(1)	27,000	$	36,985	—	—		—		—

(1)

Mr. Clynch exercised options after his employment with TransMontaigne terminated.

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Equity Compensation Plan Information

        The following table sets forth certain information regarding our common stock that may be issued upon the exercise of options, warrants and rights under all of TransMontaigne's equity compensation plans as of June 30, 2002.

Plan Category	Number of Securities to be issued upon exercise of outstanding options, warrants and rights(1) (a)	Weighted-average exercise price of outstanding options, warrants and rights(1) (b)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))(1) (c)
Equity compensation plans approved by security holders(2)	1,062,780	$	4.52	2,283,945
Equity compensation plans not approved by security holders(3)	230,450	$	5.50	3,000
Total	1,293,230	$	4.69	2,286,945

(1)

This table only includes the stock options outstanding under all of our equity compensation plans as of June 30, 2002. There were no warrants and rights outstanding at June 30, 2002 under our equity compensation plans.

(2)

Includes only the TransMontaigne equity incentive plan, or the 1997 incentive plan, as amended. The stockholders approved the 1997 incentive plan in 1997, and approved the amendment to the 1997 incentive plan in 1999. The amendment to the 1997 incentive plan increased the number of authorized shares from 1,800,000 to 3,500,000 and adding an "evergreen" provision to automatically increase the number of shares available for issuance under the 1997 incentive plan beginning on June 30, 2000, and on each June 30 thereafter during the term of the 1997 incentive plan, a number of shares of our common stock equal to one percent (1%) of the total number of issued and outstanding shares of our common stock on the last day of the immediately preceding fiscal year. The 1997 incentive plan terminates on August 27, 2007.

(3)

Includes the amended and restated employee nonqualified stock option plan, or the 1991 option plan and the TransMontaigne Oil Company employees' stock option plan, or the 1995 option plan. The 1991 option plan has no options outstanding and 3,000 shares remained available for future issuance at June 30, 2002. The 1991 option plan was terminated September 30, 2002. The 1995 option plan terminated on December 31, 2001. The 1995 option plan has 230,450 options outstanding that expire in March 2003.

Employment Contracts And Termination Of Employment And Change In Control Agreements

        With the authorization and approval of the board of directors, we have entered into change in control agreements with certain executive officers and key employees of TransMontaigne and its subsidiaries, including the named executive officers listed in the Summary Compensation Table, or the named executive officer. The agreements are for an initial term of three years, from April 12, 2001 to April 11, 2004 with respect to all named executive officers with the exception of Mr. Larson, whose change in control agreement has an initial term of three years, from May 1, 2002 to April 30, 2005, after which they automatically renew on the anniversary date for consecutive one year periods, unless terminated by either party upon ninety days prior notice, provided, that notwithstanding any such notice, the agreement will continue in effect for twenty-four months in the event an actual or threatened change in control (as defined in the agreement) occurs during the initial term or any extension thereof. The agreements provide that if the named executive officer is terminated other than

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for cause during the term of the agreement, or within two years after a change in control of TransMontaigne, or if the named executive officer terminates his employment for good reason within such time period, the named executive officer is entitled to receive a lump-sum severance payment equal to a multiple varying from one times, in the case of Mr. Clynch, to two times, in the case of all other named executive officers, the sum of such named executive officer's annual salary and target bonus, as then in effect, together with certain other payments and benefits, including continuation of employee welfare benefits. In addition, should the named executive officer be subject to the excise tax on excess parachute payments as a result of such payment and payments under other plans due to a change in control, an additional payment will be made to restore the after-tax severance payment due the named executive officer to the same amount which the named executive officer would have retained had the excise tax not been imposed.

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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

        We do not believe that any of the transactions described below were made on terms less favorable to us than those that would have been available from unaffiliated parties and do not anticipate entering into transactions with affiliated parties in the future on terms less favorable than those that would be available from unaffiliated parties.

        Harold R. Logan, Jr., one of our Directors, is also a Director of Lion Oil Company, in which the Company owns an 18.04% ownership interest. We purchased $2,983,091 of refined petroleum products from and sold $122,205 of refined petroleum products to Lion Oil Company in the year ended June 30, 2002, all of which product purchases were made at market prices negotiated between us and Lion Oil Company or through independent brokers. We believe the prices paid by and to Lion Oil Company were comparable to prices that would have been paid by and to independent third parties. We received no throughput revenue or additive revenue from Lion Oil Company in the year ended June 30, 2002. Previous years' throughput and additive revenues were earned by our petroleum distribution facilities in Little Rock, Arkansas. These facilities were sold effective June 30, 2001.

        Effective January 1, 2003, we entered into a consulting agreement with Mr. Logan pursuant to which he will provide consulting services to us in the areas of finance and operational structure. The term of the consulting agreement is two years, and will be automatically renewed for one year periods unless terminated by either party by written notice at least 90 days prior to the end of the applicable term. For the first year of the term, we will pay Mr. Logan $100,000 for his services; for the second year we will pay Mr. Logan $75,000. The pay for any renewal terms will be negotiated at the time of renewal.

        Since June 30, 2002 we paid approximately $93,740, and during the 2002 fiscal year we paid approximately $82,430, to Arapahoe Development, Inc., which is owned by Cortlandt S. Dietler, Chairman of our Board of Directors, for flights aboard an aircraft owned by Arapahoe Development. We believe that the prices paid for those flights were competitive with rates charged by other aircraft leasing companies for similar services.

        Pursuant to a private placement agreement, partnerships managed by First Reserve Corporation, Yorktown Energy Partners, L.P. and other venture capital funds managed by officers of Dillon, Read & Co. Inc., and Waterwagon & Co., nominee for Merrill Lynch Growth Fund for Investment and Retirement, have the right to require us to register their shares under the Securities Act of 1933. Pursuant to the same private placement agreement, TransMontaigne agreed to take all action necessary to cause two Directors designated by affiliates of First Reserve Corporation from time to time to be elected to our Board of Directors so long as their collective ownership of TransMontaigne is at least 10%. The affiliates of First Reserve Corporation have designated Ben A. Guill and John A. Hill as their nominees for Directors. In addition, pursuant to an antidilution agreement, if we issue common stock or certain securities convertible into common stock, Waterwagon & Co., nominee for Merrill Lynch Growth Fund for Investment and Retirement, has the right to purchase additional shares of common stock in order to maintain its percentage ownership of our outstanding common stock. The purchase price of such shares will be based on the market price of our common stock at the time of the offering giving rise to the right of Waterwagon & Co. to purchase additional common stock. Under the antidilution agreement, we may be required to register such shares pursuant to a registration statement under the Securities Act of 1933.

        In September 1998, we purchased, among other things, certain terminaling properties from Louis Dreyfus Corporation pursuant to a stock purchase agreement. Dreyfus has paid to us approximately $1,076,000 since January 1, 2001 as indemnification under the stock purchase agreement for certain environmental expenses, including approximately $203,000 during the quarter ended March 31, 2003.

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        Also pursuant to the stock purchase agreement, we agreed to take all action necessary to cause one Director designated by Louis Dreyfus from time to time to be elected to our Board of Directors as long as its ownership in TransMontaigne is at least 10% of our outstanding capital stock. Dreyfus has designated Peter B. Griffin as its nominee for Director. Pursuant to a registration rights agreement entered into between us and Dreyfus concurrently with the stock purchase agreement, Dreyfus and each entity at least eighty percent owned directly or indirectly by S.A. Louis Dreyfus et Cie., has the right to require us to register their shares under the Securities Act of 1933.

        At June 30, 2002, the Compensation Committee of the Board of Directors consisted of Bryan H. Lawrence and Edwin H. Morgens. Mr. Lawrence is a member of Yorktown Partners LLC, which participated in the recapitalization of the Company's Series A Preferred in June 2002.

Preferred stock recapitalization.

        On June 28, 2002, we entered into a Preferred Stock Recapitalization Agreement with the holders of our Series A Preferred to redeem a portion of the outstanding Series A Preferred and warrants in exchange for cash, shares of common stock and shares of a newly created and designated convertible preferred stock, the Series B Preferred. The Preferred Stock Recapitalization Agreement resulted in the redemption of 157,715 shares of Series A Preferred and warrants to purchase 9,841,493 shares of common stock in exchange for the (i) issue of 72,890 shares of Series B Preferred with a fair value of approximately $80.9 million, (ii) the 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. In connection with the Preferred Stock Recapitalization Agreement, we repurchased approximately 4.1 million shares of our common stock from a fund managed by First Reserve Corporation for cash consideration of approximately $20.4 million. The following members of our Board of Directors and/or their affiliates participated in the recapitalization on the same terms as all other holders of Series A Preferred:

•

Cortlandt S. Dietler, Chairman of our Board of Directors;



•

First Reserve Corporation, of which John A. Hill, one of our Directors, is Vice Chairman of the Board and Managing Director and Ben A. Guill, also one of our Directors, is President; and



•

Yorktown Partners LLC, of which Bryan Lawrence, one of our Directors and member of our Compensation Committee, is a member.

        As a result of the recapitalization, Mr. Dietler exchanged all of his holdings of Series A Preferred (2,141.3335 shares, $1,000 liquidation value per share) and 133,340 warrants for 161,267 shares of common stock, a cash payment of $289,000 and 988 shares of Series B Preferred, $1,000 liquidation value per share. The First Reserve Funds exchanged all of their holdings of Series A Preferred (69,593.3417 shares, $1,000 liquidation value per share) and 4,333,550 warrants for 5,241,176 shares of common stock, a cash payment of $9,381,000 and 32,095 shares of Series B Preferred, $1,000 liquidation value per share. Yorktown Partners LLC exchanged all of its holdings of Series A Preferred (22,071.7957 shares, $1,000 liquidation value per share) and 1,374,402 warrants for 1,662,259 shares of common stock, a cash payment of $2,975,000 and 10,180 shares of Series B Preferred, $1,000 liquidation value per share. The exchange values included accrued and unpaid dividends at June 30, 2002.

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PRINCIPAL STOCKHOLDERS

        The following table sets forth certain information regarding the beneficial ownership of our common stock as of April 16, 2003 by:

•

each Director;



•

each named executive officer as of April 16, 2003;



•

each person known by TransMontaigne to own more than 5% of the outstanding shares of our common stock; and



•

all Directors and those serving as executive officers as of April 16, 2003 as a group.

        The information set forth below is based solely upon information furnished by such individuals or contained in filings made by such beneficial owners with the SEC.

        We have calculated the percentage of beneficial ownership based on 40,662,447 shares of common stock outstanding as of April 16, 2003. Beneficial ownership is determined in accordance with the rules of the SEC and includes voting and investment power with respect to shares. To our knowledge, except under applicable community property laws or as otherwise indicated, the persons named in the table have sole voting and sole investment power with respect to all shares beneficially owned. Shares of common stock underlying outstanding warrants or options that are currently exercisable or exercisable within 60 days of April 16, 2003 are deemed outstanding for the purpose of computing the percentage of beneficial ownership of the person holding those options or warrants, but are not deemed outstanding for computing the percentage of beneficial ownership of any other person.

	Common Stock
Beneficial Owner	Number of Shares	Percent of Class(1)		Percent of Voting Power(2)
Cortlandt S. Dietler(3)	2,215,821	5.4	%	4.2	%
Donald H. Anderson(4)	266,670	*		*
Harold R. Logan, Jr.(5)	376,803	*		*
William S. Dickey(6)	237,096	*		*
Randall J. Larson(7)	112,833	*		*
Erik B. Carlson(8)	160,474	*		*
Peter B. Griffin(9)	4,351,080	10.7	%	8.2	%
Ben A. Guill(10)	10,112,244	22.2	%	19.0	%
John A. Hill(11)	10,112,244	22.2	%	19.0	%
Bryan H. Lawrence(12)	3,281,928	7.8	%	6.2	%
Edwin H. Morgens(13)	253,030	*		*
Walter P. Schuetze	—	—	%	—	%
First Reserve Corporation(14)	10,112,244	22.2	%	19.0	%
Louis Dreyfus Corporation(15)	4,351,080	10.7	%	8.2
Merrill Lynch Investment Managers, L.P.(16)	2,822,285	6.9	%	5.3	%
Vencap Holdings (1987) Pte Ltd(17)	3,347,584	7.8	%	5.3	%
Yorktown Energy Partners III, L.P.(18)	3,204,682	7.6	%	6.0	%
Vestar Capital Partners III, L.P.(19)	2,678,128	6.3	%	4.3	%
J.P. Morgan Chase & Co.(20)	3,108,880	7.4	%	5.8	%
All Directors and Executive Officers as a Group (12 Persons)(21)	21,367,979	45.1	%	39.8	%

*

Less than 1% of the shares of common stock deemed outstanding, assuming conversion of all of our preferred stock outstanding as of April 16, 2003 into common stock.

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(1)

The shares of common stock issuable upon conversion of the outstanding shares of preferred stock are also deemed outstanding for the purpose of computing the percentage of beneficial ownership of the person holding those shares, but are not deemed outstanding for computing the percentage of beneficial ownership of any other person.

(2)

The percentage of voting power column represents the combined voting power of our shares of common stock and preferred stock outstanding on April 16, 2003. The holders of our Series A Preferred and Series B Preferred vote together as a single class with the holders of our common stock, on an as-converted basis, on all matters submitted to a vote other than the election of directors.

(3)

Includes 2,000 shares held by Mr. Dietler's spouse, as to which Mr. Dietler disclaims beneficial ownership; 149,696 shares issuable upon the conversion of Series B Preferred; and 29,500 shares of restricted stock subject to vesting. Mr. Dietler's address is P.O. Box 5660, Denver, CO 80217.

(4)

Includes 63,000 shares issuable upon the exercise of outstanding options and 118,000 shares of restricted stock subject to vesting. Restricted stock vests 10% after the first year, 20% after the second year, 30% after the third year and 40% after the fourth year of continuous employment. Mr. Anderson's address is 1670 Broadway, Suite 3100, Denver, CO 80202.

(5)

Includes 9,000 shares issuable upon the exercise of outstanding options and 28,750 shares of restricted stock subject to vesting. Restricted stock vests 10% after the first year, 20% after the second year, 30% after the third year and 40% after the fourth year of continuous employment Mr. Logan's address is 1670 Broadway, Suite 3100, Denver, CO 80202.

(6)

Includes 60,000 shares owned by DQ Investment Group, a family general partnership, of which Mr. Dickey is a general partner. Mr. Dickey disclaims beneficial ownership of these shares. Also includes 45,000 shares issuable upon exercise of outstanding options and 114,500 shares of restricted stock subject to vesting. Restricted stock vests 10% after the first year, 20% after the second year, 30% after the third year and 40% after the fourth year of continuous employment. Mr. Dickey's address is 1670 Broadway, Suite 3100, Denver, CO 80202.

(7)

Includes 7,500 shares issuable upon exercise of outstanding options and 100,000 shares of restricted stock subject to vesting. Restricted stock vests 10% after the first year, 20% after the second year, 30% after the third year and 40% after the fourth year of continuous employment. Mr. Larson's address is 1670 Broadway, Suite 3100, Denver, CO 80202.

(8)

Includes 550 shares held in an IRA for the benefit of Mr. Carlson's spouse, and 840 shares and 725 shares held in trust for Mr. Carlson's son and daughter, respectively, as to all of which Mr. Carlson disclaims beneficial ownership. Also includes 9,000 shares issuable upon the exercise of outstanding options and 64,670 shares of restricted stock subject to vesting. Restricted stock vests 10% after the first year, 20% after the second year, 30% after the third year and 40% after the fourth year of continuous employment. Mr. Carlson's address is 1670 Broadway, Suite 3100, Denver, CO 80202.

(9)

Consists of 4,351,080 shares owned by Louis Dreyfus Corporation. Mr. Griffin may be deemed to have beneficial ownership of the shares of our common stock held by Louis Dreyfus Corporation because Mr. Griffin is President of Louis Dreyfus Corporation. Mr. Griffin expressly disclaims beneficial ownership of the shares owned by Louis Dreyfus Corporation. Mr. Griffin's address is Twenty Westport Road, P.O. Box 810, Wilton, CT 06897.

(10)

Consists of 10,112,244 shares reported as beneficially owned by First Reserve Corporation, which includes 8,190 shares owned of record by and beneficially by Mr. Hill. Mr. Guill may be deemed to beneficially own the shares reported as beneficially owned by First Reserve Corporation because of his ownership of common stock and his position as President of First Reserve

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Corporation. Mr. Guill expressly disclaims beneficial ownership of the shares reported as beneficially owned by First Reserve Corporation and of the shares owned by Mr. Hill. Mr. Guill's address is 600 Travis, Suite 6000, Houston, TX 77002.

(11)

Includes 10,104,054 of the shares reported as beneficially owned by First Reserve Corporation. Mr. Hill may be deemed to beneficially own the shares reported as beneficially owned by First Reserve Corporation because of his ownership of common stock and his position as Vice Chairman and Managing Director of First Reserve Corporation. Mr. Hill expressly disclaims beneficial ownership of the shares reported as beneficially owned by First Reserve Corporation. Mr. Hill's address is 411 West Putnam Avenue, Suite 109, Greenwich, CT 06830.

(12)

Includes 3,204,682 shares reported as beneficially owned by Yorktown Partners LLC. Mr. Lawrence is a founder and an affiliate of Yorktown Partners LLC and disclaims beneficial ownership of these shares. Mr. Lawrence's address is 410 Park Avenue, New York, NY 10022.

(13)

Includes 199,806 shares held by the Edwin Morgens and Linda Morgens 1993 Trust and 7,080 shares held by the Lauren W. Morgens 1999 Trust. Mr. Morgens disclaims beneficial ownership of these shares. Mr. Morgens' address is 600 Fifth Avenue, 27th Floor, New York, NY 10022.

(14)

Includes 3,894,481 shares held directly by First Reserve Fund VII, Limited Partnership ("Fund VII"), of which 1,870,454 shares are issuable upon conversion of our Series B Preferred, and 6,225,953 shares held directly by First Reserve Fund VIII, LP. ("Fund VIII"), of which 2,992,424 shares are issuable upon conversion of our Series B Preferred. First Reserve Corporation is the general partner of First Reserve GP VII, L.P., which is the general partner of Fund VII, and First Reserve GP VIII, L.P., which is the general partner of Fund VIII, and as such reports shared voting and dispositive power over the shares. Fund VII and its general partner report shared voting and dispositive power over the shares held directly by Fund VII, and Fund VIII and its general partner report shared voting and dispositive power over the shares held directly by Fund VIII. Each fund and its general partner disclaim beneficial ownership of the shares beneficially owned by the other fund and its general partner. Also includes 8,190 shares held by John A. Hill, a stockholder and the Vice Chairman and Managing Director of First Reserve Corporation. The First Reserve entities disclaim beneficial ownership of the shares held by Mr. Hill. The address of the First Reserve entities is One Lafayette Place, Greenwich, CT 06830.

(15)

Louis Dreyfus Corporation ("Dreyfus") reports shared voting and dispositive power over the shares held directly by it with its parent, Louis Dreyfus Holding Company Inc. ("Dreyfus Holdings"), which reports shared voting and dispositive power over the shares with its parent, S.A. Louis Dreyfus et Cie. ("Dreyfus S.A."). The address of Dreyfus S.A. is 87 Avenue de la Grande Armee, 75782 Paris, France. The address of Dreyfus and Dreyfus Holdings is Twenty Westport Road, P.O. Box 810, Wilton, CT 06897.

(16)

We have granted to Merrill Lynch Investment Managers, L.P. the right to maintain up to a 15% ownership of our common stock if we issue stock in the future. Merrill Lynch Investment Managers, L.P. is an operating division of Merrill Lynch & Co., Inc., a public company, which reports shared voting and dispositive power over the shares. ML Fundamental Growth Fund, Inc. ("ML Growth Fund") also reports shared voting and dispositive power over 2,786,100 of the shares. The address of Merrill Lynch & Co., Inc. (on behalf of Merrill Lynch Investment Managers, L.P.) is World Financial Center, North Tower, 250 Vesey Street, New York, New York 10381. The address of ML Growth Fund is 800 Scudders Mill Road, Plainsboro, NJ 08536.

(17)

Includes 904,490 and 935,151 shares of our common stock issuable upon conversion of Series A Preferred and Series B Preferred, respectively, and 500,025 shares issuable upon exercise of outstanding warrants. The address of Vencap Holdings (1987) Pte. Ltd. is c/o Government of Singapore Investment Corporation, 255 Shoreline Drive, Suite 600, Redwood City, CA 94065.

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(18)

Includes 95,650 shares beneficially owned directly by Yorktown Partners LLC, the investment manager of Yorktown Energy Partners III, L.P., 46,060 shares of which are issuable upon conversion of shares of our Series B Preferred held by it. Also includes 1,496,363 shares of common stock issuable upon conversion of shares of our Series B Preferred held directly by Yorktown Energy Partners III, L.P. The address for Yorktown Partners LLC and Yorktown Energy Partners III, L.P. is 410 Park Avenue, New York, NY 10022.

(19)

Includes 723,592 and 748,181 shares of our common stock issuable upon conversion of Series A Preferred and Series B Preferred, respectively, and 400,020 shares issuable on exercise of outstanding warrants. The address of Vestar Capital Partners III, L.P. is c/o Vestar Capital Partners, 1225 Seventeenth Street, Suite 1660, Denver, CO 80202.

(20)

Includes 2,679,424 shares held directly by the Fleming US Discovery Fund III, L.P., of which 1,289,545 shares are issuable upon conversion of outstanding shares of our Series B Preferred, and 429,456 shares held directly by Fleming US Discovery Offshore Fund III, L.P., of which 206,666 shares are issuable upon conversion of outstanding shares of our Series B Preferred (collectively, the "Fleming Funds"). J.P. Morgan Chase & Co., investment advisor to the Fleming Funds, may be deemed to have beneficial ownership of the shares of our common stock held by the Fleming Funds. The address of J.P. Morgan Chase & Co. and the Fleming Funds is c/o J.P. Morgan Chase & Co., 1211 Avenue of the Americas, 38th Floor, New York, NY 10036.

(21)

Of such 21,367,979 shares, (a) 133,500 represent shares issuable upon the exercise of outstanding options, (b) 455,420 represent shares of restricted stock subject to vesting, (c) 6,554,997 represent shares of our common stock that are issuable upon conversion of Series B Preferred, (d) one half of the aggregate number of shares indicated as being beneficially owned by Messrs. Hill and Guill have been excluded from the aggregate number of shares reported as beneficially owned by all Directors and Executive Officers as a group because the 10,112,244 shares reported as beneficially owned by each of them are the same shares, and (e) the Directors and Executive Officers as a group disclaim beneficial ownership with respect to 17,930,817 shares.

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DESCRIPTION OF OTHER INDEBTEDNESS

        The following is a summary of the material terms of several of our other material debt obligations. This summary does not restate in entirety the terms of the agreements under which we incurred these debt obligations. We urge you to read these agreements that are included as exhibits to the Registration Statement of which this prospectus forms a part because they, and not these summaries, define our rights and obligations.

Working capital credit facility

        TransMontaigne entered into a credit agreement with UBS AG, Stamford Branch, an affiliate of UBS Warburg on February 28, 2003. On May 30, 2003, TransMontaigne repaid the outstanding principal amount of the Term Loan under this credit agreement with the proceeds of the issuance of the old notes, together with other available cash. The working capital credit facility of the credit agreement remained in place. On June 25, 2003, in connection with the syndication of the working capital credit facility, TransMontaigne entered into a first amended and restated working capital credit facility with a maximum line of credit equal to the lesser of (i) $275 million or (ii) the borrowing base. The amended and restated working capital credit facility does not provide for a term loan or for scheduled amortization of the working capital credit facility. The amended and restated revolving working capital credit facility matures on February 28, 2006.

        Borrowings under the working capital credit facility bear interest, at TransMontaigne's option, at either the base rate or LIBOR plus, in each case, an applicable margin. The applicable margin for loans under our working capital credit facility varies depending on whether the applicable loan is a base rate loan or a LIBOR loan and is also subject to adjustment based upon the consolidated total leverage ratio of TransMontaigne. The applicable margin for loans under our working capital credit facility is initially 0.75% for base rate loans or 2.75% for LIBOR loans. The base rate is a fluctuating interest rate equal to the higher of (a) the prime commercial lending rate of UBS AG or (b) the Federal Funds Rate published by the Federal Reserve Bank of New York plus 0.5%. TransMontaigne must also pay customary administration fees, expenses and commitment fees on the unused portion of the revolving working capital credit facility and provide indemnities for liabilities arising in particular circumstances.

        TransMontaigne may prepay borrowings under the working capital credit facility in whole or in part, in minimum amounts and subject to other conditions set forth in the credit agreement. TransMontaigne is required to prepay the working capital credit facility with the net cash proceeds of certain asset sales and casualty loss recoveries.

        TransMontaigne's obligations under the working capital credit facility are fully and unconditionally guaranteed on a joint and several basis by our subsidiaries other than our minor subsidiaries that are inactive and have no assets or operations. Such obligations are also secured by a security interest in our cash, securities, accounts receivable, inventories and other current assets.

        The working capital credit facility contains affirmative and negative covenants (including limitations on indebtedness, limitations on dividends and other distributions, limitations on certain intercompany transactions, limitations on mergers, consolidation and the disposition of assets, limitations on investments and acquisitions and limitations on liens) as well as customary representations and warranties and events of default. It also contains certain financial covenants that are tested on a quarterly basis including a minimum fixed charge coverage ratio of 150%, a maximum funded senior debt leverage ratio of 4.5 times the last twelve months' EBITDA (as defined in the credit agreement), a minimum current ratio of 120% and a minimum consolidated tangible net worth test. In addition, we may not make aggregate expenditures in excess of $80.0 million with respect to general corporate purposes over the term of the agreement (however, such amount shall be increased by certain cash flow amounts generated after February 28, 2003).

        At March 31, 2003, we had borrowings of $265.0 million outstanding and letters of credit of $30.7 million outstanding under the credit agreement. We also had the ability to borrow an additional $99.3 million under the facility based on the borrowing base computation at March 28, 2003.

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DESCRIPTION OF THE EXCHANGE NOTES

        As used below in this "Description of the Exchange Notes" section, the "Issuer" means TransMontaigne Inc., a Delaware corporation, and its successors, but not any of its subsidiaries. The Issuer issued the old notes and will issue the exchange notes described in this prospectus (together the "Notes") under an Indenture, dated as of May 30, 2003 (the "Indenture"), among the Issuer, the Guarantors and Wells Fargo Bank Minnesota, National Association, as trustee (the "Trustee"). The terms of the Notes include those set forth in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act. The Notes are subject to all such terms, and holders of Notes are referred to the Indenture and the Trust Indenture Act for a statement thereof. You may obtain a copy of the Indenture from the Issuer at its address set forth elsewhere in this prospectus.

        The following description is a summary of the material terms and provisions of the Notes and the Indenture. The following summary does not restate the Indenture in its entirety. We urge you to read the Indenture because it, and not this description, defines your rights as holders of the Notes. You can find definitions of certain terms used in this description under the heading "—Certain definitions."

Brief description of the exchange notes

        The exchange notes will be:

•

our unsecured, senior subordinated obligations; ranked junior in right of payment with all of our existing and future Senior Debt and existing and future Senior Debt of our Subsidiaries that are Guarantors;



•

ranked equal in right of payment ("pari passu") with all of our existing and future senior subordinated Indebtedness;



•

ranked senior in right of payment to all of our existing and future Subordinated Indebtedness; and



•

jointly and severally, fully and unconditionally guaranteed by certain of our Subsidiaries.

        The term "Subsidiaries" as used in this Description of the exchange notes does not include Unrestricted Subsidiaries. As of the Closing Date, only our minor Subsidiaries will be Unrestricted Subsidiaries. Under certain circumstances, however, we will be able to designate current or future subsidiaries as Unrestricted Subsidiaries. Unrestricted Subsidiaries will not be subject to the restrictive covenants set forth in the Indenture.

Principal, maturity and interest

        An aggregate principal amount of Notes equal to $200.0 million is being issued in this offering. The Notes will be issued in registered form, without coupons, and in denominations of $1,000 and integral multiples of $1,000. The Issuer may issue additional Notes in an unlimited principal amount having identical terms and conditions to the Notes being issued in this offering (the "Additional Notes"), subject to compliance with the covenant described under "—Certain covenants—Limitations on additional indebtedness." Any Additional Notes will be part of the same issue as the Notes being issued in this offering and will be treated as a single class with the Notes being issued in this offering for all purposes under the Indenture, including voting, waivers, amendments, redemption and offers to purchase. For purposes of this "Description of the notes," except for the covenant described under "—Certain covenants—Limitations on additional indebtedness," references to the Notes include Additional Notes, if any.

        The Notes will mature on June 1, 2010. The Notes will bear interest at the rate shown on the cover page of this prospectus, payable semi-annually in arrears on June 1 and December 1 of each year, commencing on December 1, 2003, to Holders of record at the close of business on May 15 or

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November 15, as the case may be, immediately preceding the relevant interest payment date. Interest on the Notes will be computed on the basis of a 360-day year of twelve 30-day months. During any period which an Event of Default shall have occurred and be continuing, default interest on the Notes will accrue at a rate of 1% per annum in excess of the rate of interest otherwise accruing on the Notes. Additional interest may also accrue on the Notes in certain circumstances under the Registration Right Agreement.

Methods of receiving payments on the notes

        If a Holder has given wire transfer instructions to the Issuer at least ten Business Days prior to the applicable payment date, the Issuer will make all payments on such Holder's Notes by wire transfer of immediately available funds to the account specified in those instructions. Otherwise, payments on the Notes will be made at the office or agency of the paying agent (the "Paying Agent") and registrar (the "Registrar") for the Notes within the City and State of New York unless the Issuer elects to make interest payments by check mailed to the Holders at their addresses set forth in the register of Holders.

Subordination of notes

        The payment by the Issuer of all Obligations on or relating to the Notes will be subordinated in right of payment to the prior payment in full in cash or Cash Equivalents of all Obligations due in respect of Senior Debt of the Issuer, including all Obligations with respect to the Credit Agreement, whether outstanding on the Issue Date or incurred after that date. This effectively means that holders of Senior Debt of the Issuer must be paid in full in cash before any amounts are to be paid by the Issuer to the Holders of the Notes in the event that the Issuer becomes bankrupt or is liquidated and that holders of the Senior Debt of the Issuer can block payments to the Holders of the Notes (i) in the event of a payment default by us on such Senior Debt or (ii) in the event of certain defaults by us on Designated Senior Debt as more fully described below.

        As of March 31, 2003, assuming this offering and related transactions had occurred on that date, the Issuer would have had approximately $65.0 million aggregate principal amount of Senior Debt and $179.3 million of undrawn borrowings available under the Credit Agreement.

        The holders of Senior Debt or Guarantor Senior Debt of a Guarantor, as the case may be, will be entitled to receive payment in full in cash or Cash Equivalents of all Obligations due in respect of such Senior Debt or such Guarantor Senior Debt, as the case may be, before the Holders of Notes will be entitled to receive any payment or distribution of any kind or character from the Issuer or such Guarantor, as the case may be, with respect to any Obligations on or relating to the Notes or the Note Guarantee of such Guarantor, as the case may be (other than Permitted Junior Securities) in the event of any distribution to creditors of the Issuer or such Guarantor, as the case may be: in a total or partial liquidation, dissolution or winding up of the Issuer or such Guarantor, as the case may be;

•

in a bankruptcy, reorganization, insolvency, receivership or similar proceeding relating to the Issuer or its assets or such Guarantor or its assets, as the case may be;



•

in an assignment for the benefit of creditors by the Issuer or such Guarantor, as the case may be; or



•

in any marshalling of the Issuer's assets and liabilities or the assets and liabilities of such Guarantor, as the case may be.

        In addition, the Issuer may not make any payment or distribution of any kind or character with respect to any Obligations on or relating to the Notes or acquire any Notes for cash or assets or otherwise (other than, in either case, Permitted Junior Securities), if:

•

a payment default on any Senior Debt occurs and is continuing; or

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•

any other default occurs and is continuing on Designated Senior Debt that permits holders of the Designated Senior Debt to accelerate its maturity and the Trustee receives a notice of such default (a "Payment Blockage Notice") from the Representative of any Designated Senior Debt.

        Payments by the Issuer on and distributions with respect to any Obligations on or with respect to the Notes may and shall be resumed:

•

in the case of a payment default, upon the date on which all payment defaults are cured or waived; and



•

in case of a nonpayment default, the earliest of (1) the date on which all such nonpayment defaults are cured or waived or otherwise cease to exist, (2) 179 days after the date on which the applicable Payment Blockage Notice is received or (3) the date on which the Trustee receives notice from the Representative for such Designated Senior Debt rescinding the Payment Blockage Notice, unless the maturity of any Designated Senior Debt has been accelerated and such acceleration has not been rescinded or annulled.

        No new Payment Blockage Notice may be delivered unless and until 360 days have elapsed since the effectiveness of the immediately prior Payment Blockage Notice.

        No nonpayment default that existed or was continuing on the date of delivery of any Payment Blockage Notice to the Trustee shall be, or be made, the basis for a subsequent Payment Blockage Notice unless such default shall have been cured or waived for a period of not less than 90 consecutive days. Any subsequent action or any breach of any financial covenants for a period ending after the date of delivery of the initial Payment Blockage Notice that in either case would give rise to a default pursuant to any provisions under which a default previously existed or was continuing will constitute a new default for this purpose.

        Notwithstanding anything to the contrary, payments and distributions made from the trust established pursuant to the provisions described under "—Legal defeasance and covenant defeasance" will be permitted and will not be subordinated so long as the payments into the trust were made in accordance with the requirements described under "—Legal defeasance and covenant defeasance" and did not violate the subordination provisions when they were made.

        The Issuer must promptly notify holders of Senior Debt if payment of the Notes is accelerated because of an Event of Default (as defined under "—Events of default").

        As a result of the subordination provisions described above in the event of a bankruptcy, liquidation or reorganization of the Issuer, Holders of the Notes may recover proportionately less than creditors of the Issuer who are holders of Senior Debt. See "Risk factors—Risks associated with the offering—Your right to receive payment on the notes and guarantees is subordinated to our and the guarantors' senior debt."

Subordination of guarantees

        Each Note Guarantee (as defined below) will be subordinated to Guarantor Senior Debt on the same basis as the Notes are subordinated to Senior Debt.

Note guarantees

        The Issuer's obligations under the Notes and the Indenture will be jointly and severally, fully and unconditionally guaranteed (the "Note Guarantees") by each present and future Restricted Subsidiary of the Issuer (other than Foreign Subsidiaries).

        Since the Issuer holds all of its assets and conducts all of its operations through Subsidiaries and since the Subsidiaries that will not be Guarantors are a minor component of the consolidated company,

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no separate financial statements or information have been included for the Guarantors. Any Unrestricted Subsidiaries will not be Guarantors and Foreign Subsidiaries formed or acquired after the Issue Date will not be required to be Guarantors. In the event of a bankruptcy, liquidation or reorganization of any non-guarantor Subsidiaries, those non-guarantor Subsidiaries will pay the holders of their debts and their trade creditors before they will be able to distribute any of their assets to the Issuer.

        As of the date of the Indenture, all of our Subsidiaries other than minor Subsidiaries will be "Restricted Subsidiaries" and "Guarantors". However, under the circumstances described below under the subheading "—Certain covenants—Designation of unrestricted subsidiaries," the Issuer will be permitted to designate some of our Subsidiaries as "Unrestricted Subsidiaries." The effect of designating a Subsidiary as an "Unrestricted Subsidiary" will be:

•

an Unrestricted Subsidiary will not be subject to many of the restrictive covenants in the Indenture;



•

a Subsidiary that has previously been a Guarantor and that is designated an Unrestricted Subsidiary will be released from its Note Guarantee; and



•

the assets, income, cash flow and other financial results of an Unrestricted Subsidiary will not be consolidated with those of the Issuer for purposes of calculating compliance with the restrictive covenants contained in the Indenture except to the extent of the amount of dividends or distributions actually paid to the Issuer or any of the Restricted Subsidiaries in cash by such Unrestricted Subsidiary.

        The obligations of each Subsidiary Guarantor under its Note Guarantee will be limited to the maximum amount that will, after giving effect to all other contingent and fixed liabilities of such Subsidiary Guarantor (including, without limitation, any guarantees under the Credit Agreement permitted under clause (1) of "—Certain covenants—Limitations on additional indebtedness") and after giving effect to any collections from or payments made by or on behalf of any other Subsidiary Guarantor in respect of the obligations of such other Subsidiary Guarantor under its Note Guarantee or pursuant to its contribution obligations under the Indenture, result in the obligations of such Subsidiary Guarantor under its Note Guarantee not constituting a fraudulent conveyance or fraudulent transfer under federal or state law. Each Subsidiary Guarantor that makes a payment under its Note Guarantee is entitled to a contribution from each other Subsidiary Guarantor in apro rata amount based on adjusted net assets of each Subsidiary Guarantor.

        In the event of a sale or other disposition of all of the assets of any Subsidiary Guarantor, by way of merger, consolidation or otherwise, or a sale or other disposition of all of the Equity Interests of any Subsidiary Guarantor then held by the Issuer and the Restricted Subsidiaries, then that Subsidiary Guarantor will be released and relieved of any obligations under its Note Guarantee;provided that the Net Available Proceeds of such sale or other disposition are applied in accordance with the applicable provisions of the Indenture, to the extent required thereby. See "—Certain covenants—Limitations on asset sales." In addition, the Indenture will provide that any Subsidiary Guarantor that is designated as an Unrestricted Subsidiary or that otherwise ceases to be a Subsidiary Guarantor, in each case in accordance with the provisions of the Indenture, will be released from its Note Guarantee upon effectiveness of such designation or when it first ceases to be a Restricted Subsidiary, as the case may be.

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Holding company structure

        The Issuer is a holding company for its Subsidiaries, with no material operations of its own and only limited assets. Accordingly, the Issuer is dependent upon the distribution of the earnings of its Subsidiaries, whether in the form of dividends, advances or payments on account of intercompany obligations, to service its debt obligations. In addition, the claims of the Holders are subject to the prior payment of all liabilities (whether or not for borrowed money) and to any preferred stock interest of any such Subsidiaries that are not Guarantors. There can be no assurance that, after providing for all prior claims, there would be sufficient assets available from the Issuer and its Subsidiaries to satisfy the claims of the Holders of Notes. See "Risk factors—Risks related to the notes and our structure—Our ability to repay the notes and our other debt depends on cash flow from our subsidiaries."

Optional redemption

        At any time prior to June 1, 2007, the Issuer, at its option, may redeem the Notes at a redemption price equal to the sum of:

•

the principal amount thereof,plus

•

accrued and unpaid interest, if any, to the redemption date,plus

•

the Applicable Premium at the redemption date.

        At any time on or after June 1, 2007, the Issuer, at its option, may redeem the Notes, in whole or in part, at the redemption prices (expressed as percentages of principal amount) set forth below, together with accrued and unpaid interest thereon, if any, to the redemption date, if redeemed during the 12-month period beginning June 1 of the years indicated:

Year	Optional Redemption Price
2007	104.563	%
2008	102.281	%
2009 and thereafter	100.000	%

Redemption with proceeds from equity offerings

        At any time on or prior to June 1, 2006, the Issuer may redeem up to 35% of the aggregate principal amount of the Notes with the net cash proceeds of one or more Qualified Equity Offerings at a redemption price equal to 109.125% of the principal amount of the Notes to be redeemed, plus accrued and unpaid interest thereon, if any, to the date of redemption;provided that (1) at least 65% of the aggregate principal amount of Notes issued under the Indenture remains outstanding immediately after the occurrence of such redemption and (2) the redemption occurs within 90 days of the date of the closing of any such Qualified Equity Offering.

Mandatory redemption

        The Notes will not have the benefit of any sinking fund and neither the Issuer nor the Guarantors will be required to make any mandatory redemption payments with respect to the Notes.

Selection and notice of redemption

        In the event that less than all of the Notes are to be redeemed at any time pursuant to an optional redemption, selection of the Notes for redemption will be made by the Trustee in compliance with the requirements of the principal national securities exchange, if any, on which the Notes are listed or, if the Notes are not then listed on a national security exchange, on apro rata basis, by lot or by such method as the Trustee shall deem fair and appropriate;provided,however, that no Notes of a principal

141

amount of $1,000 or less shall be redeemed in part. In addition, if a partial redemption is made pursuant to the provisions described in the second paragraph under "—Optional redemption—Redemption with proceeds from equity offerings," selection of the Notes or portions thereof for redemption shall be made by the Trustee only on apro rata basis or on as nearly apro rata basis as is practicable (subject to the procedures of The Depository Trust Company), unless that method is otherwise prohibited.

        Notice of redemption will be mailed by first-class mail at least 30 but not more than 60 days before the date of redemption to each Holder of Notes to be redeemed at its registered address. If any Note is to be redeemed in part only, the notice of redemption that relates to that Note will state the portion of the principal amount of the Note to be redeemed. A new Note in a principal amount equal to the unredeemed portion of the Note will be issued in the name of the Holder of the Note upon cancellation of the original Note. On and after the date of redemption, interest will cease to accrue on Notes or portions thereof called for redemption unless the Issuer defaults in the payment thereof.

Change of control

        Upon the occurrence of any Change of Control, unless the Issuer has mailed a notice of redemption to all Holders of the Notes and has irrevocably deposited with the Trustee all monies necessary to effect such redemption, each Holder will have the right to require that the Issuer purchase that Holder's Notes for a cash price (the "Change of Control Purchase Price") equal to 101% of the principal amount of the Notes to be purchased, plus accrued and unpaid interest thereon, if any, to the date of purchase.

