Edgar Filing: TRANSMONTAIGNE INC

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TABLE OF CONTENTS

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549

FORM 10-Q

(Mark One)
/X/	Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended December 31, 2003
OR
/ /	Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Commission File Number 001-11763

TRANSMONTAIGNE INC.

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

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 /X/ No / /

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

As of February 2, 2004 there were 41,100,181 shares of the Registrant's Common Stock outstanding.

TABLE OF CONTENTS


Part I. Financial Information
Item 1.		Unaudited Consolidated Financial Statements
		Consolidated Balance Sheets as of December 31, 2003 and June 30, 2003
		Consolidated Statements of Operations for the Three and Six Months Ended December 31, 2003 and 2002
		Consolidated Statements of Preferred Stock and Common Stockholders' Equity for the Year Ended June 30, 2003 and Six Months Ended December 31, 2003
		Consolidated Statements of Cash Flows for the Three and Six Months Ended December 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

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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

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

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

The following risk factors, discussed in more detail under the heading "Risk Factors" in our Current Report on Form 8-K filed on May 14, 2003, are important factors that could cause actual results to differ materially from our expectations and may adversely affect our business and results of operations, include, but are not limited to:

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

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

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

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

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

Part I. Financial information

ITEM 1. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

The interim consolidated financial statements of TransMontaigne Inc. as of and for the three and six months ended December 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, 2003, together with our discussion and analysis of financial condition and results of operations, included in our Annual Report on Form 10-K, as amended, filed with the Securities and Exchange Commission.

TransMontaigne Inc. is a holding company with the following active wholly-owned subsidiaries during the three and six months ended December 31, 2003.

–>: TransMontaigne Product Services Inc. ("TPSI")
–>: TransMontaigne Transport Inc.
–>: Coastal Fuels Marketing, Inc.
–>: Coastal Tug and Barge, Inc.

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)

			December 31, 2003			June 30, 2003

ASSETS
Current assets:
	Cash and cash equivalents		$	16,536		$	27,969
	Restricted cash held by commodity broker			8,480			5,155
	Trade accounts receivable, net			277,478			290,007
	Inventories—discretionary volumes			325,278			226,918
	Unrealized gains on derivative contracts			19,335			16,817
	Prepaid expenses and other			4,736			5,775

				651,843			572,641
Property, plant and equipment, net				370,242			371,735
Product linefill and tank bottom volumes				21,968			22,017
Unrealized gains on derivative contracts				786			1,885
Investments in petroleum related assets				10,131			10,131
Deferred tax assets				—			482
Deferred debt issuance costs, net				11,731			12,908
Other assets, net				5,955			6,917

			$	1,072,656		$	998,716

LIABILITIES, PREFERRED STOCK, AND COMMON STOCKHOLDERS' EQUITY
Current liabilities:
	Commodity margin loan		$	9,696		$	4,534
	Working capital credit facility			215,500			175,000
	Trade accounts payable			204,872			144,443
	Unrealized losses on derivative contracts			27,444			20,151
	Inventory due to others under exchange agreements			6,698			35,121
	Excise taxes payable			91,348			99,068
	Other accrued liabilities			22,687			25,562
	Deferred revenue—supply management services			4,214			4,816

				582,459			508,695
Other liabilities:
	Long-term debt			200,000			200,000
	Deferred tax liabilities			199			—
	Unrealized losses on derivative contracts			668			423

		Total liabilities		783,326			709,118

Series B Redeemable Convertible Preferred stock				78,524			79,329

Common stockholders' equity:
	Common stock			411			407
	Capital in excess of par value			251,839			249,339
	Deferred stock-based compensation			(5,561	)		(3,943	)
	Accumulated deficit			(35,883	)		(35,534	)

				210,806			210,269

			$	1,072,656		$	998,716

See accompanying notes to consolidated financial statements.

