TRANSMONTAIGNE INC - 10-Q Quarterly Report

2750 Republic Plaza, 370 Seventeenth Street
Denver, Colorado 80202
(Address, including zip code, of principal executive offices)

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such report), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

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

As of May 3, 2003 there were 40,660,947 shares of the Registrant's Common Stock outstanding.


PART I. FINANCIAL INFORMATION
Item 1.		Unaudited Consolidated Financial Statements
		Consolidated Balance Sheets as of March 31, 2003 and June 30, 2002
		Consolidated Statements of Operations for the Three and Nine Months Ended March 31, 2003 and 2002
		Consolidated Statements of Preferred Stock and Common Stockholders' Equity for the Year Ended June 30, 2002 and Nine Months Ended March 31, 2003
		Consolidated Statements of Cash Flows for the Three and Nine Months Ended March 31, 2003 and 2002
		Notes to Consolidated Financial Statements
Item 2.		Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 3.		Qualitative and Quantitative Disclosures about Market Risk
Item 4.		Controls and Procedures
PART II. OTHER INFORMATION
Item 6.		Exhibits and Reports on Form 8-K
SIGNATURES
CERTIFICATIONS

The interim consolidated financial statements of TransMontaigne Inc. as of and for the three and nine months ended March 31, 2003 are included herein beginning on the following page. The accompanying interim consolidated financial statements should be read in conjunction with our annual 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.

TransMontaigne Inc. is a holding company with the following active subsidiaries during the three months and nine months ended March 31, 2003.

Effective December 31, 2001, TransMontaigne Terminaling Inc. and TransMontaigne Pipeline Inc. were merged into TPSI, which is now our primary operating subsidiary. Effective June 27, 2002, TransMontaigne Holding Inc. was dissolved.

We do not have any off-balance-sheet arrangements (other than operating leases) or special-purpose entities.

TRANSMONTAIGNE INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands)

TRANSMONTAIGNE INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

TRANSMONTAIGNE INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS—(Continued)

(In thousands, except per share amounts)

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)

TRANSMONTAIGNE INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

TRANSMONTAIGNE INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS—(Continued)

(In thousands)

TRANSMONTAIGNE INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2003 and June 30, 2002

The accompanying consolidated financial statements in this Quarterly Report on Form 10-Q 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.

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).

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.

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.

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:

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 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):

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.

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 margins attributable to our supply, distribution and marketing operations. Inventories—discretionary volumes are as follows (in thousands):

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):

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):

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.

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.

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.

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.

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.

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 ("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):

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 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.

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.

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

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).

	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

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.

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.

	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 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

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.

We expect to pay the accrued liability of approximately $2.9 million, net of estimated sublease rentals, as follows (in thousands):

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 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

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: $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.

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.

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.

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.

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

earnings per common share would have been reduced to the pro forma amounts indicated below (in thousands, except for per share amounts):

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.

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.

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.

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 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.

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.

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:

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):

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

This Quarterly Report contains certain forward-looking statements and information relating to TransMontaigne that are based on beliefs and assumptions made by us as well as information currently available to us. When used in this document, the words "anticipate," "believe," "estimate," "expect," and similar expressions, are intended to identify forward-looking statements. Such statements reflect our current views with respect to future events and are subject to certain risks, uncertainties, and assumptions. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those described herein as anticipated, believed, estimated or expected. We do not intend to update these forward-looking statements except as required by law.

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.

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.

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 expect to vacate our existing office space at 370 17th Street and join 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 ("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 (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. For 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 provides for a $250 million revolving line of credit ("Working Capital Credit Facility") and a $200 million senior secured term loan ("Term Loan") and, together with the Working Capital Credit Facility, the "Senior Credit Facility". TransMontaigne utilized funds available under its new Credit Agreement to consummate the acquisition of the Coastal Fuels assets. All outstanding borrowings under the Credit Agreement become due and payable on February 28, 2006, when the Credit Agreement expires. The terms of the Credit Agreement include financial covenants that are tested on a quarterly basis relating to, among others: (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.

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

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 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	)
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

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.

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 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.

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 (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 (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 (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.

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.