        Within 30 days following any Change of Control, unless the Issuer has exercised its right to redeem the Notes as described under "Optional Redemption," the Issuer will mail, or caused to be mailed, to the Holders a notice:

(1)

describing the transaction or transactions that constitute the Change of Control;



(2)

offering to purchase, pursuant to the procedures required by the Indenture and described in the notice (a "Change of Control Offer"), on a date specified in the notice (which shall be a Business Day not earlier than 30 days nor later than 60 days from the date the notice is mailed) (the "Change of Control Payment Date") and for the Change of Control Purchase Price, all Notes properly tendered by such Holder pursuant to such Change of Control Offer; and



(3)

describing the procedures that Holders must follow to accept the Change of Control Offer. The Change of Control Offer is required to remain open for at least 20 Business Days or for such longer period as is required by law.

        The Issuer will publicly announce the results of the Change of Control Offer on or as soon as practicable after the date of purchase.

        If the Change of Control Payment Date is on or after an interest record date and on or before the related interest payment date, accrued but unpaid interest, if any, will be paid to the Person in whose name a Note is registered at the close of business on such record date, and no additional interest will be payable to Holders of Notes who tender pursuant to the Change of Control Offer.

        The agreements governing our outstanding Senior Debt currently prohibit us from purchasing any Notes, and also provide that some change of control events with respect to us would constitute a default under these agreements. Any future credit agreements or other agreements relating to Senior Debt to which the Issuer becomes a party may contain similar restrictions and provisions. In the event a Change of Control occurs at a time when the Issuer is prohibited from purchasing Notes, the Issuer could seek the consent of our senior lenders to the purchase of Notes or could attempt to refinance

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the borrowings that contain the prohibition. If the Issuer does not obtain a consent or repay the borrowings, the Issuer will remain prohibited from purchasing Notes. In that case, our failure to purchase tendered Notes would constitute an Event of Default under the Indenture which would, in turn, constitute a default under the Senior Debt. In these circumstances, the subordination provisions in the Indenture would likely restrict payments to the Holders of Notes.

        The provisions described above that require us to make a Change of Control Offer following a Change of Control will be applicable regardless of whether any other provisions of the Indenture are applicable. Except as described above with respect to a Change of Control, the Indenture does not contain provisions that permit the Holders of the Notes to require that the Issuer purchase or redeem the Notes in the event of a takeover, recapitalization or similar transaction.

        The Issuer's obligation to make a Change of Control Offer will be satisfied if a third party makes the Change of Control Offer in the manner and at the times and otherwise in compliance with the requirements applicable to a Change of Control Offer made by the Issuer and purchases all Notes properly tendered and not withdrawn under the Change of Control Offer.

        With respect to any disposition of assets, the phrase "all or substantially all" as used in the Indenture (including as set forth under "—Certain covenants—Limitations on mergers, consolidations, etc." below) varies according to the facts and circumstances of the subject transaction, has no clearly established meaning under New York law (which governs the Indenture) and is subject to judicial interpretation. Accordingly, in certain circumstances there may be a degree of uncertainty in ascertaining whether a particular transaction would involve a disposition of "all or substantially all" of the assets of the Issuer, and therefore it may be unclear as to whether a Change of Control has occurred and whether the Holders have the right to require the Issuer to purchase Notes.

        The Change of Control Offer feature of the Notes may make it more difficult or discourage a takeover of the Issuer, and thus the removal of incumbent management.

        The Issuer will comply with applicable tender offer rules, including the requirements of Rule 14e-l under the Exchange Act and any other applicable laws and regulations in connection with the purchase of Notes pursuant to a Change of Control Offer. To the extent that the provisions of any securities laws or regulations conflict with the "Change of Control" provisions of the Indenture, the Issuer shall comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the "Change of Control" provisions of the Indenture by virtue of this compliance.

        The Issuer may at any time and from time to time acquire Notes by means other than a redemption, whether pursuant to an issuer tender offer, open market purchase or otherwise, so long as the acquisition does not otherwise violate the terms of any covenant in the Indenture including those described in "—Certain Covenants."

Certain covenants

        The Indenture will contain, among others, the following covenants:

Limitations on additional indebtedness

        The Issuer will not, and will not permit any Restricted Subsidiary to, directly or indirectly, incur any Indebtedness;provided that the Issuer or any Guarantor may incur additional Indebtedness if, after giving effect thereto, the Consolidated Interest Coverage Ratio would be at least 2.25 to 1.00 (the "Coverage Ratio Exception").

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        Notwithstanding the above, each of the following shall be permitted (the "Permitted Indebtedness"):

(1)

Indebtedness of the Issuer and any Guarantor under the Credit Agreement in an aggregate amount at any time outstanding not to exceed the greater of (x) $250.0 million reduced by the aggregate amount of Net Available Proceeds applied to repayments under the Credit Agreement in accordance with the covenant described under "—Limitations on asset sales" that result in a permanent reduction in commitments thereunder and (y) the amount of the Borrowing Base as of the date of such incurrence;



(2)

the Notes issued on the Issue Date and the Note Guarantees;



(3)

Indebtedness of the Issuer and the Restricted Subsidiaries to the extent outstanding on the Issue Date (other than Indebtedness referred to in clauses (1) and (2) above, and after giving effect to the intended use of proceeds of the Notes);



(4)

Indebtedness under Hedging Obligations;provided that (i) with respect to any interest rate swap agreement, interest rate collar agreement or other similar agreement or arrangement designed to protect such Person against fluctuations in interest rates, (a) such Hedging Obligations relate to payment obligations on Indebtedness otherwise permitted to be incurred by this covenant, and (b) the notional principal amount of such Hedging Obligations at the time incurred does not exceed the principal amount of the Indebtedness to which such Hedging Obligation relates and (ii) with respect to any forward contract, commodity swap agreement, commodity option agreement or other similar agreement or arrangement, such Hedging Obligation is reasonably designed to protect the Issuer or any of its Restricted Subsidiaries against fluctuations in commodity prices (subject to variations in time or between products in the ordinary course of business consistent with the Issuer's past practice), and in the case of both clause (i) and (ii) above, are entered into in the ordinary course of business.



(5)

Indebtedness of the Issuer owed to a Restricted Subsidiary and Indebtedness of any Restricted Subsidiary owed to the Issuer or any other Restricted Subsidiary;provided,however, that upon any such Restricted Subsidiary ceasing to be a Restricted Subsidiary or such Indebtedness being owed to any Person other than the Issuer or a Restricted Subsidiary, the Issuer or such Restricted Subsidiary, as applicable, shall be deemed to have incurred Indebtedness not permitted by this clause (5);



(6)

Indebtedness in respect of bid, performance or surety bonds issued for the account of the Issuer or any Restricted Subsidiary in the ordinary course of business, including guarantees or obligations of the Issuer or any Restricted Subsidiary with respect to letters of credit supporting such bid, performance or surety obligations (in each case other than for an obligation for money borrowed);



(7)

Purchase Money Indebtedness incurred by the Issuer or any Restricted Subsidiary, and Refinancing Indebtedness thereof, in an aggregate amount not to exceed at any time outstanding the greater of (a) $25.0 million and (b) 5.0% of Consolidated Net Tangible Assets at that time;



(8)

Indebtedness arising from the honoring by a bank or other financial institution of a check, draft or similar instrument inadvertently (except in the case of daylight overdrafts) drawn against insufficient funds in the ordinary course of business;provided,however, that such Indebtedness is extinguished within five Business Days of incurrence;



(9)

Indebtedness arising in connection with endorsement of instruments for deposit in the ordinary course of business;

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(10)

Refinancing Indebtedness with respect to Indebtedness incurred pursuant to the Coverage Ratio Exception or clause (2) or (3) above;



(11)

Indebtedness in respect of commodities margin loans extended by commodities brokers in an aggregate amount not to exceed at any time outstanding the greater of (a) $25.0 million and (b) 5.0% of Consolidated Net Tangible Assets at that time;



(12)

Indebtedness represented by in-kind dividends in the form of Series A Convertible Preferred Stock and Series B Convertible Preferred Stock; and



(13)

Indebtedness of the Issuer or any Restricted Subsidiary in an aggregate amount not to exceed $15.0 million at any time outstanding.

        For purposes of determining compliance with this covenant, in the event that an item of Indebtedness meets the criteria of more than one of the categories of Permitted Indebtedness described in clauses (1) through (13) above or is entitled to be incurred pursuant to the Coverage Ratio Exception, the Issuer shall, in its sole discretion, classify such item of Indebtedness and may divide and classify such Indebtedness in more than one of the types of Indebtedness described, except that Indebtedness incurred under the Credit Agreement on the Issue Date shall be deemed to have been incurred under clause (1) above.

Limitations on layering indebtedness

        The Issuer will not, and will not permit any Restricted Subsidiary to, directly or indirectly, incur or suffer to exist any Indebtedness that purports to be by its terms (or by the terms of any agreement governing such Indebtedness) senior to the Notes or the Note Guarantee of such Restricted Subsidiary and purports to be by its terms (or by the terms of any agreement governing such Indebtedness) subordinated to any other Indebtedness of the Issuer or of such Restricted Subsidiary, as the case may be, it being understood that Indebtedness will not be considered subordinated to other Indebtedness solely by reason of being secured by a Lien other than a first priority Lien.

Limitations on restricted payments

        The Issuer will not, and will not permit any Restricted Subsidiary to, directly or indirectly, make any Restricted Payment if immediately after givingpro forma effect to such Restricted Payment:

(1)

a Default shall have occurred and be continuing or shall occur as a consequence thereof;



(2)

the Issuer cannot incur $1.00 of additional Indebtedness pursuant to the Coverage Ratio Exception; or



(3)

the amount of such Restricted Payment, when added to the aggregate amount of all other Restricted Payments made after the Issue Date (other than Restricted Payments made pursuant to clause (2), (3), (4), (5), (6), (7) and (8) of the next paragraph), exceeds the sum (the "Restricted Payments Basket") of (without duplication):



(a)

50% of Consolidated Net Income for the period (taken as one accounting period) commencing on the first day of the first full fiscal quarter commencing after the Issue Date to and including the last day of the fiscal quarter ended immediately prior to the date of such calculation for which consolidated financial statements are available (or, if such Consolidated Net Income shall be a deficit, minus 100% of such aggregate deficit),plus

(b)

100% of the aggregate net cash proceeds received by the Issuer either (x) as contributions to the common equity of the Issuer after the Issue Date or (y) from the issuance and sale of Qualified Equity Interests after the Issue Date, other than any such proceeds which

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are used to redeem Notes in accordance with the second paragraph under "—Optional redemption—Redemption with proceeds from equity offerings,"plus

(c)

the aggregate amount by which Indebtedness (other than any Subordinated Indebtedness) incurred by the Issuer or any Restricted Subsidiary subsequent to the Issue Date is reduced on the Issuer's balance sheet upon the conversion or exchange (other than by a Subsidiary of the Issuer) into Qualified Equity Interests (less the amount of any cash, or the fair value of assets, distributed by the Issuer or any Restricted Subsidiary upon such conversion or exchange),plus

(d)

in the case of the disposition or repayment of or return on any Investment that was treated as a Restricted Payment made after the Issue Date, an amount (to the extent not included in the computation of Consolidated Net Income) equal to the lesser of (i) the return of capital with respect to such Investment and (ii) the amount of such Investment that was treated as a Restricted Payment, in either case, less the cost of the disposition of such Investment and net of taxes,plus

(e)

upon a Redesignation of an Unrestricted Subsidiary as a Restricted Subsidiary, the lesser of (i) the Fair Market Value of the Issuer's proportionate interest in such Subsidiary immediately following such Redesignation, and (ii) the aggregate amount of the Issuer's Investments in such Subsidiary to the extent such Investments reduced the Restricted Payments Basket and were not previously repaid or otherwise reduced.

        The foregoing provisions will not prohibit:

(1)

the payment by the Issuer or any Restricted Subsidiary of any dividend within 60 days after the date of declaration thereof, if on the date of declaration the payment would have complied with the provisions of the Indenture;



(2)

the purchase, redemption or other acquisition or retirement of any Equity Interests of the Issuer or any Restricted Subsidiary in exchange for, or out of the proceeds of the substantially concurrent issuance and sale of, Qualified Equity Interests;



(3)

the purchase, redemption, defeasance, acquisition or other retirement of Subordinated Indebtedness of the Issuer or any Restricted Subsidiary (a) in exchange for, or out of the proceeds of the substantially concurrent issuance and sale of, Qualified Equity Interests or (b) in exchange for, or out of the proceeds of the substantially concurrent incurrence of, Refinancing Indebtedness permitted to be incurred under the "Limitations on additional indebtedness" covenant and the other terms of the Indenture;



(4)

the redemption, whether optional or mandatory, of the Series A Convertible Preferred Stock and the mandatory redemption at maturity of the Series B Convertible Preferred Stock in accordance with the respective terms thereof;



(5)

the payment by the Issuer of pay-in-kind dividends in respect of the Series A Convertible Preferred Stock and the Series B Convertible Preferred Stock;



(6)

the payment by the Issuer of cash dividends in respect of the Series A Convertible Preferred Stock and the Series B Convertible Preferred Stock at dividend rates not to exceed 5% per annum and 6% per annum, respectively;



(7)

repurchases, acquisitions or retirements of Equity Interests (i) occurring or deemed to occur upon, or intended to be used to satisfy issuances of Equity Interests upon, the exercise of stock options or the purchase of restricted stock or similar rights under employee benefit plans, if the Equity Interests represent a portion of the exercise or purchase price thereof; or (ii) occurring or deemed to occur and intended to be used to satisfy the tax payment

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obligations of a participant which occur upon vesting of restricted stock or similar rights under the Issuer's employee benefit plans;

(8)

the purchase, redemption, retirement of Equity Interests of the Issuer held by officers, directors or employees or former officers, directors or employees of the Issuer or any of its Restricted Subsidiaries (or their transferees, estates or beneficiaries under their estates), upon or after their death, disability, retirement, severance or termination of employment or service;provided that the aggregate consideration paid for all such redemptions shall not exceed $2.0 million during any fiscal year,provided, however, that unutilized amounts for such fiscal year may be carried forward to the following fiscal year andprovided, further, however, that in any such fiscal year in which such carry forward has occurred, the amount of consideration paid for all such redemptions shall not exceed $4.0 million; or



(9)

additional Restricted Payments not to exceed $15.0 million in the aggregate,

provided that (a) in the case of any Restricted Payment pursuant to clause (3), (4) and (6) above, no Default shall have occurred and be continuing or occur as a consequence thereof and (b) no issuance and sale of Qualified Equity Interests pursuant to clause (2) or (3) above shall increase the Restricted Payments Basket.

        For purposes of determining compliance with the provisions of this covenant, in the event that any payment or other action meets the criteria of more than one of the categories of Permitted Investments and/or Restricted Payments permitted by the Indenture, the Issuer, in its sole discretion, may order and classify all or any portion of such Permitted Investments and/or Restricted Payments on the date of their incurrence in any manner that then complies with the Indenture and/or from time to time may reorder and reclassify all or any portion of any item of Permitted Investments and/or Restricted Payments in any manner that complies with the Indenture at the date of any such reordering or reclassification and, in each case, the Issuer shall be entitled, at its option, to divide and classify or reclassify any item of Permitted Investments and/or Restricted Payments in more than one of the types of Permitted Investments and/or Restricted Payments permitted under the Indenture in any manner that complies with the Indenture at the time of such division and classification or reclassification.

Limitations on dividend and other restrictions affecting restricted subsidiaries

        The Issuer will not, and will not permit any Restricted Subsidiary to, directly or indirectly, create or otherwise cause or permit to exist or become effective any consensual encumbrance or consensual restriction on the ability of any Restricted Subsidiary to:

(a)

pay dividends or make any other distributions on or in respect of its Equity Interests;



(b)

make loans or advances or pay any Indebtedness or other obligation owed to the Issuer or any other Restricted Subsidiary; or



(c)

transfer any of its assets to the Issuer or any other Restricted Subsidiary;

        except for:

(1)

encumbrances or restrictions existing under or by reason of applicable law;



(2)

encumbrances or restrictions existing under the Indenture, the Notes and the Note Guarantees;



(3)

non-assignment provisions of any contract, license, permit or lease entered into in the ordinary course of business;



(4)

encumbrances or restrictions existing under agreements existing on the date of the Indenture (including, without limitation, the Credit Agreement) as in effect on that date;

147

(5)

restrictions on the transfer of assets subject to any Lien permitted under the Indenture imposed by the holder of such Lien or the exercise of or the right to exercise customary remedies with respect to such assets;



(6)

encumbrances or restrictions placed on inventory held for transfer under exchange agreements;



(7)

customary encumbrances or restrictions placed on initial NYMEX margin deposits or imposed by margin loans;



(8)

encumbrances or restrictions placed on petroleum racks owned jointly with BP Amoco;



(9)

encumbrances or restrictions relating to the Issuer's (or its Subsidiaries') exchange trading privileges;



(10)

restrictions or cash or other deposits imposed by customers under contracts entered into in the ordinary course of business;



(11)

restrictions on the transfer of assets imposed under any agreement to sell such assets including Equity Interests of a Subsidiary permitted under the Indenture to any Person pending the closing of such sale;



(12)

any instrument governing Acquired Indebtedness or any agreement (including any Equity Interest) relating to any property, asset or business acquired by the Issuer or any of its Subsidiaries, which restrictions existed at the time of the acquisition, were not put in place in connection with or in anticipation of such acquisition and which encumbrance or restriction is not applicable to any Person (and its Subsidiaries), or the properties or assets of any Person, other than the Person or the properties or assets of the Person (and its Subsidiaries) so acquired or to any property, asset or business, other than the property, assets or business so acquired;



(13)

any other agreement governing Indebtedness entered into after the Issue Date that contains encumbrances and restrictions that are not materially more restrictive with respect to any Restricted Subsidiary than those in effect on the Issue Date with respect to that Restricted Subsidiary pursuant to agreements in effect on the Issue Date;



(14)

customary provisions in partnership agreements, limited liability company organizational governance documents, joint venture agreements and other similar agreements entered into in the ordinary course of business that restrict the transfer of ownership interests in, or property of, such partnership, limited liability company, joint venture or similar Person;



(15)

Purchase Money Indebtedness incurred in compliance with the covenant described under "—Limitations on additional indebtedness" that impose restrictions of the nature described in clause (c) above on the assets acquired;



(16)

any encumbrance or restriction under any instrument governing Indebtedness of a Restricted Subsidiary that is a Foreign Subsidiary, which encumbrance or restriction is not applicable to any Persons, or the property or assets of any Persons, other than Restricted Subsidiaries that are Foreign Subsidiaries; and



(17)

any encumbrances or restrictions imposed by any amendments or refinancings of the contracts, instruments or obligations referred to in clauses (1) through (16) above;provided that such amendments or refinancings are, in the good faith judgment of the Issuer's Board of Directors, not materially more restrictive with respect to such encumbrances and restrictions than those prior to such amendment or refinancing.

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Limitations on transactions with affiliates

        The Issuer will not, and will not permit any Restricted Subsidiary to, directly or indirectly, in one transaction or a series of related transactions, sell, lease, transfer or otherwise dispose of any of its assets to, or purchase any assets from, or enter into any contract, agreement, understanding, loan, advance or guarantee with, or for the benefit of, any Affiliate (an "Affiliate Transaction"), unless:

(1)

such Affiliate Transaction is on terms that are no less favorable to the Issuer or the relevant Restricted Subsidiary than those that would have been obtained in a comparable transaction at such time on an arm's-length basis by the Issuer or that Restricted Subsidiary from a Person that is not an Affiliate of the Issuer or that Restricted Subsidiary; and



(2)

the Issuer delivers to the Trustee:



(a)

with respect to any Affiliate Transaction involving aggregate value in excess of $10.0 million, an Officers' Certificate certifying that such Affiliate Transaction complies with clause (1) above and a Secretary's Certificate which sets forth and authenticates a resolution that has been approved by a majority of the Independent Directors approving such Affiliate Transaction, if any, otherwise by a majority of the entire Board; and



(b)

with respect to any Affiliate Transaction involving aggregate value of $20.0 million or more, the certificates described in the preceding clause (a) and a written opinion as to the fairness of such Affiliate Transaction to the Issuer or such Restricted Subsidiary from a financial point of view issued by an Independent Financial Advisor.

        The foregoing restrictions shall not apply to:

(1)

transactions exclusively between or among (a) the Issuer and one or more Restricted Subsidiaries or (b) Restricted Subsidiaries;provided, in each case, that no Affiliate of the Issuer (other than another Restricted Subsidiary) owns Equity Interests of any such Restricted Subsidiary;



(2)

employment contracts, "know-how" agreements, compensation (including stay-on and incentive bonus) arrangements and loans to officers and employees, in each case in the form existing on the Issue Date or representing one or more amendments, modifications, restatements, supplements, extensions, renewals, refinancings, refunds or replacements thereof on terms not materially less favorable to the Issuer or Restricted Subsidiary, as applicable, than those contained in such contracts, agreements, arrangements or loans in the form existing as of the Issue Date;



(3)

indemnities of officers, directors and employees of the Issuer or any of its Subsidiaries permitted by its certificate of incorporation, bylaws or statutory provisions;



(4)

other director, officer, employee and consultant compensation (including bonuses) and other benefits (including retirement, health, stock option and other benefit plans) and indemnification arrangements, in each case approved by a majority of the Independent Directors if any, otherwise by a majority of the entire Board;



(5)

the entering into of a tax sharing agreement, or payments pursuant thereto, between the Issuer and/or one or more Subsidiaries, on the one hand, and any other Person with which the Issuer or such Subsidiaries are required or permitted to file a consolidated tax return or with which the Issuer or such Subsidiaries are part of a consolidated group for tax purposes, on the other hand, which payments by the Issuer and the Restricted Subsidiaries are not in excess of the tax liabilities that would have been payable by them on a stand-alone basis;



(6)

any agreement or arrangement described herein under the heading "Certain relationships and related transactions" as in effect on the Issue Date or any renewals or extensions of any such

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agreement or arrangement (so long as such renewals or extensions are not less favorable to the Issuer or the applicable Restricted Subsidiary);

(7)

loans and advances made in the ordinary course of business to officers, directors and employees who are affiliates of the Issuer or the Restricted Subsidiaries, but in any event not to exceed $3.0 million in the aggregate outstanding at any one time;



(8)

any Investment or other Restricted Payments that are made in accordance with and that are not prohibited under the terms of the covenant described under "—Limitations on restricted payments";provided, however, that the restrictions set forth in clause (1) and clause (2)(a) above shall apply to all such Investments and Restricted Payments; or



(9)

any transaction with an Affiliate where the only consideration paid by the Issuer or any Restricted Subsidiary is Qualified Equity Interests.

Limitations on liens

        The Issuer shall not, and shall not permit any Restricted Subsidiary to, directly or indirectly, create, incur, assume or permit or suffer to exist any Lien of any nature whatsoever (other than Permitted Liens) against any assets of the Issuer or any Restricted Subsidiary (including Equity Interests of a Restricted Subsidiary), whether owned at the Issue Date or thereafter acquired, or any proceeds therefrom, or assign or otherwise convey any right to receive income or profits therefrom, unless contemporaneously therewith:

(1)

in the case of any Lien securing an obligation that rankspari passu with the Notes or a Note Guarantee, effective provision is made to secure the Notes or such Note Guarantee, as the case may be, at least equally and ratably with or prior to such obligation with a Lien on the same collateral; and



(2)

in the case of any Lien securing an obligation that is subordinated in right of payment to the Notes or a Note Guarantee, effective provision is made to secure the Notes or such Note Guarantee, as the case may be, with a Lien on the same collateral that is prior to the Lien securing such subordinated obligation,

        in each case, for so long as such obligation is secured by such Lien.

Limitations on asset sales

        The Issuer will not, and will not permit any Restricted Subsidiary to, directly or indirectly, consummate any Asset Sale unless:

(1)

the Issuer or such Restricted Subsidiary receives consideration at the time of such Asset Sale at least equal to the Fair Market Value of the assets included in such Asset Sale; and



(2)

at least 75% of the total consideration received in such Asset Sale consists of cash or Cash Equivalents.




For

purposes of clause (2), the following shall be deemed to be cash:



(a)

the amount (without duplication) of any Indebtedness (other than Subordinated Indebtedness) of the Issuer or such Restricted Subsidiary that is expressly assumed by the transferee in such Asset Sale and with respect to which the Issuer or such Restricted Subsidiary, as the case may be, is unconditionally released by the holder of such Indebtedness,

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(b)

the amount of any obligations received from such transferee that are within 90 days converted by the Issuer or such Restricted Subsidiary to cash (to the extent of the cash actually so received), and



(c)

the Fair Market Value of any assets (other than securities) received by the Issuer or any Restricted Subsidiary to be used by it in the Permitted Business.

        If at any time any non-cash consideration received by the Issuer or any Restricted Subsidiary of the Issuer, as the case may be, in connection with any Asset Sale is repaid or converted into or sold or otherwise disposed of for cash (other than interest received with respect to any such non-cash consideration), then the date of such repayment, conversion or disposition shall be deemed to constitute the date of an Asset Sale hereunder and the Net Available Proceeds thereof shall be applied in accordance with this covenant.

        If the Issuer or any Restricted Subsidiary engages in an Asset Sale, the Issuer or such Restricted Subsidiary shall, no later than 365 days following the consummation thereof, apply all or any of the Net Available Proceeds therefrom to:

(1)

repay Senior Debt or Guarantor Senior Debt;



(2)

repay any Indebtedness which was secured by the assets sold in such Asset Sale; and/or



(3)

invest all or any part of the Net Available Proceeds thereof in the purchase of assets (other than securities) to be used by the Issuer or any Restricted Subsidiary in the Permitted Business.

        The amount of Net Available Proceeds not applied or invested as provided in this paragraph will constitute "Excess Proceeds."

        When the aggregate amount of Excess Proceeds equals or exceeds $10.0 million, the Issuer will be required to make an offer to purchase from all Holders and, if applicable, redeem (or make an offer to do so) any Pari Passu Indebtedness of the Issuer or a Guarantor the provisions of which require the Issuer or such Guarantor to redeem such Indebtedness with the proceeds from any Asset Sales (or offer to do so), in an aggregate principal amount of Notes and such Pari Passu Indebtedness equal to the amount of such Excess Proceeds as follows:

(1)

the Issuer will (a) make an offer to purchase (a "Net Proceeds Offer") to all Holders in accordance with the procedures set forth in the Indenture, and (b) redeem (or make an offer to do so) any such other Pari Passu Indebtedness, pro rata in proportion to the respective principal amounts of the Notes and such other Indebtedness required to be redeemed, the maximum principal amount of Notes and Pari Passu Indebtedness that may be redeemed out of the amount (the "Payment Amount") of such Excess Proceeds;



(2)

the offer price for the Notes will be payable in cash in an amount equal to 100% of the principal amount of the Notes tendered pursuant to a Net Proceeds Offer, plus accrued and unpaid interest thereon, if any, to the date such Net Proceeds Offer is consummated (the "Offered Price"), in accordance with the procedures set forth in the Indenture and the redemption price for such Pari Passu Indebtedness (the "Pari Passu Indebtedness Price") shall be as set forth in the related documentation governing such Indebtedness;



(3)

if the aggregate Offered Price of Notes validly tendered and not withdrawn by Holders thereof exceeds thepro rata portion of the Payment Amount allocable to the Notes, Notes to be purchased will be selected on apro rata basis; and



(4)

upon completion of such Net Proceeds Offer in accordance with the foregoing provisions, the amount of Excess Proceeds with respect to which such Net Proceeds Offer was made shall be deemed to be zero.

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        To the extent that the sum of the aggregate Offered Price of Notes tendered pursuant to a Net Proceeds Offer and the aggregate Pari Passu Indebtedness Price paid to the holders of such Pari Passu Indebtedness is less than the Payment Amount relating thereto (such shortfall constituting a "Net Proceeds Deficiency"), the Issuer may use the Net Proceeds Deficiency, or a portion thereof, for general corporate purposes, subject to the provisions of the Indenture.

        In the event of the transfer of substantially all (but not all) of the assets of the Issuer and the Restricted Subsidiaries as an entirety to a Person in a transaction covered by and effected in accordance with the covenant described under "—Limitations on Mergers, Consolidations, Etc.," the successor entity shall be deemed to have sold for cash at Fair Market Value the assets of the Issuer and the Restricted Subsidiaries not so transferred for purposes of this covenant, and shall comply with the provisions of this covenant with respect to such deemed sale as if it were an Asset Sale (with such Fair Market Value being deemed to be Net Available Proceeds for such purpose).

        The Issuer will comply with applicable tender offer rules, including the requirements of Rule 14e-1 under the Exchange Act and any other applicable laws and regulations in connection with the purchase of Notes pursuant to a Net Proceeds Offer. To the extent that the provisions of any securities laws or regulations conflict with the "Limitations on Asset Sales" provisions of the Indenture, the Issuer shall comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the "Limitations on asset sales" provisions of the Indenture by virtue of this compliance.

        Notwithstanding the foregoing, in the event that the Issuer consummates an Asset Sale that results in a Change of Control, the provisions of this covenant will be deemed to be satisfied and complied with in the event the Issuer makes a Change of Control Offer pursuant to, and otherwise complying with, the covenant described under "—Change of control" or elects to redeem the Notes at the Issuer's option as described under "Optional redemption."

Limitations on designation of unrestricted subsidiaries

        On the Issue Date, the following Subsidiaries will be Restricted Subsidiaries: TransMontaigne Product Services Inc., TransMontaigne Transport Inc., Coastal Fuels Marketing, Inc. and Coastal Tug and Barge, Inc.

        After the Issue Date, the Issuer may designate any Subsidiary of the Issuer as an "Unrestricted Subsidiary" under the Indenture (a "Designation") only if:

(1)

no Default shall have occurred and be continuing at the time of or after giving effect to such Designation; and



(2)

the Issuer would be permitted to make, at the time of such Designation, (a) a Permitted Investment pursuant to clause (12) of the definition thereof or (b) an Investment pursuant to the first paragraph or clause (9) of the second paragraph of "—Limitations on restricted payments" above, in either case, in an amount (the "Designation Amount") equal to the Fair Market Value of the Issuer's proportionate interest in such Subsidiary on such date.

        No Subsidiary shall be Designated as an "Unrestricted Subsidiary" unless such Subsidiary:

(1)

has no Indebtedness other than Non-Recourse Debt;



(2)

is not party to any agreement, contract, arrangement or understanding with the Issuer or any Restricted Subsidiary unless the terms of the agreement, contract, arrangement or understanding are no less favorable to the Issuer or the Restricted Subsidiary than those that might be obtained at the time from Persons who are not Affiliates; and

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(3)

is a Person with respect to which neither the Issuer nor any Restricted Subsidiary has any direct or indirect obligation (a) to subscribe for additional Equity Interests or (b) to maintain or preserve the Person's financial condition or to cause the Person to achieve any specified levels of operating results.

        If, at any time, any Unrestricted Subsidiary fails to meet the preceding requirements as an Unrestricted Subsidiary, it shall thereafter cease to be an Unrestricted Subsidiary for purposes of the Indenture and any Indebtedness of the Subsidiary and any Liens on assets of such Subsidiary shall be deemed to be incurred by a Restricted Subsidiary as of the date and, if the Indebtedness is not permitted to be incurred under the covenant described under "—Limitations on additional indebtedness" or the Lien is not permitted under the covenant described under "—Limitations on liens," the Issuer shall be in default of the applicable covenant.

        The Issuer may redesignate an Unrestricted Subsidiary as a Restricted Subsidiary (a "Redesignation") only if:

(1)

no Default shall have occurred and be continuing at the time of and after giving effect to such Redesignation; and



(2)

all Liens, Indebtedness and Investments of such Unrestricted Subsidiary outstanding immediately following such Redesignation would, if incurred or made at such time, have been permitted to be incurred or made for all purposes of the Indenture.

        All Designations and Redesignations must be evidenced by resolutions of the Board of Directors of the Issuer, delivered to the Trustee certifying compliance with the foregoing provisions.

Limitations on the issuance or sale of equity interests of restricted subsidiaries

        The Issuer will not, and will not permit any Restricted Subsidiary to, directly or indirectly, sell or issue any shares of Equity Interests of any Restricted Subsidiary except (1) to the Issuer, a Restricted Subsidiary or the minority stockholders of any Restricted Subsidiary, on apro rata basis, at Fair Market Value, (2) to the extent such shares represent directors' qualifying shares or shares required by applicable law to be held by a Person other than the Issuer or a Wholly-Owned Restricted Subsidiary or (3) if after giving effect thereto, such Restricted Subsidiary no longer qualifies as such and the sale is not otherwise prohibited by the Indenture. The sale of all the Equity Interests of any Restricted Subsidiary is permitted by this covenant but is subject to the covenant described under "—Limitations on asset sales."

Limitations on mergers, consolidations, etc.

        The Issuer will not, directly or indirectly, in a single transaction or a series of related transactions, (a) consolidate or merge with or into another Person (other than a merger with a Wholly-Owned Restricted Subsidiary solely for the purpose of changing the Issuer's jurisdiction of incorporation to another State of the United States), or sell, lease, transfer, convey or otherwise dispose of or assign all or substantially all of the assets of the Issuer or the Issuer and the Restricted Subsidiaries (taken as a whole) or (b) adopt a Plan of Liquidation unless, in either case:

(1)

either:



(a)

the Issuer will be the surviving or continuing Person; or



(b)

the Person formed by or surviving such consolidation or merger or to which such sale, lease, conveyance or other disposition shall be made (or, in the case of a Plan of Liquidation, any Person to which assets are transferred) (collectively, the "Successor") is a corporation organized and existing under the laws of any State of the United States of America or the District of Columbia, and the Successor expressly assumes, by

153

supplemental indenture in form and substance satisfactory to the Trustee, all of the obligations of the Issuer under the Notes, the Indenture and the Registration Rights Agreement (as defined under "Exchange offer; registration rights");

(2)

immediately prior to and immediately after giving effect to such transaction and the assumption of the obligations as set forth in clause (1)(b) above and the incurrence of any Indebtedness to be incurred in connection therewith, no Default shall have occurred and be continuing; and



(3)

except in the case of the consolidation or merger of any Wholly-Owned Restricted Subsidiary with or into the Issuer, immediately after and giving effect to such transaction and the assumption of the obligations set forth in clause (1)(b) above and the incurrence of any Indebtedness to be incurred in connection therewith, and the use of any net proceeds therefrom on a pro forma basis, (a) the Consolidated Net Worth of the Issuer or the Successor, as the case may be, would be at least equal to the Consolidated Net Worth of the Issuer immediately prior to such transaction and (b) the Issuer or the Successor, as the case may be, could incur $1.00 of additional Indebtedness pursuant to the Coverage Ratio Exception.

        For purposes of this covenant, any Indebtedness of the Successor which was not Indebtedness of the Issuer immediately prior to the transaction shall be deemed to have been incurred in connection with such transaction.

        Except as provided in the fifth paragraph under the caption "—Note guarantees," no Guarantor may consolidate with or merge with or into (whether or not such Guarantor is the surviving Person) another Person, whether or not affiliated with such Guarantor, unless:

(1)

either:



(a)

such Guarantor will be the surviving or continuing Person; or



(b)

the Person formed by or surviving any such consolidation or merger assumes, by supplemental indenture in form and substance satisfactory to the Trustee, all of the obligations of such Guarantor under the Note Guarantee of such Guarantor, the Indenture and the Registration Rights Agreement; and Description of the notes



(2)

immediately after giving effect to such transaction, no Default shall have occurred and be continuing.

        For purposes of the foregoing, the transfer (by lease, assignment, sale or otherwise, in a single transaction or series of transactions) of all or substantially all of the properties or assets of one or more Restricted Subsidiaries, the Equity Interests of which constitute all or substantially all of the properties and assets of the Issuer, will be deemed to be the transfer of all or substantially all of the properties and assets of the Issuer.

        Upon any consolidation, combination or merger of the Issuer or a Guarantor, or any transfer of all or substantially all of the assets of the Issuer in accordance with the foregoing, in which the Issuer or such Guarantor is not the continuing obligor under the Notes or its Note Guarantee, the surviving entity formed by such consolidation or into which the Issuer or such Guarantor is merged or to which the conveyance, lease or transfer is made will succeed to, and be substituted for, and may exercise every right and power of, the Issuer or such Guarantor under the Indenture, the Notes and the Note Guarantees with the same effect as if such surviving entity had been named therein as the Issuer or such Guarantor and, except in the case of a conveyance, transfer or lease, the Issuer or such Guarantor, as the case may be, will be released from the obligation to pay the principal of and interest on the Notes or in respect of its Note Guarantee, as the case may be, and all of the Issuer's or such

154

Guarantor's other obligations and covenants under the Notes, the Indenture and its Note Guarantee, if applicable.

        In the event of a sale or other disposition of all of the assets of any Guarantor, by way of merger, consolidation or otherwise, or a sale or other disposition of all of the Equity Interests of any Guarantor, then such Guarantor (in the event of a sale or other disposition, by way of merger, consolidation or otherwise, of all of the Equity Interests of such Guarantor) or the corporation acquiring the property (in the event of a sale or other disposition of all or substantially all of the assets of such Guarantor) will be released and relieved of any obligations under its Note Guarantee;provided that the net proceeds of such sale or other disposition are applied in accordance with the provisions set forth under "—Limitations on asset sales."

        Notwithstanding the foregoing, any Restricted Subsidiary may merge into the Issuer or another Restricted Subsidiary.

Additional note guarantees

        If, after the Issue Date, (a) the Issuer or any Restricted Subsidiary shall acquire or create another Subsidiary (other than in any case a Subsidiary (x) that is a Foreign Subsidiary or (y) that has been designated an Unrestricted Subsidiary) or (b) any Unrestricted Subsidiary is redesignated a Restricted Subsidiary, then, in each such case, the Issuer shall cause such Restricted Subsidiary to:

(1)

execute and deliver to the Trustee (a) a supplemental indenture in form and substance satisfactory to the Trustee pursuant to which such Restricted Subsidiary shall unconditionally guarantee all of the Issuer's obligations under the Notes and the Indenture and (b) a notation of guarantee in respect of its Note Guarantee; and



(2)

deliver to the Trustee one or more opinions of counsel that such supplemental indenture (a) has been duly authorized, executed and delivered by such Restricted Subsidiary and (b) constitutes a valid and legally binding obligation of such Restricted Subsidiary in accordance with its terms.

Conduct of business

        The Issuer will not, and will not permit any Restricted Subsidiary to, engage in any business other than the Permitted Business.

Reports

        Whether or not required by the SEC, so long as any Notes are outstanding, the Issuer will furnish or make available to the Holders of Notes, within the time periods specified in the SEC's rules and regulations:

(1)

all quarterly and annual financial information that would be required to be contained in a filing with the SEC on Forms 10-Q and 10-K if the Issuer were required to file these Forms, including a "Management's discussion and analysis of financial condition and results of operations" and, with respect to the annual information only, a report on the annual financial statements by the Issuer's certified independent accountants; and



(2)

all current reports that would be required to be filed with the SEC on Form 8-K if the Issuer were required to file these reports.

        In addition, whether or not required by the SEC, the Issuer will file a copy of all of the information and reports referred to in clauses (1) and (2) above with the SEC for public availability within the time periods specified in the SEC's rules and regulations (unless the SEC will not accept the filing) and make the information available to securities analysts and prospective investors upon request.

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The Issuer and the Guarantors have agreed that, for so long as any Notes remain outstanding, the Issuer and the Guarantors will furnish to the Holders and to securities analysts and prospective investors, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act.

Events of default

        Each of the following is an "Event of Default":

(1)

failure by the Issuer to pay interest on any of the Notes when it becomes due and payable and the continuance of any such failure for 30 days (whether or not such payment is prohibited by the subordination provisions of the Indenture);



(2)

failure by the Issuer to pay the principal on any of the Notes when it becomes due and payable, whether at stated maturity, upon redemption, upon purchase, upon acceleration or otherwise (whether or not such payment is prohibited by the subordination provisions of the Indenture);



(3)

failure by the Issuer to comply with any of its agreements or covenants described above under "—Certain covenants—Limitations on mergers, consolidations, etc.," or in respect of its obligations to make a Change of Control Offer as described above under "—Change of Control" (whether or not such payment is prohibited by the subordination provisions of the Indenture);



(4)

failure by the Issuer to comply with any other agreement or covenant in the Indenture and continuance of this failure for 45 days after notice of the failure has been given to the Issuer by the Trustee or by the Holders of at least 25% of the aggregate principal amount of the Notes then outstanding;



(5)

default under any mortgage, indenture or other instrument or agreement under which there may be issued or by which there may be secured or evidenced Indebtedness of the Issuer or any Restricted Subsidiary, whether such Indebtedness now exists or is incurred after the Issue Date, which default:



(a)

is caused by a failure to pay when due principal on such Indebtedness within the applicable express grace period,



(b)

results in the acceleration of such Indebtedness prior to its express final maturity or



(c)

results in the commencement of judicial proceedings to foreclose upon, or to exercise remedies under applicable law or applicable security documents to take ownership of, the assets securing such Indebtedness, and

in each case, the principal amount of such Indebtedness, together with any other Indebtedness with respect to which an event described in clause (a), (b) or (c) has occurred and is continuing, aggregates $10.0 million or more;

(6)

one or more judgments or orders that exceed $10.0 million in the aggregate (net of amounts covered by insurance or bonded) for the payment of money have been entered by a court or courts of competent jurisdiction against the Issuer or any Restricted Subsidiary and such judgment or judgments have not been satisfied, stayed, annulled or rescinded within 60 days of being entered (or such longer period as may be permitted for timely appeal under applicable law);

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(7)

the Issuer or any Significant Subsidiary pursuant to or within the meaning of any Bankruptcy Law:



(a)

commences a voluntary case,



(b)

consents to the entry of an order for relief against it in an involuntary case,



(c)

consents to the appointment of a Custodian of it or for all or substantially all of its assets, or



(d)

makes a general assignment for the benefit of its creditors;



(8)

a court of competent jurisdiction enters an order or decree that remains unstayed and in effect for 60 days under any Bankruptcy Law that:



(a)

is for relief against the Issuer or any Significant Subsidiary as debtor in an involuntary case,



(b)

appoints a Custodian of the Issuer or any Significant Subsidiary or a Custodian for all or substantially all of the assets of the Issuer or any Significant Subsidiary, or



(c)

orders the liquidation of the Issuer or any Significant Subsidiary; or



(9)

any Note Guarantee of any Significant Subsidiary ceases to be in full force and effect (other than in accordance with the terms of such Note Guarantee and the Indenture) or is declared null and void and unenforceable or found to be invalid or any Guarantor denies its liability under its Note Guarantee (other than by reason of release of a Guarantor from its Note Guarantee in accordance with the terms of the Indenture and the Note Guarantee) and in either case such condition continues for 45 days.