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

				Three months ended December 31,						Six months ended December 31,
				2003			2002			2003			2002

Supply, distribution, and marketing:
	Revenues			$	2,148,365		$	2,006,592		$	4,671,918		$	3,733,934
	Cost of product sold and other direct costs and expenses				(2,139,962	)		(2,015,516	)		(4,651,773	)		(3,735,246	)

			Net operating margins (deficiencies)		8,403			(8,924	)		20,145			(1,312	)

Terminals, pipelines, and tugs and barges:
	Revenue				25,797			17,265			52,818			34,660
	Direct operating costs and expenses				(10,632	)		(6,520	)		(22,958	)		(12,987	)

			Net operating margins		15,165			10,745			29,860			21,673

			Total net operating margins		23,568			1,821			50,005			20,361

Costs and expenses:
	Selling, general and administrative				(10,944	)		(8,775	)		(21,315	)		(18,106	)
	Depreciation and amortization				(5,932	)		(4,293	)		(11,469	)		(8,549	)
	Lower of cost or market write-downs on product linefill and tank bottom volumes				(17	)		—			(49	)		—
	Corporate relocation and transition				—			(365	)		—			(1,449	)

			Total costs and expenses		(16,893	)		(13,433	)		(32,833	)		(28,104	)

			Operating income (loss)		6,675			(11,612	)		17,172			(7,743	)

Other income (expenses):
	Dividend income				—			—			6			374
	Interest income				80			99			108			168
	Interest expense				(6,703	)		(3,066	)		(13,127	)		(6,359	)
	Loss on disposition of assets				(805	)		—			(805	)		—
	Other financing costs:
		Amortization of deferred debt issuance costs			(819	)		(233	)		(1,632	)		(462	)
		Gain on interest rate swap			—			1,199			—			1,274

			Total other expenses		(8,247	)		(2,001	)		(15,450	)		(5,005	)

			Earnings (loss) before income taxes and cumulative effect of a change in accounting principle		(1,572	)		(13,613	)		1,722			(12,748	)
Income tax (expense) benefit					629			5,173			(689	)		4,844

			Net earnings (loss) before cumulative effect of a change in accounting principle		(943	)		(8,440	)		1,033			(7,904	)
Cumulative effect of a change in accounting principle of $2,092, net of tax benefit of $795					—			(1,297	)		—			(1,297	)

			Net earnings (loss) before preferred stock dividends		(943	)		(9,737	)		1,033			(9,201	)
Preferred stock dividends, net					(691	)		(995	)		(1,382	)		(1,990	)

			Net loss attributable to common stockholders	$	(1,634	)	$	(10,732	)	$	(349	)	$	(11,191	)

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

		Three months ended December 31,						Six months ended December 31,
		2003			2002			2003			2002

Net loss after preferred stock dividends and before cumulative effect of a change in accounting principle		$	(1,634	)	$	(9,435	)	$	(349	)	$	(9,894	)
Cumulative effect of a change in accounting principle			—			(1,297	)		—			(1,297	)

Net loss attributable to common stockholders		$	(1,634	)	$	(10,732	)	$	(349	)	$	(11,191	)

Basic net loss per common share:
	Net loss after preferred stock dividends and before cumulative effect of a change in accounting principle	$	(0.04	)	$	(0.24	)	$	(0.01	)	$	(0.25	)
	Cumulative effect of a change in accounting principle		—			(0.03	)		—			(0.03	)

		$	(0.04	)	$	(0.27	)	$	(0.01	)	$	(0.28	)

Diluted net loss per common share:
	Net loss after preferred stock dividends and before cumulative effect of a change in accounting principle	$	(0.04	)	$	(0.24	)	$	(0.01	)	$	(0.25	)
	Cumulative effect of a change in accounting principle		—			(0.03	)		—			(0.03	)

		$	(0.04	)	$	(0.27	)	$	(0.01	)	$	(0.28	)

Weighted average common shares outstanding:
	Basic		39,364			39,127			39,271			39,079

	Diluted		39,364			39,127			39,271			39,079

See accompanying notes to consolidated financial statements.