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 during the three months ended March 31, 2003. 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 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 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):

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 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 $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 $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.

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.

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 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 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 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 (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.

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.

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

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.

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 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 (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 (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 (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.

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, 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.

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

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

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.

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.

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.

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 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 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%.

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 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 (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.

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.

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 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 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.

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.

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):

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):

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):

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):

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 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):

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 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. 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 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 include financial covenants that are tested on a quarterly basis relating to, among others: (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.

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

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.

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.

The information contained in Item 3 updates, and should be read in conjunction with, information set forth in Part II, Item 7A in our Annual Report on Form 10-K for the year ended June 30, 2002, in addition to the interim consolidated financial statements, accompanying notes and management's discussion and analysis of financial condition and results of operations presented in Items 1 and 2 of this Quarterly Report on Form 10-Q.

There are no material changes in market risks faced by us from those reported in our Annual Report on Form 10-K for the year ended June 30, 2002.

Within the 90 days prior to the date of this report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of TransMontaigne's disclosure controls and procedures pursuant to Exchange Act Rule 13a-14. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that TransMontaigne's disclosure controls and procedures are effective in timely alerting them to material information required to be included in TransMontaigne's periodic Securities and Exchange Commission filings relating to TransMontaigne (including its consolidated subsidiaries). There were no significant changes in TransMontaigne's internal controls or in other factors that could significantly affect these internal controls subsequent to the date of our most recent evaluation.

A Current Report on Form 8-K filed on March 17, 2003 reporting Item 2, the acquisition of all the issued and outstanding shares of capital stock of Coastal Fuels Marketing, Inc. and Coastal Tug and Barge, Inc. (collectively referred to as the "Acquired Companies") from El Paso CGP Company and Item 7, deferring filing of the historical and pro forma financial statements for the Acquired Companies.

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

I, Donald H. Anderson, President, Chief Executive Officer, Chief Operating Officer and Vice Chairman of TransMontaigne Inc., certify that:

I, Randall J. Larson, Executive Vice President, Chief Financial Officer, Chief Accounting Officer and Controller, certify that:

(Mark One)
ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2003
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

			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

					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

	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

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

	Preferred stock												Retained earnings (accumulated deficit)		Total common stockholders' equity
	Preferred stock					Common stock			Capital in excess of par value		Deferred stock-based compensation
	Series A			Series B		Common stock			Capital in excess of par value		Deferred stock-based compensation
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

	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

	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

	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

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

Years ending:
	June 30, 2003	$	—
	June 30, 2004		—
	June 30, 2005		—
	June 30, 2006		265,000

		$	265,000

							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

	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

			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

			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

	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

	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

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

10.1		Consulting Agreement by and between Harold R. Logan, Jr. and TransMontaigne Inc. effective as of January 1, 2003. FILED HEREWITH.
10.2		Stock Purchase Agreement, dated January 13, 2003, by and between El Paso CGP Company and TransMontaigne Product Services Inc. Incorporated by reference to TransMontaigne Inc. Current Report on Form 8-K (Securities and Exchange Commission File No. 001-11763) on March 17, 2003.
10.3		First Amendment to Stock Purchase Agreement, dated February 28, 2003, by and between El Paso CGP Company and TransMontaigne Product Services Inc. Incorporated by reference to TransMontaigne Inc. Current Report on Form 8-K (Securities and Exchange Commission File No. 001-11763) on March 17, 2003.
10.4		Credit Agreement, dated February 28, 2003, by and between TransMontaigne Inc., UBS AG, Stamford Branch, and UBS Warburg LLC. Incorporated by reference to TransMontaigne Inc. Current Report on Form 8-K (Securities and Exchange Commission File No. 001-11763) on March 17, 2003.
99.1		Written statement of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350). FILED HEREWITH.

Dated May 14, 2003				TRANSMONTAIGNE INC. (Registrant)
				By: /s/ DONALD H. ANDERSON Donald H. Anderson President, Chief Executive, Chief Operating Officer and Vice Chairman
				/s/ RANDALL J. LARSON Randall J. Larson Executive Vice President, Chief Financial Officer, Chief Accounting Officer and Controller