        If an Event of Default (other than an Event of Default specified in clause (7) or (8) above with respect to the Issuer), shall have occurred and be continuing under the Indenture, the Trustee, by written notice to the Issuer, or the Holders of at least 25% in aggregate principal amount of the Notes then outstanding by written notice to the Issuer and the Trustee, may declare all amounts owing under the Notes to be due and payable immediately. Upon such declaration of acceleration, the aggregate principal of and accrued and unpaid interest on the outstanding Notes shall immediately become due and payable;provided,however, that after such acceleration, but before a judgment or decree based on acceleration, the Holders of a majority in aggregate principal amount of such outstanding Notes may, under certain circumstances, rescind and annul such acceleration if all Events of Default, other than the nonpayment of accelerated principal and interest, have been cured or waived as provided in the Indenture. If an Event of Default specified in clause (7) or (8) with respect to the Issuer occurs, all outstanding Notes shall become due and payable without any further action or notice.

        The Trustee shall, within 30 days after the occurrence of any Default with respect to the Notes, give the Holders notice of all uncured Defaults thereunder known to it;provided,however, that, except in the case of an Event of Default in payment with respect to the Notes or a Default in complying with "—Limitations on mergers, consolidations, etc.," the Trustee shall be protected in withholding such notice if and so long as a committee of its trust officers in good faith determines that the withholding of such notice is in the interest of the Holders.

        The Issuer may cure a Default or Event of Default by designating a Restricted Subsidiary as an Unrestricted Subsidiary in compliance with the covenant described under "—Limitation on designation of unrestricted subsidiaries," if the circumstances giving rise to such Default or Event of Default would not have constituted a Default or Event of Default had such Restricted Subsidiary been an Unrestricted Subsidiary during the relevant period of such circumstances.

157

        No Holder will have any right to institute any proceeding with respect to the Indenture or for any remedy thereunder, unless the Trustee:

(1)

has failed to act for a period of 60 days after receiving written notice of a continuing Event of Default by such Holder and a request to act by Holders of at least 25% in aggregate principal amount of Notes outstanding;



(2)

has been offered indemnity satisfactory to it in its reasonable judgment; and



(3)

has not received from the Holders of a majority in aggregate principal amount of the outstanding Notes a direction inconsistent with such request.

        However, such limitations do not apply to a suit instituted by a Holder of any Note for enforcement of payment of the principal of or interest on such Note on or after the due date therefor (after giving effect to the grace period specified in clause (1) of the first paragraph of this "—Events of default" section).

        The Issuer is required to deliver to the Trustee annually a statement regarding compliance with the Indenture and, upon any Officer of the Issuer becoming aware of any Default, a statement specifying such Default and what action the Issuer is taking or proposes to take with respect thereto.

Legal defeasance and covenant defeasance

        The Issuer may, at its option and at any time, elect to have its obligations and the obligations of the Guarantors discharged with respect to the outstanding Notes ("Legal Defeasance"). Legal Defeasance means that the Issuer and the Guarantors shall be deemed to have paid and discharged the entire indebtedness represented by the Notes and the Note Guarantees, and the Indenture shall cease to be of further effect as to all outstanding Notes and Note Guarantees, except as to

(1)

rights of Holders to receive payments in respect of the principal of and interest on the Notes when such payments are due from the trust funds referred to below,



(2)

the Issuer's obligations with respect to the Notes concerning issuing temporary Notes, registration of Notes, mutilated, destroyed, lost or stolen Notes, and the maintenance of an office or agency for payment and money for security payments held in trust,



(3)

the rights, powers, trust, duties, and immunities of the Trustee, and the Issuer's obligation in connection therewith, and



(4)

the Legal Defeasance provisions of the Indenture.

        In addition, the Issuer may, at its option and at any time, elect to have its obligations and the obligations of the Guarantors released with respect to most of the covenants under the Indenture, except as described otherwise in the Indenture ("Covenant Defeasance"), and thereafter any omission to comply with such obligations shall not constitute a Default. In the event Covenant Defeasance occurs, certain Events of Default (not including non-payment and, solely for a period of 91 days following the deposit referred to in clause (1) of the next paragraph, bankruptcy, receivership, rehabilitation and insolvency events) will no longer apply. Covenant Defeasance will not be effective until such bankruptcy, receivership, rehabilitation and insolvency events no longer apply. The Issuer may exercise its Legal Defeasance option regardless of whether it previously exercised Covenant Defeasance.

        In order to exercise either Legal Defeasance or Covenant Defeasance:

(1)

the Issuer must irrevocably deposit with the Trustee, in trust, for the benefit of the Holders, U.S. legal tender, U.S. Government Obligations or a combination thereof, in such amounts as will be sufficient (without reinvestment) in the opinion of a nationally recognized firm of

158

independent public accountants selected by the Issuer, to pay the principal of and interest on the Notes on the stated date for payment or on the redemption date of the principal or installment of principal of or interest on the Notes, and the Holders must have a valid, perfected, exclusive security interest in such trust,

(2)

in the case of Legal Defeasance, the Issuer shall have delivered to the Trustee an opinion of counsel in the United States reasonably acceptable to the Trustee confirming that:



(a)

the Issuer has received from, or there has been published by the Internal Revenue Service, a ruling, or



(b)

since the date of the Indenture, there has been a change in the applicable U.S. federal income tax law,

in either case to the effect that, and based thereon this opinion of counsel shall confirm that, the Holders will not recognize income, gain or loss for U.S. federal income tax purposes as a result of the Legal Defeasance and will be subject to U.S. federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Legal Defeasance had not occurred,

(3)

in the case of Covenant Defeasance, the Issuer shall have delivered to the Trustee an opinion of counsel in the United States reasonably acceptable to the Trustee confirming that the Holders will not recognize income, gain or loss for U.S. federal income tax purposes as a result of such Covenant Defeasance and will be subject to U.S. federal income tax on the same amounts, in the same manner and at the same times as would have been the case if the Covenant Defeasance had not occurred,



(4)

no Default shall have occurred and be continuing on the date of such deposit (other than a Default resulting from the borrowing of funds to be applied to such deposit and the grant of any Lien securing such borrowing),



(5)

the Legal Defeasance or Covenant Defeasance shall not result in a breach or violation of, or constitute a default under the Indenture or any other material agreement or instrument to which the Issuer or any of its Subsidiaries is a party or by which the Issuer or any of its Subsidiaries is bound,



(6)

the Issuer shall have delivered to the Trustee an Officers' Certificate stating that the deposit was not made by it with the intent of preferring the Holders over any other of its creditors or with the intent of defeating, hindering, delaying or defrauding any other of its creditors or others, and



(7)

the Issuer shall have delivered to the Trustee an Officers' Certificate and an opinion of counsel, each stating that the conditions provided for in, in the case of the Officers' Certificate, clauses (1) through (6) and, in the case of the opinion of counsel, clauses (1) (with respect to the validity and perfection of the security interest), (2) and /or (3) and (5) of this paragraph have been complied with.

        If the funds deposited with the Trustee to effect Covenant Defeasance are insufficient to pay the principal of and interest on the Notes when due, then our obligations and the obligations of Guarantors under the Indenture will be revived and no such defeasance will be deemed to have occurred. Before or after a deposit, the Issuer may make arrangement satisfactory to the Trustee for the redemption of Notes at a future date in accordance with the provisions set forth under "—Optional redemption."

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Satisfaction and discharge

        The Indenture will be discharged and will cease to be of further effect (except as to rights of registration of transfer or exchange of Notes which shall survive until all Notes have been canceled) as to all outstanding Notes when either

(1)

all the Notes that have been authenticated and delivered (except lost, stolen or destroyed Notes which have been replaced or paid and Notes for whose payment money has been deposited in trust or segregated and held in trust by the Issuer and thereafter repaid to the Issuer or discharged from this trust) have been delivered to the Trustee for cancellation, or



(2)

(a) all Notes not delivered to the Trustee for cancellation otherwise have become due and payable or have been called for redemption pursuant to the provisions described under "—Optional redemption," and the Issuer has irrevocably deposited or caused to be deposited with the Trustee trust funds in trust in an amount of money sufficient to pay and discharge the entire Indebtedness (including all principal and accrued interest) on the Notes not theretofore delivered to the Trustee for cancellation,



(b)

the Issuer has paid all sums payable by it under the Indenture,



(c)

the Issuer has delivered irrevocable instructions to the Trustee to apply the deposited money toward the payment of the Notes at maturity or on the date of redemption, as the case may be, and



(d)

the Holders have a valid, perfected, exclusive security interest in this trust.

        In addition, the Issuer must deliver an Officers' Certificate and an opinion of counsel stating that all conditions precedent to satisfaction and discharge have been complied with.

Transfer and exchange

        A Holder will be able to register the transfer of or exchange Notes only in accordance with the provisions of the Indenture. The Registrar may require a Holder, among other things, to furnish appropriate endorsements and transfer documents and to pay any taxes and fees required by law or permitted by the Indenture. Without the prior consent of the Issuer, the Registrar is not required (1) to register the transfer of or exchange any Note selected for redemption, (2) to register the transfer of or exchange any Note for a period of 15 days before a selection of Notes to be redeemed or (3) to register the transfer or exchange of a Note between a record date and the next succeeding interest payment date.

        The Notes will be issued in registered form and the registered Holder will be treated as the owner of such Note for all purposes.

Amendment, supplement and waiver

        Subject to certain exceptions, the Indenture or the Notes may be amended with the consent (which may include consents obtained in connection with a tender offer or exchange offer for Notes) of the Holders of at least a majority in principal amount of the Notes then outstanding, and any existing Default under, or compliance with any provision of, the Indenture may be waived (other than any continuing Default in the payment of the principal or interest on the Notes) with the consent (which may include consents obtained in connection with a tender offer or exchange offer for Notes) of the Holders of a majority in principal amount of the Notes then outstanding;provided that:

(a)

no such amendment may, without the consent of the Holders of two-thirds in aggregate principal amount of Notes then outstanding, amend the obligation of the Issuer under the

160

heading "—Change of control" or the related definitions that could adversely affect the rights of any Holder; and

(b)

without the consent of each Holder affected, the Issuer and the Trustee may not:



(1)

change the maturity of any Note;



(2)

reduce the amount, extend the due date or otherwise affect the terms of any scheduled payment of interest on or principal of the Notes;



(3)

reduce any premium payable upon optional redemption of the Notes, change the date on which any Notes are subject to redemption or otherwise alter the provisions with respect to the redemption of the Notes;



(4)

make any Note payable in money or currency other than that stated in the Notes;



(5)

modify or change any provision of the Indenture or the related definitions affecting the subordination of the Notes or any Note Guarantee in a manner that adversely affects the Holders;



(6)

reduce the percentage of Holders necessary to consent to an amendment or waiver to the Indenture or the Notes;



(7)

impair the rights of Holders to receive payments of principal of or interest on the Notes;



(8)

release any Guarantor from any of its obligations under its Note Guarantee or the Indenture, except as permitted by the Indenture; or



(9)

make any change in these amendment and waiver provisions.

        Notwithstanding the foregoing, the Issuer and the Trustee may amend the Indenture, the Note Guarantees or the Notes without the consent of any Holder, to cure any ambiguity, defect or inconsistency, to provide for uncertificated Notes in addition to or in place of certificated Notes, to provide for the assumption of the Issuer's obligations to the Holders in the case of a merger or acquisition, to release any Guarantor from any of its obligations under its Note Guarantee or the Indenture (to the extent permitted by the Indenture), to make any change that does not materially adversely affect the rights of any Holder or, in the case of the Indenture, to maintain the qualification of the Indenture under the Trust Indenture Act. In connection with any amendment, supplement or waiver, the Issuer may, but shall not be obligated to, offer any Holder who consents to such amendment, supplement or waiver, or to all Holders, consideration for such Holder's consent to such amendment, supplement or waiver.

        No amendment of, or supplement or waiver to, the Indenture shall adversely affect the rights of any holder of Senior Debt or Guarantor Senior Debt under the subordination provisions of the Indenture, without the consent of such holder.

No personal liability of directors, officers, employees and stockholders

        No director, officer, employee, incorporator or stockholder of the Issuer or any Guarantor will have any liability for any obligations of the Issuer under the Notes or the Indenture or of any Guarantor under its Note Guarantee or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes and the Note Guarantees. The waiver may not be effective to waive liabilities under the federal securities laws. It is the view of the SEC that this type of waiver is against public policy.

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Concerning the trustee

        Wells Fargo Bank Minnesota, National Association is the Trustee under the Indenture and has been appointed by the Issuer as Registrar and Paying Agent with regard to the Notes. The Indenture contains certain limitations on the rights of the Trustee, should it become a creditor of the Issuer, to obtain payment of claims in certain cases, or to realize on certain assets received in respect of any such claim as security or otherwise. The Trustee will be permitted to engage in other transactions; however, if it acquires any conflicting interest (as defined in the Indenture), it must eliminate such conflict or resign.

        The Holders of a majority in principal amount of the then outstanding Notes will have the right to direct the time, method and place of conducting any proceeding for exercising any remedy available to the Trustee, subject to certain exceptions. The Indenture provides that, in case an Event of Default occurs and is not cured, the Trustee will be required, in the exercise of its power, to use the degree of care of a prudent person in similar circumstances in the conduct of his own affairs. Subject to such provisions, the Trustee will be under no obligation to exercise any of its rights or powers under the Indenture at the request of any Holder, unless such Holder shall have offered to the Trustee security and indemnity satisfactory to the Trustee.

Governing law

        The Indenture, the Notes and the Note Guarantees will be governed by, and construed in accordance with, the laws of the State of New York.

Certain definitions

        Set forth below is a summary of certain of the defined terms used in the Indenture. Reference is made to the Indenture for the full definition of all such terms.

        "Acquired Indebtedness" means (1) with respect to any Person that becomes a Restricted Subsidiary after the Issue Date, Indebtedness of such Person and its Subsidiaries existing at the time such Person becomes a Restricted Subsidiary that was not incurred in connection with, or in contemplation of, such Person becoming a Restricted Subsidiary and (2) with respect to the Issuer or any Restricted Subsidiary, any Indebtedness of a Person (other than the Issuer or a Restricted Subsidiary) existing at the time such Person is merged with or into the Issuer or a Restricted Subsidiary, or Indebtedness expressly assumed by the Issuer or any Restricted Subsidiary in connection with the acquisition of an asset or assets from another Person, which Indebtedness was not, in any case, incurred by such other Person in connection with, or in contemplation of, such merger or acquisition.

        "Additional Interest" has the meaning set forth in the Registration Rights Agreement.

        "Affiliate" of any Person means any other Person which directly or indirectly controls or is controlled by, or is under direct or indirect common control with, the referent Person. For purposes of the covenant described under "—Certain covenants—Limitations on transactions with affiliates," Affiliates shall be deemed to include, with respect to any Person, any other Person (1) which beneficially owns or holds, directly or indirectly, 10% or more of any class of the Voting Stock of the referent Person, (2) of which 10% or more of the Voting Stock is beneficially owned or held, directly or indirectly, by the referenced Person or (3) with respect to an individual, any immediate family member of such Person. For purposes of this definition, "control" of a Person shall mean the power to direct the management and policies of such Person, directly or indirectly, whether through the ownership of voting securities, by contract or otherwise.

        "amend" means to amend, supplement, restate, amend and restate or otherwise modify; and "amendment" shall have a correlative meaning.

162

        "Applicable Premium" means with respect to a Note at any time, the greater of (1) 1.0% of the principal amount of such Note at such time and (2) the excess of (A) the present value at such time of the principal amount of such Note plus any required interest payments due on such Note from the redemption date to June 1, 2007, computed using a discount rate equal to the Treasury Rate plus 50 basis points, over (B) the principal amount of such Note.

        "asset" means any asset or property.

        "Asset Acquisition" means

(1)

an Investment by the Issuer or any Restricted Subsidiary of the Issuer in any other Person if, as a result of such Investment, such Person shall become a Restricted Subsidiary of the Issuer, or shall be merged with or into the Issuer or any Restricted Subsidiary of the Issuer, or



(2)

the acquisition by the Issuer or any Restricted Subsidiary of the Issuer of all or substantially all of the assets of any other Person or any division or line of business of any other Person.

        "Asset Sale" means any sale, issuance, conveyance, transfer, lease, assignment or other disposition by the Issuer or any Restricted Subsidiary to any Person other than the Issuer or any Restricted Subsidiary (including by means of a Sale and Leaseback Transaction or a merger or consolidation) (collectively, for purposes of this definition, a "transfer"), in one transaction or a series of related transactions, of any assets of the Issuer or any of its Restricted Subsidiaries other than in the ordinary course of business. For purposes of this definition, the term "Asset Sale" shall not include:

(1)

transfers of cash or Cash Equivalents;



(2)

transfers of assets (including Equity Interests) that are governed by, and made in accordance with, the covenant described under "—Limitations on mergers, consolidations, etc.";



(3)

Permitted Investments and Restricted Payments permitted under the covenant described under "—Limitations on restricted payments";



(4)

the creation or realization of any Permitted Lien;



(5)

transfers of damaged, worn-out or obsolete equipment or assets that, in the Issuer's reasonable judgment, are no longer used or useful in the business of the Issuer or its Restricted Subsidiaries; and



(6)

the surrender or waiver of contract rights or the settlement, release, or surrender or contract, tort or other claims of any kind;



(7)

exchanges of assets of the Issuer or any of its Restricted Subsidiaries for consideration consisting of other assets used in the business of the Issuer or such Restricted Subsidiary;provided, however, that at least 80% of the consideration received in any such exchange shall consist of assets used or useful in the Permitted Business and the balance of such consideration shall consist of cash and Cash Equivalents and;provided, further, that such exchanges of assets shall be subject to clause (1) of the covenant "—Limitation on asset sales"; and



(8)

any transfer or series of related transfers that, but for this clause, would be Asset Sales, if after giving effect to such transfers, the aggregate Fair Market Value of the assets transferred in such transaction or any such series of related transactions does not exceed $5.0 million.

        "Attributable Indebtedness", when used with respect to any Sale and Leaseback Transaction, means, as at the time of determination, the present value (discounted at a rate equivalent to the Issuer's then-current weighted average cost of funds for borrowed money as at the time of determination, compounded on a semi-annual basis) of the total obligations of the lessee for rental payments during the remaining term of the lease included in any such Sale and Leaseback Transaction.

163

        "Bankruptcy Law" means Title 11 of the United States Code, as amended, or any similar federal or state law for the relief of debtors.

        "Board of Directors" means, with respect to any Person, the board of directors or comparable governing body of such Person.

        "Borrowing Base" means, on any date, the sum of the following (without duplication):

(1)

100% of cash and Cash Equivalents including, without limitation, cash being held as margin deposits in respect of commodities margin loans irrespective of whether such cash is restricted as a result thereof,



(2)

plus 85% of Receivables, and



(3)

plus 80% of Inventory and 100% of Eligible Exchange Contract Balances (if positive),

minus any and all outstanding Indebtedness in respect of commodities margin loans.

        "Business Day" means a day other than a Saturday, Sunday or other day on which banking institutions in New York are authorized or required by law to close.

        "Capitalized Lease" means a lease required to be capitalized for financial reporting purposes in accordance with GAAP.

        "Capitalized Lease Obligations" of any Person means the obligations of such Person to pay rent or other amounts under a Capitalized Lease, and the amount of such obligation shall be the capitalized amount thereof determined in accordance with GAAP.

        "Cash Equivalents" means:

(1)

marketable obligations with a maturity of 360 days or less issued or directly and fully guaranteed or insured by the United States of America or any agency or instrumentality thereof (provided that the full faith and credit of the United States of America is pledged in support thereof);



(2)

demand and time deposits and certificates of deposit or acceptances with a maturity of 180 days or less of any financial institution that is a member of the Federal Reserve System having combined capital and surplus and undivided profits of not less than $500 million and is assigned at least a "B" rating by Thomson Financial BankWatch;



(3)

commercial paper maturing no more than 180 days from the date of creation thereof issued by a corporation that is not the Issuer or an Affiliate of the Issuer, and is organized under the laws of any State of the United States of America or the District of Columbia and rated at least A-1 by S&P or at least P-1 by Moody's;



(4)

repurchase obligations with a term of not more than ten days for underlying securities of the types described in clause (1) above entered into with any commercial bank meeting the specifications of clause (2) above; and



(5)

investments in money market or other mutual funds substantially all of whose assets comprise securities of the types described in clauses (1) through (4) above.

        "Change of Control" means the occurrence of any of the following events:

(1)

any "person" or "group" (as such terms are used in Sections 13(d) and 14(d) of the Exchange Act), is or becomes the beneficial owner (as defined in Rules 13d-3 and 13d-5 under the Exchange Act, except that for purposes of this clause (1) that person or group shall be deemed to have "beneficial ownership" of all securities that any such person or group has the right to acquire, whether such right is exercisable immediately or only after the passage of

164

time), directly or indirectly, of Voting Stock representing more than 40% of the voting power of the total outstanding Voting Stock of the Issuer;

(2)

during any period of two consecutive years, individuals who at the beginning of such period constituted the Board of Directors (together with any new directors whose election to such Board of Directors or whose nomination for election by the stockholders of the Issuer was approved by a vote of the majority of the directors of the Issuer then still in office who were either directors at the beginning of such period or whose election or nomination for election was previously so approved) cease for any reason to constitute a majority of the Board of Directors of the Issuer;



(3)

(a) all or substantially all of the assets of the Issuer and the Restricted Subsidiaries are sold or otherwise transferred to any Person other than a Wholly-Owned Restricted Subsidiary or (b) the Issuer consolidates or merges with or into another Person or any Person consolidates or merges with or into the Issuer, in either case under this clause (3), in one transaction or a series of related transactions in which immediately after the consummation thereof Persons owning Voting Stock representing in the aggregate a majority of the total voting power of the Voting Stock of the Issuer immediately prior to such consummation do not own Voting Stock representing a majority of the total voting power of the Voting Stock of the Issuer or the surviving or transferee Person; or



(4)

the Issuer shall adopt a plan of liquidation or dissolution or any such plan shall be approved by the stockholders of the Issuer.

        "Consolidated Amortization Expense" for any period means the amortization expense of the Issuer and the Restricted Subsidiaries for such period, determined on a consolidated basis in accordance with GAAP.

        "Consolidated Cash Flow" for any period means, without duplication, the sum of the amounts; in each case determined on a consolidated basis in accordance with GAAP, for such period of

(1)

Consolidated Net Income,

plus

(2)

in each case only to the extent (and in the same proportion) deducted in determining Consolidated Net Income and with respect to the portion of Consolidated Net Income attributable to any Restricted Subsidiary only if a corresponding amount would be permitted at the date of determination to be distributed to the Issuer by such Restricted Subsidiary without prior approval (that has not been obtained), pursuant to the terms of its charter and all agreements, instruments, judgments, decrees, orders, statutes, rules and governmental regulations applicable to such Restricted Subsidiary or its stockholders,



(a)

Consolidated Income Tax Expense,



(b)

Consolidated Amortization Expense (but only to the extent not included in Consolidated Interest Expense),



(c)

Consolidated Depreciation Expense,



(d)

Consolidated Interest Expense, and



(e)

all other non-cash items reducing the Consolidated Net Income (excluding any non-cash charge that results in an accrual of a reserve for cash charges in any future period) for such period, in each case determined on a consolidated basis in accordance with GAAP,

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minus

(3)

the aggregate amount of all non-cash items, determined on a consolidated basis, to the extent such items increased Consolidated Net Income for such period,

minus

(4)

any gain recognized on beginning inventory-discretionary volumes and any gain on liquidation of inventories-minimum volumes,

plus,

(5)

any gain deferred on ending inventory-discretionary volumes, any lower of cost or market write-downs on base inventory volumes and any lower of cost or market write-downs on inventories-minimum volumes.

        "Consolidated Current Liabilities" means, at any date, all amounts that are or should be carried as current liabilities on the balance sheet of the Issuer and its Restricted Subsidiaries determined in accordance with GAAP on a consolidated basis, including the current portion of all Funded Debt.

        "Consolidated Depreciation Expense" for any period means the depreciation expense of the Issuer and the Restricted Subsidiaries for such period, determined on a consolidated basis in accordance with GAAP.

        "Consolidated Income Tax Expense" for any period means the provision for taxes of the Issuer and the Restricted Subsidiaries, determined on a consolidated basis in accordance with GAAP.

        "Consolidated Interest Coverage Ratio" means the ratio of Consolidated Cash Flow during the most recent four consecutive full fiscal quarters for which financial statements are available (the "Four-Quarter Period") ending on or prior to the date of the transaction giving rise to the need to calculate the Consolidated Interest Coverage Ratio (the "Transaction Date") to Consolidated Interest Expense for the Four-Quarter Period. For purposes of this definition, Consolidated Cash Flow and Consolidated Interest Expense shall be calculated after giving effect on a pro forma basis for the period of such calculation to:

(1)

the incurrence of any Indebtedness or the issuance of any Preferred Stock of the Issuer or any Restricted Subsidiary (and the application of the proceeds thereof) and any repayment of other Indebtedness or redemption of other Preferred Stock (and the application of the proceeds therefrom) (other than the incurrence or repayment of Indebtedness in the ordinary course of business for working capital purposes pursuant to any revolving credit arrangement) occurring during the Four-Quarter Period or at any time subsequent to the last day of the Four-Quarter Period and on or prior to the Transaction Date, as if such incurrence, repayment, issuance or redemption, as the case may be (and the application of the proceeds thereof), occurred on the first day of the Four-Quarter Period; and



(2)

any Asset Sale or other disposition or Asset Acquisition (including, without limitation, any Asset Acquisition giving rise to the need to make such calculation as a result of the Issuer or any Restricted Subsidiary (including any Person who becomes a Restricted Subsidiary as a result of such Asset Acquisition) incurring Acquired Indebtedness and also including any Consolidated Cash Flow (including any pro forma expense and cost reductions calculated on a basis consistent with Regulation S-X under the Exchange Act) associated with any such Asset Acquisition) occurring during the Four-Quarter Period or at any time subsequent to the last day of the Four-Quarter Period and on or prior to the Transaction Date, as if such Asset Sale or Asset Acquisition or other disposition (including the incurrence of, or assumption or

166

liability for, any such Indebtedness or Acquired Indebtedness) occurred on the first day of the Four-Quarter Period.

        If the Issuer or any Restricted Subsidiary directly or indirectly guarantees Indebtedness of a third Person, the preceding sentence shall give effect to the incurrence of such guaranteed Indebtedness as if the Issuer or such Restricted Subsidiary had directly incurred or otherwise assumed such guaranteed Indebtedness.

        For purposes of this definition, whenever pro forma effect is to be given to an Asset Acquisition, the amount of income or earnings relating thereto and the amount of Consolidated Interest Expense associated with Indebtedness incurred in connection therewith shall be based upon the reasonable good faith determination of the Chief Financial Officer of the Issuer.

        In calculating Consolidated Interest Expense for purposes of determining the denominator (but not the numerator) of this Consolidated Interest Coverage Ratio:

(1)

interest on outstanding Indebtedness determined on a fluctuating basis as of the Transaction Date and which will continue to be so determined thereafter shall be deemed to have accrued at a fixed rate per annum equal to the rate of interest on this Indebtedness in effect on the Transaction Date;



(2)

if interest on any Indebtedness actually incurred on the Transaction Date may optionally be determined at an interest rate based upon a factor of a prime or similar rate, a eurocurrency interbank offered rate, or other rates, then the interest rate in effect on the Transaction Date will be deemed to have been in effect during the Four-Quarter Period; and



(3)

notwithstanding clause (1) or (2) above, interest on Indebtedness determined on a fluctuating basis, to the extent such interest is covered by agreements relating to Hedging Obligations, shall be deemed to accrue at the rate per annum resulting after giving effect to the operation of these agreements.

        "Consolidated Interest Expense" for any period means the sum, without duplication, of the total interest expense of the Issuer and the Restricted Subsidiaries for such period, determined on a consolidated basis in accordance with GAAP and including without duplication,

(1)

imputed interest on Capitalized Lease Obligations and Attributable Indebtedness,



(2)

commissions, discounts and other fees and charges owed with respect to letters of credit securing financial obligations, bankers' acceptance financing and receivables financings,



(3)

the net costs associated with Hedging Obligations under clause (1) of the definition of such term;provided, however, that the calculation of such costs shall not include the cash settlement amount paid on the early termination of Hedging Obligations terminated prior to March 31, 2003,



(4)

amortization of debt issuance costs, debt discount or premium and other financing fees and expenses, except those incurred in connection with the Notes and the Credit Agreement and except those amortized or written off prior to the Issue Date with respect to Indebtedness no longer outstanding as of the Issue Date,



(5)

the interest portion of any deferred payment obligations,



(6)

all other non-cash interest expense,



(7)

capitalized interest,



(8)

the product of (a) all dividend payments on any series of Disqualified Equity Interests of the Issuer or any Preferred Stock of any Restricted Subsidiary (other than any such Disqualified

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Equity Interests or any Preferred Stock held by the Issuer or a Wholly-Owned Restricted Subsidiary),multiplied by (b) a fraction, the numerator of which is one and the denominator of which is oneminus the lower of the then current combined federal, state and local current or statutory tax rate of the Issuer and the Restricted Subsidiaries, expressed as a decimal,

(9)

all interest payable with respect to discontinued operations, and



(10)

all interest on any Indebtedness of any other Person guaranteed by the Issuer or any Restricted Subsidiary.

        "Consolidated Net Income" for any period means the net income (or loss) of the Issuer and the Restricted Subsidiaries for such period determined on a consolidated basis in accordance with GAAP;provided that there shall be excluded from such net income (to the extent otherwise included therein), without duplication:

(1)

the net income (or loss) of any Person (other than a Restricted Subsidiary) in which any Person other than the Issuer and the Restricted Subsidiaries has an ownership interest, except to the extent that cash in an amount equal to any such income has actually been received by the Issuer or any of its Wholly-Owned Restricted Subsidiaries during such period;



(2)

except to the extent includible in the consolidated net income of the Issuer pursuant to the foregoing clause (1), the net income (or loss) of any Person that accrued prior to the date that (a) such Person becomes a Restricted Subsidiary or is merged into or consolidated with the Issuer or any Restricted Subsidiary or (b) the assets of such Person are acquired by the Issuer or any Restricted Subsidiary;



(3)

the net income of any Restricted Subsidiary during such period to the extent that the declaration or payment of dividends or similar distributions by such Restricted Subsidiary of that income is not permitted by operation of the terms of its charter or any agreement, instrument, judgment, decree, order, statute, rule or governmental regulation applicable to that Subsidiary during such period, except that the Issuer's equity in a net loss of any such Restricted Subsidiary for such period shall be included in determining Consolidated Net Income;



(4)

for the purposes of calculating the Restricted Payments Basket only, in the case of a successor to the Issuer by consolidation, merger or transfer of its assets, any income (or loss) of the successor prior to such merger, consolidation or transfer of assets;



(5)

for purposes of calculating the Restricted Payments Basket only, (y) the sum of (i) any gain recognized on beginning inventory-discretionary volumes, (ii) plus, any net margin recognized on sale of inventory—minimum volumes, (iii) minus, any gain deferred on ending inventory-discretionary volumes, (iv) minus, any lower of cost or market write-downs on base inventory volumes, (v) minus, any lower of cost or market write-downs on inventories-minimum volumes,plus (z) the product of (y) and the Issuer's combined federal and state income tax rate.



(6)

other than for purposes of calculating the Restricted Payments Basket, any gain (or loss), together with any related provisions for taxes on any such gain (or the tax effect of any such loss), realized during such period by the Issuer or any Restricted Subsidiary upon (a) the acquisition of any securities, or the extinguishment of any Indebtedness, of the Issuer or any Restricted Subsidiary or (b) any Asset Sale by the Issuer or any Restricted Subsidiary; and



(7)

other than for purposes of calculating the Restricted Payments Basket, any extraordinary gain (or extraordinary loss), together with any related provision for taxes on any such extraordinary gain (or the tax effect of any such extraordinary loss), realized by the Issuer or any Restricted Subsidiary during such period.

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        In addition any return of capital with respect to an Investment that increased the Restricted Payments Basket pursuant to clause (3)(d) of the first paragraph under "—Certain covenants—Limitations on restricted payments" or decreased the amount of Investments outstanding pursuant to clause (12) of the definition of "Permitted Investments" shall be excluded from Consolidated Net Income for purposes of calculating the Restricted Payments Basket.

        "Consolidated Net Tangible Assets" means, at any date, the total of:

(1)

the total assets of the Issuer and its Restricted Subsidiaries determined in accordance with GAAP on a consolidated basis;minus

(2)

Consolidated Current Liabilities;minus

(3)

all other liabilities of the Issuer and its Restricted Subsidiaries determined in accordance with GAAP on a consolidated basis other than liabilities for Funded Debt;minus

(4)

the amount of intangible assets carried on the balance sheet of the Issuer and its Restricted Subsidiaries determined in accordance with GAAP on a consolidated basis, including goodwill, patents, patent applications, copyrights, trademarks, trade names, research and development expense, organizational expense, annualized debt discount and expense, deferred financing charges and debt acquisition costs;minus

(5)

the amount at which any minority interest in a Restricted Subsidiary appears as a liability on the consolidated balance sheet of the Issuer and its Restricted Subsidiaries.

        "Consolidated Net Worth" means, with respect to any Person as of any date, the consolidated stockholders' equity of such Person, determined on a consolidated basis in accordance with GAAP, less (without duplication) (1) any amounts thereof attributable to Disqualified Equity Interests of such Person or its Subsidiaries or any amount attributable to Unrestricted Subsidiaries and (2) all write-ups (other than write-ups resulting from foreign currency translations and write-ups of tangible assets of a going concern business made within twelve months after the acquisition of such business) subsequent to the Issue Date in the book value of any asset owned by such Person or a Subsidiary of such Person.

        "Coverage Ratio Exception" has the meaning set forth in the proviso in the first paragraph of the covenant described under "—Certain covenants—Limitations on additional indebtedness."

        "Credit Agreement" means the Credit Agreement dated as of February 28, 2003 by and among the Issuer, as Borrower, UBS AG, Stamford Branch, as administrative agent and collateral agent, UBS Warburg LLC, as lead arranger and book manager, and the other lenders named therein, including any notes, guarantees, collateral and security documents, instruments and agreements executed in connection therewith (including Hedging Obligations related to the Indebtedness incurred thereunder), and in each case as amended or refinanced from time to time, including any agreement extending the maturity of, refinancing, replacing or otherwise restructuring (including increasing the amount of borrowings or other Indebtedness outstanding or available to be borrowed thereunder) all or any portion of the Indebtedness under such agreement, and any successor or replacement agreement or agreements with the same or any other agents, creditor, lender or group of creditors or lenders.

        "Custodian" means any receiver, trustee, assignee, liquidator or similar official under any Bankruptcy Law.

        "Default" means (1) any Event of Default or (2) any event, act or condition that, after notice or the passage of time or both, would be an Event of Default.

        "Designated Senior Debt" means (1) Senior Debt Indebtedness under or in respect of the Credit Agreement and (2) any other Indebtedness constituting Senior Debt which, at the time of determination, has an aggregate principal amount of at least $25.0 million and is specifically designated in the instrument evidencing such Senior Debt as "Designated Senior Debt."

169

        "Designation" has the meaning given to this term in the covenant described under "—Certain covenants—Limitations on designation of unrestricted subsidiaries."

        "Designation Amount" has the meaning given to this term in the covenant described under "—Limitations on designation of unrestricted subsidiaries."

        "Disqualified Equity Interests" of any Person means any Equity Interests of such Person that, by its terms, or by the terms of any related agreement or of any security into which it is convertible, putable or exchangeable, is, or upon the happening of any event or the passage of time would be, required to be redeemed by such Person, whether or not at the option of the holder thereof, or matures or is mandatorily redeemable, pursuant to a sinking fund obligation or otherwise, in whole or in part, on or prior to the date which is 91 days after the final maturity date of the Notes;provided,however, that any class of Equity Interests of such Person that, by its terms, authorizes such Person to satisfy in full its obligations with respect to the payment of dividends or upon maturity, redemption (pursuant to a sinking fund or otherwise) or repurchase thereof or otherwise by the delivery of Equity Interests that is not Disqualified Equity Interests, and that is not convertible, puttable or exchangeable for Disqualified Equity Interests or Indebtedness, will not be deemed to be Disqualified Equity Interests so long as such Person satisfies its obligations with respect thereto solely by the delivery of Equity Interests that is not Disqualified Equity Interests;provided,further,however, that any Equity Interests that would not constitute Disqualified Equity Interests but for provisions thereof giving holders thereof (or the holders of any security into or for which such Equity Interests is convertible, exchangeable or exercisable) the right to require the Issuer to redeem such Equity Interests upon the occurrence of a change in control occurring prior to the final maturity date of the Notes shall not constitute Disqualified Equity Interests if the change in control provisions applicable to such Equity Interests are no more favorable to such holders than the provisions described under "—Change of control" and such Equity Interests specifically provides that the Issuer will not redeem any such Equity Interests pursuant to such provisions prior to the Issuer's purchase of the Notes as required pursuant to the provisions described under "—Change of control."

        "Eligible Exchange Contract Balances" means, at any date, the amount of the balance, determined in accordance with prices set forth in the applicable exchange contracts, based on current value on a mark-to-market basis, of any rights of the Issuer and its Restricted Subsidiaries to receive petroleum products, money or other value arising from the trading, lending, borrowing or exchange of petroleum products.

        "Equity Interests" of any Person means (1) any and all shares or other equity interests (including common stock, preferred stock, limited liability company interests and partnership interests) in such Person and (2) all rights to purchase, warrants or options (whether or not currently exercisable), participations or other equivalents of or interests in (however designated) such shares or other interests in such Person.

        "Exchange Act" means the U.S. Securities Exchange Act of 1934, as amended.

        "Fair Market Value" means, with respect to any asset, the price (after taking into account any liabilities relating to such assets) that would be negotiated in an arm's-length transaction for cash between a willing seller and a willing and able buyer, neither of which is under any compulsion to complete the transaction, as such price is determined in good faith by the Board of Directors of the Issuer or a duly authorized committee thereof, as evidenced by a resolution of such Board or committee.

        "Foreign Subsidiary" means any Subsidiary of the Issuer which (i) is not organized under the laws of (x) the United States or any state thereof or (y) the District of Columbia and (ii) conducts substantially all of its business operations outside the United States of America.

170

        "Foreign Trade Regulations" means (a) any act that prohibits or restricts, or empowers the President or any executive agency of the United States of America to prohibit or restrict, exports to or financial transactions with any foreign country or foreign national, (b) the regulations with respect to certain prohibited foreign trade transactions set forth at 22 C.F.R. Parts 120-130 and 31 C.F.R. Part 500 and (c) any order, regulation, ruling, interpretation, direction, instruction or notice relating to any of the foregoing.

        "Funded Debt" means all Indebtedness of the Issuer or other specified Person which is payable more than one year from the date of creation thereof and shall include (a) current maturities of such Indebtedness and (b) all Indebtedness consisting of reimbursement obligations with respect to letters of credit other than letters of credit issued to finance inventory purchases or to secure other debt appearing on the balance sheet of the obligor.

        "GAAP" means generally accepted accounting principles set forth in the opinions and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants and statements and pronouncements of the Financial Accounting Standards Board or in such other statements by such other entity as may be approved by a significant segment of the accounting profession of the United States, as in effect on the Issue Date.

        "guarantee" means a direct or indirect guarantee by any Person of any Indebtedness of any other Person and includes any obligation, direct or indirect, contingent or otherwise, of such Person: (1) to purchase or pay (or advance or supply funds for the purchase or payment of) Indebtedness of such other Person (whether arising by virtue of partnership arrangements, or by agreements to keep-well, to purchase assets, goods, securities or services (unless such purchase arrangements are on arm's-length terms and are entered into in the ordinary course of business), to take-or-pay, or to maintain financial statement conditions or otherwise); or (2) entered into for purposes of assuring in any other manner the obligee of such Indebtedness of the payment thereof or to protect such obligee against loss in respect thereof (in whole or in part). "guarantee," when used as a verb, and "guaranteed" have correlative meanings.