TransMontaigne Inc. and subsidiaries
Consolidated statements of preferred stock and common stockholders' equity
Year ended June 30, 2003 and six months ended December 31, 2003
(In thousands)

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

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

Balance at June 30, 2003		—			79,329			407			249,339			(3,943	)		(35,534	)		210,269
Common stock issued for options exercised		—			—			—			123			—			—			123
Common stock repurchased from employees for withholding taxes		—			—			(1	)		(502	)		—			—			(503	)
Deferred compensation related to restricted stock awards		—			—			5			3,051			(3,056	)		—			—
Forfeiture of restricted stock awards prior to vesting		—			—			—			(172	)		172			—			—
Amortization of deferred stock-based compensation		—			—			—			—			1,266			—			1,266
Preferred stock dividends		—			—			—			—			—			(2,187	)		(2,187	)
Amortization of premium on Series B Redeemable Convertible Preferred stock		—			(805	)		—			—			—			805			805
Net earnings		—			—			—			—			—			1,033			1,033

Balance at December 31, 2003	$	—		$	78,524		$	411		$	251,839		$	(5,561	)	$	(35,883	)	$	210,806

See accompanying notes to consolidated financial statements.

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

					Three months ended December 31,						Six months ended December 31,
					2003			2002			2003			2002

Cash flows from operating activities:
	Net earnings (loss)				$	(943	)	$	(9,737	)	$	1,033		$	(9,201	)
	Adjustments to reconcile net earnings to net cash used by operating activities:
		Amortization of deferred revenue				(1,315	)		(150	)		(2,527	)		(300	)
		Depreciation and amortization				5,932			4,293			11,469			8,549
		Deferred tax expense (benefit)				(633	)		(6,202	)		681			(5,959	)
		Net tax effect arising from stock-based compensation				—			33			—			97
		Amortization of deferred stock-based compensation				662			457			1,266			858
		Amortization of debt issuance costs				819			233			1,632			462
		Unrealized gain on interest rate swap				—			(1,199	)		—			(1,274	)
		Loss on disposition of assets				805			—			805			—
		Net change in unrealized gains/losses on long-term derivative contracts				876			1,548			2,265			1,954
		Lower of cost or market write-down on base operating inventory volumes				271			—			2,333			—
		Lower of cost or market write-down on product linefill and tank bottom volumes				17			—			49			—
		Changes in operating assets and liabilities, net of effects from acquisitions:
			Trade accounts receivable, net			(32,173	)		(11,842	)		12,529			(37,795	)
			Inventories—discretionary volumes			(38,092	)		(54,563	)		(99,136	)		(59,635	)
			Prepaid expenses and other			(2,721	)		(910	)		(1,220	)		(906	)
			Trade accounts payable			36,438			32,781			61,779			68,553
			Inventory due to others under exchange agreements			(9,799	)		(10,833	)		(28,423	)		6,183
			Unrealized (gain) loss on derivative contracts			9,478			(4,760	)		5,779			9,389
			Excise taxes payable and other accrued liabilities			6,579			13,872			(10,987	)		785

				Net cash used by operating activities		(23,799	)		(46,979	)		(40,673	)		(18,240	)

Cash flows from investing activities:
	Acquisition of terminals, pipelines, and tugs and barges					(3,070	)		—			(3,070	)		(630	)
	Additions to property, plant and equipment—expansion of facilities					(1,607	)		(2,084	)		(6,443	)		(2,945	)
	Additions to property, plant and equipment—maintain existing facilities					(1,238	)		(1,342	)		(2,716	)		(1,831	)
	Decrease in restricted cash held by commodity broker					(1,278	)		(10,170	)		(3,325	)		(10,904	)
	Proceeds from disposition of assets					501			—			501			—
	Other					711			(2	)		1,653			59

				Net cash used by investing activities		(5,981	)		(13,598	)		(13,400	)		(16,251	)

Cash flows from financing activities:
	Net borrowings of debt					20,500			60,000			40,500			13,000
	Net borrowings (repayments) of commodity margin loan					9,696			(7,245	)		5,162			(1,470	)
	Deferred debt issuance costs					(300	)		(44	)		(455	)		(73	)
	Common stock issued for options exercised					—			—			123			11
	Common stock repurchased from employees for withholding taxes					(430	)		(111	)		(503	)		(161	)
	Preferred stock dividends paid in cash					(1,094	)		(1,704	)		(2,187	)		(1,704	)

				Net cash provided by financing activities		28,372			50,896			42,640			9,603

				Decrease in cash and cash equivalents		(1,408	)		(9,681	)		(11,433	)		(24,888	)
Cash and cash equivalents at beginning of period						17,944			15,645			27,969			30,852

Cash and cash equivalents at end of period					$	16,536		$	5,964		$	16,536		$	5,964

See accompanying notes to consolidated financial statements.