        "Guarantor Senior Debt" means, with respect to any Guarantor, the principal of, premium, if any, and interest (including any interest accruing subsequent to the filing of a petition of bankruptcy at the rate provided for in the documentation with respect thereto, whether or not such interest is an allowed claim under applicable law) on any Indebtedness of such Guarantor, whether outstanding on the Issue Date or thereafter created, incurred or assumed, unless, in the case of any particular Indebtedness, the instrument creating or evidencing the same or pursuant to which the same is outstanding expressly provides that such Indebtedness shall not be senior in right of payment to the Notes.

        Without limiting the generality of the foregoing, "Guarantor Senior Debt" shall also include the principal of, premium, if any, interest (including any interest accruing subsequent to the filing of a petition of bankruptcy at the rate provided for in the documentation with respect thereto, whether or not such interest is an allowed claim under applicable law) on, and all other amounts owing in respect of:

(1)

all monetary obligations of every nature of such Guarantor under, or with respect to, the Credit Agreement, including, without limitation, obligations to pay principal and interest, reimbursement obligations under letters of credit, fees, expenses and indemnities (and guarantees thereof); and



(2)

all Hedging Obligations in respect of the Credit Agreement;

        in each case whether outstanding on the Issue Date or thereafter incurred.

        Notwithstanding the foregoing, "Guarantor Senior Debt" shall not include:

(1)

any Indebtedness of such Guarantor to the Issuer or any of its Subsidiaries;

171

(2)

Indebtedness to, or guaranteed on behalf of, any director, officer or employee of the Issuer or any of its Subsidiaries (including, without limitation, amounts owed for compensation);



(3)

obligations to trade creditors and other amounts incurred (but not under the Credit Agreement) in connection with obtaining goods, materials or services;



(4)

Indebtedness represented by Disqualified Equity Interests;



(5)

any liability for taxes owed or owing by such Guarantor;



(6)

that portion of any Indebtedness incurred in violation of the covenant described under "—Certain covenants—Limitations on additional indebtedness" covenant (but, as to any such obligation, no such violation shall be deemed to exist for purposes of this clause (6) if the holder(s) of such obligation or their representative shall have received an officers' certificate of such Guarantor to the effect that the incurrence of such Indebtedness does not (or, in the case of revolving credit indebtedness, that the incurrence of the entire committed amount thereof at the date on which the initial borrowing thereunder is made would not) violate such provisions of the Indenture);



(7)

Indebtedness which, when incurred and without respect to any election under Section 1111(b) of Title 11, United States Code, is without recourse to such Guarantor; and



(8)

any Indebtedness which is, by its express terms, subordinated in right of payment to any other Indebtedness of such Guarantor.

        "Guarantors" means each Restricted Subsidiary of the Issuer on the Issue Date, and each other Person that is required to become a Guarantor by the terms of the Indenture after the Issue Date, in each case, until such Person is released from its Note Guarantee.

        "Hedging Obligations" of any Person means the obligations of such Person pursuant to (1) any interest rate swap agreement, interest rate collar agreement or other similar agreement or arrangement designed to protect such Person against fluctuations in interest rates or (2) any forward contract, commodity swap agreement, commodity option agreement or other similar agreement.

        "Holder" means any registered holder, from time to time, of the Notes.

        "incur" means, with respect to any Indebtedness or Obligation, incur, create, issue, assume, guarantee or otherwise become directly or, indirectly liable, contingently or otherwise, with respect to such Indebtedness or Obligation;provided that (1) the Indebtedness of a Person existing at the time such Person became a Restricted Subsidiary shall be deemed to have been incurred at such time by such Restricted Subsidiary and (2) neither the accrual of interest nor the accretion of original issue discount shall be deemed to be an incurrence of Indebtedness.

        "Indebtedness" of any Person at any date means, without duplication:

(1)

all liabilities, contingent or otherwise, of such Person for borrowed money (whether or not the recourse of the lender is to the whole of the assets of such Person or only to a portion thereof);



(2)

all obligations of such Person evidenced by bonds, debentures, notes or other similar instruments;



(3)

all obligations of such Person in respect of letters of credit or other similar instruments (or reimbursement obligations with respect thereto);



(4)

all obligations of such Person to pay the deferred and unpaid purchase price of property or services, except trade payables and accrued expenses incurred by such Person in the ordinary course of business in connection with obtaining goods, materials or services;

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(5)

the maximum fixed redemption or repurchase price of all Disqualified Equity Interests of such Person;



(6)

all Capitalized Lease Obligations of such Person;



(7)

all Indebtedness of others secured by a Lien on any asset of such Person, whether or not such Indebtedness is assumed by such Person;



(8)

all Indebtedness of others guaranteed by such Person to the extent of such guarantee;provided that Indebtedness of the Issuer or its Subsidiaries that is guaranteed by the Issuer or the Issuer's Subsidiaries shall only be counted once in the calculation of the amount of Indebtedness of the Issuer and its Subsidiaries on a consolidated basis;



(9)

all Attributable Indebtedness;



(10)

to the extent not otherwise included in this definition, Hedging Obligations of such Person; and



(11)

all obligations of such Person under conditional sale or other title retention agreements relating to assets purchased by such Person.

        Any Indebtedness which is incurred at a discount to the principal amount at maturity thereof shall be deemed to have been incurred at the full principal amount at maturity thereof. The amount of Indebtedness of any Person at any date shall be the outstanding balance at such date of all unconditional obligations as described above, the maximum liability of such Person for any such contingent obligations at such date and, in the case of clause (7), the lesser of (a) the Fair Market Value of any asset subject to a Lien securing the Indebtedness of others on the date that the Lien attaches and (b) the amount of the Indebtedness secured. For purposes of clause (5), the "maximum fixed redemption or repurchase price" of any Disqualified Equity Interests that do not have a fixed redemption or repurchase price shall be calculated in accordance with the terms of such Disqualified Equity Interests as if such Disqualified Equity Interests were redeemed or repurchased on any date on which an amount of Indebtedness outstanding shall be required to be determined pursuant to the Indenture.

        "Independent Director" means a director of the Issuer who

(1)

is independent with respect to the transaction at issue;



(2)

does not have any material financial interest in the Issuer or any of its Affiliates (other than as a result of holding securities of the Issuer); and



(3)

has not and whose Affiliates or affiliated firm has not, at any time during the twelve months prior to the taking of any action hereunder, directly or indirectly, received, or entered into any understanding or agreement to receive, any compensation, payment or other benefit, of any type or form, from the Issuer or any of its Affiliates, other than customary directors' fees, stock option grants or other compensation for serving on the Board of Directors of the Issuer or any Affiliate and reimbursement of out-of-pocket expenses for attendance at the Issuer's or Affiliate's board and board committee meetings.

        "Independent Financial Advisor" means an accounting, appraisal or investment banking firm of nationally recognized standing that is, in the reasonable judgment of the Issuer's Board of Directors, qualified to perform the task for which it has been engaged and disinterested and independent with respect to the Issuer and its Affiliates.

        "interest" means, with respect to the Notes, interest and Additional Interest, if any, on the Notes.

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        "Inventory" means, at any date, the Fair Market Value of all inventory of refined petroleum products owned by the Issuer or any of its Restricted Subsidiaries (including discretionary and minimum volumes), and which meets all of the following requirements:

(1)

is in good saleable condition, is not deteriorating in quality and is not obsolete;



(2)

is physically located within the United States of America; and



(3)

has not been placed on consignment.

        "Investments" of any Person means:

(1)

all direct or indirect investments by such Person in any other Person in the form of loans, advances or capital contributions or other credit extensions constituting Indebtedness of such other Person, and any guarantee of Indebtedness of any other Person;



(2)

all purchases (or other acquisitions for consideration) by such Person of Indebtedness, Equity Interests or other securities of any other Person;



(3)

all other items that would be classified as investments (including purchases of assets outside the ordinary course of business) on a balance sheet of such Person prepared in accordance with GAAP; and



(4)

the Designation of any Subsidiary as an Unrestricted Subsidiary.

        Except as otherwise expressly specified in this definition, the amount of any Investment (other than an Investment made in cash) shall be the Fair Market Value thereof on the date such Investment is made. The amount of Investment pursuant to clause (4) shall be the Designation Amount determined in accordance with the covenant described under "—Certain covenants—Limitations on designation of unrestricted subsidiaries." If the Issuer or any Subsidiary sells or otherwise disposes of any Equity Interests of any direct or indirect Subsidiary such that, after giving effect to any such sale or disposition, such Person is no longer a Subsidiary, the Issuer shall be deemed to have made an Investment on the date of any such sale or other disposition equal to the Fair Market Value of the Equity Interests of and all other Investments in such Subsidiary not sold or disposed of, which amount shall be determined by the Board of Directors. The acquisition by the Issuer or any Restricted Subsidiary of a Person that holds an Investment in a third Person shall be deemed to be an Investment by the Issuer or such Restricted Subsidiary in the third Person in an amount equal to the Fair Market Value of the Investment held by the acquired Person in the third Person. Notwithstanding the foregoing, purchases or redemptions of Equity Interests of the Issuer shall be deemed not to be Investments.

        "Issue Date" means the date on which the Notes are originally issued.

        "Lien" means, with respect to any asset, any mortgage, deed of trust, lien (statutory or other), pledge, lease, easement, restriction, covenant, charge, security interest or other encumbrance of any kind or nature in respect of such asset, whether or not filed, recorded or otherwise perfected under applicable law, including any conditional sale or other title retention agreement, and any lease in the nature thereof, any option or other agreement to sell, and any filing of, or agreement to give, any financing statement under the Uniform Commercial Code (or equivalent statutes) of any jurisdiction (other than cautionary filings in respect of operating leases).

        "Moody's" means Moody's Investors Service, Inc., and its successors.

        "Net Available Proceeds" means, with respect to any Asset Sale, the proceeds thereof in the form of cash or Cash Equivalents, net of

(1)

brokerage commissions and other fees and expenses (including fees and expenses of legal counsel, accountants and investment banks) of such Asset Sale;

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(2)

provisions for taxes payable as a result of such Asset Sale (after taking into account any available tax credits or deductions and any tax sharing arrangements);



(3)

amounts required to be paid to any Person (other than the Issuer or any Restricted Subsidiary) owning a beneficial interest in the assets subject to the Asset Sale or having a Lien thereon;



(4)

payments of unassumed liabilities (not constituting Indebtedness) relating to the assets sold at the time of, or within 30 days after the date of, such Asset Sale; and



(5)

appropriate amounts to be provided by the Issuer or any Restricted Subsidiary, as the case may be, as a reserve required in accordance with GAAP against any liabilities associated with such Asset Sale and retained by the Issuer or any Restricted Subsidiary, as the case may be, after such Asset Sale, including pensions and other postemployment benefit liabilities, liabilities related to environmental matters and liabilities under any indemnification obligations associated with such Asset Sale, all as reflected in an Officers' Certificate delivered to the Trustee;provided,however, that any amounts remaining after adjustments, revaluations or liquidations of such reserves shall constitute Net Available Proceeds.

        "Non-Recourse Debt" means Indebtedness of an Unrestricted Subsidiary:

(1)

as to which neither the Issuer nor any Restricted Subsidiary (a) provides credit support of any kind (including any undertaking, agreement or instrument that would constitute Indebtedness), (b) is directly or indirectly liable as a guarantor or otherwise, or (c) constitutes the lender; and



(2)

no default with respect to which (including any rights that the holders thereof may have to take enforcement action against an Unrestricted Subsidiary) would permit upon notice, lapse of time or both any holder of any other Indebtedness (other than the Notes) of the Issuer or any Restricted Subsidiary to declare a default on the other Indebtedness or cause the payment thereof to be accelerated or payable prior to its stated maturity.

        "Obligation" means any principal, interest, penalties, fees, indemnification, reimbursements, costs, expenses, damages and other liabilities payable under the documentation governing any Indebtedness.

        "Officer" means any of the following of the Issuer: the Chairman of the Board of Directors, the Chief Executive Officer, the Chief Financial Officer, the President, any Vice President, the Treasurer or the Secretary.

        "Officers' Certificate" means a certificate signed by two Officers.

        "Pari Passu Indebtedness" means any Indebtedness of the Issuer or any Guarantor that rankspari passu as to payment with the Notes or the Note Guarantees, as applicable.

        "Permitted Business" means the businesses and joint ventures engaged in by the Issuer and its Subsidiaries on the Issue Date as described in this prospectus and businesses and joint ventures that are reasonably related thereto or reasonable extensions thereof.

        "Permitted Investment" means:

(1)

Investments by the Issuer or any Restricted Subsidiary in (a) any Restricted Subsidiary or (b) in any Person that is or will become immediately after such Investment a Restricted Subsidiary or that will merge or consolidate into the Issuer or a Restricted Subsidiary;



(2)

Investments in the Issuer by any Restricted Subsidiary;



(3)

loans and advances made in the ordinary course of business to directors, employees and officers of the Issuer and the Restricted Subsidiaries for bona fide business purposes not in excess of $3.0 million at any one time outstanding;

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(4)

Hedging Obligations incurred pursuant to clause (4) of the second paragraph under the covenant described under "—Certain covenants—Limitations on additional indebtedness";



(5)

cash or Cash Equivalents;



(6)

receivables owing to the Issuer or any Restricted Subsidiary if created or acquired in the ordinary course of business and payable or dischargeable in accordance with customary trade terms;provided,however, that such trade terms may include such concessionary trade terms as the Issuer or any such Restricted Subsidiary deems reasonable under the circumstances;



(7)

Investments in securities of trade creditors or customers received pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of such trade creditors or customers;



(8)

Investments made by the Issuer or any Restricted Subsidiary as a result of consideration received in connection with an Asset Sale made in compliance with the covenant described under "—Certain covenants—Limitations on asset sales";



(9)

lease, utility and other similar deposits in the ordinary course of business;



(10)

Investments made by the Issuer or a Restricted Subsidiary for consideration consisting only of Qualified Equity Interests of the Issuer or the proceeds thereof;provided, that such proceeds do not increase the Restricted Payments Basket;



(11)

stock, obligations or securities received in settlement of debts created in the ordinary course of business and owing to the Issuer or any Restricted Subsidiary or in satisfaction of judgments;



(12)

Investments made by the Issuer or a Restricted Subsidiary in a Permitted Business reasonably related to the businesses currently operated by the Issuer or such Restricted Subsidiary, not to exceed $25.0 million at any one time outstanding; and



(13)

other Investments in an aggregate amount not to exceed $15.0 million at any one time outstanding (with each Investment being valued as of the date made and without regard to subsequent changes in value).

        The amount of Investments outstanding at any time pursuant to clause (12) above shall be deemed to be reduced:

(a)

upon the disposition or repayment of or return on any Investment made pursuant to clause (12) above, by an amount equal to the return of capital with respect to such Investment to the Issuer or any Restricted Subsidiary (to the extent not included in the computation of Consolidated Net Income), less the cost of the disposition of such Investment and net of taxes; and



(b)

upon a Redesignation of an Unrestricted Subsidiary as a Restricted Subsidiary, by an amount equal to the lesser of (x) the Fair Market Value of the Issuer's proportionate interest in such Subsidiary immediately following such Redesignation, and (y) the aggregate amount of Investments in such Subsidiary that increased (and did not previously decrease) the amount of Investments outstanding pursuant to clause (12) above.

        "Permitted Junior Securities" means:

(1)

Equity Interests in the Issuer or any Guarantor; or



(2)

debt securities that are subordinated to (a) all Senior Debt and Guarantor Senior Debt and (b) any debt securities issued in exchange for Senior Debt to substantially the same extent as,

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or to a greater extent than, the Notes and the Note Guarantees are subordinated to Senior Debt and Guarantor Senior Debt under the Indenture.

        "Permitted Liens" means the following types of Liens:

(1)

Liens for taxes, assessments or governmental charges or claims either (a) not delinquent or (b) contested in good faith by appropriate proceedings and as to which the Issuer or the Restricted Subsidiaries shall have set aside on its books such reserves as may be required pursuant to GAAP;



(2)

statutory, contractual or common law Liens of landlords and Liens of carriers, warehousemen, mechanics, suppliers, materialmen, repairmen and other Liens imposed by law incurred in the ordinary course of business for sums not yet delinquent for a period of more than 30 days or are being contested in good faith, and as to which the Issuer or the Restricted Subsidiaries shall have set aside on its books such reserves as may be required pursuant to GAAP;



(3)

Liens incurred or deposits made in the ordinary course of business in connection with workers' compensation, unemployment insurance and other types of social security, or to secure the performance of tenders, statutory obligations, surety and appeal bonds, bids, leases, government contracts, performance and return-of-money bonds and other similar obligations (exclusive of obligations for the payment of borrowed money);



(4)

Liens upon specific items of inventory or other goods and proceeds of any Person securing such Person's obligations in respect of bankers' acceptances issued or created for the account of such Person to facilitate the purchase, shipment or storage of such inventory or other goods;



(5)

judgment Liens not giving rise to a Default so long as such Liens are adequately bonded and any appropriate legal proceedings which may have been duly initiated for the review of such judgment have not been finally terminated or the period within which the proceedings may be initiated has not expired;



(6)

easements, rights-of-way, zoning restrictions and other similar charges, restrictions or encumbrances in respect of real property or immaterial imperfections of title which do not, in the aggregate, impair in any material respect the ordinary conduct of the business of the Issuer and the Restricted Subsidiaries taken as a whole;



(7)

Liens securing reimbursement obligations with respect to commercial letters of credit which encumber documents and other assets relating to such letters of credit and products and proceeds thereof;



(8)

Liens encumbering deposits made to secure obligations arising from statutory, regulatory, contractual or warranty requirements of the Issuer or any Restricted Subsidiary, including rights of offset and setoff;



(9)

bankers' Liens, rights of setoff and other similar Liens existing solely with respect to cash and Cash Equivalents on deposit in one or more of accounts maintained by the Issuer or any Restricted Subsidiary, in each case granted in the ordinary course of business in favor of the bank or banks with which such accounts are maintained, securing amounts owing to such bank with respect to cash management and operating account arrangements, including those involving pooled accounts and netting arrangements;provided that in no case shall any such Liens secure (either directly or indirectly) the repayment of any Indebtedness;



(10)

leases or subleases granted to others that do not materially interfere with the ordinary course of business of the Issuer or any Restricted Subsidiary;



(11)

Liens arising from filing Uniform Commercial Code financing statements regarding leases;

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(12)

Liens securing all of the Notes and Liens securing any Note Guarantee;



(13)

Liens securing Senior Debt or Guarantor Senior Debt;



(14)

Liens existing on the Issue Date;



(15)

Liens in favor of the Issuer or a Guarantor;



(16)

Liens securing Indebtedness under the Credit Agreement;



(17)

Liens securing Purchase Money Indebtedness;



(18)

Liens securing Acquired Indebtedness permitted to be incurred under the Indenture;provided that the Liens do not extend to assets not subject to such Lien at the time of acquisition (other than improvements thereon) and are no more favorable to the lienholders than those securing such Acquired Indebtedness prior to the incurrence of such Acquired Indebtedness by the Issuer or a Restricted Subsidiary;



(19)

Liens on assets of a Person existing at the time such Person is acquired or merged with or into or consolidated with the Issuer or any such Restricted Subsidiary (and not created in anticipation or contemplation thereof);



(20)

Liens to secure Refinancing Indebtedness of Indebtedness secured by Liens referred to in the foregoing clauses (13), (14), (16), (17), (18), (19), (21) and (22);provided that in each case such Liens do not extend to any additional assets (other than improvements thereon and replacements thereof);



(21)

Liens (a) to secure Attributable Indebtedness;provided that any such Lien shall not extend to or cover any assets of the Issuer or any Restricted Subsidiary other than the assets which are the subject of the Sale and Leaseback Transaction in which the Attributable Indebtedness is incurred or (b) arising in connection with Capitalized Leases; Description of the notes



(22)

Liens securing Indebtedness in respect of commodities margin loans permitted under clause (11) of the definition of Permitted Indebtedness contained in the covenant "—Limitations on additional indebtedness."



(23)

Restrictions under Foreign Trade Regulations on the transfer or licensing of assets of the Issuer or its Restricted Subsidiaries; and



(24)

Liens incurred in the ordinary course of business of the Issuer or any Restricted Subsidiary with respect to obligations (other than Indebtedness) that do not in the aggregate exceed $10.0 million at any one time outstanding.

        "Person" means any individual, corporation, partnership, limited liability company, joint venture, incorporated or unincorporated association, joint-stock company, trust, unincorporated organization or government or other agency or political subdivision thereof or other entity of any kind.

        "Plan of Liquidation" with respect to any Person, means a plan that provides for, contemplates or the effectuation of which is preceded or accompanied by (whether or not substantially contemporaneously, in phases or otherwise): (1) the sale, lease, conveyance or other disposition of all or substantially all of the assets of such Person otherwise than as an entirety or substantially as an entirety; and (2) the distribution of all or substantially all of the proceeds of such sale, lease, conveyance or other disposition of all or substantially all of the remaining assets of such Person to holders of Equity Interests of such Person.

        "Preferred Stock" means, with respect to any Person, any and all preferred or preference stock or other equity interests (however designated) of such Person whether now outstanding or issued after the Issue Date.

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        "principal" means, with respect to the Notes, the principal of, and premium, if any, on the Notes.

        "Purchase Money Indebtedness" means Indebtedness, including Capitalized Lease Obligations, of the Issuer or any Restricted Subsidiary incurred for the purpose of financing all or any part of the purchase price of property, plant or equipment used in the business of the Issuer or any Restricted Subsidiary or the cost of installation, construction or improvement thereof;provided,however, that (1) the amount of such Indebtedness shall not exceed such purchase price or cost, (2) such Indebtedness shall not be secured by any asset other than the specified asset being financed or, in the case of real property or fixtures, including additions and improvements, the real property to which such asset is attached and (3) such Indebtedness shall be incurred within 180 days after such acquisition of such asset by the Issuer or such Restricted Subsidiary or such installation, construction or improvement.

        "Qualified Equity Interests" means Equity Interests of the Issuer other than Disqualified Equity Interests;provided that such Equity Interests shall not be deemed Qualified Equity Interests to the extent sold or owed to a Subsidiary of the Issuer or financed, directly or indirectly, using funds (1) borrowed from the Issuer or any Subsidiary of the Issuer until and to the extent such borrowing is repaid or (2) contributed, extended, guaranteed or advanced by the Issuer or any Subsidiary of the Issuer (including, without limitation, in respect of any employee stock ownership or benefit plan).

        "Qualified Equity Offering" means the issuance and sale of Qualified Equity Interests of the Issuer to any Person other than a Subsidiary of the Issuer.

        "Receivables" means, at any date, the aggregate amount (without duplication) of all accounts receivable carried on the books of the Issuer and its Restricted Subsidiaries in accordance with GAAP on a consolidated basis arising in the ordinary course of business,less all reserves with respect to such accounts receivable and less any and all offsets, counterclaims or contras in respect thereof (including the amount of any account payable (including any uninvoiced account payable) or other liability owed by the Issuer or any of its Restricted Subsidiaries to the account debtor on such account receivable, whether or not a specific netting agreement may exist).

        "redeem" means to redeem, repurchase, purchase, defease, retire, discharge or otherwise acquire or retire for value; and "redemption" shall have a correlative meaning; provided that this definition shall not apply for purposes of "—Optional redemption."

        "Redesignation" has the meaning given to such term in the covenant described under "—Certain covenants—Limitations on designation of unrestricted subsidiaries."

        "refinance" means to refinance, repay, prepay, replace, renew or refund.

        "Refinancing Indebtedness" means Indebtedness of the Issuer or a Restricted Subsidiary issued in exchange for, or the proceeds from the issuance and sale or disbursement of which are used substantially concurrently to redeem or refinance in whole or in part, any Indebtedness of the Issuer or any Restricted Subsidiary (the "Refinanced Indebtedness") in a principal amount not in excess of the principal amount plus accrued interest, penalties and other costs of retiring the Refinanced Indebtedness so repaid or amended and the costs of issuance of such Refinancing Indebtedness (or, if such Refinancing Indebtedness refinances Indebtedness under a revolving credit facility or other agreement providing a commitment for subsequent borrowings, with a maximum commitment not to exceed the maximum commitment under such revolving credit facility or other agreement);provided that:

(1)

the Refinancing Indebtedness is the obligation of the same Person as that of the Refinanced Indebtedness;



(2)

if the Refinanced Indebtedness was subordinated to orpari passu with the Notes or the Note Guarantees, as the case may be, then such Refinancing Indebtedness, by its terms, is expresslypari passu with (in the case of Refinanced Indebtedness that waspari passu with) or

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subordinate in right of payment to (in the case of Refinanced Indebtedness that was subordinated to) the Notes or the Note Guarantees, as the case may be, at least to the same extent as the Refinanced Indebtedness;

(3)

the Refinancing Indebtedness is scheduled to mature either (a) no earlier than the Refinanced Indebtedness being repaid or amended or (b) after the maturity date of the Notes;



(4)

the portion, if any, of the Refinancing Indebtedness that is scheduled to mature on or prior to the maturity date of the Notes has a Weighted Average Life to Maturity at the time such Refinancing Indebtedness is incurred that is equal to or greater than the Weighted Average Life to Maturity of the portion of the Refinanced Indebtedness being repaid that is scheduled to mature on or prior to the maturity date of the Notes; and



(5)

the Refinancing Indebtedness is secured only to the extent, if at all, and by the assets, that the Refinanced Indebtedness being repaid or amended is secured.

        "Representative" means any agent or representative in respect of any Designated Senior Debt;provided that if, and for so long as, any Designated Senior Debt lacks such representative, then the Representative for such Designated Senior Debt shall at all times constitute the holders of a majority in outstanding principal amount of such Designated Senior Debt.

        "Restricted Payment" means any of the following:

(1)

the declaration or payment of any dividend or any other distribution on Equity Interests of the Issuer or any Restricted Subsidiary or any payment made to the direct or indirect holders (in their capacities a such) of Equity Interests of the Issuer or any Restricted Subsidiary, including, without limitation, any payment in connection with any merger or consolidation involving the Issuer but excluding (a) dividends or distributions payable solely in Qualified Equity Interests and (b) in the case of Restricted Subsidiaries, dividends or distributions payable to the Issuer or to a Restricted Subsidiary and pro rata dividends or distributions payable to minority stockholders of any Restricted Subsidiary;



(2)

the redemption of any Equity Interests of the Issuer or any Restricted Subsidiary, including, without limitation, any payment in connection with any merger or consolidation involving the Issuer but excluding any such Equity Interests held by the Issuer or any Restricted Subsidiary;



(3)

any Investment other than a Permitted Investment; or



(4)

any redemption prior to the scheduled maturity or prior to any scheduled repayment of principal or sinking fund payment, as the case may be, in respect of Subordinated Indebtedness.

        "Restricted Payments Basket" has the meaning given to such term in the first paragraph of the covenant described under "—Certain covenants—Limitations on restricted payments."

        "Restricted Subsidiary" means any Subsidiary of the Issuer other than an Unrestricted Subsidiary.

        "S&P" means Standard & Poor's Ratings Services, a division of the McGraw-Hill Companies, Inc., and its successors.

        "SEC" means the U.S. Securities and Exchange Commission.

        "Sale and Leaseback Transactions" means with respect to any Person an arrangement with any bank, insurance company or other lender or investor or to which such lender or investor is a party, providing for the leasing by such Person of any asset of such Person which has been or is being sold or transferred by such Person to such lender or investor or to any Person to whom funds have been or are to be advanced by such lender or investor on the security of such asset;provided that a sale of a terminal or other facility shall not be deemed to constitute a Sale and Leaseback Transaction solely

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because the Issuer or any of its Subsidiaries agree in connection with such sale to use such terminal or other facility at specified minimum levels unless such arrangement results in the transaction being treated as a Capitalized Lease.

        "Secretary's Certificate" means a certificate signed by the Secretary of the Issuer.

        "Securities Act" means the U.S. Securities Act of 1933, as amended.

        "Senior Debt" means the principal of, premium, if any, and interest (including any interest accruing subsequent to the filing of a petition of bankruptcy at the rate provided for in the documentation with respect thereto, whether or not such interest is an allowed claim under applicable law) on any Indebtedness of the Issuer, whether outstanding on the Issue Date or thereafter created, incurred or assumed, unless, in the case of any particular Indebtedness, the instrument creating or evidencing the same or pursuant to which the same is outstanding expressly provides that such Indebtedness shall not be senior in right of payment to the Notes.

        Without limiting the generality of the foregoing, "Senior Debt" shall also include the principal of, premium, if any, interest (including any interest accruing subsequent to the filing of a petition of bankruptcy at the rate provided for in the documentation with respect thereto, whether or not such interest is an allowed claim under applicable law) on, and all other amounts owing in respect of:

(1)

all monetary obligations of every nature under, or with respect to, the Credit Agreement, including, without limitation, obligations to pay principal and interest, reimbursement obligations under letters of credit, fees, expenses and indemnities (and guarantees thereof); and



(2)

all Hedging Obligations in respect of the Credit Agreement; in each case whether outstanding on the Issue Date or thereafter incurred.

        Notwithstanding the foregoing, "Senior Debt" shall not include:

(1)

any Indebtedness of the Issuer to any of its Subsidiaries;



(2)

Indebtedness to, or guaranteed on behalf of, any director, officer or employee of the Issuer or any of its Subsidiaries (including, without limitation, amounts owed for compensation);



(3)

obligations to trade creditors and other amounts incurred (but not under the Credit Agreement) in connection with obtaining goods, materials or services;



(4)

Indebtedness represented by Disqualified Equity Interests;



(5)

any liability for taxes owed or owing by the Issuer;



(6)

that portion of any Indebtedness incurred in violation of the "Limitations on additional indebtedness" covenant (but, as to any such obligation, no such violation shall be deemed to exist for purposes of this clause (6) if the holder(s) of such obligation or their representative shall have received an Officers' Certificate of the Issuer to the effect that the incurrence of such Indebtedness does not (or, in the case of revolving credit indebtedness, that the incurrence of the entire committed amount thereof at the date on which the initial borrowing thereunder is made would not) violate such provisions of the Indenture);



(7)

Indebtedness which, when incurred and without respect to any election under Section 1111(b) of Title 11, United States Code, is without recourse to the Issuer; and



(8)

any Indebtedness which is, by its express terms, subordinated in right of payment to any other Indebtedness of the Issuer.

        "Series A Convertible Preferred Stock" means the Series A Convertible Preferred Stock, par value $.01 per share, issued by the Company on or after March 25, 1999 in the aggregate initial amount of

181

up to 200,000 shares having an initial liquidation value of $1,000 per share and any additional shares of such series of convertible preferred stock issued as or in lieu of dividends thereon.

        "Series B Convertible Preferred Stock" means the Series B Convertible Preferred Stock, par value $.01 per share, issued by the Company on or after June 27, 2002 in the aggregate initial amount of up to 100,000 shares having an initial liquidation value of $1,000 per share and any additional shares of such series of convertible preferred stock issued as or in lieu of dividends thereon.

        "Significant Subsidiary" means (1) any Restricted Subsidiary that would be a "significant subsidiary" as defined in Regulation S-X promulgated pursuant to the Securities Act as such Regulation is in effect on the Issue Date and (2) any Restricted Subsidiary that, when aggregated with all other Restricted Subsidiaries that are not otherwise Significant Subsidiaries and as to which any event described in clause (7) or (8) under "—Events of default" has occurred and is continuing, would constitute a Significant Subsidiary under clause (1) of this definition.

        "Subordinated Indebtedness" means Indebtedness of the Issuer or any Restricted Subsidiary that is subordinated in right of payment to the Notes or the Note Guarantees, respectively.

        "Subsidiary" means, with respect to any Person:

(1)

any corporation, limited liability company, association or other business entity of which more than 50% of the total voting power of the Equity Interests entitled (without regard to the occurrence of any contingency) to vote in the election of the Board of Directors thereof are at the time owned or controlled, directly or indirectly, by such Person or one or more of the other Subsidiaries of that Person (or a combination thereof); and



(2)

any partnership (a) the sole general partner or the managing general partner of which is such Person or a Subsidiary of such Person or (b) the only general partners of which are such Person or of one or more Subsidiaries of such Person (or any combination thereof).

        Unless otherwise specified, "Subsidiary" refers to a Subsidiary of the Issuer.

        "Treasury Rate" means the yield to maturity at the time of computation of United States Treasury securities with a constant maturity (as compiled and published in the most recent Federal Reserve Statistical Release H.15(519) which has become publicly available at least two Business Days prior to the date fixed for redemption or, in the case of defeasance, prior to the date of deposit (or, if such Statistical Release is no longer published, any publicly available source of similar market data)) most nearly equal to the then remaining average life to June 1, 2007 or, in the case of defeasance, to maturity;provided,however, that if the average life to June 1, 2007 or maturity, as the case may be, of the Notes is not equal to the constant maturity of a United States Treasury security for which a weekly average yield is given, the Treasury Rate shall be obtained by linear interpolation (calculated to the nearest one-twelfth of a year) from the weekly average yields of United States Treasury securities for which such yields are given, except that if the average life to June 1, 2007 or maturity, as the case may be, of the Notes is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year shall be used.

        "Trust Indenture Act" means the Trust Indenture Act of 1939, as amended.

        "Unrestricted Subsidiary" means (1) any Subsidiary that at the time of determination shall be designated an Unrestricted Subsidiary by the Board of Directors of the Issuer in accordance with the covenant described under "—Certain covenants—Limitations on designation of unrestricted subsidiaries" and (2) any Subsidiary of an Unrestricted Subsidiary.

        "U.S. Government Obligations" means direct non-callable obligations of, or obligations guaranteed by, the United States of America for the payment of which guarantee or obligations the full faith and credit of the United States is pledged.

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        "Voting Stock" with respect to any Person, means securities of any class of Equity Interests of such Person entitling the holders thereof (whether at all times or only so long as no senior class of stock or other relevant equity interest has voting power by reason of any contingency) to vote in the election of members of the Board of Directors of such Person.

        "Weighted Average Life to Maturity" when applied to any Indebtedness at any date, means the number of years obtained by dividing (1) the sum of the products obtained by multiplying (a) the amount of each then remaining installment, sinking fund, serial maturity or other required payment of principal, including payment at final maturity, in respect thereof by (b) the number of years (calculated to the nearest one-twelfth) that will elapse between such date and the making of such payment by (2) the then outstanding principal amount of such Indebtedness.

        "Wholly-Owned Restricted Subsidiary" means a Restricted Subsidiary of which 100% of the Equity Interests (except for directors' qualifying shares or certain minority interests owned by other Persons solely due to local law requirements that there be more than one stockholder, but which interest is not in excess of what is required for such purpose) are owned directly by the Issuer or through one or more Wholly-Owned Restricted Subsidiaries.

Book-entry, delivery and form of securities

        The Notes will be represented by one or more global notes (the "Global Notes") in definitive form. The Global Notes will be deposited on the Issue Date with, or on behalf of, DTC and registered in the name of Cede & Co., as nominee of DTC (such nominee being referred to herein as the "Global Note Holder"). The Global Notes will be subject to certain restrictions on transfer and will bear the legend regarding these restrictions set forth under the heading "Notice to Investors." DTC will maintain the Notes in denominations of $1,000 and integral multiples thereof through its book-entry facilities.

        DTC has advised the Issuer as follows:

        DTC is a limited-purpose trust company that was created to hold securities for its participating organizations, including Euroclear and Clearstream (collectively, the "Participants" or the "Depositary's Participants"), and to facilitate the clearance and settlement of transactions in these securities between Participants through electronic book-entry changes in accounts of its Participants. The Depositary's Participants include securities brokers and dealers (including the initial purchaser), banks and trust companies, clearing corporations and certain other organizations. Access to DTC's system is also available to other entities such as banks, brokers, dealers and trust companies (collectively, the "Indirect Participants" or the "Depositary's Indirect Participants") that clear through or maintain a custodial relationship with a Participant, either directly or indirectly. Persons who are not Participants may beneficially own securities held by or on behalf of DTC only through the Depositary's Participants or the Depositary's Indirect Participants. Pursuant to procedures established by DTC, ownership of the Notes will be shown on, and the transfer of ownership thereof will be effected only through, records maintained by DTC (with respect to the interests of the Depositary's Participants) and the records of the Depositary's Participants (with respect to the interests of the Depositary's Indirect Participants).

        The laws of some states require that certain persons take physical delivery in definitive form of securities that they own. Consequently, the ability to transfer the Notes will be limited to such extent.

        So long as the Global Note Holder is the registered owner of any Notes, the Global Note Holder will be considered the sole Holder of outstanding Notes represented by such Global Notes under the Indenture. Except as provided below, owners of Notes will not be entitled to have Notes registered in their names and will not be considered the owners or holders thereof under the Indenture for any purpose, including with respect to the giving of any directions, instructions, or approvals to the Trustee

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thereunder. None of the Issuer, the Guarantors or the Trustee will have any responsibility or liability for any aspect of the records relating to or payments made on account of Notes by DTC, or for maintaining, supervising or reviewing any records of DTC relating to such Notes.

        Payments in respect of the principal of, premium, if any, and interest on any Notes registered in the name of a Global Note Holder on the applicable record date will be payable by the Trustee to or at the direction of such Global Note Holder in its capacity as the registered holder under the Indenture. Under the terms of the Indenture, the Issuer and the Trustee may treat the persons in whose names any Notes, including the Global Notes, are registered as the owners thereof for the purpose of receiving such payments and for any and all other purposes whatsoever. Consequently, neither the Issuer or the Trustee has or will have any responsibility or liability for the payment of such amounts to beneficial owners of Notes (including principal, premium, if any, and interest). The Issuer believes, however, that it is currently the policy of DTC to immediately credit the accounts of the relevant Participants with such payments, in amounts proportionate to their respective beneficial interests in the relevant security as shown on the records of DTC. Payments by the Depositary's Participants and the Depositary's Indirect Participants to the beneficial owners of Notes will be governed by standing instructions and customary practice and will be the responsibility of the Depositary's Participants or the Depositary's Indirect Participants.

        Subject to certain conditions, any person having a beneficial interest in the Global Notes may, upon request to the Trustee and confirmation of such beneficial interest by the Depositary or its Participants or Indirect Participants, exchange such beneficial interest for Notes in definitive form. Upon any such issuance, the Trustee is required to register such Notes in the name of and cause the same to be delivered to, such person or persons (or the nominee of any thereof). Such Notes would be issued in fully registered form and would be subject to the legal requirements described in this prospectus under the caption "Notice to Investors." In addition, if (1) the Depositary notifies the Issuer in writing that DTC is no longer willing or able to act as a depositary and the Issuer is unable to locate a qualified successor within 90 days or (2) the Issuer, at its option, notifies the Trustee in writing that it elects to cause the issuance of Notes in definitive form under the Indenture, then, upon surrender by the relevant Global Note Holder of its Global Note, Notes in such form will be issued to each person that such Global Note Holder and DTC identifies as being the beneficial owner of the related Notes.

        Neither the Issuer nor the Trustee will be liable for any delay by the Global Note Holder or DTC in identifying the beneficial owners of Notes and the Issuer and the Trustee may conclusively rely on, and will be protected in relying on, instructions from the Global Note Holder or DTC for all purposes.

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CERTAIN UNITED STATES FEDERAL INCOME TAX CONSEQUENCES

        The following general discussion summarizes certain material U.S. federal income tax consequences to original investors in the notes who exchange old notes for exchange notes pursuant to the exchange offer. This discussion is limited to original investors who were initial purchasers of the old notes that purchased the old notes at the offering price. This summary is based on the Internal Revenue Code of 1986, as amended, or the "Internal Revenue Code," Treasury Regulations promulgated under the Internal Revenue Code, administrative positions of the Internal Revenue Service, or the "IRS," and judicial decisions now in effect, all of which are subject to change (possibly with retroactive effect) or to different interpretations.

        We have not sought a ruling from the IRS with respect to the U.S. federal income tax consequences of acquiring, holding or disposing of a note or of the exchange offer. We cannot assure you that the IRS will not challenge one or more of the conclusions described herein.

        This discussion does not purport to deal with all aspects of U.S. federal income taxation that may be relevant to a particular holder in light of the holder's circumstances (for example, a person subject to the alternative minimum tax provisions of the Internal Revenue Code). This discussion does not address the U.S. federal income tax consequences to investors subject to special treatment under the federal income tax laws, such as partnerships or other pass-through entities, dealers in securities or foreign currency, traders who elect to mark the notes to market, tax-exempt entities, banks, thrifts, insurance companies, persons holding a note as part of a "straddle," "hedge," "conversion transaction" or other risk reduction transaction, investors in partnerships or other pass-through entities, and persons that have a functional currency other than the U.S. dollar.

        This discussion does not address any aspect of state, local or foreign law, or U.S. federal estate and gift tax law other than U.S. federal estate tax law as applicable to a non-U.S. Holder. In addition this discussion is limited to a beneficial owner of the note who purchased the note pursuant to the initial offering thereof at the initial issue price and holds the note as a "capital asset" within the meaning of Section 1221 of the Internal Revenue Code.

        For purposes of this discussion, a "U.S. Holder" is a beneficial owner of a note who is (i) a citizen or resident (as defined in Section 7701(b) of the Internal Revenue Code) of the United States, (ii) a corporation (or an entity treated as a corporation) created or organized in the United States or a political subdivision thereof, (iii) an estate the income of which is subject to U.S. federal income taxation regardless of source or (iv) a trust if a U.S. court is able to exercise primary supervision over the administration of the trust and one or more U.S. persons have the authority to control all substantial decisions of the trust. A "Non-U.S. Holder" is any beneficial owner of a note who is not a U.S. Holder.

        All original investors in the notes are urged to consult their tax advisers regarding the U.S. federal, state, local and foreign tax consequences of the purchase, ownership and disposition of the notes.