TransMontaigne Inc. and subsidiaries
Notes to consolidated financial statements
December 31, 2003 and June 30, 2003

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a) Principles of Consolidation and Use of Estimates

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, 2003, together with our discussion and analysis of financial condition and results of operations, included in our Annual Report on Form 10-K, as amended, filed with the Securities and Exchange Commission.

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

The preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. The following estimates, in our opinion, are subjective in nature, require the exercise of judgment, and involve complex analysis: allowance for doubtful accounts; fair value of inventories—discretionary volumes held for immediate sale or exchange (as of and for periods prior to October 1, 2002); fair value of derivative contracts; prepaid transportation costs; accrued lease abandonment costs; accrued transportation and deficiency obligations; and accrued environmental obligations. Changes in these estimates and assumptions will occur as a result of the passage of time and the occurrence of future events. Actual results could differ from these estimates.

(b) Nature of Business and Basis of Presentation

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

pipeline, and tug and barge operations, (ii) supply, distribution, and marketing, and (iii) supply management services.

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

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

In connection with our terminal, pipeline, and tug and barge operations, we utilize the accrual method of accounting for revenue and expenses. We generate revenues in our terminal, pipeline, and tug and barge operations from throughput fees, storage fees, transportation fees, ship-assist fees and fees from other ancillary services. Throughput revenue is recognized when the product is delivered to the customer; storage revenue is recognized ratably over the term of the storage contract; transportation revenue is recognized when the product has been delivered to the customer at the specified delivery location; ship-assist revenue is recognized when docking and other services are provided to marine vessels; and other service revenue is recognized as the services are performed.

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

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

In our supply, distribution and marketing operations, we purchase refined petroleum products primarily from refineries, schedule them for delivery to our terminals, as well as terminals owned by third parties, and then sell those products to our customers through rack sales, bulk sales, and contract sales. Revenue from our sales of physical inventory is recognized pursuant to the accrual method accounting (i.e., when cash becomes due and payable to us pursuant to the terms of the sales contracts). 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.

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

(e) Accounting for Supply Management Services Activities

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.

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

(f) Accounting for Risk Management Activities

We enter into risk management contracts, principally NYMEX futures contracts, to manage our exposure to changes in commodity prices. We evaluate our market risk exposure from an overall portfolio basis that considers changes in physical inventories—discretionary volumes held for immediate sale or exchange, open positions in derivative contracts, and open positions in risk management contracts. We enter into risk management contracts that offset the changes in the values of our inventories—discretionary volumes held for immediate sale or exchange and derivative contracts. At December 31, 2003 and June 30, 2003, our open positions in risk management contracts were NYMEX futures contracts (purchases and sales).

(g) Accounting for Derivative Contracts

Our bulk sales, contract sales, delivered fuel price management, retail price management and risk management contracts qualify as derivative instruments pursuant to the requirements of Statement of Financial Accounting Standards No. 133 ("SFAS No. 133"), Accounting for Derivative Instruments and Hedging Activities. All derivative contracts are required to be reported as assets and liabilities at fair value in the accompanying consolidated balance sheet in accordance with SFAS No. 133. The fair value of our derivative contracts is included in "Unrealized gains or losses on derivative contracts" in the accompanying consolidated balance sheet. At December 31, 2003 and June 30, 2003, there were no unrealized gains or losses on risk management contracts because NYMEX futures contracts require daily settlement for changes in commodity prices on open futures contracts. Changes in the fair value of our derivative contracts are included in net operating margins attributable to our supply, distribution and marketing operations.