Exchange of old notes for exchange notes

        The exchange of old notes for exchange notes pursuant to the exchange offer will not constitute a taxable event to holders. Rather, the exchange notes will be treated as a continuation of the old notes for federal income tax purposes, and are referred to together as "notes" in this summary of federal income tax considerations. Consequently, no gain or loss will be recognized by a holder upon receipt of an exchange note, the holding period of the exchange note will include the holding period of the old note, and the initial basis of the exchange note will be the same as the basis of the old note immediately before the exchange.

185

Tax consequences to U.S. Holders

        Interest.    Payments of interest on a note will be includable in ordinary income when accrued or received in accordance with the U.S. Holder's regular method of tax accounting.

        In certain circumstances, we may be obligated to pay amounts in excess of the stated interest and principal payable on the notes. The obligation to make such payments may implicate the provisions of Treasury Regulations relating to "contingent payment debt instruments." If the notes were deemed to be contingent payment debt instruments, a U.S. Holder might, among other consequences, be required to accrue income on its notes in excess of stated interest and to treat any gain recognized on the sale or other disposition of the notes as ordinary income rather than as capital gain. We intend to treat the notes as not subject to these regulations. The regulations applicable to contingent payment debt instruments, however, have not been the subject of authoritative interpretation and therefore the scope of the regulations is not certain. You are urged to consult your tax advisors regarding the possible application of contingent payment debt instrument rules to the notes.

        Sale or Exchange.    Upon a sale, exchange, or other disposition of a note, a U.S. Holder will generally recognize capital gain or loss equal to the difference between (i) the amount realized on such disposition (except to the extent attributable to accrued but unpaid interest, which is treated as interest as described above) and (ii) the holder's adjusted tax basis in the note. Such gain or loss will be long term if the note is held for more than one year. A U.S. Holder's adjusted tax basis in a note generally will equal the cost of the note to such holder less any principal payments received on the note. In the case of a U.S. Holder other than a corporation, preferential tax rates may apply to long term capital gains. The claim of a deduction in respect of a capital loss may be subject to limitation.

        Information Reporting and Backup Withholding.    In general, information reporting requirements will apply to certain payments of principal and interest paid on notes and to the proceeds of the sale of a note made to you (unless you are an exempt recipient such as a corporation). A 30% backup withholding tax (which rate is scheduled to be reduced in future years) will apply to such payments if you fail to provide a taxpayer identification number, a certification of exempt status, or fail to report in full dividend and interest income. Any amounts withheld under the backup withholding rules will be allowed as a credit against the U.S. Holder's United States federal income tax and may entitle the holder to a refund, provided that the required information is furnished to the IRS.

Tax consequences to Non-U.S. Holders

        For purposes of the discussion below, interest and gain on the sale, exchange or other disposition of the notes will be considered to be "U.S. trade or business income" if such income or gain is:

•

effectively connected with the conduct of a U.S. trade or business; and



•

in the case of a Non-U.S. Holder eligible for the benefits of an applicable U.S. income tax treaty, attributable to a U.S. permanent establishment (or, in the case of an individual, a fixed base) in the United States.

        Interest.    Interest payments (including payments of additional interest, if any) made to a Non-U.S. Holder with respect to the notes will generally not be subject to United States federal income tax or withholding tax, provided that:

•

the Non-U.S. Holder does not actually or constructively own ten percent or more of the total combined voting power of all classes of our stock entitled to vote,



•

the Non-U.S. Holder is not a controlled foreign corporation that is related to us through stock ownership,

186

•

the Non-U.S. Holder is not a bank described in Section 881(c)(3)(A) of the Internal Revenue Code, and



•

either (A) the beneficial owner of the notes certifies to us or our agent on IRS Form W-8BEN (or successor form), under penalties of perjury, that it is not a "U.S. person" (as defined in the Internal Revenue Code) and provides its name and address and the certificate is renewed periodically as required by Treasury Regulations, or (B) a securities clearing organization, bank or other financial institution that holds customers' securities in the ordinary course of its trade or business, commonly referred to as a financial institution, and holds the notes on behalf of the beneficial owner certifies to us or our agent, under penalties of perjury, that such statement has been received from the beneficial owner by it or a financial institution between it and the beneficial owner and furnishes us with a copy thereof. These four requirements are referred to as the Portfolio Interest Exemption.

        The gross amount of payments of interest that do not qualify for the Portfolio Interest Exception and that are not U.S. trade or business income will be subject to U.S. withholding tax at a rate of 30% unless a treaty applies to reduce or eliminate withholding. U.S. trade or business income will be subject to tax on a net income basis at regular graduated U.S. rates rather than the 30% gross rate. In the case of a Non-U.S. Holder that is a corporation, such U.S. trade or business income also may be subject to the 30% branch profits tax. To claim an exemption from withholding, or to claim the benefits of a treaty, a Non-U.S. Holder must provide a properly executed Form W-8BEN (claiming treaty benefits) or W-8ECI (claiming exemption from withholding because income is U.S. trade or business income) (or such successor forms as the IRS designates), as applicable prior to the payment of interest. These forms must be periodically updated. A Non-U.S. Holder who is claiming the benefits of a treaty may be required, in certain instances, to obtain a U.S. taxpayer identification number and to provide certain documentary evidence issued by foreign governmental authorities to prove residence in the foreign country. Also, under these regulations special procedures are provided for payments through qualified intermediaries.

        Disposition of the Notes.    A Non-U.S. Holder generally will not be subject to U.S. federal income tax in respect of gain recognized on a disposition of the notes unless:

•

the gain is U.S. trade or business income, in which case the branch profits tax also may apply to a corporate Non-U.S. Holder;



•

the Non-U.S. Holder is an individual who is present in the United States for 183 or more days in the taxable year of the disposition and meets other requirements; or



•

the Non-U.S. Holder is subject to U.S. tax under provisions applicable to certain U.S. expatriates (including certain former citizens or residents of the United States).

        United States Federal Estate Tax.    Notes held (or treated as held) by an individual who is a Non-U.S. Holder at the time of his or her death will not be subject to U.S. federal estate tax, provided that the interest on such notes would be exempt as portfolio interest when received by the Non-U.S. Holder at the time of his or her death and income on the notes was not U.S. trade or business income.

        Information Reporting Requirements and Backup Withholding Tax.    We must report annually to the IRS and to each Non-U.S. Holder any interest that is paid to a Non-U.S. Holder. Copies of these information returns also may be made available under the provisions of a specific treaty or other agreement to the tax authorities of the country in which the Non-U.S. Holder resides.

        The backup withholding tax and certain information reporting will not apply to payments of interest with respect to which either the requisite certification as to non-U.S. status has been received or an exemption otherwise has been established, provided that neither we nor our paying agent have

187

actual knowledge or reason to know that the holder is a U.S. person or that the conditions of any other exemption are not, in fact, satisfied.

        The payment of the proceeds from the disposition of the notes to or through the U.S. office of any broker, U.S. or foreign, will be subject to information reporting and possible backup withholding unless the owner certifies as to its non-U.S. status under penalties of perjury or otherwise establishes an exemption under applicable Treasury regulations,provided that the broker does not have actual knowledge that the holder is a U.S. person or that the conditions of any other exemption are not, in fact, satisfied. The payment of the proceeds from the disposition of the notes to or through a non-U.S. office of a non-U.S. broker will not be subject to information reporting or backup withholding unless the non-U.S. broker has certain types of relationships with the United States, referred to as a "U.S. related person." In the case of the payment of the proceeds from the disposition of the notes to or through a non-U.S. office of a broker that is either a U.S. person or a U.S. related person, the Treasury Regulations require information reporting (but not backup withholding) on the payment unless the broker has documentary evidence in its files that the owner is a Non-U.S. Holder and the broker has no actual knowledge or reason to know to the contrary.

        Backup withholding is not an additional tax.    Any amounts withheld under the backup withholding rules from a payment to a Non-U.S. Holder will be refunded or credited against the holder's U.S. federal income tax liability, if any, if the holder provides the required information to the IRS. The information reporting requirements may apply regardless of whether withholding is required.

188

PLAN OF DISTRIBUTION

        Each broker-dealer that receives exchange notes in the exchange offer for its own account must acknowledge that it will deliver a prospectus meeting the requirements of the Securities Act in connection with any resales of such exchange notes. We reserve the right in our sole discretion to purchase or make offers for, or to offer exchange notes for, any old notes that remain outstanding subsequent to the expiration of the exchange offer pursuant to this prospectus or otherwise and, to the extent permitted by applicable law, purchase old notes in the open market, in privately negotiated transactions or otherwise. This prospectus, as it may be amended or supplemented from time to time, may be used by all persons subject to the prospectus delivery requirements of the Securities Act, including broker-dealers in connection with resales of exchange notes received in the exchange offer, where such old notes were acquired as a result of market-making activities or other trading activities and may be used by us to purchase any old notes outstanding after expiration of the exchange offer. We have agreed that, for a period of 180 days from the date on which the exchange offer is completed, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale. In addition, until            , 2003, all dealers effecting transactions in the exchange notes may be required to deliver a prospectus.

        We will not receive any proceeds from any sale of exchange notes by broker-dealers. Exchange notes received by broker-dealers in the exchange offer for their own account may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the exchange notes or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or negotiated prices. Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such exchange notes. Any broker-dealer that resells exchange notes that were received by it in the exchange offer for its own account and any broker or dealer that participates in a distribution of such exchange notes may be deemed to be an "underwriter" within the meaning of the Securities Act and any profit on any such resale of such exchange notes and any commissions or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The letter of transmittal states that, by acknowledging that it will deliver and by delivering a prospectus meeting the requirements of the Securities Act, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act.

        For a period of 180 days from the date on which the exchange offer is completed, we will promptly send a sufficient number of additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents in the letter of transmittal. We have agreed to pay all expenses incident to the exchange offer (including the reasonable fees and expenses of one counsel for the holders of the old notes) other than commissions or concessions of any brokers or dealers and will indemnify holders of the notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

189

LEGAL MATTERS

        Certain legal matters with respect to the exchange notes offered hereby will be passed upon for us by Hogan & Hartson L.L.P., Denver, Colorado.

EXPERTS

        The consolidated financial statements of TransMontaigne Inc. as of June 30, 2002 and 2001, and for each of the years in the three-year period ended June 30, 2002, have been included herein and in the registration statement in reliance upon the report of KPMG LLP, independent accountants, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

        The combined financial statements for Coastal Fuels Marketing, Inc. and Subsidiaries and the Southeast Marketing Division of El Paso Merchant Energy Petroleum Company as of December 31, 2002 and 2001 and for each of the three years in the period ended December 31, 2002 included in this prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, independent accountants, given on the authority of said firm as experts in auditing and accounting.

SUBSIDIARY GUARANTORS

        Each subsidiary guarantor is exempt from Exchange Act reporting pursuant to Rule 12h-5 under the Exchange Act, as: we have no independent assets or operations; the guarantees of the subsidiary guarantors are full and unconditional and joint and several; and any subsidiaries of ours other than the subsidiary guarantors are, individually and in the aggregate, minor. There are no significant restrictions on our ability or any subsidiary guarantor to obtain funds from its subsidiaries.

WHERE YOU CAN FIND MORE INFORMATION

        We have filed with the SEC a registration statement on Form S-4 (Commission File. No. 333-            ) with respect to the exchange notes. This prospectus does not contain all the information contained in the registration statement, including its exhibits and schedules. You should refer to the registration statement including the exhibits and schedules, for further information about us and the exchange notes. Statements we make in this prospectus about certain contracts or other documents are not necessarily complete. When we make such statements, we refer you to the copies of the contracts or documents that are filed as exhibits to the registration statement because those statements are qualified in all respects by reference to those exhibits. The registration statement, including exhibits and schedules, is on file at the offices of the SEC and may be inspected without charge.

        Upon effectiveness of the registration statement of which this prospectus is a part, we will file annual, quarterly, special reports and other information with the SEC. You may read and copy any document we file with the SEC at the SEC's public reference room at the following address:

Public Reference Room
450 Fifth Street, N.W.
Room 1024
Washington, D.C. 20549

        Please call the SEC at 1-800-SEC-0330 for further information on the operations of the public reference rooms. Our SEC filings are also available at the SEC's web site athttp://www.sec.gov.

        You can obtain a copy of any of our filings, at no cost, by writing to or telephone us at the following address:

TransMontaigne Inc.
1670 Broadway, Suite 3100
Denver, Colorado 80202
Attention: General Counsel
(303) 626-8200

        To ensure timely delivery, please make your request as soon as practicable and, in any event, no later than five business days prior to the expiration of the exchange offer.

190

Index to consolidated financial statements

TransMontaigne Inc. and Subsidiaries:

Unaudited Financial Statements:

Audited Financial Statements:

Coastal Fuels Marketing, Inc.:

Audited Financial Statements:

F-1

TransMontaigne Inc. and subsidiaries

Consolidated balance sheets

(In thousands)

			March 31, 2003			June 30, 2002
ASSETS
Current assets:
	Cash and cash equivalents		$	26,314		$	30,852
	Restricted cash held by commodity broker			23,351			8,621
	Trade accounts receivable, net			244,983			173,736
	Inventories—discretionary volumes			178,384			175,169
	Unrealized gains on supply management services contracts			21,313			14,525
	Prepaid expenses and other			3,776			2,598
				498,121			405,501
Property, plant and equipment, net				377,802			251,431
Inventories—minimum volumes				22,017			45,298
Unrealized gains on supply management services contracts				3,948			8,093
Investments in petroleum related assets				10,131			10,131
Deferred tax assets				103			7,882
Deferred debt issuance costs, net				11,558			2,729
Other assets				4,203			4,263
			$	927,883		$	735,328
LIABILITIES, PREFERRED STOCK, AND COMMON STOCKHOLDERS' EQUITY
Current liabilities:
	Commodity margin loan		$	—		$	11,312
	Working capital credit facility			65,000			—
	Trade accounts payable			150,482			102,780
	Unrealized losses on supply management services contracts			19,945			8,522
	Inventory due to others under exchange agreements			32,485			16,908
	Excise taxes payable			86,940			72,045
	Other accrued liabilities			47,020			24,242
	Deferred revenue—supply management services			4,734			1,600
				406,606			237,409
Other liabilities:
	Long-term debt			200,000			187,000
	Unrealized losses on supply management services contracts			107			209
		Total liabilities		606,713			424,618
Preferred stock:
	Series A Convertible Preferred stock			24,421			24,421
	Series B Redeemable Convertible Preferred stock			79,732			80,939
				104,153			105,360
Common stockholders' equity:
	Common stock			407			399
	Capital in excess of par value			249,258			245,844
	Deferred stock-based compensation			(4,489	)		(2,540	)
	Accumulated deficit			(28,159	)		(38,353	)
				217,017			205,350
			$	927,883		$	735,328

See accompanying notes to consolidated financial statements.

F-2

TransMontaigne Inc. and subsidiaries

Consolidated statements of operations

(In thousands, except per share amounts)

				Three months ended March 31,						Nine months ended March 31,
				2003			2002			2003			2002
Supply, distribution, and marketing:
	Revenues			$	2,280,115		$	1,309,934		$	5,949,896		$	4,001,858
	Cost of product sold				(2,192,853	)		(1,227,309	)		(5,817,624	)		(3,884,248	)
			Net margin before other direct costs and expenses		87,262			82,625			132,272			117,610
	Other direct costs and expenses:
		Losses on NYMEX futures contracts used for hedging purposes			(33,172	)		(15,631	)		(78,072	)		(55,173	)
		Change in unrealized gains (losses) on supply management services contracts			—			(46,888	)		—			(1,003	)
		Lower of cost or market write-downs on inventories—minimum volumes			(633	)		—			(633	)		(12,963	)
			Net operating margins		53,457			20,106			53,567			48,471
Terminals, pipelines, and tugs and barges:
	Revenue				21,544			15,764			56,204			46,455
	Direct operating costs and expenses				(8,994	)		(6,168	)		(21,981	)		(20,005	)
			Net operating margins		12,550			9,596			34,223			26,450
			Total net operating margins		66,007			29,702			87,790			74,921
Costs and expenses:
	Selling, general and administrative				10,440			8,955			28,547			25,605
	Depreciation and amortization				4,851			4,143			13,400			12,449
	Corporate relocation and transition				—			315			1,449			315
					15,291			13,413			43,396			38,369
			Operating income		50,716			16,289			44,394			36,552
Other income (expense):
	Dividend income from and equity in earnings (loss) of petroleum related investments				—			(7	)		374			1,450
	Interest income				63			66			231			489
	Interest expense				(3,822	)		(3,643	)		(10,181	)		(9,614	)
	Other financing costs:
			Amortization of debt issuance costs		(487	)		(456	)		(948	)		(1,376	)
			Write-off of debt issuance costs related to former bank credit facility		(2,188	)		—			(2,188	)		—
			Gain (loss) on interest rate swap		950			1,840			2,224			(1,325	)
	Loss on disposition of assets, net				—			—			—			(1,295	)
					(5,484	)		(2,200	)		(10,488	)		(11,671	)
			Earnings before income taxes and cumulative effect of a change in accounting principle		45,232			14,089			33,906			24,881
Income tax expense					(17,192	)		(5,354	)		(12,888	)		(9,455	)
			Net earnings before cumulative effect of a change in accounting principle		28,040			8,735			21,018			15,426
Cumulative effect of change in accounting principle of $12,644, net of income tax benefit of $4,805					—			—			(7,839	)		—
			Net earnings		28,040			8,735			13,179			15,426
Preferred stock dividends					(995	)		(2,470	)		(2,985	)		(7,311	)
			Net earnings attributable to common stockholders	$	27,045		$	6,265		$	10,194		$	8,115

F-3

		Three months ended March 31,				Nine months ended March 31,
		2003		2002		2003			2002
Net earnings after preferred stock dividends and before cumulative effect of a change in accounting principle		$	27,045	$	6,265	$	18,033		$	8,115
Cumulative effect of a change in accounting principle			—		—		(7,839	)		—
Net earnings attributable to common stockholders		$	27,045	$	6,265	$	10,194		$	8,115
Basic net earnings (loss) per common share:
	Net earnings after preferred stock dividends and before cumulative effect of a change in accounting principle	$	0.69	$	0.20	$	0.46		$	0.26
	Cumulative effect of a change in accounting principle		—		—		(0.20	)		—
		$	0.69	$	0.20	$	0.26		$	0.26
Diluted net earnings (loss) per common share:
	Net earnings after preferred stock dividends and before cumulative effect of a change in accounting principle	$	0.54	$	0.20	$	0.40		$	0.26
	Cumulative effect of a change in accounting principle		—		—		(0.16	)		—
		$	0.54	$	0.20	$	0.24		$	0.26
Weighted average common shares outstanding:
	Basic		39,144		31,217		39,101			31,189
	Diluted		51,935		31,536		50,288			31,538

See accompanying notes to consolidated financial statements.

F-4

TransMontaigne Inc. and subsidiaries

Consolidated statements of preferred stock and common stockholders' equity

Year ended June 30, 2002 and nine months ended March 31, 2003

(In thousands)

	Preferred stock															Retained earnings (accumulated deficit)			Total common stockholders' equity
							Common stock			Capital in excess of par value			Deferred stock-based compensation
	Series A			Series B
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		—			—			—			11			—			—			11
Common stock repurchased from employees for withholding taxes		—			—			—			(190	)		—			—			(190	)
Net tax effect arising from stock-based compensation		—			—			—			90			—			—			90
Forfeiture of restricted stock awards prior to vesting		—			—			—			(227	)		227			—			—
Deferred compensation related to restricted stock awards		—			—			8			3,470			(3,478	)		—			—
Deferred compensation related to non-employee stock options		—			—			—			260			(260	)		—			—
Amortization of deferred stock-based compensation		—			—			—			—			1,562			—			1,562
Preferred stock dividends		—			—			—			—			—			(4,192	)		(4,192	)
Amortization of premium on Series B Redeemable Convertible Preferred stock		—			(1,207	)		—			—			—			1,207			1,207
Net earnings		—			—			—			—			—			13,179			13,179
Balance at March 31, 2003	$	24,421		$	79,732		$	407		$	249,258		$	(4,489	)	$	(28,159	)	$	217,017

See accompanying notes to consolidated financial statements.

F-5

TransMontaigne Inc. and subsidiaries

Consolidated statements of cash flows

(In thousands)

					Three months ended March 31,						Nine months ended March 31,
					2003			2002			2003			2002
Cash flows from operating activities:
	Net earnings				$	28,040		$	8,735		$	13,179		$	15,426
	Adjustments to reconcile net earnings to net cash provided (used) by operating activities:
		Amortization of deferred revenue				(1,041	)		—			(1,341	)		—
		Depreciation and amortization				4,851			4,143			13,400			12,449
		Equity in earnings of petroleum related investments				—			7			—			—
		Deferred tax expense				17,208			5,199			7,779			8,701
		Net tax effect arising from stock-based compensation				(7	)		4			90			(14	)
		Loss on disposition of assets, net				—			—			—			1,295
		Amortization of deferred stock-based compensation				704			382			1,562			1,148
		Amortization of debt issuance costs				487			456			948			1,376
		Repayment of interest rate swap				(3,205	)		—			(3,205	)		—
		Write-off of debt issuance costs				2,188			—			2,188			—
		Unrealized (gain) loss on interest rate swap				(950	)		(1,840	)		(2,224	)		1,325
		Net change in unrealized gains/losses on long-term supply management services contracts				2,089			3,246			4,043			798
		Lower of cost or market write-down on base operating inventory volumes				12,412			—			12,412			—
		Lower of cost or market write-down on minimum inventory volumes				633			—			633			12,963
		Changes in operating assets and liabilities, net of non-cash activities:
			Trade accounts receivable, net			(33,452	)		(13,547	)		(71,247	)		(70,906	)
			Inventories—discretionary volumes			63,840			629			13,333			(60,034	)
			Prepaid expenses and other			(272	)		660			(1,178	)		922
			Trade accounts payable			(20,851	)		(40,747	)		47,702			21,664
			Inventory due to others under exchange agreements			9,394			7,873			15,577			(68,881	)
			Unrealized (gain) loss on supply management services contracts			(381	)		43,644			5,085			206
			Excise taxes payable and other accrued liabilities			10,326			9,810			15,034			27,902
				Net cash provided (used) by operating activities		92,013			28,654			73,770			(93,660	)
Cash flows from investing activities:
	Acquisition of Coastal Fuels assets					(95,000	)		—			(95,000	)		—
	Purchases of property, plant and equipment					(8,366	)		(3,346	)		(13,772	)		(4,461	)
	Proceeds from sales of assets					—			—			—			117,243
	Increase in restricted cash held by commodity broker					(3,827	)		(14,549	)		(14,730	)		(6,565	)
	Purchase of inventories—minimum volumes					(6,311	)		—			(6,311	)		—
	Decrease (increase) in other assets					—			10			60			(1,618	)
				Net cash provided (used) by investing activities		(113,504	)		(17,885	)		(129,753	)		104,599
Cash flows from financing activities:
	Net repayments of bank credit facility					(200,000	)		(500	)		(187,000	)		(4,500	)
	Proceeds from borrowings of working capital credit facility					65,000			—			65,000			—
	Proceeds from borrowings of term loan					200,000			—			200,000			—
	Net repayments of commodity margin loan					(9,841	)		(20,000	)		(11,312	)		(20,000	)
	Deferred debt issuance costs					(11,893	)		—			(11,965	)		—
	Common stock issued for options exercised					—			—			11			30
	Common stock repurchased from employees for withholding taxes					(29	)		(12	)		(190	)		(83	)
	Preferred stock dividends paid in cash					(1,396	)		—			(3,099	)		—
				Net cash provided (used) by financing activities		41,841			(20,512	)		51,445			(24,553	)
				Increase (decrease) in cash and cash equivalents		20,350			(9,743	)		(4,538	)		(13,614	)
Cash and cash equivalents at beginning of period						5,964			21,904			30,852			25,775
Cash and cash equivalents at end of period					$	26,314		$	12,161		$	26,314		$	12,161

F-6

					Three months ended March 31,				Nine months ended March 31,
					2003		2002		2003		2002
Supplemental disclosures of cash flow information:
	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				—		—		—		3,416
		Gain on disposition				—		—		—		8,601
			Cash received from sale		$	—	$	—	$	—	$	61,750
		Other cash sales:
			Cash received from sale of Little Rock facilities		$	—	$	—	$	—	$	29,033
			Cash received from sales of other assets		$	—	$	—	$	—	$	404
				Total cash received from sales of assets	$	—	$	—	$	—	$	117,243

See accompanying notes to consolidated financial statements.

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TransMontaigne Inc. and subsidiaries

Notes to consolidated financial statements

March 31, 2003 and June 30, 2002

(1) SUMMARY OF CRITICAL AND SIGNIFICANT ACCOUNTING POLICIES

(a)   Principles of Consolidation and Use of Estimates

        The accompanying consolidated financial statements in this Offering Memorandum have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, these statements reflect adjustments (consisting only of normal recurring entries), which are, in our opinion, necessary for a fair presentation of the financial results for the interim periods presented. Certain information and notes normally included in annual financial statements have been condensed in or omitted from these interim financial statements pursuant to such rules and regulations. These consolidated financial statements should be read in conjunction with the consolidated financial statements and related notes for the year ended June 30, 2002, together with our discussion and analysis of financial condition and results of operations, included in our Current Report on Form 8-K dated May 14, 2003.

        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.

        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 (for periods as of and prior to October 1, 2002); fair value of supply management services 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 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).

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(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 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; and other service revenue is recognized as the services are performed.

(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 sales, bulk sales, and contract sales. Revenue from rack 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.

(e)   Accounting for Derivative Contracts

        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 energy trading and risk management activities should no longer be marked to market pursuant to the guidance in Issue No. 98-10 ("EITF 98-10"),Accounting for Contracts Involved in Energy Trading and Risk Management Activities. Pursuant to the consensus on EITF 02-03, energy trading and risk management activities that qualify as derivative contracts are reported as assets and liabilities at fair value in accordance with Statement of Financial Accounting Standards No. 133 ("SFAS No. 133"),Accounting for Derivative Instruments and Hedging Activities. Energy trading and risk management activities that do not qualify as derivative contracts are treated as executory contracts and recognized pursuant to the accrual method of accounting (i.e., when cash becomes due and payable to us or our customers pursuant to the terms of the contracts). Under SFAS No. 133, a derivative instrument is a financial instrument or other contract with all three of the following characteristics:

a.

It has one or more underlyings (e.g., specified interest rate, security price, commodity price, index of prices or rates), and one or more notional amounts (e.g., number of currency units, shares, or other units specified in the contract) or payment provisions, or both;

b.

It requires no initial net investment or an initial net investment that is smaller than would be required for other types of contracts that would be expected to have a similar response to changes in market factors; and

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c.

Its terms require or permit net settlement, it can readily be settled net by a means outside the contract, or it provides delivery of an asset that puts the recipient in a position not substantially different from net settlement.

        In accordance with EITF 02-03, all gains and losses (realized and unrealized) on derivative contracts are to be presented on a net basis in the consolidated statement of operations whether or not the contracts are settled physically. Gains and losses on executory contracts are to be presented on a gross basis in the consolidated statements of operations. 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 at fair value effective October 1, 2002. The excess of the fair value of our inventories—discretionary volumes over their cost basis as of October 1, 2002 has been reflected in the accompanying consolidated statement of operations as a cumulative effect of a change in accounting principle. Our supply management services contracts and risk management contracts will continue to be marked to market because these contracts qualify as derivative instruments pursuant to the requirements of SFAS No. 133.

        Supply Management Services Contracts.    We provide supply 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 management services: delivered fuel price management, retail price management, and logistical supply 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 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.

        Our delivered fuel price management and retail price management contracts are based on commodity prices, stipulated volumes of product, permit net settlement for differences between actual and stipulated volumes, and do not require an initial net investment. Therefore, these contracts qualify as derivative instruments pursuant to SFAS No. 133. Our delivered fuel price management and retail price management contracts are carried at fair value in the accompanying consolidated financial statements. The fair value of these contracts is included in "Unrealized gains or losses on supply management services contracts" in the accompanying consolidated balance sheets. 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.

        For the three and nine months ended March 31, 2003 our revenues from delivered fuel price management and retail price management contracts are presented in the accompanying consolidated statement of operations on a net basis (i.e., product costs are netted directly against gross revenues to arrive at net revenues). For the three and nine months ended March 31, 2002, our revenues from delivered fuel price management and retail price management contracts are presented in the

F-10

accompanying consolidated statement of operations on a gross basis because the cost of revenues information is not available to present them on a comparable net basis for periods prior to July 1, 2002. Product costs represent the cost of the products sold, settlement of risk management contracts, transportation, storage, terminaling costs, and commissions. Revenues attributable to our delivered fuel price management and retail price management contracts are as follows (in thousands):

			Three months ended March 31,					Nine months ended March 31,
			2003			2002		2003			2002
Gross revenues			$	44,692		$	30,252	$	116,385		$	95,113
Less:
	Cost of revenues			(39,612	)				(96,645	)
	Change in unrealized gains (losses) on contracts			(1,558	)				(8,678	)
		Net revenues	$	3,522				$	11,062

        Risk Management Contracts.    We enter into risk management contracts to reduce 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, open positions in supply management services contracts, and open positions in risk management contracts. We enter into risk management contracts that offset the changes in the values of our inventories—discretionary volumes and supply management services contracts. At March 31, 2003, our open positions in risk management contracts were NYMEX futures contracts (purchases and sales).

        Our risk management contracts are based on commodity prices, stipulated volumes of refined petroleum product, permit net settlement, and do not require an initial net investment. Therefore, our risk management contracts qualify as derivative instruments pursuant to SFAS No. 133. Our risk management contracts are carried at fair value in the accompanying consolidated balance sheets. Changes in the fair value of our risk management contracts are included in net operating margins attributable to our supply, distribution and marketing operations. At March 31, 2003 and June 30, 2002, 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.

(f)    Accounting for Inventories—Discretionary Volumes

        Our 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 were carried at fair value with the changes in the fair value included in net

F-11

margins attributable to our supply, distribution and marketing operations. Inventories—discretionary volumes are as follows (in thousands):

	March 31, 2003			June 30, 2002
	Amount		Bbls	Amount		Bbls
Volumes held for immediate sale or exchange	$	74,045	2,099	$	175,169	5,749
Volumes held for base operations		104,339	2,922		—	—
Inventories—discretionary volumes	$	178,384	5,021	$	175,169	5,749

        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.

        Effective October 1, 2002, we adjusted the carrying amount of our inventories—discretionary volumes to the lower of cost 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 and is calculated as follows (in thousands):

Inventories—discretionary volumes:
	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
	Income tax effects at 38%			(4,805	)
Cumulative effect of a change in accounting principle			$	7,839

(g)   Accounting for Inventories—Minimum Volumes

        At March 31, 2003 and June 30, 2002, our inventories—minimum volumes are presented in the accompanying consolidated balance sheets as non-current assets and are carried at the lower of cost (weighted average) or market (replacement cost). Inventories—minimum volumes are as follows (in thousands):

	March 31, 2003			June 30, 2002
	Amount		Bbls	Amount		Bbls
Gasolines	$	13,020	497	$	27,855	1,200
Distillates		7,449	319		17,443	800
No. 6 oil		1,548	61		—	—
Inventories—minimum volumes	$	22,017	877	$	45,298	2,000

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(h)   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.

(i)    Earnings (Loss) Per Common 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.

(j)    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 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 August 2001, the FASB issued SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets, which addresses the financial accounting and reporting for long-lived assets to be disposed of by sale and broadens the presentation of discontinued operations to include more disposal transactions. SFAS No. 144 also provides guidance that will eliminate inconsistencies in accounting for the impairment or disposal of long-lived assets under existing accounting pronouncements. We adopted the provisions of SFAS No. 144 effective July 1, 2002. The adoption of SFAS No. 144 did not have an impact on our consolidated financial statements.

F-13

        In December 2002, the FASB issued SFAS No. 148,Accounting for Stock-Based Compensation—Transition and Disclosure—an amendment of FASB Statement No. 123 ("SFAS No. 123"), which addresses alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. We have adopted the disclosure provisions of SFAS No. 148 as of and for the three and nine months ended March 31, 2003.

(k)   Reclassifications

        Certain amounts in the prior years have been reclassified to conform to the current year's presentation. We have presented our revenues and cost of revenues resulting from executory contracts on a gross basis in the accompanying consolidated statements of operations. We have classified the portion of our restricted cash held by commodity broker that represents the variation margin deposits as an offset against unrealized gains and losses on risk management contracts in the accompanying consolidated balance sheets. Net earnings have not been affected by these reclassifications.

(2) ACQUISITIONS

        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 purchase price for the acquisition was approximately $157.0 million, including approximately $37.0 million of product inventory. The purchase price includes contingent consideration of approximately $25.0 million that becomes due and payable to CGP upon delivery by CGP of audited financial statements of the Coastal Fuels assets. On April 25, 2003, CGP delivered to us the audited financial statements of the Coastal Fuels assets and CGP was paid $25.0 million on April 30, 2003. 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 $6.3 million a 500,000-barrel products terminal in Fairfax, Virginia. The terminal increases our presence in the Mid-Atlantic market and supplies product to the Washington, D.C. market.

        On July 31, 2002, we acquired for cash consideration of approximately $0.6 million a products terminal in Brownsville, Texas. The 25,000-barrel terminal provides us with additional storage and rail car handling facilities in Brownsville, Texas.

        Effective June 30, 2002, we acquired for cash consideration of approximately $7.2 million the remaining 40% interest that we previously did not own in the Razorback Pipeline system

F-14

("Razorback"), a 67 mile petroleum products pipeline between Mount Vernon, Missouri and Rogers, Arkansas with approximately 0.4 million barrels of storage capacity. We accounted for the step-acquisition of Razorback using the purchase method of accounting as of the effective date of the transaction.

        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):

	Coastal Fuels			Fairfax		Razorback			Brownsville
Discretionary inventory volumes	$	30,500		$	—	$	—		$	—
Prepaid expenses and other current assets		—			—		2			—
Property, plant and equipment		125,000			6,284		7,188			630
Minimum inventory volumes		6,500			—		—			—
Contingent consideration due to seller		(25,000	)		—		—			—
Other accrued liabilities assumed		(6,000	)		—		(75	)		—
Cash paid, net of cash acquired of $0, $0, $85 and $0, respectively	$	131,000		$	6,284	$	7,115		$	630

        At March 31, 2003, the allocation of the purchase price to the Coastal Fuels assets is preliminary. We are awaiting the receipt of appraisals on certain of the real estate and equipment. The pro forma combined results of operations as if the acquisition of the Coastal Fuels assets and the step-acquisition of Razorback had occurred on July 1, 2001 are as follows (in thousands, except per share data):

	Year ended June 30, 2002			Nine months ended March 31, 2003
Revenue	$	6,489,196		$	6,356,653
Net earnings	$	9,991		$	27,428
Basic earnings (loss) per share	$	(0.04	)	$	0.63

(3) DISPOSITIONS

        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 $1.2 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.

        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

F-15

approximated our adjusted cost basis. For the three and nine months ended March 31, 2002, we recognized $nil and $0.7 million of dividend income from West Shore.

(4) TRADE ACCOUNTS RECEIVABLE

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

	March 31, 2003			June 30, 2002
Trade accounts receivable	$	246,905		$	174,986
Less allowance for doubtful accounts		(1,922	)		(1,250	)
	$	244,983		$	173,736

(5) INVENTORIES—DISCRETIONARY VOLUMES

        Our inventories—discretionary volumes consist of refined petroleum products, primarily gasolines, distillates, and No. 6 oil. At March 31, 2003 and June 30, 2002, we held approximately 5.0 million and 5.7 million barrels of discretionary inventory at a weighted average fair value of approximately $0.84 and $0.72 per gallon, respectively. At March 31, 2003, the cost basis of our discretionary inventory volumes exceeded their market value by approximately $22.4 million. During the three months ended March 31, 2003, we recognized an impairment loss of approximately $22.4 million due to lower of cost or market write-downs on this inventory.

        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 March 31, 2003 and June 30, 2002, current liabilities include inventory due to others under exchange agreements of approximately 0.9 million barrels and 0.5 million barrels, respectively, with a market value of approximately $32.5 million and $16.9 million respectively. The amount recorded represents the market value of inventory due to others under exchange agreements at the balance sheet date.

(6) UNREALIZED GAINS AND LOSSES ON SUPPLY MANAGEMENT SERVICES CONTRACTS

        Unrealized gains and losses on supply management services contracts are as follows (in thousands):

			March 31, 2003			June 30, 2002
Unrealized gains—current			$	21,313		$	14,525
Unrealized gains—long-term				3,948			8,093
	Unrealized gains—asset			25,261			22,618
Unrealized losses—current				(19,945	)		(8,522	)
Unrealized losses—long-term				(107	)		(209	)
	Unrealized losses—liability			(20,052	)		(8,731	)
		Net asset position	$	5,209		$	13,887

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        Our supply management services contracts primarily are delivered fuel price management ("fixed-price" sales commitments to end-users of product) and retail price management contracts (retail price swap contracts with ground fleet customers).

(7) PROPERTY, PLANT AND EQUIPMENT

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

	March 31, 2003			June 30, 2002
Land	$	54,125		$	14,125
Terminals, pipelines and equipment		359,460			276,559
Technology and equipment		13,290			12,645
Tugs and barges		15,000			—
Furniture, fixtures and equipment		6,055			5,732
Construction in progress		4,192			3,291
		452,122			312,352
Less accumulated depreciation		(74,320	)		(60,921	)
	$	377,802		$	251,431

(8) INVENTORIES—MINIMUM VOLUMES

        Our inventories—minimum volumes are not held for sale or exchange in the ordinary course of business and, therefore, we do not hedge the market risks associated with this minimum inventory. Prior to March 1, 2003, our inventories—minimum volumes aggregated approximately 2.0 million barrels of product reflecting tank bottoms, line fill in our proprietary pipelines, and in-transit volumes on common carrier pipelines. On March 1, 2003, we transferred to inventories—discretionary volumes approximately 1.3 million barrels of inventories—minimum volumes representing the volumes associated with our in-transit volumes on common carrier pipelines. During the three months ended March 31, 2003, we recognized a net operating margin of approximately $18.9 million from the sale of those transferred barrels; those transferred barrels had a weighted average adjusted cost basis of approximately $0.54 at their date of sale. Subsequent to February 28, 2003, our inventories—minimum volumes aggregate approximately 880,000 barrels of product reflecting tank bottoms and line fill in our proprietary pipelines. Our inventories—minimum volumes are presented in the accompanying consolidated balance sheets as non-current assets and are carried at the lower of cost or market. At March 31, 2003 and June 30, 2002, the weighted average adjusted cost basis of our inventories—minimum volumes was approximately $0.60 and $0.54 per gallon, respectively.

        During the three months ended March 31, 2003 and 2002, we recognized an impairment loss of approximately $0.6 million and $nil, respectively, due to lower of cost or market write-downs on our inventories—minimum volumes. During the nine months ended March 31, 2003 and 2002, we recognized an impairment loss of approximately $0.6 million and $13.0 million, respectively, due to lower of cost or market write-downs on our inventories—minimum volumes.

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(9) OTHER ASSETS

        Other assets are as follows (in thousands):

	March 31, 2003		June 30, 2002
Prepaid transportation	$	2,644	$	2,644
Commodity trading membership		1,500		1,500
Deposits and other assets		59		119
	$	4,203	$	4,263

        Prepaid transportation relates to our contractual transportation and deficiency agreements with three interstate product pipelines (see Note 16 of Notes to Consolidated Financial Statements).

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

(10) ACCRUED LIABILITIES

        Accrued liabilities are as follows (in thousands):

	March 31, 2003		June 30, 2002
Acquisition related liabilities—Coastal Fuels	$	31,000	$	—
Interest rate swap, at fair value		—		5,429
Accrued environmental obligations		2,036		2,329
Accrued corporate relocation and transition		20		2,029
Accrued lease abandonment		2,918		3,110
Accrued indemnities—NORCO		1,300		1,300
Accrued transportation and deficiency obligations		2,819		2,839
Accrued expenses		2,546		5,080
Dividend payable—preferred stock		1,093		—
Deposits and other accrued liabilities		3,288		2,126
	$	47,020	$	24,242

        Acquisition Related Liabilities—Coastal Fuels.    Acquisition related liabilities—Coastal Fuels is comprised of a deferred purchase price payable to EPME-PC and accrued liabilities assumed in the acquisition. Deferred purchase price payable of approximately $25.0 million represents contingent consideration due and payable to EPME-PC upon delivery by EPME-PC of audited financial statements of the Coastal Fuels assets. On April 25, 2003, EPME-PC delivered to us the audited financial statements of the Coastal Fuels assets and EPME-PC was paid $25.0 million on April 30, 2003. Accrued liabilities of approximately $6.0 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, litigation and lease abandonment costs and property taxes.

        Interest Rate Swap.    We had a $150 million notional value "periodic knock-out" swap agreement with a money center bank to offset the exposure of an increase in interest rates. The interest rate swap

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was carried as fair value in the accompanying consolidated balance sheets as it did not qualify as an accounting hedge for financial reporting purposes. On February 28, 2003, we settled our obligations under the interest rate swap when we repaid our former bank credit facility.

        Accrued Corporate Relocation and Transition.    During the year ended June 30, 2002, we announced to our employees that our supply, distribution, and marketing operations in Atlanta, Georgia would be relocated to Denver, Colorado. On March 19, 2002, we offered approximately 72 employees the opportunity to relocate to Denver, Colorado and we informed approximately 25 employees that they would not be offered the opportunity to relocate to Denver, Colorado. Ultimately, 35 employees chose to relocate to Denver, Colorado. Those employees are entitled to receive a transition bonus and a relocation package payable upon transfer to the Denver office. The transition bonus is being accrued over the period from date of acceptance by the employee to the expected date of arrival in Denver, Colorado. The relocation costs are being accrued as incurred or earned by the employee. Ultimately, 37 employees chose not to relocate and those employees are entitled to receive special termination benefits upon their termination date as determined by us. The special termination benefits were accrued upon receipt of the notification from the employee that they did not intend to accept the offer to relocate to Denver, Colorado.