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

(h) Accounting for Inventories—Discretionary Volumes

Our inventories—discretionary volumes consist of refined petroleum products, primarily gasolines, distillates, and No. 6 oil. Our volumes held for immediate sale or exchange are subject to our risk

management policy or commodity price risk management and represent those volumes held for immediate sale or exchange in the ordinary course of business. Our volumes held for base operations generally are not subject to commodity price risk management and represent in-transit volumes on common carrier pipelines. 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 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. Inventories—discretionary volumes are presented in the accompanying consolidated balance sheet as current assets and are carried at the lower of cost (first-in, first-out) or market (replacement cost) for periods subsequent to September 30, 2002. Prior to October 1, 2002, our inventories—discretionary volumes held for immediate sale or exchange were carried at fair value with the changes in the fair value included in net margins attributable to our supply, distribution and marketing operations. Prior to October 1, 2002, our volumes held for base operations were carried at original cost adjusted for impairment write-downs. Inventories—discretionary volumes are as follows (in thousands):

	December 31, 2003			June 30, 2003
	Amount		Bbls	Amount		Bbls

Volumes held for immediate sale or exchange	$	225,467	6,487	$	130,492	3,890
Volumes held for base operations		99,811	2,922		96,426	2,922

Inventories—discretionary volumes	$	325,278	9,409	$	226,918	6,812

At December 31, 2003 and June 30, 2003, the market value of our volumes held for immediate sale or exchange exceeded their cost basis by approximately $15.5 million and $5.9 million, respectively. For the three and six months ended December 31, 2003 we recognized lower of cost or market write-downs on certain of our base operating inventory volumes of approximately $0.3 million and $2.3 million, respectively, which are included in cost of products sold and other direct costs and expenses in the accompanying consolidated statements of operations.

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 December 31, 2003 and June 30, 2003, current liabilities include inventory due to others under exchange agreements of approximately 0.2 million barrels and 1.0 million barrels, respectively, with a fair value of approximately $6.7 million and $35.1 million, respectively. The amount recorded represents the fair value of inventory due to others under exchange agreements at the balance sheet date.

(i) Accounting for Product Linefill and Tank Bottom Volumes

At December 31, 2003 and June 30, 2003, our product linefill and tank bottom volumes are presented in the accompanying consolidated balance sheet as non-current assets and are carried at the lower of

cost (weighted average) or market (replacement cost). Product linefill and tank bottom volumes are as follows (in thousands):

	December 31, 2003			June 30, 2003
	Amount		Bbls	Amount		Bbls

Gasolines	$	12,994	497	$	13,020	497
Distillates		7,449	319		7,449	319
No. 6 oil		1,525	61		1,548	61

Product linefill and tank bottom volumes	$	21,968	877	$	22,017	877

At December 31, 2003 and June 30, 2003, the weighted average adjusted cost basis of our product linefill and tank bottom volumes was approximately $0.60 per gallon. During the three months ended December 31, 2003 and 2002, we recognized impairment losses of approximately $17,000 and $nil, respectively, due to write-downs on certain of our product linefill and tank bottom volumes to current market values. During the six months ended December 31, 2003 and 2002, we recognized impairment losses of approximately $49,000 and $nil, respectively, due to write-downs on certain of our product linefill and tank bottom volumes to current market values.

(j) Cash and Cash Equivalents

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

(k) Deferred Debt Issuance Costs

Deferred debt issuance costs are as follows (in thousands):

	June 30, 2003		Additions		Amortization			December 31, 2003

Working capital credit facility	$	5,941	$	23	$	(1,115	)	$	4,849
Senior subordinated notes		6,967		432		(517	)		6,882

	$	12,908	$	455	$	(1,632	)	$	11,731

(l) Environmental Obligations

At December 31, 2003 and June 30, 2003, we have accrued environmental obligations of approximately $5.9 million and $5.6 million, respectively, representing our best estimate of our remediation obligations (see Note 7 of Notes to consolidated financial statements). During the three and six months ended December 31, 2003, we made payments of approximately $0.1 million and $0.2 million, respectively, towards our environmental remediation obligations. During the three and six months ended December 31, 2003, we increased our estimate of our future environmental remediation obligations by approximately $0.5 million, of which approximately $0.3 million was assumed in connection with our acquisition of the Norfolk terminal (see Note 2 of Notes to consolidated financial statements). During the three and six months ended December 31, 2002, we did not revise our estimate of our future environmental remediation obligations. During the three months ended December 31, 2003 and 2002, we received insurance recoveries of approximately $0.2 million and $0.2 million, respectively, which are recorded as a reduction of direct operating costs and expenses in the accompanying consolidated statements of operations. During the six months ended December 31, 2003 and 2002, we received insurance recoveries of approximately $1.0 million and $0.2 million, respectively, which are recorded as a reduction of direct operating costs and expenses in the accompanying consolidated statements of operations.

(m) Equity-Based Compensation Plans

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

			Three months ended December 31,						Six months ended December 31,
			2003			2002			2003			2002

Net loss attributable to common stockholders:
	As reported		$	(1,634	)	$	(10,732	)	$	(349	)	$	(11,191	)
	Amortization of the fair value of stock options granted to employees			(55	)		(90	)		(117	)		(194	)

	Pro forma		$	(1,689	)	$	(10,822	)	$	(466	)	$	(11,385	)

Loss per common share:
	As reported
		Basic	$	(0.04	)	$	(0.27	)	$	(0.01	)	$	(0.28	)
		Diluted	$	(0.04	)	$	(0.27	)	$	(0.01	)	$	(0.28	)
	Pro forma
		Basic	$	(0.04	)	$	(0.28	)	$	(0.01	)	$	(0.29	)
		Diluted	$	(0.04	)	$	(0.28	)	$	(0.01	)	$	(0.29	)

There were no options granted during the six months ended December 31, 2003 and the year ended June 30, 2003. The weighted average fair value at grant dates for options granted during the years ended June 30, 2002 and 2001 was $3.08 and $2.12, respectively. The primary assumptions used to estimate the fair value of options granted on the date of grant using the Black-Scholes option-pricing model during the years ended June 30, 2002 and 2001 were as follows: no dividend yield, expected volatility of 79% and 61%, risk-free rates of 4.49% and 4.95%, and expected lives of 4 years and 5 years, respectively.

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

(q) Earnings (Loss) Per Common Share

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

(r) Reclassification

Certain amounts in the prior periods have been reclassified to conform to the current period's presentation.

(2) ACQUISITIONS AND DISPOSITIONS

On October 1, 2003, we acquired for cash consideration of approximately $3.1 million a 900,000-barrel products terminal in Norfolk, Virginia. The terminal increases our presence in the Mid-Atlantic market and includes a docking facility that will permit us to receive shipments off and deliver shipments to the water.

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

On January 31, 2003, we acquired for cash consideration of approximately $6.4 million a 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.

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 preliminarily allocated as follows (in thousands):

		Norfolk			Coastal Fuels			Fairfax			Brownsville

Discretionary inventory volumes		$	1,557		$	30,625		$	—		$	—
Prepaid expenses and other current assets			—			2,259			—			—
Property, plant and equipment			1,906			121,287			6,773			630
Other assets—acquired intangible			—			2,500			—			—
Product linefill and tank bottom volumes			—			6,311			—			—
Trade accounts payable—due diligence costs			—			(1,350	)		—			—
Acquisition related liabilities			(393	)		(5,664	)		(420	)		—

	Cash paid	$	3,070		$	155,968		$	6,353		$	630

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

(3) CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE

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

	December 31, 2003			June 30, 2003

Trade accounts receivable	$	278,151		$	291,929
Less allowance for doubtful accounts		(673	)		(1,922	)

	$	277,478		$	290,007

During the three months ended December 31, 2003 and 2002, we increased the allowance for doubtful accounts through a charge to income of approximately $nil and $0.3 million, respectively. During the six months ended December 31, 2003 and 2002, we increased the allowance for doubtful accounts through a charge to income of approximately $0.1 million and $0.6 million, respectively.