        During the three months ended March 31, 2003, we substantially completed our employee relocation program. We expect to pay the remaining employee relocation costs before June 30, 2003.

	Accrued liability at June 30, 2002		Amounts incurred/accrued during the period		Amounts paid during the period			Accrued liability at March 31, 2003
	(in thousands)
Accrued special termination benefits to employees not relocating to Denver, Colorado	$	1,428	$	—	$	(1,428	)	$	—
Accrued transition benefits payable to employees relocating to Denver, Colorado		501		225		(726	)		—
Relocation costs incurred during the period		100		1,224		(1,304	)		20
	$	2,029	$	1,449	$	(3,458	)	$	20

        Accrued Lease Abandonment.    In connection with our corporate relocation and transition, we entered into an operating lease for new office space in Denver, Colorado. The new lease was executed on April 19, 2002. We expect to vacate our existing office space in Denver, Colorado during June 2003 and we vacated our excess space in Atlanta, Georgia during October 2002. 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

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conditions. At March 31, 2003 and June 30, 2002, the accrued liability for lease abandonment costs was approximately $2.9 million and $3.1 million, respectively.

	Accrued liability at June 30, 2002		Amounts paid during the period			Accrued liability at March 31, 2003
	(in thousands)
Accrued lease abandonment	$	3,110	$	(192	)	$	2,918

        We expect to pay the accrued liability of approximately $2.9 million, net of estimated sublease rentals, as follows (in thousands):

Years ending June 30:		Lease payments		Estimated sublease rentals			Accrued liability
	2003	$	553	$	(97	)	$	456
	2004		991		(562	)		429
	2005		1,020		(565	)		455
	2006		1,045		(569	)		476
	2007		948		(508	)		440
	Thereafter		1,243		(581	)		662
		$	5,800	$	(2,882	)	$	2,918

(11) DEFERRED REVENUE—SUPPLY MANAGEMENT SERVICES

        In connection with providing delivered fuel price management to ground fleet customers, we commit to provide our customers with logistical supply management services over the term of their respective supply contracts. At June 30, 2002, our deferred revenue associated with logistical supply management services was approximately $1.6 million. During the three and nine months ended March 31, 2003, we recognized approximately $150,000 and $450,000, respectively, in net revenues attributable to our supply, distribution and marketing operations from the amortization of the deferred revenues—supply management services.

        We enter into price management contracts with ground fleet customers that permit these customers to fix the price of their fuel purchases. During the three and nine months ended March 31, 2003, we originated price management contracts with an estimated fair value of approximately $252,000 and $4.5 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 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 will amortize the deferred revenue—supply management services

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into net 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.

	Deferred revenue at June 30, 2002		Additions during the period		Amounts amortized during the period			Deferred revenue at March 31, 2003
	(in thousands)
Logistical supply management services	$	1,600	$	—	$	(450	)	$	1,150
Retail price management contracts		—		1,683		(419	)		1,264
Delivered fuel price management contracts		—		2,792		(472	)		2,320
	$	1,600	$	4,475	$	(1,341	)	$	4,734

(12) DEBT

        Debt is as follows (in thousands):

	March 31, 2003			June 30, 2002
Commodity margin loan	$	—		$	11,312
Working capital credit facility		65,000			—
Senior secured term loan		200,000			—
Bank credit facility		—			187,000
		265,000			198,312
Less debt classified as current		(65,000	)		(11,312	)
Long-term debt	$	200,000		$	187,000

        Commodity Margin Loan.    We currently have a commodity margin loan agreement with Salomon Smith Barney 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 Salomon Smith Barney. 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% (2.92% at March 31, 2003).

        Bank Credit Facility.    On February 28, 2003 we repaid in full our former bank credit facility. Our former bank credit facility consisted of a $300.0 million revolving credit facility that was scheduled to mature on June 27, 2005. During the three and nine months ended March 31, 2003, we wrote-off the unamortized deferred debt issuance costs of approximately $2.2 million associated with the repayment of our former bank credit facility.

        New Credit Agreement.    On February 28, 2003, we executed a Credit Agreement with UBS AG that provides for a $250 million revolving line of credit ("Working Capital Credit Facility") and a $200 million senior secured term loan ("Term Loan"). In connection with the new Credit Agreement, we paid approximately $11.9 million in costs to execute the financing. The costs are comprised of:

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$5.6 million in fees paid to UBS AG for the Working Capital Credit Facility, $5.0 million in fees paid to UBS AG for the Term Loan, and $1.3 million paid to legal advisers to draft the Credit Agreement.

        Working Capital Credit Facility.    The Working Capital Credit Facility provides for a maximum borrowing line of credit that is the lesser of (i) $250 million and (ii) the borrowing base (as defined; $389 million at March 28, 2003). The maximum borrowing amount is reduced by the amount of letters of credit that are outstanding ($30.7 million at March 31, 2003). Borrowings under the Working Capital Credit Facility bear interest (at our option) based on a base rate plus a specified margin, or LIBOR plus a specified margin; the specified margins are a function of our leverage ratio (as defined). Accrued interest on the outstanding borrowings is due monthly. Borrowings under the Working Capital Credit Facility are secured by substantially all of our current assets. The terms of the Working Capital Credit Facility include financial covenants relating to fixed charge coverage, current ratio, consolidated tangible net worth, capital expenditures, cash distributions and open inventory positions that are tested on a quarterly and annual basis. As of March 31, 2003, we were in compliance with all covenants included in the Working Capital Credit Facility. The Working Capital Credit Facility matures February 28, 2006. In the accompanying consolidated balance sheet at March 31, 2003, we have classified the outstanding borrowings under the Working Capital Credit Facility as a current liability because we have pledged our current assets as security for the facility and because currently it is our expectation that we will repay the outstanding borrowings within one year of the balance sheet date.

        Senior Secured Term Loan.    The Term Loan provides for a one-time borrowing of $200 million. The Term Loan bears interest (at our option) based on a base rate plus a specified margin, or LIBOR plus a specified margin; the specified margins are a function of our leverage ratio (as defined). Accrued interest on the outstanding borrowings is due monthly. The Term Loan matures February 28, 2006. The Term Loan is secured by our property, plant and equipment and a negative pledge of the outstanding capital stock of TransMontaigne's subsidiaries. The Term Loan includes financial covenants relating to fixed charge coverage, current ratio, maximum leverage ratio, consolidated tangible net worth, capital expenditures, cash distributions and open inventory positions that are tested on a quarterly and annual basis. As of March 31, 2003, we were in compliance with all covenants included in the Term Loan.

        Scheduled maturities of debt at March 31, 2003 are as follows (in thousands):

Years ending:
	June 30, 2003	$	—
	June 30, 2004		—
	June 30, 2005		—
	June 30, 2006		265,000
		$	265,000

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(13) PREFERRED STOCK

        At March 31, 2003 and June 30, 2002, we have authorized the issuance of up to 2,000,000 shares of preferred stock. Preferred stock is as follows (in thousands, except share data):

	March 31, 2003		June 30, 2002
Series A Convertible Preferred stock, par value $0.01 per share, 250,000 shares authorized, 24,421 shares issued and outstanding, liquidation preference of $24,421	$	24,421	$	24,421
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	$	79,732	$	80,939

        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 a newly created and designated preferred stock ("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.

        Preferred stock dividends on the Series A Convertible Preferred stock were $0.3 million and $2.5 million for the three months ended March 31, 2003 and 2002, respectively. Preferred stock dividends on the Series A Convertible Preferred stock were $0.9 million and $7.3 million for the nine months ended March 31, 2003 and 2002, respectively. Preferred Stock dividends on the Series B Redeemable Convertible Preferred Stock were $0.7 million and $2.1 million for the three and nine months ended March 31, 2003, respectively. The amount of the Series B Redeemable Convertible Preferred Stock dividend recognized for financial reporting purposes for the nine months ended March 31, 2003 is composed of the amount of the dividend payable and paid to the holders of the Series B Redeemable Convertible Preferred Stock of $3.3 million offset by the amortization of the premium on the carrying amount of the Series B Redeemable Convertible Preferred Stock of $1.2 million.

(14) COMMON STOCK

        At March 31, 2003 and June 30, 2002, we were authorized to issue up to 80,000,000 shares of common stock with a par value of $0.01 per share. At March 31, 2003 and June 30, 2002, there were 40,663,447 shares and 39,942,658 shares issued and outstanding, respectively. Our credit agreement and the certificates of designations of our preferred stock contain restrictions on the payment of dividends on our common stock.

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        We have a restricted stock plan that provides for awards of common stock to certain key employees, subject to forfeiture if employment terminates prior to the vesting dates. The market value of shares awarded under the plan is recorded in common stockholders' equity as deferred stock-based compensation. On October 25, 2002 and March 1, 2003, we granted awards of 690,000 and 120,500 shares of restricted common stock to certain key employees. The deferred-stock based compensation associated with those awards is approximately $3.5 million, which is being amortized to income over their respective four-year vesting period.

        During December 2002, two employees experienced a change in employment status. Following the change in employment status, the former employees began to provide consulting services. Pursuant to the existing terms of our stock option plans, the employees were permitted to retain their original grants of stock options and awards of restricted stock. In accordance with FASB Interpretation No. 44,Accounting for Certain Transactions involving Stock Compensation, we recognized deferred-stock based compensation of approximately $0.3 million, which is being amortized to income over their respective vesting periods. The deferred-stock based compensation was calculated using the Black-Scholes model and the unvested portion of the original grants at the date of change in employment status.

        Amortization of deferred compensation of approximately $0.7 million and $0.4 million is included in selling, general and administrative expense for the three months ended March 31, 2003 and 2002, respectively. Amortization of deferred compensation of approximately $1.6 million and $1.1 million is included in selling, general and administrative expense for the nine months ended March 31, 2003 and 2002, respectively.

(15) STOCK OPTIONS

        We have three stock option plans under which stock options have been granted to employees. At June 30, 2002, we had options outstanding to acquire approximately 1.3 million shares of common stock of which options to acquire approximately 0.4 million shares were vested. We did not grant any options during the three and nine months ended March 31, 2003. 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. If compensation expense for our stock-based compensation plans had been determined based on the fair value method pursuant to SFAS 123, our net earnings and

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earnings per common share would have been reduced to the pro forma amounts indicated below (in thousands, except for per share amounts):

			Three months ended March 31,				Nine months ended March 31,
			2003		2002		2003			2002
Net earnings attributable to common stockholders:									��
	As reported		$	27,045	$	6,265	$	10,194		$	8,115
	Pro forma		$	26,972	$	6,213	$	9,976		$	7,958
Earnings per common share:
	As reported
		Basic	$	0.69	$	0.20	$	0.26		$	0.26
		Diluted	$	0.54	$	0.20	$	0.24		$	0.26
	Pro forma
		Basic	$	0.69	$	0.20	$	0.26		$	0.26
		Diluted	$	0.52	$	0.20	$	0.20		$	0.25

        For purposes of these pro forma disclosures, the estimated fair value of options granted to employees is amortized to expense over the vesting period of the options.

(16) 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, 2002, we recognized an accrued liability of approximately $1.0 million (see Note 10 of Notes to Consolidated Financial Statements) representing our estimate of the future payments 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 nine months ended March 31, 2003, we paid approximately $0.2 million as settlement for our shortfall in volumes for the year ended June 30, 2002. Based on actual throughput volumes for the nine months ended March 31, 2003, we increased our accrued liabilities by $0.2 million resulting in a total accrued liability of $1.0 million as of and for the nine months ended March 31, 2003.

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        We also are subject to three transportation and deficiency agreements ("T&D's") with three separate product 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 counter-party for any shortfall at the contracted pipeline tariff. Such payments are accounted for as prepaid transportation, since we have a contractual right to apply the amounts to charges for using the interstate pipeline after the end of the term of the T&D.

        At June 30, 2002, prepaid transportation of approximately $2.6 million is included in other assets (see Note 9 of Notes to Consolidated Financial Statements) and our accrued liability, representing our estimate of the future payments we expect to pay for the estimated shortfall in volumes for the remainder of the terms of the T&D agreements, is approximately $1.8 million (see Note 10 of Notes to Consolidated Financial Statements). Based on actual volumes shipped during the nine months ended March 31, 2003, we made no adjustments to the prepaid transportation or accrued liability as of and for the nine months ended March 31, 2003.

(17) EARNINGS PER SHARE

        The following table reconciles the computation of basic and diluted weighted average shares (in thousands):

			Three months ended March 31,		Nine months ended March 31,
			2003	2002	2003	2002
Basic weighted average shares			39,144	31,217	39,101	31,189
Effect of dilutive securities:
	Restricted common stock subject to continuing vesting requirements		22	85	12	91
	Stock options		97	234	131	258
	Common stock issuable upon conversion of:
		Series A Convertible Preferred stock	1,628	—	—	—
		Series B Redeemable Convertible Preferred stock	11,044	—	11,044	—
Diluted weighted average shares			51,935	31,536	50,288	31,538

        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 dilutive earnings per

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share computation for the nine months ended March 31, 2003, as their inclusion would have been anti-dilutive:

		Nine months ended March 31, 2003
Restricted common stock subject to continuing vesting requirements		716,429
Common stock issuable upon exercise of stock options		399,000
Common stock issuable upon exercise of stock purchase warrants		900,045
Common stock issuable upon conversion of
	Series A Convertible Preferred stock	1,628,082
		3,643,556

        For the three and nine months ended March 31, 2003, the stock options had a weighted average exercise price of $5.70 per share, and the stock purchase warrants had a weighted average exercise price of $14.00 per share. The Series A Convertible Preferred stock had a conversion price of $15.00 for the nine months ended March 31, 2003.

(18) BUSINESS SEGMENTS

        Our chief operating decision maker is our chief executive officer ("CEO"). Our CEO reviews financial performance presented on a consolidated basis, accompanied by disaggregated information about net operating margins by operating activity for purposes of making operating decisions and assessing financial performance. Accordingly, we present net operating margins for our two business segments: (i) terminals, pipelines, and tugs and barges and (ii) supply, distribution and marketing.

        Our CEO assesses the financial performance of our supply, distribution, and marketing segment using financial information that is prepared pursuant to the mark-to-market method of accounting. Under the mark-to-market method of accounting, the effects of changes in the fair value of our supply, distribution, and marketing activities are included in net operating margins. Our inventories—discretionary volumes are an integral component of our supply, distribution and marketing activities and, therefore, are measured at fair value for purposes of determining our net operating margins attributable to our supply, distribution, and marketing segment.

        During the three months ended March 31, 2003, our CEO began receiving additional disaggregated information regarding the components contributing to the net operating margins within the supply, distribution and marketing segment. That detailed information has been presented below for the three and nine months ended March 31, 2003; however, it is not available for periods beginning before July 1, 2002.

        We believe that "operating results for debt covenant compliance" is an important measure of the profit and loss for our reportable segments. We consider this measure important because it reflects the ability of our operations to generate funds to pay our fixed obligations, including interest and principal on our debt, as they become due. This measure is used as a measure of our financial performance in our borrowing arrangements.

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        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:

•

Supply, distribution and marketing—consists of services for the supply and distribution of refined petroleum products through rack sales, bulk sales and contract sales in the physical and derivative markets, with retail, wholesale, industrial and commercial customers using our truck terminal rack locations and marine refueling equipment, and providing related value-added fuel procurement and supply management services.



•

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 Williams pipeline systems.



•

Corporate—consists of our investments in non-controlled business ventures and general corporate items that are not allocated to specific segments (e.g., financing costs and income taxes).

F-28

        The operating performance of our business segments, including a reconciliation of the segments' operating performance to earnings before income taxes as presented in the accompanying consolidated statements of operations is as follows (in thousands):

							Three months ended March 31, 2003			Nine months ended March 31, 2003
Net Operating Margins:
	Terminals, pipelines, and tugs and barges:
		Historical facilities					$	10,874		$	32,547
		Coastal facilities						1,676			1,676
				Total terminals, pipelines, and tugs and barges				12,550			34,223
	Supply, distribution and marketing:
		Light oil marketing:
			Rack sales margins					2,991			5,531
			Contract sales margins					3,712			6,187
			Bulk sales margins					22,069			38,528
					Margins before hedging cost			28,772			50,246
			Unwinding hedging positions during inventory liquidation and rolling inventory hedges to future months					(20,655	)		(26,760	)
					Margins, net of hedging activity			8,117			23,486
			Trading activity					30			(1,923	)
								8,147			21,563
		Supply management services						3,522			11,062
		Heavy oil marketing						2,489			2,489
				Total supply, distribution and marketing				14,158			35,114
						Total net operating margins		26,708			69,337
Selling, general and administrative expenses								(10,440	)		(29,996	)
Dividend income								—			374
						Operating results for debt covenant compliance	$	16,268		$	39,715
Reconciliation to Earnings Before Income Taxes:
	Operating results for debt covenant compliance						$	16,268		$	39,715
	Inventory adjustments:
		Gains recognized on beginning inventories—discretionary volumes						33,490			12,644
		Net margin recognized on sale of inventories—minimum volumes						18,854			18,854
		Lower of cost or market write-down on base operating inventory volumes						(12,412	)		(12,412	)
		Lower of cost or market write-down on inventories—minimum volumes						(633	)		(633	)
	Other Items:
		Depreciation and amortization						(4,851	)		(13,400	)
		Dividend income						—			(374	)
						Operating income		50,716			44,394
		Other income (expense), net						(5,484	)		(10,488	)
						Earnings before income taxes	$	45,232		$	33,906

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	Three months ended March 31, 2002
	Product supply, distribution, and marketing			Terminals and pipelines			Corporate			Total consolidated
Net operating margins	$	20,106		$	9,596		$	—		$	29,702
Selling, general and administrative		(5,298	)		(2,041	)		(1,616	)		(8,955	)
Depreciation and amortization		(59	)		(3,556	)		(528	)		(4,143	)
Corporate relocation and transition		(315	)		—			—			(315	)
		(5,672	)		(5,597	)		(2,144	)		(13,413	)
Operating income (loss)	$	14,434		$	3,999		$	(2,144	)		16,289
Other income (expense), net											(2,200	)
Earnings before income taxes										$	14,089
Capital expenditures	$	—		$	1,331		$	2,020		$	3,351

	Nine months ended March 31, 2002
	Product supply, distribution, and marketing			Terminals and pipelines			Corporate			Total consolidated
Net operating margins	$	48,471		$	26,450		$	—		$	74,921
Selling, general and administrative		(15,214	)		(5,673	)		(4,718	)		(25,605	)
Depreciation and amortization		(59	)		(10,815	)		(1,575	)		(12,449	)
Corporate relocation and transition		(315	)		—			—			(315	)
		(15,588	)		(16,488	)		(6,293	)		(38,369	)
Operating income (loss)	$	32,883		$	9,962		$	(6,293	)		36,552
Other income (expense), net											(11,671	)
Earnings before income taxes										$	24,881
Capital expenditures	$	62		$	2,244		$	2,155		$	4,461

F-30

Independent auditors' report

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, 2002 and 2001, 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, 2002. These consolidated financial statements are the responsibility of TransMontaigne's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

        We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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, 2002 and 2001, and the results of their operations and their cash flows for each of the years in the three-year period ended June 30, 2002, in conformity with accounting principles generally accepted in the United States of America.

/s/ KPMG LLP

Denver, Colorado
September 13, 2002, except as to the fourth paragraph of note 1(c),
which is as of May 12, 2003

F-31

TransMontaigne Inc. and subsidiaries

Consolidated balance sheets

(In thousands, except share amounts)

			June 30, 2002			June 30, 2001
ASSETS
Current assets:
	Cash and cash equivalents		$	30,852		$	25,775
	Restricted cash held by commodity broker			8,621			7,984
	Trade accounts receivable, net			173,736			79,050
	Inventories—discretionary volumes			175,169			96,988
	Unrealized gains on supply management services			14,525			28,689
	Receivable from sale of assets			—			29,033
	Prepaid expenses and other			2,598			4,130
				405,501			271,649
Property, plant and equipment, net				251,431			304,232
Inventories—minimum volumes				45,298			58,261
Unrealized gains on supply management services				8,093			9,875
Investments in petroleum related assets				10,131			47,760
Deferred tax assets				7,882			12,944
Deferred debt issuance costs, net				2,729			4,667
Other assets				4,263			2,977
			$	735,328		$	712,365
LIABILITIES, PREFERRED STOCK, AND COMMON STOCKHOLDERS' EQUITY
Current liabilities:
	Commodity margin loan		$	11,312		$	20,000
	Trade accounts payable			102,780			72,170
	Unrealized losses on supply management services			8,522			24,596
	Inventory due to others under exchange agreements			16,908			76,754
	Excise taxes payable			72,045			32,025
	Other accrued liabilities			25,842			14,170
				237,409			239,715
Other liabilities:
	Long-term debt			187,000			130,000
	Unrealized losses on supply management services			209			275
		Total liabilities		424,618			369,990
Preferred stock:
	Series A Convertible Preferred stock			24,421			174,825
	Series B Redeemable Convertible Preferred stock			80,939			—
				105,360			174,825
Common stockholders' equity:
	Common stock			399			318
	Capital in excess of par value			245,844			205,256
	Deferred stock-based compensation			(2,540	)		(2,465	)
	Accumulated deficit			(38,353	)		(35,559	)
				205,350			167,550
			$	735,328		$	712,365

See accompanying notes to consolidated financial statements.

F-32

TransMontaigne Inc. and subsidiaries

Consolidated statements of operations

(In thousands, except per share amounts)

				Year ended June 30, 2002			Year ended June 30, 2001			Year ended June 30, 2000
Supply, distribution and marketing:
	Revenues			$	6,001,170		$	5,182,492		$	5,014,752
	Cost of product sold				(5,932,423	)		(5,136,174	)		(4,995,899	)
	Lower of cost or market write-downs on minimum inventory volumes				(12,963	)		(18,318	)		—
			Net operating margins		55,784			28,000			18,853
Terminal and pipelines:
	Revenues				63,386			82,305			78,522
	Less direct operating costs and expenses				(27,668	)		(36,415	)		(34,268	)
			Net operating margins		35,718			45,890			44,254
Natural gas services:
	Revenues				—			—			18,249
	Less direct operating costs and expenses				—			—			(7,759	)
			Net operating margins		—			—			10,490
			Total net operating margins		91,502			73,890			73,597
Costs and expenses:
	Selling, general and administrative				(35,211	)		(34,072	)		(41,680	)
	Depreciation and amortization				(16,556	)		(19,510	)		(22,344	)
	Impairment of long-lived assets				—			—			(50,136	)
	Corporate relocation and transition:
		Severance, transition, and relocation benefits			(2,138	)		—			—
		Abandonment of office leases and leasehold improvements			(4,178	)		—			—
					(58,083	)		(53,582	)		(114,160	)
			Operating income (loss)		33,419			20,308			(40,563	)
Other income (expenses):
	Dividend income from and equity in earnings of petroleum related investments				1,450			3,060			1,590
	Interest income				599			2,914			3,419
	Interest expense				(12,436	)		(18,129	)		(28,540	)
	Other financing costs:
		Early payment penalty on senior notes			(1,943	)		(1,277	)		(875	)
		Amortization of debt issuance costs			(1,744	)		(3,499	)		(3,770	)
		Write-off of debt issuance costs related to bank credit facility and senior notes			(2,987	)		(3,885	)		(3,855	)
		Unrealized gain (loss) on interest rate swap			(2,322	)		(3,634	)		1,560
	Gain (loss) on disposition of assets, net				(13	)		22,146			13,930
					(19,396	)		(2,304	)		(16,541	)
			Earnings (loss) before income taxes		14,023			18,004			(57,104	)
Income tax benefit (expense)					(5,465	)		(6,666	)		19,167
			Net earnings (loss)	$	8,558		$	11,338		$	(37,937	)

F-33

			Year ended June 30, 2002			Year ended June 30, 2001			Year ended June 30, 2000
Computation of earnings (loss) per share:
	Net earnings (loss)		$	8,558		$	11,338		$	(37,937	)
	Preferred stock dividends			(11,351	)		(8,963	)		(8,506	)
		Net earnings (loss) attributable to common stockholders	$	(2,793	)	$	2,375		$	(46,443	)
Earnings (loss) per common share
		Basic	$	(0.09	)	$	0.08		$	(1.52	)
		Diluted	$	(0.09	)	$	0.08		$	(1.52	)
Weighted average common shares outstanding:
		Basic		31,267			30,879			30,491
		Diluted		31,267			31,003			30,491

See accompanying notes to consolidated financial statements.

F-34

TransMontaigne Inc. and subsidiaries

Consolidated statements of preferred stock and common stockholders' equity

Years ended June 30, 2002, 2001 and 2000

(In thousands)

		Preferred stock														Retained earnings (accumulated deficit)			Total common stockholders' equity
							Common stock			Capital in excess of par value			Deferred stock-based compensation
		Series A			Series B
Balance at June 30, 1999		$	170,115		$	—	$	305		$	197,122		$	—		$	8,509		$	205,936
	Common stock issued for options exercised		—			—		—			136			—			—			136
	Net tax effect arising from stock-based compensation		—			—		—			(68	)		—			—			(68	)
	Deferred compensation related to restricted stock awards		—			—		2			1,863			(1,865	)		—			—
	Amortization of deferred stock-based compensation		—			—		—			—			400			—			400
	Compensation expense related to extension of exercise period of options		—			—		—			2,022			—			—			2,022
	Preferred stock dividends		—			—		—			—			—			(8,506	)		(8,506	)
	Net loss		—			—		—			—			—			(37,937	)		(37,937	)
Balance at June 30, 2000			170,115			—		307			201,075			(1,465	)		(37,934	)		161,983
	Common stock issued for options and warrants exercised		—			—		6			1,891			—			—			1,897
	Net tax effect arising from stock-based compensation		—			—		—			(5	)		—			—			(5	)
	Forfeiture of restricted stock awards prior to vesting		—			—		—			(135	)		135			—			—
	Deferred compensation related to restricted stock awards		—			—		5			2,430			(2,435	)		—			—
	Amortization of deferred stock-based compensation		—			—		—			—			1,300			—			1,300
	Preferred stock dividends, including $4,710 paid-in-kind		4,710			—		—			—			—			(8,963	)		(8,963	)
	Net earnings		—			—		—			—			—			11,338			11,338
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

See accompanying notes to consolidated financial statements.

F-35

TransMontaigne Inc. and subsidiaries

Consolidated statements of cash flows

(In thousands)

					Year ended June 30, 2002			Year ended June 30, 2001			Year ended June 30, 2000
Cash flows from operating activities:
	Net earnings (loss)				$	8,558		$	11,338		$	(37,937	)
	Adjustments to reconcile net earnings (loss) to net cash provided (used) by operating activities:
		Depreciation and amortization				16,556			19,510			22,344
		Equity in earnings of petroleum related investments				—			93			—
		Deferred tax expense (benefit)				5,062			6,224			(19,948	)
		Net tax effect arising from stock-based compensation				(24	)		(5	)		(68	)
		Loss (gain) on disposition of assets, net				13			(22,146	)		(13,930	)
		Impairment of long-lived assets				—			—			50,136
		Abandonment of office leases				3,110			—			—
		Abandonment of leasehold improvements				1,068			—			—
		Amortization of deferred stock-based compensation				1,512			1,300			400
		Amortization of debt issuance costs				1,744			3,499			3,770
		Write-off of debt issuance costs				2,987			3,885			3,855
		Unrealized loss (gain) on interest rate swap				2,322			3,634			(1,560	)
		Net change in unrealized (gains)/losses on long-term supply management services contracts				1,716			(13,307	)		—
		Lower of cost or market write-downs on minimum inventory volumes				12,963			18,318			—
		Compensation expense related to extension of exercise period on options				—			—			2,022
		Other				538			—			316
		Changes in operating assets and liabilities, net of non-cash activities:
			Trade accounts receivable, net			(94,686	)		38,689			56,383
			Inventories—discretionary volumes			(78,182	)		67,302			127,891
			Prepaid expenses and other			1,533			1,944			(1,719	)
			Trade accounts payable			30,609			(34,507	)		(58,795	)
			Unrealized (gain)/loss on supply management services contracts			(1,910	)		(14,724	)		32,783
			Inventory due under exchange agreements, net			(59,845	)		(48,504	)		99,467
			Excise taxes payable and other accrued liabilities			42,844			9,393			2,116
				Net cash provided (used) by operating activities		(101,512	)		51,936			267,526
Cash flows from investing activities:
	Purchases of property, plant and equipment					(15,809	)		(11,542	)		(61,264	)
	Proceeds from sale of assets					120,510			1,439			137,357
	Decrease (increase) in restricted cash held by commodity broker					(637	)		(7,984	)		—
	Decrease (increase) in other assets					(1,286	)		(882	)		1,809
				Net cash provided (used) by investing activities		102,778			(18,969	)		77,902
Cash flows from financing activities:
	Net borrowings (repayments) of long-term debt					57,000			(76,995	)		(290,677	)
	Net borrowings (repayments) of commodity margin loan					(8,688	)		20,000			—
	Deferred debt issuance costs					(2,791	)		(1,779	)		(6,370	)
	Common stock issued for options and warrants exercised					151			1,897			136
	Common stock repurchased from employees for withholding taxes					(112	)		—			—
	Common stock repurchased and retired					(20,446	)		—			—
	Cash paid to recapitalize preferred stock					(21,303	)		—			—
	Preferred stock dividends paid in cash					—			(4,253	)		(8,506	)
				Net cash provided (used) by financing activities		3,811			(61,130	)		(305,417	)
				Increase (decrease) in cash and cash equivalents		5,077			(28,163	)		40,011
Cash and cash equivalents at beginning of year						25,775			53,938			13,927
Cash and cash equivalents at end of year					$	30,852		$	25,775		$	53,938

F-36

			Year ended June 30, 2002			Year ended June 30, 2001			Year ended June 30, 2000
Supplemental disclosures of cash flow information:
Cash paid for income taxes			$	600		$	700		$	200
Cash paid for interest expense			$	12,240		$	19,731		$	26,542
Sale of Bear Paw on December 31, 1999:
	Assets disposed		$	—		$	—		$	(114,313	)
	Liabilities recorded			—			—			(250	)
	Interest income			—			—			(78	)
	Gain on disposition			—			—			(16,587	)
	Cash received from sale		$	—		$	—		$	131,228
Sale of Little Rock facilities on June 30, 2001:
	Proceeds receivable		$	—		$	29,033		$	—
	Assets disposed			—			(6,162	)		—
	Liabilities recorded:
		Accrued environmental obligations		—			(700	)		—
		Other		—			(25	)		—
	Gain on disposition			—			(22,146	)		—
	Cash received from sale		$	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			$	631		$	1,439		$	6,129
Total cash received from sales of assets			$	120,510		$	1,439		$	137,357

See accompanying notes to consolidated financial statements.

F-37

TransMontaigne Inc. and subsidiaries

Notes to consolidated financial statements

Years ended June 30, 2002, 2001 and 2000

(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 intercompany accounts and transactions have been eliminated in consolidation.

        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. 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"), was formed in 1995 to create an independent petroleum products merchant based in Denver, Colorado. We are a holding company that conducts operations primarily in the Mid-Continent, Gulf Coast, Southeast, Mid-Atlantic and Northeast regions of the United States. We provide a broad range of integrated supply, distribution, marketing, terminal storage, and transportation services to refiners, distributors, marketers, and industrial/commercial end-users of refined petroleum products (e.g., gasoline, diesel fuel, and heating oil), chemicals, crude oil and other bulk liquids.

        Our commercial operations currently are divided into two main areas: (i) supply, distribution, and marketing, and (ii) terminals and pipelines.

(c)   Accounting for Supply, Distribution, and Marketing Operations

        Our supply, distribution, and marketing operations include energy trading and risk management activities. Our energy trading and risk management activities are marked to market (i.e., recorded at fair value in the accompanying consolidated balance sheet) in accordance with Emerging Issues Task Force 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.

        The consensus on EITF 98-10 previously permitted revenues from energy trading and risk management activities to be presented on the face of the statement of operations on either a gross or net basis. We previously elected to present revenues from our supply, distribution, and marketing operations on a gross basis with a separate line item entitled "Product costs" in the costs and expenses section of the accompanying consolidated statements of operations. Product costs represent the cost of the products sold, settlement of risk management contracts, transportation, storage, terminaling costs, and commissions. At its June 2002 meeting, the EITF amended its consensus on EITF 98-10 to require that revenues from energy trading and risk management activities be reported on a net basis (i.e., product costs are required to be netted directly against gross revenues to arrive at net revenues). That

F-38

amended guidance is effective for financial statements issued for periods ending after July 15, 2002. We previously chose to adopt early that amended guidance for all periods presented. Therefore, for the year ended June 30, 2002 and all prior periods, we originally presented revenues from our supply, distribution and marketing operation on a net basis.

        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 energy trading and risk management activities should no longer be marked to market pursuant to the guidance in Issue No. 98-10 ("EITF 98-10"),Accounting for Contracts Involved in Energy Trading and Risk Management Activities. Pursuant to the consensus on EITF 02-03, energy trading and risk management activities that qualify as derivative contracts are reported as assets and liabilities at fair value in accordance with Statement of Financial Accounting Standards No. 133 ("SFAS No. 133"),Accounting for Derivative Instruments and Hedging Activities. Energy trading and risk management activities that do not qualify as derivative contracts are treated as executory contracts and recognized pursuant to the accrual method of accounting (i.e., when cash becomes due and payable to us or our customers pursuant to the terms of the contracts).

        In accordance with EITF 02-03, all gains and losses (realized and unrealized) on derivative contracts are to be presented on a net basis in the consolidated statement of operations whether or not the contracts are settled physically. Gains and losses on executory contracts are to be presented on a gross basis in the consolidated statements of operations. Accordingly, our bulk, rack, and contract sales have been recast to be presented on a gross basis for each of the years in the three-year period ended June 30, 2002. Revenue from our supply management services contracts is required to be presented on a net basis, however, it is impracticable to derive this information.

        The cash flow impact of these energy trading and risk management activities is reflected in cash flows from operating activities in the accompanying consolidated statements of cash flows.

        We evaluate our market exposure, primarily commodity price risk, from an overall portfolio basis that considers both continuous movement of discretionary inventory volumes and related open positions in energy services and risk management contracts. Our inventories—discretionary volumes are an integral component of our overall energy trading and risk management activities.

        Supply Management Services Contracts.    We enter into supply management services contracts that require us to deliver physical quantities of product over a specified term at a specified price. The pricing of the product delivered under supply management services contracts may be fixed at a stipulated price per gallon, or it may vary based on changes in published indices (e.g., Platt's—Bulk and OPIS—Wholesale).

        Our supply management services contracts are carried at fair value in the accompanying consolidated financial statements. The fair value of our supply management services contracts is included in "Unrealized gains or losses on supply management services and risk management contracts" in the accompanying consolidated balance sheet. Changes in the fair value of our supply management services contracts are included in net operating margins attributable to our supply, distribution and marketing operations.

F-39

        The fair value of a supply management services contract is based on a combination of published daily 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, and/or a throughput/exchange arrangement, fair value is determined by adding the quoted near month New York Mercantile Exchange ("NYMEX") futures quote to the appropriate basis (geographical location) 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 (geographical location) differentials for certain deferred trading months and city-specific locations because we cannot secure a forward traded basis (geographical location) differential quote from a broker. In those situations, our mark-to-market model estimates the basis (geographical locations) differentials based on a rolling historical average, which is updated quarterly.

        For market locations in which we do not have access to product via our terminals, dedicated pipeline capacity, and/or a throughput/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 wholesale 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 (geographical location) differential to each city-specific location.

        Risk Management Contracts.    We enter into risk management contracts to minimize 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, open positions in supply management services contracts, and open positions in risk management contracts. We enter into risk management contracts that offset the changes in the values of our inventories—discretionary volumes and supply management services contracts. At June 30, 2002, our open positions in risk management contracts include forward contracts (purchases and sales).

        Our risk management contracts are carried at fair value in the accompanying consolidated financial statements. Changes in the fair value of our risk management contracts are included in net operating margins attributable to our supply, distribution and marketing operations. The fair value of our risk management contracts is based on quoted market prices. Forward contracts (purchases and sales) are valued using NYMEX quoted market prices.

        We also enter into various swap agreements with our trading partners and price risk management customers that settle against a wide variety of wholesale and retail pricing indices. We utilize a combination of futures contracts and over-the-counter forward contracts to manage the commodity price risk associated with these contracts. Our methodology used to calculate a forward replacement cost for these instruments is consistent with the methodology used to value our forward physical cash commitments. We use a rolling historical average difference between the pricing index that the swap contract utilizes (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.

        Inventories—Discretionary Volumes.    Our inventories—discretionary volumes are held for sale or exchange in the ordinary course of business and consist of refined petroleum products, primarily gasoline and distillates. Our inventories—discretionary volumes are carried at fair value in the

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accompanying consolidated financial statements. Changes in the fair value of our inventories—discretionary volumes are included in net operating margins attributable to our supply, distribution and marketing operations.

        We maintain and hold for sale or exchange discretionary inventory that has different quality grades but is interchangeable within these grades (e.g., premium, mid-grade, and regular unleaded gasoline). Our refined petroleum products inventories are traded in futures markets, 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. The valuation of our inventories—discretionary volumes is based on the nearest quoted market price, plus quoted basis (geographical location) differentials to the various bulk market areas, plus Federal Energy Regulatory Commission regulated transportation costs and industry recognized handling charges to city-specific wholesale markets. Near-term basis (geographical location) differentials are quoted and traded in the over-the-counter petroleum markets and are verified by the various cash brokers that facilitate trading. We estimate the basis (geographical location) differentials for certain deferred trading months and city-specific locations because we cannot secure a forward traded basis (geographical location) differential quote from a broker. In those situations, our mark-to-market model estimates the basis (geographical locations) differentials based on a rolling historical average, which is updated quarterly.

        We utilize this valuation methodology for all inventories—discretionary volumes held by us in storage, along with any valuation of a related exchange imbalance with a trading partner. This methodology provides us a consistent means of valuing discretionary inventory volumes at a spot liquidation value and utilizes pricing components that are based on market prices and regulated pipeline tariffs.

        Inventories—Minimum Volumes.    Our inventories—minimum volumes are required to be held for operating balances in the conduct of our overall operating activities. We do not consider our inventories—minimum volumes to be a component of our energy trading and risk management activities. We do not intend to sell or exchange these inventories in the ordinary course of business and, therefore, we do not hedge the market risks associated with this minimum inventory.

        Our inventories—minimum volumes are presented in the accompanying consolidated balance sheet as non-current assets and are carried at the lower of cost or market (replacement cost). The replacement cost of our inventories—minimum volumes is based on the nearest quoted market price, plus quoted basis (geographical location) differentials to the various bulk market areas, plus Federal Energy Regulatory Commission regulated transportation costs and industry recognized handling charges to city-specific wholesale markets. Near-term basis (geographical location) differentials are quoted and traded in the over-the-counter petroleum markets and are easily verified by the various cash brokers that facilitate trading.

        Prior to July 1, 2000, we carried our inventories—minimum volumes at fair value because they were a component of our energy trading and risk management activities. Effective July 1, 2000, upon completion of a review of our inventory management strategies and customer contracts, we designated 2.0 million barrels of refined petroleum products as inventories—minimum volumes and we changed our risk management strategy associated with this minimum inventory. In accordance with our revised

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risk management strategy, we removed the hedging contracts on the inventories—minimum volumes prior to July 1, 2000.

(d)   Accounting for Terminal and Pipeline Activities

        In connection with our terminal and pipeline operations, we utilize the accrual method of accounting for revenue and expenses. At our terminals and pipelines, we provide throughput, storage, and transportation related services to distributors, marketers, and industrial/commercial end-users of products. 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.

(e)   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.

(f)    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. For the years ended June 30, 2002, 2001 and 2000, we incurred repairs and maintenance costs of approximately $7.7 million, $8.7 million, and $7.3 million, respectively. Computer software costs are capitalized and amortized over their useful lives, generally not to exceed 5 years. The costs of installing certain enterprise wide information systems are amortized over periods not exceeding 10 years.

        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 (see Note 9 of Notes to Consolidated Financial Statements).

(g)   Deferred Debt Issuance Costs

        Deferred debt issuance costs are amortized using the interest method over the term of the underlying debt instrument.

(h)   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

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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 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. At June 30, 2002 and 2001, we had accrued environmental reserves of approximately $2.3 million and $0.7 million, respectively, representing our best estimate of our remediation obligations (see Note 11 of Notes to Consolidated Financial Statements). During the year ended June 30, 2002, we made payments of approximately $0.4 million towards our remediation obligations.

(i)    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.

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

(k)   Earnings (Loss) Per Common 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

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earnings (loss) per share also gives effect, when dilutive, to the conversion of the preferred stock pursuant to the if-converted method.

(l)    Reclassifications

        Certain amounts in the prior years have been reclassified to conform to the current year's presentation. We have classified the portion of our restricted cash held by commodity broker that represents the variation margin deposits as an offset against unrealized gains and losses on risk management contracts in the accompanying consolidated balance sheets. We have classified inventories—minimum volumes as a non-current asset in the accompanying consolidated balance sheet (see Note 7 of Notes to Consolidated Financial Statements). We also have presented separately the current and non-current unrealized gains/losses on open supply management services contracts in the accompanying consolidated balance sheet (see Note 5 of Notes to Consolidated Financial Statements). At June 30, 2001, we presented our commodity margin loan (see Note 12 of Notes to Consolidated Financial Statements) as an offset to cash and cash equivalents and we presented our preferred stock as a component of stockholders' equity (see Note 14 of Notes to Consolidated Financial Statements) in the accompanying consolidated balance sheet. Net earnings (loss) have not been affected by these reclassifications.