(4) UNREALIZED GAINS AND LOSSES ON DERIVATIVE CONTRACTS

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

			December 31, 2003			June 30, 2003

Unrealized gains—current			$	19,335		$	16,817
Unrealized gains—long-term				786			1,885

	Unrealized gains—asset			20,121			18,702

Unrealized losses—current				(27,444	)		(20,151	)
Unrealized losses—long-term				(668	)		(423	)

	Unrealized losses—liability			(28,112	)		(20,574	)

		Net liability position	$	(7,991	)	$	(1,872	)

At December 31, 2003 and June 30, 2003, there were no unrealized gains or losses on risk management contracts because NYMEX futures contracts require daily settlement for changes in commodity prices on open futures contracts.

(5) PROPERTY, PLANT AND EQUIPMENT

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

	December 31, 2003			June 30, 2003

Land	$	45,281		$	46,477
Terminals, pipelines and equipment		371,990			365,379
Technology and equipment		14,008			13,426
Tugs and barges		18,044			15,914
Furniture, fixtures and equipment		6,905			6,539
Construction in progress		4,597			4,125

		460,825			451,860
Less accumulated depreciation		(90,583	)		(80,125	)

	$	370,242		$	371,735

(6) OTHER ASSETS

Other assets are as follows (in thousands):

	December 31, 2003		June 30, 2003

Prepaid transportation	$	2,309	$	3,021
Acquired intangible, net of accumulated amortization of $417 and $167, respectively		2,083		2,333
Commodity trading membership		1,500		1,500
Deposits and other assets		63		63

	$	5,955	$	6,917

Prepaid transportation relates to our contractual transportation and deficiency agreements with three interstate product pipelines (see Note 13 of Notes to consolidated financial statements).

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

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

(7) ACCRUED LIABILITIES

Accrued liabilities are as follows (in thousands):

	December 31, 2003		June 30, 2003

Accrued environmental obligations	$	5,885	$	5,577
Accrued lease abandonment		2,821		3,178
Accrued transportation and deficiency obligations		1,384		2,013
Dividend payable—preferred stock		1,093		1,093
Accrued interest payable		1,882		1,788
Accrued expenses and other		9,622		11,913

	$	22,687	$	25,562

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 vacated our office space in Denver, Colorado during June 2003 and we vacated our excess space in Atlanta, Georgia during October 2002. In connection with our acquisition of the Coastal Fuels assets, we vacated a sales office in Coral Gables, Florida. 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 December 31, 2003 and June 30, 2003, the accrued liability for lease abandonment costs was approximately $2.8 million and $3.2 million, respectively.

(in thousands)	Accrued liability at June 30, 2003		Change in accrued liability		Amounts paid during the period			Accrued liability at December 31, 2003

Accrued lease abandonment	$	3,178	$	156	$	(513	)	$	2,821

We expect to pay the accrued liability of approximately $2.8 million, net of estimated sublease rentals, as follows (in thousands):

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

2004 (Remainder of the year)	$	531	$	(89	)	$	442
2005		1,263		(481	)		782
2006		1,108		(548	)		560
2007		928		(452	)		476
2008		370		(187	)		183
Thereafter		763		(385	)		378

	$	4,963	$	(2,142	)	$	2,821

(8) DEFERRED REVENUE—SUPPLY MANAGEMENT SERVICES

At December 31, 2003 and June 30, 2003, our deferred revenue associated with logistical supply management services was approximately $0.7 million and $1.0 million, respectively. We amortize the deferred revenue from these contracts into revenues attributable to our supply, distribution and marketing operations on a straight-line basis over the respective terms of the contracts. During the three months ended December 31, 2003 and 2002, we recognized approximately $150,000 in net revenues attributable to our supply, distribution and marketing operations from the amortization of the deferred revenues. During the six months ended December 31, 2003 and 2002, we recognized approximately $300,000 in net revenues attributable to our supply, distribution and marketing operations from the amortization of the deferred revenues.