(2) DISPOSITIONS OF TERMINALS AND PIPELINES

        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 year ended June 30, 2001, we recognized net revenues of approximately $8.6 million, direct operating costs and expenses of approximately $3.3 million, and depreciation and amortization expense of approximately $3.0 million related to the operations of the NORCO system.

        Effective June 30, 2001, we sold two petroleum distribution facilities in Little Rock, Arkansas for $29.0 million. The cash proceeds from the sales transactions were received on July 3, 2001. We recognized a net gain in June 2001 of approximately $22.1 million on the sale. For the year ended June 30, 2001, we recognized net revenues of approximately $4.7 million, direct operating costs and expenses of approximately $0.9 million, and depreciation and amortization expense of approximately $0.4 million.

        Effective December 31, 1999, we sold our natural gas gathering subsidiary, Bear Paw Energy Inc. ("BPEI"), for cash consideration of $131.2 million and recognized a net gain of approximately $16.6 million on the sale.

(3) ACQUISITIONS OF TERMINALS AND PIPELINES

        Effective June 30, 2002, we acquired for cash consideration of approximately $7.2 million the remaining 40% interest that we previously did not own in the Razorback Pipeline system ("Razorback"), a 67 mile petroleum products pipeline between Mount Vernon, Missouri and Rogers, Arkansas with approximately .4 million barrels of storage capacity.

        On May 31, 2000, we acquired two products terminals located in Richmond and Montvale, Virginia for cash consideration of approximately $3.2 million. These facilities are interconnected to the Colonial and Plantation pipeline systems and include approximately 0.5 million barrels of storage capacity.

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        We accounted for these acquisitions using the purchase method of accounting as of the effective date of each transaction. Accordingly, the purchase price of each transaction was allocated to the assets and liabilities acquired based upon the estimated fair value of those assets and liabilities as of the acquisition date. The purchase price was allocated as follows (in thousands):

	Razorback			Virginia terminals
Prepaid expenses and other current assets	$	2		$	—
Property, plant and equipment		7,188			3,234
Other accrued liabilities assumed		(75	)		—
Cash paid, net of cash acquired of $85 and $0, respectively	$	7,115		$	3,234

        The proforma combined results of operations including Razorback as if the acquisition of Razorback had occurred on July 1, 2001 would not have been materially different from the results of operations reported in the accompanying consolidated statements of operations.

(4) INVENTORIES—DISCRETIONARY VOLUMES

        Inventories—discretionary volumes are as follows (in thousands):

		June 30, 2002		June 30, 2001
Products held for sale or exchange		$	158,261	$	20,234
Products due under exchange agreements, net			16,908		76,754
	Inventories—discretionary volumes	$	175,169	$	96,988

        Our inventories—discretionary volumes are held for sale or exchange in the ordinary course of business and consist of products, primarily gasolines and distillates. Our inventories—discretionary volumes are presented in the accompanying consolidated balance sheet as current assets and are carried at fair value. Changes in the fair value of our inventories—discretionary volumes are included in net operating margins attributable to our supply, distribution and marketing segment. Products due under exchange agreements represent physical products in our possession that we owe to counterparties pursuant to an exchange agreement in which we exchange product in a specified delivery location for product in a different delivery location.

        Our inventories—discretionary volumes are an integral component of our overall energy trading and risk management activities. We manage inventories—discretionary volumes in combination with supply management services and risk management contracts by utilizing risk and portfolio management disciplines, including certain hedging strategies, forward purchases and sales, swaps and other financial instruments to manage market exposure, primarily commodity price risk (see Note 5 of Notes to Consolidated Financial Statements). At June 30, 2002 and 2001, we held for sale or exchange approximately 5.7 million and 3.3 million barrels of discretionary inventory, including .5 million and 2.8 million barrels due to others under exchange agreements, at a weighted average value of approximately $0.72 and $1.03 per gallon, respectively.

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(5) UNREALIZED GAINS/LOSSES ON SUPPLY MANAGEMENT SERVICES CONTRACTS

        Unrealized gains and losses on supply management services contracts are as follows (in thousands):

			June 30, 2002			June 30, 2001
Unrealized gains—current			$	14,525		$	28,689
Unrealized gains—long-term				8,093			9,875
	Unrealized gains—asset			22,618			38,564
Unrealized losses—current				(8,522	)		(24,596	)
Unrealized losses—long-term				(209	)		(275	)
	Unrealized losses—liability			(8,731	)		(24,871	)
		Net asset position	$	13,887		$	13,693

        Our supply management services contracts are primarily sales commitments to industrial/commercial end users, logistical service contracts, and basis (geographical) differentials versus published indices (referred to as "swaps"). These commitments provide our customers both price risk management and real time inventory management solutions via our web-based information systems.

(6) PROPERTY, PLANT AND EQUIPMENT, NET

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

	June 30, 2002			June 30, 2001
Land	$	14,125		$	15,181
Terminals, pipelines, and equipment		276,559			320,127
Technology and equipment		12,645			12,654
Furniture, fixtures, and equipment		5,732			6,703
Construction in progress		3,291			3,592
		312,352			358,257
Less accumulated depreciation		(60,921	)		(54,025	)
	$	251,431		$	304,232

(7) INVENTORIES—MINIMUM VOLUMES

        Inventories—minimum volumes are as follows (in thousands):

			June 30, 2002			June 30, 2001
Products:
	At original cost basis		$	76,579		$	76,579
	Adjustment for write-downs to lower of cost or market			(31,281	)		(18,318	)
		Inventories—minimum volumes	$	45,298		$	58,261

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        Our inventories—minimum volumes are required to be held for operating balances in the conduct of our overall operating activities. We do not consider our inventories—minimum volumes to be a component of our energy trading and risk management activities. We do not intend to sell or exchange these inventories in the ordinary course of business and, therefore, we do not hedge the market risks associated with this minimum inventory. Our inventories—minimum volumes are presented in the accompanying consolidated balance sheet as non-current assets and are carried at the lower of cost or market. During the year ended June 30, 2002 and 2001, we recognized impairment losses of approximately $13.0 million and $18.3 million, respectively, due to lower of cost or market write-downs on this minimum inventory. These write-downs are included in net operating margins attributable to our supply, distribution, and marketing operations. At June 30, 2002 and 2001, the weighted average adjusted cost basis of our inventories—minimum volumes was $0.54 and $0.69 per gallon, respectively.

        Prior to July 1, 2000, we carried our inventories—minimum volumes at fair value because they were a component of our energy trading and risk management activities. Effective July 1, 2000, upon completion of a review of our inventory management strategies and customer contracts, we designated 2.0 million barrels of products as inventories—minimum volumes and we changed our risk management strategy associated with this minimum inventory. In accordance with our revised risk management strategy, we removed the hedging contracts on the inventories—minimum volumes prior to July 1, 2000.

(8) INVESTMENTS IN PETROLEUM RELATED ASSETS

        Investments in petroleum related assets are as follows (in thousands):

	June 30, 2002		June 30, 2001
Lion Oil Company	$	10,131	$	10,131
ST Oil Company		—		1,677
West Shore		—		35,952
	$	10,131	$	47,760

        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. For the years ended June 30, 2002, 2001 and 2000, we recorded dividend income from Lion of approximately $0.7 million, $0.8 million, and none, respectively.

        In August 2000, we converted our note receivable and accrued interest from ST Oil Company into an additional 11.6% equity ownership position resulting in our owning a 30.02% equity ownership position. We accounted for our investment in ST Oil Company on the equity method. For the years ended June 30, 2002 and 2001, we recorded equity in earnings from ST Oil Company of less than $0.1 million. 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.

        We owned 20.38% of the common stock of West Shore Pipeline Company ("West Shore"). Although we owned 20.38%, we did not have the ability to significantly influence the activities of West Shore and, therefore, carried our investment at cost. On July 27, 2001, we sold 861 shares of the

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common stock of West Shore, thereby reducing our ownership interest to 18.50%. The West Shore common stock was sold to Midwest Pipeline Company, LLC for cash consideration of approximately $2.9 million. We recognized a net loss of approximately $1.1 million on this sale. As a result of this transaction, we also recognized a loss on our remaining investment in West Shore of approximately $8.8 million. On October 29, 2001, we sold our remaining interest to Buckeye Partners L.P. for cash consideration of approximately $23.1 million, which approximated our adjusted cost basis. For the years ended June 30, 2002, 2001 and 2000, we recognized dividend income from West Shore of approximately $0.7 million, $2.2 million, and $1.6 million, respectively.

(9) IMPAIRMENT OF LONG-LIVED ASSETS

        There were no impairment charges on long-lived assets for the years ended June 30, 2002 and 2001. For the year ended June 30, 2000, we recognized an impairment charge on long-lived assets of approximately $50.1 million, before income taxes. The charge includes $31.9 million relating to certain of our product terminals acquired in the 1998 acquisition of Louis Dreyfus Energy Corporation and $18.2 million relating to certain intangible assets recorded as a result of the same acquisition. In calculating this impairment charge, we estimated future cash flows by terminal, discounting those estimated future cash flows at a 10% rate, which approximates our cost of capital, and then comparing the discounted future cash flows to the net book value of each terminal. The impairment charge resulted from the change in the planned use of certain terminals and the abandonment of a pipeline that supplied one terminal, thereby significantly impacting the economic viability of such terminals. Each of these factors reduced or eliminated future cash flows. The $31.9 million impairment charge for the terminals reduced the book value of the assets to their estimated fair value.

        The additional $18.2 million impairment charge for the intangible assets represented the unamortized balance of the intangible assets. Management's review of the market location differentials associated with those intangible assets showed that we received little or no value from those assets in the period ended June 30, 2000.

(10) OTHER ASSETS

        Other assets are as follows (in thousands):

	June 30, 2002		June 30, 2001
Prepaid transportation	$	2,644	$	2,601
Commodity trading membership		1,500		—
Deposits and other assets		119		376
	$	4,263	$	2,977

        Prepaid transportation relates to our contractual transportation and deficiency agreements with three interstate Product pipelines (see Note 19 of Notes to Consolidated Financial Statements).

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

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(11) ACCRUED LIABILITIES

        Accrued liabilities are as follows (in thousands):

	June 30, 2002		June 30, 2001
Interest rate swap, at fair value	$	5,429	$	3,107
Accrued environmental obligations		2,329		700
Accrued corporate relocation and transition		2,029		—
Accrued lease abandonment		3,110		—
Accrued indemnities—NORCO		1,300		—
Accrued transportation and deficiency obligations		2,839		1,579
Deferred revenue—energy services		1,600		—
Accrued expenses		5,080		5,903
Deposits and other accrued liabilities		2,126		2,881
	$	25,842	$	14,170

        Interest Rate Swap.    We have a $150 million notional value "periodic knock-out" swap agreement with a money center bank to offset the exposure of an increase in variable interest rates. This swap agreement expires in August 2003. The swap settles monthly and contains a knock-out provision that is activated when the one-month LIBOR is at or above 6.75%. The swap agreement provides that we pay a fixed interest rate of 5.48% on the notional amount in exchange for receiving a variable rate based on LIBOR so long as the one-month LIBOR interest rate does not rise above 6.75%. If the one-month LIBOR rate rises above 6.75%, the swap knocks out and no payments will be received by us under the agreement until such time as the one-month LIBOR rate declines below 6.75%. At June 30, 2002 and 2001, the one-month LIBOR rate was 1.84% and 4.08%, respectively. For the years ended June 30, 2002, 2001 and 2000, we made net payments to (received net payments from) the money center bank of approximately $4.6 million, $(0.7) million, and $(1.0) million, respectively, which is included in interest expense (income) in the accompanying consolidated statements of operations.

        The interest rate swap is carried at fair value for financial reporting purposes as it does not qualify as a hedge. As of June 30, 2002 and 2001, the fair value of the interest rate swap agreement was a liability of $5.4 million and $3.1 million, respectively. The changes in the fair value of the interest rate swap are recorded as "Unrealized gain (loss) on interest rate swap" in the accompanying consolidated statements of operations. For the years ended June 30, 2002, 2001 and 2000, we recognized unrealized gains (losses) of approximately $(2.3) million, $(3.6) million and $1.6 million, respectively, for changes in the fair value of the interest rate swap.

        Accrued Corporate Relocation and Transition.    During the year ended June 30, 2002, we announced to our employees that our supply, distribution, and marketing operations in Atlanta, Georgia would be relocated to Denver, Colorado. On March 19, 2002, we offered approximately 72 employees the opportunity to relocate to Denver, Colorado and we informed approximately 25 employees that they would not be offered the opportunity to relocate to Denver, Colorado. Ultimately, 36 employees chose to relocate to Denver, Colorado. Those employees are entitled to receive a transition bonus and a relocation package payable upon transfer to the Denver office. The transition bonus is being accrued over the period from date of acceptance by the employee to the expected date of arrival in Denver, Colorado. The relocation costs are being accrued as incurred/earned by the employee. Ultimately, 36

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employees chose not to relocate and those employees are entitled to receive termination benefits upon their termination date as determined by us. The special termination benefits were accrued upon receipt of the notification from the employee that they did not intend to accept the offer to relocate to Denver, Colorado. For the year ended June 30, 2002, we accrued approximately $2.1 million of benefits due to employees, of which approximately $2.0 million remains unpaid as of June 30, 2002.

	Special charge		Amounts paid			Accrued liability at June 30, 2002
Accrued severance payable to employees not relocating to Denver, Colorado	$	1,512	$	(84	)	$	1,428
Accrued transition benefits payable to employees relocating to Denver, Colorado		501		—			501
Relocation costs incurred during the period		100		—			100
Other		25		(25	)		—
	$	2,138	$	(109	)	$	2,029

        We expect to pay the accrued liability of approximately $2.0 million during the year ending June 30, 2003.

        Accrued Lease Abandonment.    In connection with our corporate relocation and transition, we entered into an operating lease for new office space in Denver, Colorado. The new lease was executed on April 19, 2002. Prior to June 30, 2002, we engaged commercial real estate agents to solicit prospective tenants to sublease our existing office space in Denver, Colorado and the vacated space in Atlanta, Georgia. We expect to vacate our existing office space in Denver, Colorado during June 2003 and the space in Atlanta, Georgia during September 2002. 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. The abandonment of leasehold improvements represents the carrying amount of those assets expected to be abandoned in connection with the abandonment of the office leases. For the year ended June 30, 2002, we charged to income approximately $4.2 million for abandonment of office leases and leasehold improvements.

		Special charge		Amounts paid			Accrued liability at June 30, 2002
Abandonment of office leases:
	Denver, Colorado	$	1,150	$	—		$	1,150
	Atlanta, Georgia		1,960		—			1,960
Abandonment of leasehold improvements:
	Denver, Colorado		550		(550	)		—
	Atlanta, Georgia		518		(518	)		—
		$	4,178	$	(1,068	)	$	3,110

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        We expect to pay the accrued liability of approximately $3.1 million, net of estimated sublease rentals, as follows:

Years ending June 30:	Lease payments		Estimated sublease rentals			Accrued liability
2003	$	745	$	(97	)	$	648
2004		991		(562	)		429
2005		1,020		(565	)		455
2006		1,045		(569	)		476
2007		948		(508	)		440
Thereafter		1,243		(581	)		662
	$	5,992	$	(2,882	)	$	3,110

        Accrued Indemnities—NORCO.    In connection with the sale of the NORCO system to Buckeye 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.

        Deferred Revenue—Supply Management Services.    During the quarter ended March 31, 2002, we renegotiated and extended through February 2005 a fixed-price supply contract with a large industrial/commercial end-user and recognized approximately $3.0 million in net operating margins attributable to our supply, distribution and marketing operations associated with this contract extension. The $3.0 million in net operating margins represents our estimate of the fair value of the supply contract at the date of execution. The fair value of the supply contract was net of the estimated value of the logistical supply management services that we are committed to provide this customer over the term of the supply contract. The estimated value of the logistical supply management services was approximately $1.7 million based on the prices charged to industrial/commercial customers who pay for logistical supply management services separately. The deferred revenue—supply management services is being amortized into revenues attributable to our supply, distribution and marketing operations on a straight line basis over the remaining term of the supply contract. For the year ended June 30, 2002, we recognized approximately $0.1 million in revenues from the amortization of the deferred revenue—supply management services.

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(12) DEBT

        Long-term debt is as follows (in thousands):

		June 30, 2002			June 30, 2001
Commodity margin loan		$	11,312		$	20,000
Bank credit facility			187,000			80,000
Senior notes			—			50,000
			198,312			150,000
Less current debt			(11,312	)		(20,000	)
	Long-term debt	$	187,000		$	130,000

        Commodity Margin Loan.    We currently have a commodity margin loan agreement with Salomon Smith Barney 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 Salomon Smith Barney. 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% (3.46% at June 30, 2002).

        Bank Credit Facility.    On June 28, 2002, we executed an amended and restated Senior Secured Credit Facility ("New Facility") with a syndication of banks. The New Facility provides for a maximum borrowing line of credit that is the lesser of (i) $300 million and (ii) the borrowing base. The borrowing base is a function of our accounts receivable, inventory, exchanges, margin deposits, open positions of energy services and risk management contracts, outstanding letters of credit, and outstanding indebtedness as defined in the New Facility. Borrowings under the New Facility bear interest (at our option) based on the lender's base rate plus a specified margin, or LIBOR plus a specified margin; the specified margins are a function of our leverage ratio (as defined). Borrowings under the New Facility are secured by substantially all of our assets. The New Facility matures June 27, 2005. The terms of the New Facility include financial covenants relating to fixed charge coverage, current ratio, maximum leverage ratio, consolidated tangible net worth, capital expenditures, cash distributions and open inventory positions that are tested on a quarterly and annual basis. As of June 30, 2002, we were in compliance with all covenants included in the New Facility.

        In connection with the New Facility, the Company paid approximately $2.7 million in costs to execute the financing. The costs are comprised of: $2.625 million in bank fees paid to the lenders, $28,000 paid to the financial examiners, and $100,000 paid to the attorneys that drafted the New Facility.

        Our former bank credit facility consisted of a $240 million revolving credit facility and a $45 million letter of credit facility that was due December 31, 2003. Borrowings under the former credit facility bore interest, at our option, at the lender's alternate base rate plus a spread, or LIBOR plus a spread, as in effect at the time of the borrowings. The average interest rate under the bank credit facility was 5.13%, 6.6%, and 8.65% for the years ended June 30, 2002, 2001 and 2000, respectively. During the year ended June 30, 2002, we wrote-off the unamortized deferred debt issuance costs of approximately $2.7 million associated with the former bank credit facility. During the year ended

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June 30, 2001, we wrote-off deferred debt issuance costs of approximately $1.0 million associated with an amendment to the former bank credit facility.

        Pursuant to our bank credit facility, we had outstanding letters of credit with third parties in the amount of $11.5 million and $12.3 million at June 30, 2002 and 2001, respectively. At June 30, 2002, all outstanding letters of credit expire within one year.

        Senior Notes.    In April 1997, we entered into a Master Shelf Agreement (Senior Notes) with an institutional lender. During the year ended June 30, 1998, we sold $50 million of 7.85% due April 17, 2003 and $25 million of 7.22% Senior Notes due October 17, 2004. On January 20, 2000, we repaid $25 million of 7.85% Senior Notes with a portion of the proceeds from the sale of BPEI (see Note 2 of Notes to Consolidated Financial Statements). At June 30, 2001, the outstanding balance of the Senior Notes was $50 million. During the year ended June 30, 2001, we wrote-off deferred debt issuance costs of approximately $2.9 million associated with the prepayment of a portion of the Senior Notes. During the year ended June 30, 2001, we also recognized a prepayment penalty of approximately $1.3 million associated with the prepayment of a portion of the Senior Notes.

        On July 6, 2001, we repaid and retired the outstanding $25 million of 7.85% Senior Notes with a portion of the proceeds from the sale of the Little Rock facilities (see Note 2 of Notes to Consolidated Financial Statements). On June 28, 2002, we repaid and retired the outstanding $25 million of 7.22% Senior Notes with a portion of the proceeds from the New Facility. At June 30, 2002, no amounts remain outstanding on the Senior Notes. During the year ended June 30, 2002, we wrote-off deferred debt issuance costs of approximately $0.3 million associated with the prepayment of the Senior Notes. During the year ended June 30, 2002, we also recognized a prepayment penalty of approximately $1.9 million associated with the prepayment of the Senior Notes.

        Maturities of long-term debt are as follows (in thousands):

Years ending:
	June 30, 2003	$	11,312
	June 30, 2004		—
	June 30, 2005		187,000
		$	198,312

(13) 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, 2002 and 2001.

        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 carrying value of the Senior Notes approximates fair value since the interest rates approximate the current market rates for similar debt instruments.

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(14) PREFERRED STOCK

        At June 30, 2002 and 2001, we have authorized the issuance of up to 2,000,000 shares of preferred stock. Preferred stock is as follows (in thousands):

	June 30, 2002		June 30, 2001
Series A Convertible Preferred stock, par value $0.01 per share, 250,000 shares authorized, 24,421 shares issued and outstanding at June 30, 2002, 174,825 shares issued and outstanding at June 30, 2001, liquidation preference of $24,421 and $174,825, respectively	$	24,421	$	174,825
Series B Redeemable Convertible Preferred stock, par value $0.01 per share, 100,000 shares authorized, 72,890 shares issued and outstanding at June 30, 2002, liquidation preference of $72,890	$	80,939	$	—

        On March 25, 1999 and March 30, 1999, we closed a private placement of $170.1 million of $1,000 Series A Convertible Preferred Stock Units (the "Units"). Each Unit consists of one share of 5% convertible preferred stock ("Series A Convertible Preferred Stock"), convertible at any time by the holder into common stock at $15 per share, and 66.67 warrants, each warrant exercisable to purchase six-tenths of a share of common stock at $14 per share. Dividends are cumulative and payable quarterly. The dividends are payable, at our option, in cash or additional shares of Series A Convertible Preferred Stock. If the dividends are paid-in-kind with additional shares of Series A Convertible Preferred Stock, the number of additional shares issued in lieu of a cash payment is determined by multiplying the cash dividend that would have been paid by 110%. During the year ended June 30, 2000, cash dividend payments were $8.5 million. During the year ended June 30, 2001, we elected to pay-in-kind a portion of the preferred dividends. For the year ended June 30, 2001, cash dividend payments were $4.3 million and paid-in-kind dividends were $4.7 million. For the year ended June 30, 2002, paid-in-kind dividends were approximately $9.8 million.

        On June 28, 2002, we entered into an agreement with the holders of the Series A Convertible Preferred Stock (the "Preferred Stock Recapitalization Agreement") to redeem a portion of the 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 ("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 $21.3 million. We retired the 157,715 shares of Series A Convertible Preferred Stock and associated warrants. The fair value of the consideration paid to the holders of the Series A Convertible Preferred Stock and associated warrants was in excess of the financial statement carrying amount of the Series A Convertible Preferred Stock that was redeemed. That excess of approximately $1.5 million has been treated in a manner similar to preferred stock dividends in the accompanying consolidated financial statements.

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        At June 30, 2002, there are 24,421 shares of Series A Convertible Preferred Stock that remain outstanding. We may redeem all, but not less than all, of the then outstanding shares of the Series A Convertible Preferred Stock on December 31, 2003 at the liquidation value of $1,000 per share plus any accrued but unpaid dividends thereon through the redemption date (the "Mandatory Redemption Price"). The Mandatory Redemption Price shall be paid, at our election, in cash or shares of common stock, or any combination thereof, subject to limitations on the total number of common shares permitted to be used in the exchange and issued to any shareholder. For purposes of calculating the number of shares of common stock to be received, each such share of common stock shall be valued at 90 percent of the average market price for the common stock for the 20 consecutive business days prior to the redemption date. If the Series A Convertible Preferred Stock remains outstanding after December 31, 2003, the dividend rate will increase to an annual rate of 16%. We may call the Series A Convertible Preferred Stock for redemption if the market price of our common stock is greater than 175% of the conversion price at the date of the call.

        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 the New 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 (as defined). 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 and the Series A Convertible Preferred Stock (voting collectively as a single class).

        At June 30, 2002, there are 72,890 shares of Series B Redeemable Convertible Preferred Stock outstanding. The Series B Redeemable Convertible Preferred Stock initially was recorded at its estimated fair value of approximately $80.9 million. The estimated fair value was determined by adding together (i) the present value of the expected dividend payments and mandatory redemption value discounted at a risk-adjusted rate of approximately 15% and (ii) the value of the embedded conversion option using the Black-Scholes model with the following assumptions: exercise price of $6.60 per share, volatility factor of 70%, contractual life of 5 years, no dividend yield, and a risk-free rate of 3.6%. In subsequent periods, the initial carrying amount of the Series B Redeemable Convertible Preferred Stock 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.

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(15) COMMON STOCK

        At June 30, 2002 and 2001, we are authorized to issue up to 80,000,000 shares of common stock with a par value of $0.01 per share. In connection with the Preferred Stock Recapitalization Agreement, we repurchased approximately 4.1 million shares of our common stock from an institutional holder of the Series A Convertible Preferred Stock for cash consideration of approximately $20.4 million. At June 30, 2002 and 2001, there are 39,942,658 shares and 31,834,669 shares issued and outstanding, respectively. Our New Facility and certificate of designations of our 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 key employees, subject to forfeiture if employment terminates prior to the vesting dates. The market value of shares awarded under the plan is recorded in common stockholders' equity as deferred compensation. Amortization of deferred compensation of approximately $1.5 million, $1.3 million and $0.4 million is included in selling, general and administrative expense for the years ended June 30, 2002, 2001 and 2000, respectively.

        During the year ended June 30, 2001, 261,280 shares of restricted common stock were issued to employees in exchange for the cancellation of 1,681,300 stock options with exercise prices ranging from $11.00 to $17.25 per share that had been granted to employees in prior years. Information about restricted common stock activity for the years ended June 30, 2002, 2001 and 2000 is as follows:

	Total shares		Vested shares		Unvested shares
Outstanding at June 30, 1999	68,000		68,000		—
Granted	227,500		—		227,500
Outstanding at June 30, 2000	295,500		68,000		227,500
Granted	512,680		—		512,680
Cancelled	(29,020	)	—		(29,020	)
Repurchased	(201	)	(201	)	—
Vested	—		22,750		(22,750	)
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

(16) STOCK OPTIONS

        We have three stock option plans (the "1991 Plan", the "1995 Plan" and the "1997 Plan") under which stock options have been granted to employees. Options granted under the 1991 Plan and the 1997 Plan expire no later than ten years from the date of grant and options under the 1995 Plan expire no later than seven years from the date of grant. At June 30, 2002, options granted under the 1991 Plan and 1995 Plan and those granted through July 1998 under the 1997 Plan have vested. Options granted subsequent to March 1999 under the 1997 Plan vest 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

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fourth year. Information about stock option activity for the years ended June 30, 2002, 2001 and 2000 is as follows:

	1991 Plan			1995 Plan			1997 Plan
	Shares		Weighted average exercise price	Shares		Weighted average exercise price	Shares		Weighted average exercise price
Outstanding at June 30, 1999	11,000		6.10	731,950		3.96	2,743,400		12.71
Granted	—		—	—		—	733,000		7.91
Cancelled	—		—	(1,000	)	5.50	(577,160	)	13.06
Exercised	(8,000	)	6.10	(14,000	)	4.30	(2,000	)	13.50
Outstanding at June 30, 2000	3,000		6.10	716,950		3.95	2,897,240		11.42
Granted	—		—	—		—	750,000		3.75
Cancelled	(3,000	)	6.10	(46,500	)	5.38	(2,478,410	)	12.22
Exercised	—		—	(372,000	)	2.70	—		—
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
Exercisable at June 30, 2002	—		—	230,450		5.50	178,170		5.31

        Information about stock options outstanding at June 30, 2002 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
1995 Plan	$	5.50	230,450	0.7	5.50	230,450	5.50
1997 Plan		3.75 - 7.25	1,044,900	8.5	4.40	165,650	4.80
		11.00 - 13.50	16,880	6.4	11.44	11,520	11.65
		15.00 - 17.25	1,000	5.2	17.25	1,000	17.25
			1,293,230			408,620

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        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 three 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,
			2002			2001		2000
Net earnings (loss) attributable to common stockholders:
	As reported		$	(2,793	)	$	2,375	$	(46,443	)
	Pro forma		$	(3,003	)	$	2,249	$	(47,721	)
Earnings (loss) per common share
	As reported
		Basic	$	(0.09	)	$	0.08	$	(1.52	)
		Diluted	$	(0.09	)	$	0.08	$	(1.52	)
	Pro forma
		Basic	$	(0.10	)	$	0.07	$	(1.56	)
		Diluted	$	(0.10	)	$	0.07	$	(1.56	)

        The weighted average fair value at grant dates for options granted during the years ended June 30, 2002, 2001 and 2000 was $3.08, $2.12 and $3.16, respectively. 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 years ended June 30, 2002, 2001 and 2000 were as follows: no dividend yield, expected volatility of 79%, 61% and 36%, risk-free rates of 4.49%, 4.95% and 5.6%, and expected lives of 4 years, 5 years, and 7 years, respectively.

(17) EMPLOYEE BENEFIT PLAN

        We have established 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, with our making discretionary contributions as determined by management based upon our financial performance. Employees vest 25% per year in our discretionary contributions. Our discretionary contributions for the years ended June 30, 2002, 2001 and 2000 were approximately $0.5 million, $0.6 million and $0.8 million, respectively.

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(18) INCOME TAXES

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

				Years ended June 30,
				2002			2001			2000
Current:
	Federal income taxes			$	(240	)	$	(288	)	$	—
	State income taxes				643			735			272
		Current income taxes			403			447			272
Deferred:
	Federal income taxes				4,483			5,500			(17,393	)
	State income taxes				579			719			(2,046	)
		Deferred income taxes			5,062			6,219			(19,439	)
			Income tax expense (benefit)	$	5,465		$	6,666		$	(19,167	)

        Income tax expense (benefit) 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,
		2002			2001			2000
Computed "expected" tax expense (benefit)		$	4,908		$	6,458		$	(19,415	)
Increase (reduction) in income taxes resulting from:
	Adjustment of prior year's cumulative temporary differences		(273	)		(331	)		1,858
	State income taxes, net of federal income tax benefit		387			945			(1,171	)
	Other, net		443			(406	)		(439	)
	Income tax expense (benefit)	$	5,465		$	6,666		$	(19,167	)

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        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, 2002			June 30, 2001
Deferred tax assets:
	Net operating loss carry forwards		$	31,224		$	44,386
	Allowance for doubtful accounts			475			399
	Accrual for corporate relocation and transition plan			1,953			165
	Other non-deductible accruals			2,920			1,102
	Amortization of debt costs, principally due to differences in amortization methods			1,327			831
	Intangible assets, principally due to differences in amortization methods and impairment allowances			5,417			6,448
	Deferred compensation			925			697
	Inventories—minimum volumes, principally due to lower of cost or market write-downs			6,047			—
	Accrued environmental obligations			710			266
	Alternative minimum tax credit carry forwards			59			335
		Deferred tax assets		51,057			54,629
Deferred tax liabilities:
	Plant and equipment, principally due to differences in depreciation methods and impairment allowances			(43,175	)		(41,431	)
	Investments in affiliated companies, principally due to undistributed earnings			—			(254	)
		Deferred tax liabilities		(43,175	)		(41,685	)
		Net deferred tax assets	$	7,882		$	12,944

        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 for future taxable income over the periods which the deferred tax assets are deductible, management believes the "more likely than not" criteria has been satisfied as of June 30, 2002 and 2001, and that the benefits of future deductible differences will be realized.

        At June 30, 2002, we have aggregate net operating loss carry forwards for federal income tax purposes of approximately $81 million which were available to offset future federal taxable income, if any, through 2021.

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(19) COMMITMENTS AND CONTINGENCIES

        Transportation and Deficiency Agreements.    In connection with our June 30, 2001 sale of the 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. For the year ended June 30, 2002, our actual volumes were between 20,000 and 32,500 BPD. As a result, we recognized an accrued liability of approximately $1.0 million with an offsetting reduction in net operating margins attributable to our supply, distribution and marketing operations (see Note 11 of Notes to Consolidated Financial Statements). That accrued liability represents our estimate of the future payments we expect to pay for the shortfall in our current year volumes and our estimated shortfall in volumes for the remainder of the term of the agreement.

        We also are subject to three transportation and deficiency agreements ("T&D's") with three separate Product 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 counterparty 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. 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.

        During the year ended June 30, 2001, we made payments of approximately $3.2 million pursuant to the T&D agreements because our actual volumes shipped during that year were less than the guaranteed minimum volumes for that year. We also recognized an accrued liability of approximately $1.6 million representing our estimate of the future payments we expect to pay for the estimated shortfall in volumes for the remainder of the terms of the T&D agreements. At June 30, 2001, we included approximately $2.6 million of prepaid transportation in other assets (see Note 10 of Notes to Consolidated Financial Statements) and we reduced net operating margins attributable to our supply, distribution and marketing operations by approximately $2.2 million.

        During the year ended June 30, 2002, we made payments of approximately $0.4 million pursuant to the T&D agreements because our actual volumes shipped during that year were less than the guaranteed minimum volumes for that year. We also recognized an additional accrued liability of approximately $0.2 million representing a change in our estimate of the future payments we expect to pay for the estimated shortfall in volumes for the remainder of the terms of the T&D agreements. For the year ended June 30, 2002, we reduced net operating margins attributable to our supply, distribution and marketing operations by approximately $0.6 million. At June 30, 2002, prepaid transportation of approximately $2.6 million remains in other assets and our accrued liability, representing our estimate of the future payments we expect to pay for the estimated shortfall in volumes for the remainder of the terms of the T&D agreements, is approximately $1.8 million.

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        Operating Leases.    On April 19, 2002, we executed a 10-year non-cancelable operating lease for new office space to accommodate our corporate headquarters. We anticipate the lease will commence October 1, 2002 and March 1, 2003 with respect to approximately one-half of the total leased square footage, respectively. We also lease property and equipment under non-cancelable operating leases that expire through January 2007, including ground at our Brownsville, Texas facility, pipeline capacity on an intrastate pipeline, and technology-related equipment. At June 30, 2002, future minimum lease payments under these non-cancelable operating leases are as follows (in thousands):

Years ending June 30:	Office space		Property and equipment
2003	$	—	$	1,304
2004		524		1,294
2005		968		1,141
2006		968		324
2007		1,015		162
Thereafter		5,788		—
	$	9,263	$	4,225

        We also will continue to lease office space at our existing locations until we vacate those premises to move to our new corporate headquarters. We anticipate that we will occupy the Denver, Colorado office space until March 1, 2003, one-half of the Atlanta, Georgia office space until October 1, 2002, and the remainder of the Atlanta, Georgia space until June 2010 when the lease expires. At June 30, 2002, future minimum lease payments under these non-cancelable operating lease agreements through the expected date of vacancy by us are as follows (in thousands):

Years ending June 30:
2003	$	1,143
2004		407
2005		415
2006		423
2007		432
Thereafter		1,348
	$	4,168

        Rental expense under operating leases was $2.8 million, $2.9 million, and $2.3 million for the years ended June 30, 2002, 2001 and 2000, respectively.

(20) LITIGATION

        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.

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(21) 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,
		2002			2001			2000
Net earnings (loss)		$	8,558		$	11,338		$	(37,937	)
Preferred stock dividends			(11,351	)		(8,963	)		(8,506	)
Net earnings (loss) attributable to common stockholders for basic and diluted EPS		$	(2,793	)	$	2,375		$	(46,443	)
Basic weighted average shares			31,267			30,879			30,491
Effect of dilutive securities:
	Stock options		—			100			—
	Stock purchase warrants		—			24			—
Diluted weighted average shares			31,267			31,003			30,491
Earnings (loss) per shares:
	Basic	$	(0.09	)	$	0.08		$	(1.52	)
	Diluted	$	(0.09	)	$	0.08		$	(1.52	)

        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, 2002	June 30, 2001	June 30, 2000
Restricted common stock subject to continuing vesting requirements		913,968	688,410	227,500
Common stock issuable upon exercise of stock options		1,293,230	688,280	3,617,190
Common stock issuable upon exercise of stock purchase warrants		900,045	6,804,940	7,053,626
Common stock issuable upon conversion of:
	Series A Convertible Preferred Stock	1,628,083	11,655,000	11,341,000
	Series B Redeemable Convertible Preferred Stock	11,043,939	—	—
		15,779,265	19,836,630	22,239,316

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        For the year ended June 30, 2001, shares of restricted common stock subject to continuing vesting requirements were excluded from the computation of earnings per share because the associated unamortized deferred compensation exceeded the average quoted market price of our common stock during those periods. For the year ended June 30, 2001, stock options and stock purchase warrants were excluded from the computation of earnings per share because their exercise prices exceeded the average quoted market price of our common stock during those periods. For the years ended June 30, 2002 and 2000, all potentially dilutive securities were excluded because we reported a net loss for those years. For the years ended June 30, 2002, 2001 and 2000, the stock options had weighted average exercise prices of $4.69, $6.24 and $9.94 per share, respectively, the stock purchase warrants had weighted average exercise prices of $14.00, $14.00 and $13.63 per share, respectively, the Series A Convertible Preferred Stock had a conversion price of $15.00, and the Series B Redeemable Convertible Preferred Stock had a conversion price of $6.60.

(22) 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 and exchange receivable balances due from major integrated oil companies, independent oil companies, other wholesalers, waste management companies 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 utilize letters of credit, prepayments and guarantees. We maintain allowances for potentially uncollectible accounts receivable.

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

	June 30, 2002			June 30, 2001
Trade accounts receivable	$	174,986		$	80,100
Less allowance for doubtful accounts		(1,250	)		(1,050	)
	$	173,736		$	79,050

(23) BUSINESS SEGMENTS

        We provide a broad range of integrated supply, distribution, marketing, terminal storage and transportation services to refiners, distributors, marketers and industrial end-users of products, chemicals, crude oil and other bulk liquids in the midstream sector of the petroleum and chemical industries and in the upstream NGL sector prior to the sale of BPEI. We conduct business in the following segments:

•

Supply, distribution, and marketing—consists of services for the supply and distribution of products through exchanges, and bulk sales in the physical and derivative markets, and the marketing of products to retail, wholesale and industrial customers at truck terminal rack locations, and providing related value-added fuel procurement and management services.

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•

Terminals and pipelines—consists of an extensive terminal and pipeline infrastructure that handles products with transportation connections via pipelines, barges, 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 Williams pipeline systems.



•

Natural gas services—consisted of services provided through the ownership and operation of natural gas pipeline gathering systems, processing plants and related facilities for the gathering, processing, fractionating and reselling of natural gas and natural gas liquids. This segment was divested effective December 31, 1999.



•

Corporate—consists of our investments in non-controlled business ventures and general corporate items that are not allocated to specific segments (e.g., financing costs and income taxes).

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

		Year ended June 30, 2002
		Supply, distribution and marketing			Terminals and pipelines			Natural gas services		Corporate			Total consolidated
Revenues from external customers		$	6,001,170		$	29,732		$	—	$	—		$	6,030,902
Inter-segment revenues			—			33,654			—		—			33,654
	Revenues		6,001,170			63,386			—		—			6,064,556
Lower of cost or market write- downs on minimum inventories			(12,963	)		—			—		—			(12,963	)
Direct operating costs and expenses			(5,932,423	)		(27,668	)		—		—			(5,960,091	)
	Net operating margins		55,784			35,718			—		—			91,502
Selling, general and administrative			(20,882	)		(8,038	)		—		(6,291	)		(35,211	)
Depreciation and amortization			(330	)		(14,365	)		—		(1,861	)		(16,556	)
Corporate relocation and transition			(4,597	)		—			—		(1,719	)		(6,316	)
			(25,809	)		(22,403	)		—		(9,871	)		(58,083	)
	Operating income (loss)	$	29,975		$	13,315		$	—	$	(9,871	)	$	33,419
Identifiable assets		$	441,474		$	253,417		$	—	$	40,437		$	735,328
Capital expenditures		$	62		$	13,592		$	—	$	2,155		$	15,809

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		Year ended June 30, 2001
		Supply, distribution and marketing			Terminals and pipelines			Natural gas services		Corporate			Total consolidated
Revenues from external customers		$	5,182,492		$	40,646		$	—	$	—		$	5,223,138
Inter-segment revenues			—			41,659			—		—			41,659
	Revenues		5,182,492			82,305			—		—			5,264,797
Lower of cost or market write- downs on minimum inventories			(18,318	)		—			—		—			(18,318	)
Direct operating costs and expenses			(5,136,174	)		(36,415	)		—		—			(5,172,589	)
	Net operating margins		28,000			45,890			—		—			73,890
Selling, general and administrative			(19,661	)		(7,648	)		—		(6,763	)		(34,072	)
Depreciation and amortization			(24	)		(17,351	)		—		(2,135	)		(19,510	)
			(19,685	)		(24,999	)		—		(8,898	)		(53,582	)
	Operating income (loss)	$	8,315		$	20,891		$	—	$	(8,898	)	$	20,308
Identifiable assets		$	298,572		$	332,717		$	—	$	81,076		$	712,365
Capital expenditures		$	1,222		$	8,585		$	—	$	1,735		$	11,542

		Year ended June 30, 2000
		Supply, distribution and marketing			Terminals and pipelines			Natural gas services			Corporate			Total consolidated
Revenues from external customers		$	5,014,752		$	16,522		$	18,249		$	—		$	5,049,523
Inter-segment revenues			—			62,000			—			—			62,000
	Revenues		5,014,752			78,522			18,249			—			5,111,523
Direct operating costs and expenses			(4,995,899	)		(34,268	)		(7,759	)		—			(5,037,926	)
	Net operating margins		18,853			44,254			10,490			—			73,597
Selling, general and administrative			(19,468	)		(8,157	)		(1,923	)		(12,132	)		(41,680	)
Depreciation and amortization			(519	)		(16,139	)		(3,141	)		(2,545	)		(22,344	)
Impairment of long-lived assets			(18,236	)		(31,900	)		—			—			(50,136	)
			(38,223	)		(56,196	)		(5,064	)		(14,677	)		(114,160	)
	Operating income (loss)	$	(19,370	)	$	(11,942	)	$	5,426		$	(14,677	)	$	(40,563	)
Identifiable assets		$	375,271		$	318,611		$	—		$	140,690		$	834,572
Capital expenditures		$	—		$	32,954		$	24,264		$	4,046		$	61,264

F-66

(24) FINANCIAL RESULTS BY QUARTER (UNAUDITED)

(in thousands, except per share amounts)

		Three months ended
		September 30, 2001		December 31, 2001			March 31, 2002		June 30, 2002			Year ended June 30, 2002
Revenues		$	1,549,758	$	1,172,856		$	1,325,699	$	2,016,243		$	6,064,556
Net operating margins		$	35,091	$	10,128		$	29,702	$	16,581		$	91,502
Net earnings (loss) attributable to common stockholders		$	7,227	$	(5,377	)	$	6,265	$	(10,908	)	$	(2,793	)
Earnings (loss) per common share
	Basic	$	0.23	$	(0.17	)	$	0.19	$	(0.35	)	$	(0.09	)
	Diluted	$	0.22	$	(0.17	)	$	0.19	$	(0.35	)	$	(0.09	)

		Three months ended
		September 30, 2000			December 31, 2000			March 31, 2001			June 30, 2001		Year ended June 30, 2001
Revenues		$	1,224,723		$	1,300,783		$	1,289,070		$	1,450,221	$	5,264,797
Net operating margins		$	16,134		$	20,543		$	22,920		$	14,293	$	73,890
Net earnings (loss) attributable to common stockholders		$	(1,857	)	$	(384	)	$	(1,875	)	$	6,491	$	2,375
Earnings (loss) per common share
	Basic	$	(0.06	)	$	(0.01	)	$	(0.06	)	$	0.20	$	0.08
	Diluted	$	(0.06	)	$	(0.01	)	$	(0.06	)	$	0.20	$	0.08

F-67

Coastal Fuels Marketing, Inc. and subsidiaries and Southeast Marketing Division

Combined financial statements
As of December 31, 2002 and 2001 and for the Three Years ended December 31, 2002

F-68

Report of independent accountants

To the Stockholders and Board of Directors of
Coastal Fuels Marketing, Inc. and Subsidiaries:

        In our opinion, the accompanying combined balance sheets and the related combined statements of income, owner's net investment and cash flows present fairly, in all material respects, the combined financial position of Coastal Fuels Marketing, Inc. and Subsidiaries and the Southeast Marketing Division of El Paso Merchant Energy Petroleum Company at December 31, 2002 and December 31, 2001, and the results of their combined operations and their combined cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas
April 24, 2003

F-69

Coastal Fuels Marketing, Inc. and subsidiaries and Southeast Marketing Division

Combined balance sheets

December 31, 2002 and 2001

(in thousands)

				2002		2001
ASSETS
Current assets:
	Cash and Cash equivalents			$	837	$	1,084
	Accounts receivable:
		Trade, net of allowance of $583 and $579			46,375		42,565
		Affiliates			98,775		65,173
	Refined products inventories				38,245		35,012
	Other current assets				550		3,680
			Total current assets		184,782		147,514
Property, plant and equipment—at cost:
	Land				4,191		4,134
	Terminals, barges and equipment				101,735		98,082
					105,926		102,216
	Less—accumulated depreciation				51,471		50,203
					54,455		52,013
	Construction in progress				29,805		14,230
			Total property, plant and equipment, net		84,260		66,243
Other assets					4,928		8,384
			Total assets	$	273,970	$	222,141
LIABILITIES AND OWNER'S NET INVESTMENT
Current liabilities:
	Accounts payable:
		Trade		$	6,487	$	41,414
		Affiliates			105,913		—
	Notes payable to affiliates				7,782		30,715
	Income taxes payable				8,130		7,649
	Deferred income taxes				2,910		1,321
	Other current liabilities				4,422		1,247
			Total current liabilities		135,644		82,346
Deferred income taxes					7,911		8,065
Long-term debt					—		10,647
Other long-term liabilities					2,040		3,007
Commitment and contingencies
Owner's net investment					128,375		118,076
			Total liabilities and owner's net investment	$	273,970	$	222,141

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

F-70

Coastal Fuels Marketing, Inc. and subsidiaries and Southeast Marketing Division

Combined statements of income and owner's net investment

Years ended December 31, 2002, 2001 and 2000

(in thousands)

			2002			2001			2000
Operating revenues:
	Refined products		$	859,021		$	792,275		$	830,333
	Other revenues			—			22			3,480
				859,021			792,297			833,813
Operating expenses:
	Cost of products sold			802,755			733,891			777,580
	Operation and maintenance			35,058			44,253			45,366
	Depreciation and amortization			2,728			2,413			6,863
				840,541			780,557			829,809
Operating income				18,480			11,740			4,004
Other (income) and expenses:
	Interest income:
		Affiliates		(812	)		(2,445	)		(14,127	)
	Interest expense:
		Nonaffiliates		354			519			695
		Affiliates		1,076			3,171			4,404
	Dividends received			—			(4,959	)		(47	)
	Other			(30	)		100			(268	)
	Income before income taxes			17,892			15,354			13,347
	Income taxes			7,593			4,198			5,679
Net income				10,299			11,156			7,668
Owner's net investment, beginning of year				118,076			106,920			99,252
Owner's net investment, end of year			$	128,375		$	118,076		$	106,920

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

F-71

Coastal Fuels Marketing, Inc. and subsidiaries and Southeast Marketing Division

Combined statements of cash flows

Years ended December 31, 2002, 2001 and 2000

(in thousands)

					2002			2001			2000
Cash flows from operating activities:
	Net income				$	10,299		$	11,156		$	7,668
	Adjustments to reconcile net income to cash from operations:
		Depreciation and amortization				2,728			2,413			6,863
		Liquidating dividend on cost method investment				—			(4,959	)		—
		Deferred income taxes				1,039			(2,507	)		(2,839	)
		Working capital changes, net of noncash transactions:
			Accounts receivable			(3,810	)		14,536			(16,382	)
			Accounts receivable from affiliates			(33,602	)		(34,933	)		(3,355	)
			Refined products inventories			(3,233	)		(6,998	)		(2,768	)
			Other current assets			1,007			(90	)		2,800
			Accounts payable			(34,927	)		(1,164	)		27,849
			Accounts payable to affiliates			106,223			(74,166	)		(1,937	)
			Other			3,656			(85	)		3,372
		Nonworking capital changes, net of noncash transactions:
			Other long-term liabilities			(967	)		3,691			(2,713	)
				Net cash provided by (used in) operating activities		48,413			(93,106	)		18,558
Cash flows from investing activities:
	Capital expenditures					(18,536	)		(10,658	)		(5,030	)
	Net change in notes receivable from affiliates					—			55,105			(1,478	)
	Decrease (increase) in other assets					3,456			1,941			(10,826	)
	Proceeds from liquidation of cost method investment					—			13,223			—
				Net cash provided by (used in) investing activities		(15,080	)		59,611			(17,334	)
Cash flows from financing activities:
	Net change in notes payable to affiliates					(22,933	)		30,715			—
	Repayment of long-term debt					(10,647	)		—			—
				Net cash used in financing activities		(33,580	)		30,715			—
Increase (decrease) in cash and cash equivalents						(247	)		(2,780	)		1,224
Cash and cash equivalents:
	Beginning of period					1,084			3,864			2,640
	End of period				$	837		$	1,084		$	3,864

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

F-72

Coastal Fuels Marketing, Inc. and subsidiaries and Southeast Marketing Division

Notes to combined financial statements

December 31, 2002 and 2001

1. BASIS OF PRESENTATION

        These combined financial statements present, in conformity with accounting principles generally accepted in the United States, the combined assets, liabilities, revenues and expenses of Coastal Fuels Marketing, Inc. and Subsidiaries and Southeast Marketing Division of El Paso Merchant Energy Petroleum Company (EPME-PC). Coastal Fuels Marketing, Inc. and its subsidiaries and the Southeast Marketing Division provide refined-products, marketing, terminalling and tug and barge services primarily in the state of Florida and other parts of the southeast United States. These entities are collectively referred to as the "Business." The Business is wholly owned by El Paso CGP Company (EPCGP), which is a wholly owned subsidiary of the El Paso Corporation (El Paso). EPCGP, formerly the Coastal Corporation (Coastal), merged with a subsidiary of El Paso in January 2001. On February 28, 2003, TransMontaigne Product Services Inc., a wholly owned subsidiary of TransMontaigne Inc., acquired all of the outstanding shares of capital stock of Coastal Fuels Marketing, Inc. and its subsidiary, Coastal Tug & Barge, Inc., from EPCGP along with the rights to and operations of the southeast marketing division of EPME-PC.

        These combined financial statements include costs for facilities, functions, and services used by the Business, including those performed by centralized organizations of El Paso and directly charged to the Business based on formulas (see Note 3 for a discussion of the amounts and manner of allocation). All of the allocations and estimates in these financial statements are based on assumptions that management believes are reasonable under the circumstances. However, these allocations and estimates are not necessarily indicative of the costs and expenses that would have resulted if the Business had been operated as a separate entity.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

        The preparation of these financial statements in conformity with accounting principles generally accepted in the United States of America requires the use of estimates and assumptions that affect the amounts the Business reports as assets, liabilities, revenues, and expenses and the disclosures in these financial statements. Actual results can, and often do, differ from those estimates.

Cash and Cash Equivalents

        The Business considers short-term investments with original maturities of less than three months to be cash equivalents.

Allowance for Doubtful Accounts

        The Business establishes provisions for losses on accounts receivables if it determines that it will not collect all or part of the outstanding balance. The Business regularly reviews collectibility and adjusts its allowance, as necessary, using the specific identification method.

Inventory

        The Business's inventory consists of refined products. The Business values all inventory at the lower of cost or market. The Business used the first-in, first-out method to estimate the cost of its refined products for the periods through December 31, 2001. The Business began using the average

F-73

cost method for refined products on January 1, 2002. The change did not have a material impact on these combined financial statements.

        The Business enters into exchange contracts for inventory with wholesale suppliers. Exchange contracts occur when parties agree to a physical exchange of like or different commodities at different locations. The parties agree to pay cash differentials when different products are exchanged. The exchange imbalance (under delivered) of $2.5 million as of December 31, 2002 is reflected in other current liabilities. The exchange imbalance (over delivered) of $1.4 million as of December 31, 2001 is reflected in other current assets.

Price Risk Management Activities

        The Business buys and sells refined products as part of its operations. Affiliates of the Business conduct and manage the price risks associated with these activities through the use of derivative financial instruments. The income or loss primarily associated with the settlement of these derivative instruments was allocated to the Business and has been included in the income statement in these combined financial statements. These gain and loss allocations are based on the commodity type, transaction type, region and average inventory balances of the Business. Derivative activities conducted on behalf of the Business resulted in an increase to cost of products sold of $10.3 million in 2002, a decrease to cost of products sold of $3.5 million in 2001 and an increase to cost of products sold of $8.3 million in 2000.

Property, Plant and Equipment

        Property, plant, and equipment is recorded at its original cost of construction or upon acquisition, at the fair value of the assets acquired. The Business capitalizes direct costs, such as labor and materials, and indirect costs, such as overhead and interest. The Business capitalizes the major units of property replacements or improvements and expenses minor items. Repair and maintenance costs are generally expensed as incurred, unless they improve the operating efficiency or extend the useful life of an asset. Depreciation of property, plant and equipment is recorded on a straight-line basis over the estimated useful lives of the properties, which range from 3 to 30 years with an estimated 10 percent salvage value. Management of the Business believes that the use of the straight-line method is adequate to allocate the costs of the properties over their estimated useful lives. In 2000, depreciation and amortization expense included $4.3 million of abandonment charges related to several terminal and marine assets that were retired prior to the end of their estimated useful lives. These retirements were the result of an evaluation of the ongoing utility of these assets based on projected repair costs.

        On January 1, 2002, the Business adopted Statement of Financial Accounting Standards (SFAS) No. 144, Accounting for Impairment or Disposal of Long-Lived Assets. SFAS No. 144 changed the accounting requirements related to when an asset qualifies as held for sale or as a discontinued operation and the way in which the Business evaluates the impairment of assets. There was no initial impact on adoption of this standard.

F-74

Revenue Recognition

        The Business derives revenues from a number of sources, including the physical sales of commodities and providing transportation and storage services. Revenues for the physical sales are recognized based on the volumes of refined products delivered and the contracted or market price and are recognized at the time the commodity is delivered to the specified delivery point. For transportation and storage services, the Business recognizes revenues at the time the service is rendered based on terms agreed with the customer.

Income Taxes

        The Business reports current income taxes based on its taxable income along with a provision for deferred income taxes to reflect estimated future tax payments and receipts. Deferred income taxes represent the tax impact of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. The Business accounts for tax credits under the flow-through method, which reduces the provision for income taxes in the year the tax credits first become available. The Business reduces deferred tax assets by a valuation allowance when, based on its estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The estimates utilized in the recognition of deferred tax assets are subject to revision, either up or down, in future periods based on new facts or circumstances.

        El Paso maintains a tax accrual policy for companies included in its consolidated federal income tax return. The policy provides, among other things, that (i) each company in a taxable income position will accrue a current expense equivalent to its federal tax, and (ii) each company in a tax loss position will accrue a benefit to the extent its deductions, including general business credits, can be utilized in the consolidated return. El Paso pays all federal income taxes directly to the IRS and, under a separate tax billing agreement, El Paso may bill or provide a refund to its subsidiaries for their portion of these tax payments.

Excise Taxes

        The Business does not recognize revenues for the amounts of excise taxes billed to and collected from customers. Rather, it records a receivable from the customers and a payable to an affiliate that remits the excise taxes to the taxing authorities.

Environmental Costs and Other Contingencies

        The Business records liabilities when its environmental assessments indicate that remediation efforts are probable, and the costs can be reasonably estimated. The Business recognizes a current period expense for the liability when clean-up efforts do not benefit future periods. The Business capitalizes costs that benefit more than one accounting period. Estimates of the Business's liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of inflation and other societal and economic factors, and include estimates of associated legal costs. The amounts also consider prior experience in remediating contaminated sites, other companies' clean-up experience and data released by the EPA or other organizations. The estimates are subject to revision in future periods based on actual costs or new

F-75

circumstances and are included in the Business's balance sheet in other current and long-term liabilities at their undiscounted amounts. The Business evaluates recoveries from insurance coverage or government sponsored programs separately from its liability and, when recovery is assured, the Business records and reports an asset separately from the associated liability in these combined financial statements.

        The Business recognizes liabilities for other contingencies when the Business has an exposure that, when fully analyzed, indicates it is both probable that an asset has been impaired or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. Funds spent to remedy these contingencies are charged against the accrued liability, if one exists, or expensed if no liability was previously established. When a range of probable loss can be estimated, the Business accrues the most likely amount or at least the minimum within the range of probable losses.

3. RELATED PARTY TRANSACTIONS

Revenues

        The Business charges affiliates for use of some of its property, plant, or equipment based upon relevant factors such as actual usage, throughput or other relevant measurements. The charges to affiliates were based on a market-based methodology for the first six months of 2002 and all of 2001 and 2000. A cost recovery methodology was used for the first six months of 2002. Charges to affiliates were $8.9 million, $13.3 million and $12.5 million in 2002, 2001 and 2000. Charges to affiliates would have been approximately $13.0 million had the market based methodology been applied for all of 2002.

        The Business sold refined products and provided transportation services to affiliates of $62.4 million, $153.6 million and $142.9 million in 2002, 2001, and 2000, respectively.

Freight

        Prior to 2002, freight expense was charged directly to the Business based on services received and market rates. In 2002, all freight expense was recorded by an affiliate. In preparing the 2002 combined financial statements, freight costs were identified and allocated to the Business based on the destination of the spot and term-chartered supply vessels and by region for the tug and barge operations. Freight expense allocated to the Business was $14.4 million in 2002.

General and Administrative

        Shared service costs for services performed by centralized El Paso functions (such as legal, treasury, employee benefits and environmental services) and general corporate expenses have been allocated to the Business based on headcount, property costs, or some combination thereof. Allocated corporate general and administrative costs amounted to $4.6 million in 2002, $6.6 million in 2001 and $3.3 million in 2000. In addition to allocated amounts, Coastal charged the Business $2.7 million directly for employee benefits in 2000 that were included in the administrative allocation in later years.

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Interest Income and Expense

        Prior to 2001, the Business participated in Coastal Corporation's cash management program. For the year ended December 31, 2000, the Business earned interest income on receivables under the program of $9.0 million.

        Beginning in January 2001, the Business started participating in El Paso's cash pool program, which balances short-term cash surplus and need requirements of its participating affiliates.

        Borrowings under this program are reflected as notes payable to affiliates at December 31, 2002 and 2001 in the amount of $7.8 million and $30.7 million. The weighted average interest rates at December 31, 2002 and December 31, 2001, were 1.45% and 2.13%.

        The business also has notes and accounts receivable with other affiliated companies of El Paso that arose as part of the ongoing operating activities of the Business. These notes and accounts are noninterest bearing and had balances of $95.2 million at December 31, 2002 and $66.0 million at December 31, 2001.

Investment in Unconsolidated Affiliate

        In 1996, Coastal Medical Services Inc. was formed to improve the value of Coastal's medical benefit program for its employees and employees of its subsidiaries by managing the medical obligations of its participating subsidiaries. Coastal Medical Services was created through the contribution of cash by 25 EPCGP subsidiaries in exchange for Coastal Medical Services stock. The Business owned 1% of the outstanding shares of Coastal Medical Services and accounted for the investment using the cost method because it did not have the ability to exert significant influence over operating or managing decisions of Coastal Medical Services. In December 2001, the Business redeemed the ownership interest in Coastal Medical Services and recorded dividend income of approximately $5 million.

4. CONCENTRATION OF CREDIT RISK

        The Business's market area is Florida. The Business has a concentration of trade receivable balances due from oil companies, wholesalers, cruise ships, and aviation companies. These concentrations of customers may effect the Business's overall credit risk in that the customers may be similarly affected by changes in economic, regulatory, or other factors. The Business's historical and future credit positions are analyzed prior to extending credit. The Business manages the exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures. For some sales transactions the Business uses letters of credit, prepayments, and guarantees. The Business maintains allowances for potentially uncollectible accounts receivable on a specific identification basis.

5. INTANGIBLE ASSET

        The Business's intangible asset consists of a customer list that was acquired in 2000. The Business applies SFAS No. 142, Goodwill and Other Intangible Assets to account for this intangible asset. The intangible asset is being amortized on a straight-line basis over its estimated useful life of five years.

F-77

Gross carrying amounts and accumulated amortization of the Business's intangible asset at December 31 were as follows (in thousands):

	2002			2001
Intangible asset subject to amortization	$	1,700		$	1,700
Accumulated amortization		(822	)		(482	)
Intangible asset, net of accumulated amortization	$	878		$	1,218

        Amortization expense of the Business's intangible asset subject to amortization was $340 thousand for both the years ended December 31, 2002 and 2001. For its remaining useful life, estimated amortization expense will be (in thousands):

Year ending December 31,		Amortization expense
2003		$	340
2004			340
2005			198
	Total	$	878

6. INCOME TAXES

        The following table reflects the components of the provisions for income taxes for each of the three years ended December 31 (in thousands):

			2002		2001			2000
Current:
	Federal		$	4,828	$	6,821		$	7,292
	State			618		(116	)		1,226
	Foreign			1,108		—			—
		Total		6,554		6,705			8,518
Deferred:
	Federal			289		(2,601	)		(2,735	)
	State			750		94			(104	)
		Total deferred		1,039		(2,507	)		(2,839	)
		Total income tax	$	7,593	$	4,198		$	5,679

F-78

        The Business's income taxes differed from the amounts computed by applying the statutory federal income tax rate of 35 percent for the following reasons for each of the three years ended December 31 (in thousands):

		2002			2001			2000
Income taxes at the statutory federal rate of 35%		$	6,262		$	5,374		$	4,671
Increase (decrease):
	State income taxes, net of federal benefit		889			(11	)		729
	Dividend exclusion		—			(1,736	)		(16	)
	Foreign earnings not subject to U.S.		4			(2	)		111
	Foreign tax, net of federal benefit		720			—			—
	Captive insurance premium/casualty losses		(119	)		222			(13	)
	Other		(163	)		351			197
Income taxes		$	7,593		$	4,198		$	5,679
Pretax income		$	17,892		$	15,354		$	13,347
Effective tax rate			42	%		27	%		43	%

        The following were the components of net deferred tax liability as of December 31 (in thousands):

			2002		2001
Deferred tax liability:
	Property, plant and equipment		$	13,196	$	12,712
	Other			10		10
		Total deferred tax liability	$	13,206	$	12,722
Deferred tax assets:
	Bad debt allowance		$	219	$	206
	Vacation accruals			44		9
	Deferred employee benefits			17		993
	Accruals and contingent liabilities			1,008		965
	Environmental liability			1,089		1,155
	Other			8		8
		Total deferred tax assets		2,385		3,336
Net deferred tax liability			$	10,821	$	9,386

F-79

7. SUPPLEMENTAL CASH FLOW INFORMATION

        The following table contains supplemental cash flow information for the years ended December 31 (in thousands):

	2002		2001		2000
Interest paid	$	1,280	$	3,334	$	4,670
Income tax payments		6,906		3,311		—
Property, plant and equipment transferred in		86		888		131
Deferred taxes on property, plant and equipment transferred in		396		980		—

        In 2000, Coastal paid all taxes on behalf of the Business.

        In July 2002, Coastal Tug and Barge, Inc. foreclosed on property that was originally sold in 1995 in exchange for a note receivable. As a result, the Business capitalized $2.1 million, which represented the remaining net book value of the note. For purposes of the statement of cash flows, this transaction was treated as a noncash transaction.

8. LONG-TERM DEBT

        In July 2002, Coastal Fuels Marketing, Inc. retired $8.2 million of marine terminal facilities revenue bonds due on December 1, 2010. These bonds had a variable interest rate of 74% of the then current prime rate as defined in the indenture.

        In July 2002, Coastal Tug and Barge, Inc. retired $2.4 million of industrial development revenue bonds due on September 1, 2012. These bonds had a variable interest rate of 60% of the then current prime rate as defined in the indenture.

9. COMMITMENTS AND CONTINGENCIES

Operating Leases

        Rent expense for 2002, 2001 and 2000 was $1.9 million, $1.8 million and $1.2 million, respectively. The Business maintains operating leases in the ordinary course of its business activities. These leases include those for office space and operating facilities and the terms of the agreements vary from 2003 through 2020. As of December 31, 2002, the total commitments under the operating leases were approximately $6.5 million. Minimum annual rental commitments at December 31, 2002, were as follows (in thousands):

Year ending December 31,		Operating leases
2003		$	1,259
2004			1,324
2005			1,530
2006			404
2007			397
Thereafter			1,635
	Total	$	6,549

F-80

Legal Proceedings

        The Business is a named defendant in several lawsuits arising in the ordinary course of business. While the outcome of these lawsuits cannot be predicted with certainty, management does not expect the ultimate resolution of these matters will have a material adverse effect on the Business's financial position, operating results or cash flows. The Business has accrued $750 thousand related to its legal proceedings at December 31, 2002.

Environmental Matters

        The Business's operations are subject to extensive and evolving federal, state and local environmental laws and regulations. Compliance with such laws and regulations can be costly. Additionally, governmental authorities may enforce the laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties and remediation requirements. It is possible that new information or future developments could require the Business to reassess its potential exposure related to environmental matters. The Business may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws and regulations, and claims for damages to property, employees, other persons and the environment resulting from current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or other relevant developments occur, the Business establishes accrued liabilities or adjusts previously accrued amounts accordingly. While there are still uncertainties relating to the ultimate costs the Business may incur, based upon management's evaluation and experience to date, management believes that compliance with all applicable laws and regulations will not have a material adverse impact on the Business's financial position, operating results or cash flows. The Business has accrued $2.0 million for its environmental matters at December 31, 2002.

F-81

$200,000,000
TransMontaigne Inc.
9¹/8% Series B Senior Subordinated Notes Due 2010

PROSPECTUS

Dated                        , 2003

        DEALER PROSPECTUS DELIVERY OBLIGATION.Until                        , 2003, all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers' obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

PART II
INFORMATION NOT REQUIRED IN THE PROSPECTUS

ITEM 20. INDEMNIFICATION OF DIRECTORS AND OFFICERS.

Section 145 of Delaware General Corporation Law

        Section 145 of the Delaware General Corporation Law, or DGCL, provides that a corporation may indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of the corporation) by reason of the fact that the person is or was a director, officer, employee, or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise against expenses (including attorneys' fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by him in connection with such action, suit, or proceeding if the person acted in good faith and in a manner the person reasonably believed to be in or not opposed to the best interests of the corporation, and, with respect to any criminal action or proceeding, had no reasonable cause to believe the person's conduct was unlawful.

        Section 145 also provides that a corporation may indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending, or completed action or suit by or in the right of the corporation to procure a judgment in its favor by reason of the fact that he is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise against expenses (including attorneys' fees) actually and reasonably incurred by the person in connection with the defense or settlement of such action or suit if the person acted in good faith and in a manner the person reasonably believed to be in or not opposed to the best interests of the corporation and except that no indemnification shall be made in respect of any claim, issue or matter as to which such person shall have been adjudged to be liable to the corporation unless and only to the extent that the Court of Chancery of Delaware or the court in which such action or suit was brought shall determine upon application that, despite the adjudication of liability but in view of all the circumstances of the case, such person is fairly and reasonably entitled to indemnity for such expenses which the Court of Chancery of Delaware or such other court shall deem proper.

        To the extent that a present or former director or officer of a corporation has been successful on the merits or otherwise in defense of any action, suit or proceeding referred to above, or in defense of any claim, issue or matter therein, such person shall be indemnified against expenses (including attorneys' fees) actually and reasonably incurred by such person in connection therewith; provided that indemnification provided for by Section 145 or granted pursuant thereto shall not be deemed exclusive of any other rights to which the indemnified party may be entitled; and a corporation shall have power to purchase and maintain insurance on behalf of any person who is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise against any liability asserted against such person and incurred by such person in any such capacity or arising out of such person's status as such whether or not the corporation would have the power to indemnify such person against such liabilities under Section 145.

Certificate of Incorporation

        Section 102(b)(7) of the DGCL permits Delaware corporations to include a provision in their certificates of incorporation eliminating or limiting the personal liability of a director to the corporation or its stockholders for monetary damages for breach of fiduciary duty as a director, provided that such provisions shall not eliminate or limit the liability of a director: (i) for any breach of the director's duty of loyalty to the corporation or its stockholders; (ii) for acts or omissions not in good faith or that

II-1

involve intentional misconduct or a knowing violation of law; (iii) for unlawful payment of dividends or unlawful stock purchases or redemptions; or (iv) for any transactions from which the director derived an improper personal benefit.

        Our Certificate of Incorporation currently provides that each director shall not be personally liable to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except as to liability (i) for any breach of the director's duty of loyalty to us or our stockholders, (ii) for acts or omissions which are not in good faith or which involve intentional misconduct or knowing violation of the law, (iii) for violations of Section 174 of the DGCL, or (iv) for any transaction from which the director shall have derived any improper personal benefit. If the DGCL is amended to eliminate or limit further the ability of a director, then, in addition to the elimination and limitation of liability provided by the certificate of incorporation, the liability of each director shall be eliminated or limited to the fullest extent provided or permitted by the amended DGCL.

Bylaw Provisions on Indemnity

        Article six of our Bylaws sets forth the extent to which our directors and officers may be indemnified by us against liabilities which they may incur while serving in such capacity. Article six generally provides that we shall indemnify our directors and officers who were, are, or are threatened to be made party to any threatened, pending, or contemplated action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of the corporation), by reason of the fact that he or she is or was our director or officer, or is or was serving at our request as a director, officer, employee or agent of another corporation, partnership, joint venture, trust, association, or other enterprise against expenses (including attorneys' fees), judgments, fines and amounts paid in settlement actually and reasonably incurred in connection therewith, provided he or she acted in good faith and in a manner reasonably believed to be in or not opposed to our best interests, and, with respect to any criminal action or proceeding, had no reasonable cause to believe his or her conduct was unlawful. Subject to the procedures for indemnification of directors and officers set forth in the Bylaws, the indemnification of our directors and officers provided for therein is in all other respects substantially similar to that provided for in Section 145 of the DGCL.

        Any such indemnification shall continue as to a person who has ceased to be our director or officer and shall inure to the benefit of the heirs, executors, and administrators of such person.

        TransMontaigne Product Services Inc. and TransMontaigne Transport Inc., which are subsidiaries of TransMontaigne Inc. and also registrants under this Registration Statement, are incorporated under the laws of the State of Delaware and are subject to the provisions of the laws of the Delaware General Corporate Law described above. Coastal Fuels Marketing, Inc. and Coastal Tug and Barge, which are subsidiaries of TransMontaigne Inc. and also registrants under this Registration Statement, are incorporated under the laws of the State of Florida and are subject to the provisions of the laws of the State of Florida.

        The directors and officers of all of the aforementioned subsidiaries of the Company are entitled to the rights under the DGCL described above. In addition, the directors and officers are also entitled to certain similar rights under the laws of the State of Florida. Certain of the certificates or articles of incorporation and bylaws of the aforementioned subsidiaries of TransMontaigne Inc. include similar provisions to those described above.

        The above discussion of our Certificate of Incorporation and Bylaws and of Section 145 of the DGCL law is not intended to be exhaustive and is qualified in its entirety by such Certificate of Incorporation and Bylaws and the DGCL.

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ITEM 21. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

(a)

Exhibits.

Exhibit Number	Description of Exhibits
2.1	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).
2.2	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).
2.3	Second Amendment to Stock Purchase Agreement by and between El Paso CGP Company and TransMontaigne Product Services Inc., dated as of June 27, 2003.
3.1	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).
3.1A	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).
3.1B	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).
3.1C	Certificate of Designations of Series A Convertible Preferred Stock (incorporated by reference to Exhibit 99.3 of TransMontaigne Inc.'s Current Report on Form 8-K filed on April 1, 1999).
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).
3.3	Certificate of Incorporation of TransMontaigne Product Services Inc. and Certificates of Merger.
3.4	By-laws of TransMontaigne Product Services Inc.
3.5	Certificate of Incorporation of TransMontaigne Transport Inc.
3.6	By-laws of TransMontaigne Transport Inc.
3.7	Articles of Incorporation of Coastal Fuels Marketing, Inc., as amended, and Articles of Merger.
3.8	By-laws of Coastal Fuels Marketing, Inc.
3.9	Certificate of Incorporation of Coastal Tug and Barge, Inc., as amended, and Articles of Merger.
3.10	By-laws of Coastal Tug and Barge, Inc.

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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).
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).
5.1	Opinion of Hogan & Hartson L.L.P. as to the validity of the 91/8% Series B Senior Subordinated Notes due 2010.
10.1	The TransMontaigne Oil Company Amended and Restated 1995 Stock Option Plan (incorporated by reference to Exhibit 10.1 of TransMontaigne Oil Company's Form 10-K for the year ended April 30, 1996).
10.2	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).
10.3	Stock Purchase Agreement effective April 17, 1996 between TransMontaigne Oil Company and the investors named therein (incorporated by reference to Exhibit 10.3 TransMontaigne Oil Company's Form 10-K for the year ended April 30, 1996).
10.4	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 10.4 of TransMontaigne Oil Company's Form 10-K for the year ended April 30, 1996).
10.5	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 10.5 of TransMontaigne Oil Company's Form 10-K for the year ended April 30, 1996).
10.6	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).
10.7	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 10.7 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002).
10.8	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 10.8 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002).
10.9	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 10.9 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002).

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10.10	Form of Preferred Stock and Warrant Purchase Agreement (without exhibits) (incorporated by reference to Exhibit 10.10 of TransMontaigne Inc.'s Current Report on Form 8-K filed on April 1, 1999).
10.11	Form of Preferred Stock Recapitalization Agreement dated as of June 27, 2002 (without exhibits) (incorporated by reference to Exhibit 10.11 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002).
10.12	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 10.12 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002).
10.13	Fifth Amended and Restated Credit Agreement between TransMontaigne Inc. and Fleet National Bank as Administrative Agent and Collateral Agent, dated as of June 27, 2002 (incorporated by reference to Exhibit 10.13 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002).
10.14	Stock Purchase Agreement dated as of September 13, 1998, between Louis Dreyfus Corporation and TransMontaigne Inc. (incorporated by reference to Exhibit 10.14 of TransMontaigne Inc.'s Current Report on Form 8-K filed on November 13, 1998).
10.15	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 10.15 of TransMontaigne Inc.'s Current Report on Form 8-K filed on November 13, 1998).
10.16	Letter Agreement dated as of June 27, 2002 between First Reserve Fund VI, Limited Partnership and TransMontaigne Inc. (incorporated by reference to Exhibit 10.16 of TransMontaigne Inc.'s Current Report on Form 8-K filed on July 15, 2002).
10.17	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).
10.18	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).
10.19	Change in Control Agreement between TransMontaigne Inc. and Larry F. Clynch dated April 12, 2001 (incorporated by reference to Exhibit 10.3 of TransMontaigne Inc.'s Form 10-Q for the quarter ended September 30, 2002).
10.20	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).
10.21	Change in Control Agreement between TransMontaigne Inc. and Harold R. Logan, Jr. dated April 12, 2001 (incorporated by reference to Exhibit 10.5 of TransMontaigne Inc.'s Form 10-Q for the quarter ended September 30, 2002).
10.22	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).

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10.23	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).
10.24	Credit Agreement by and among TransMontaigne Inc., UBS AG, Stamford Branch as Administrative Agent and Collateral Agent, UBS Warburg LLC as Lead Arranger and Book Manager and certain lenders party thereto, dated as of February 28, 2003 (incorporated by reference to Exhibit 99.4 of TransMontaigne Inc.'s Current Report on Form 8-K filed on March 17, 2003).
10.25	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.
10.26	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.
12.1	Statement of Computation of Ratios of Earnings to Fixed Charges.*
21.1	List of Subsidiaries.
23.1	Consent of KPMG LLP, Independent Auditors.
23.2	Consent of PricewaterhouseCoopers LLP, Independent Accountants.
23.3	Consent of Hogan & Hartson L.L.P. (included in Exhibit 5.1).
24.1	Power of Attorney (included on signature page).
25.1	Form T-1 Statement of Eligibility and Qualification under the Trust Indenture Act of 1939, as amended, of Wells Fargo Bank Minnesota, National Association, as trustee.
99.1	Form of Letter of Transmittal.
99.2	Form of Notice of Guaranteed Delivery.
99.3	Notice to Brokers.
99.4	Notice to Clients.

*

To be filed by amendment

ITEM 22. UNDERTAKINGS.

        The undersigned Registrant hereby undertakes:

(1)

That, insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer, or controlling person in connection with the securities being registered, the registrant will, unless in the

II-6

opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act of 1933 and will be governed by the final adjudication of such issue.

(2)

To supply by means of a post-effective amendment all information concerning a transaction, and the company being acquired involved therein, that was not the subject of and included in this registration statement when it became effective.



(3)

To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:



(i)

to include any prospectus required by Section 10(a)(3)of the Securities Act;



(ii)

to reflect in the prospectus any facts or events arising after the effective date of this registration statement (or the most recent post-effective amendment hereof) that, individually or in the aggregate, represents a fundamental change in the information set forth in this registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Securities and Exchange commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than a 20% change in the maximum aggregate offering price set forth in the "Calculation of Registration Fee" table in this registration statement when it becomes effective; and



(iii)

to include any material information with respect to the plan of distribution not previously disclosed in this registration statement or any material change to such information in this registration statement.



(4)

That, for the purpose of determining any liability under the Securities Act, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.



(5)

To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

II-7

SIGNATURES

        Pursuant to the requirements of the Securities Act, each registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Denver, State of Colorado on July 22, 2003.

TRANSMONTAIGNE INC.     a Delaware corporation
By:	/s/  DONALD H. ANDERSON      Donald H. Anderson Chief Executive Officer
SUBSIDIARY GUARANTORS:
TRANSMONTAIGNE PRODUCT SERVICES INC.     a Delaware corporation COASTAL FUELS MARKETING, INC.     a Florida corporation COASTAL TUG AND BARGE, INC.     a Florida corporation
By:	/s/  DONALD H. ANDERSON      Donald H. Anderson Chief Executive Officer
TRANSMONTAIGNE TRANSPORT INC.     a Delaware corporation
By:	/s/  DONALD H. ANDERSON      Donald H. Anderson President

II-S-1

POWER OF ATTORNEY

        Each person whose signature appears below hereby appoints Donald H. Anderson, Randall J. Larson and Erik B. Carlson, and each of them, as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement, and to file the same, with all exhibits thereto and all other documents in connection therewith, with the SEC, granting unto said attorneys-in-fact and agents full power and authority to perform each and every act and thing appropriate or necessary to be done, as fully and for all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or their substitute or substitutes may lawfully do or cause to be done by virtue hereof.

        Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed by the following persons in the capacities and on the dates indicated.

Signature	Capacity in Which Signed	Date
/s/  CORTLANDT S. DIETLER      Cortlandt S. Dietler	Chairman of the Board of TransMontaigne Inc.; Chairman of the Board of TransMontaigne Product Services Inc; Chairman of the Board of Coastal Fuels Marketing, Inc. and Chairman of the Board of Coastal Tug and Barge, Inc.	July 22, 2003
/s/  DONALD H. ANDERSON      Donald H. Anderson	Vice Chairman, Chief Executive Officer and President of TransMontaigne Inc.; Chairman of the Board and President of TransMontaigne Transport Inc.; Director and Chief Executive Officer of TransMontaigne Product Services Inc.; Director and Chief Executive Officer of Coastal Fuels Marketing, Inc. and Director and Chief Executive Officer of Coastal Tug and Barge, Inc.	July 22, 2003
/s/  PETER B. GRIFFIN      Peter B. Griffin	Director of TransMontaigne Inc.	July 22, 2003
/s/  BEN A. GUILL      Ben A. Guill	Director of TransMontaigne Inc.	July 22, 2003
/s/  JOHN A. HILL      John A. Hill	Director of TransMontaigne Inc.	July 22, 2003
/s/  BRYAN H. LAWRENCE      Bryan H. Lawrence	Director of TransMontaigne Inc.	July 22, 2003
/s/  HAROLD R. LOGAN, JR.      Harold R. Logan, Jr.	Director of TransMontaigne Inc. and Director of TransMontaigne Product Services Inc.	July 22, 2003
/s/  EDWIN H. MORGENS      Edwin H. Morgens	Director of TransMontaigne Inc.	July 22, 2003
/s/  WALTER P. SCHUETZE      Walter P. Schuetze	Director of TransMontaigne Inc.	July 22, 2003
/s/  WILLIAM S. DICKEY      William S. Dickey	Director of Coastal Fuels Marketing, Inc. and Director of Coastal Tug and Barge, Inc.	July 22, 2003
/s/  FREDERICK W. BOUTIN      Frederick W. Boutin	Director of TransMontaigne Transport Inc.	July 22, 2003

II-S-2

EXHIBIT INDEX

Exhibit Number	Description of Exhibits
2.3	Second Amendment to Stock Purchase Agreement by and between El Paso CGP Company and TransMontaigne Product Services Inc., dated as of June 27, 2003.
3.3	Certificate of Incorporation of TransMontaigne Product Services Inc. and Certificates of Merger.
3.4	By-laws of TransMontaigne Product Services Inc.
3.5	Certificate of Incorporation of TransMontaigne Transport Inc.
3.6	By-laws of TransMontaigne Transport Inc.
3.7	Articles of Incorporation of Coastal Fuels Marketing, Inc., as amended, and Articles of Merger.
3.8	By-laws of Coastal Fuels Marketing, Inc.
3.9	Certificate of Incorporation of Coastal Tug and Barge, Inc., as amended, and Articles of Merger.
3.10	By-laws of Coastal Tug and Barge, Inc.
5.1	Opinion of Hogan & Hartson L.L.P. as to the validity of the 91/8% Series B Senior Subordinated Notes due 2010.
10.25	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.
10.26	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.
21.1	List of Subsidiaries.
23.1	Consent of KPMG LLP, Independent Auditors.
23.2	Consent of PricewaterhouseCoopers LLP, Independent Accountants.
23.3	Consent of Hogan & Hartson L.L.P. (included in Exhibit 5.1).
24.1	Power of Attorney (included on signature page).
25.1	Form T-1 Statement of Eligibility and Qualification under the Trust Indenture Act of 1939, as amended, of Wells Fargo Bank Minnesota, National Association, as trustee.
99.1	Form of Letter of Transmittal.
99.2	Form of Notice of Guaranteed Delivery.
99.3	Notice to Brokers.
99.4	Notice to Clients