During the six months ended December 31, 2003 and 2002, we originated retail and delivered fuel price management contracts with an estimated fair value of approximately $1.9 million and $4.2 million, respectively, representing the excess of the amounts we expect to receive from the ground fleet customers over our estimate of the forward price curve of the underlying commodity adjusted for basis differentials. We have deferred the estimated fair value of these contracts at origination because our estimate of the fair value is not evidenced by quoted market prices or current market transactions for the contracts in their entirety. We amortize the deferred revenue 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. During the three months ended December 31, 2003 and 2002, we recognized approximately $1.2 million and $nil, respectively, in revenues attributable to our supply, distribution and marketing operations from the amortization of the deferred revenue from these contracts. During the six months ended December 31, 2003 and 2002, we recognized approximately $2.2 million and $nil, respectively, in revenues attributable to our supply, distribution and marketing operations from the amortization of the deferred revenue from these contracts.

(in thousands)	Deferred revenue at June 30, 2003		Additions during the period		Amounts amortized during the period			Deferred revenue at December 31, 2003

Logistical supply management services	$	1,000	$	—	$	(300	)	$	700
Retail price management contracts		2,047		370		(1,148	)		1,269
Delivered fuel price management contracts		1,769		1,555		(1,079	)		2,245

	$	4,816	$	1,925	$	(2,527	)	$	4,214

(9) DEBT

Debt is as follows (in thousands):

	December 31, 2003			June 30, 2003

Commodity margin loan	$	9,696		$	4,534
Working capital credit facility		215,500			175,000
Senior subordinated notes		200,000			200,000

		425,196			379,534
Less debt classified as current		(225,196	)		(179,534	)

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

Commodity Margin Loan. We currently have a commodity margin loan agreement with Salomon Smith Barney that allows us to borrow up to $20 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% (2.70% at December 31, 2003).

Working Capital Credit Facility. On February 28, 2003, we executed a Credit Agreement with UBS AG that initially provided for a revolving line of credit ("Working Capital Credit Facility") and a senior secured term loan ("Term Loan"). The Working Capital Credit Facility is our primary means of financing our working capital requirements and, as such, it is material to our operations. The Working Capital Credit Facility currently provides for a maximum borrowing line of credit that is the lesser of (i) $275 million and (ii) the borrowing base (as defined; $444 million at December 31, 2003). The maximum borrowing amount is reduced by the amount of letters of credit that are outstanding ($22.3 million at December 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. The weighted average interest rate on the borrowings under the Working Capital Credit Facility was 4.0% and 3.9% during the three and six months ended December 31, 2003, respectively. 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 December 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 sheets at December 31, 2003 and June 30, 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 provided for a one-time borrowing of $200 million with a scheduled maturity of February 28, 2006. The proceeds from the Term Loan were used primarily to finance the acquisition of the Coastal Fuels assets. The Term Loan was repaid in full on May 30, 2003 with the proceeds from the Senior Subordinated Notes.

Former 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 million revolving credit facility that was scheduled to mature on June 27, 2005.

Senior Subordinated Notes. On May 30, 2003, we consummated the sale and issuance of $200 million aggregate principal amount of 9¹/8% Senior Subordinated Notes due 2010 and received proceeds of $194.5 million (net of underwriters' discounts of $5.5 million). The Senior Subordinated Notes mature on June 1, 2010 and interest is payable semi-annually in arrears on each June 1 and December 1 commencing on December 1, 2003. The Senior Subordinated Notes are unsecured and subordinated to all of our existing and future senior debt. Upon certain change of control events, each holder of the Senior Subordinated Notes may require us to repurchase all or a portion of its notes at a purchase price equal to 101% of the principal amount thereof, plus accrued interest. The indenture governing the Senior Subordinated Notes contains covenants that, among other things, limit our ability to incur additional indebtedness, pay dividends on, redeem or repurchase our common stock, make investments, make certain dispositions of assets, engage in transactions with affiliates, create certain liens, and consolidate, merge, or transfer all or substantially all of our assets. The Senior Subordinated Notes are fully and unconditionally guaranteed on a joint and several basis by our subsidiaries other than minor subsidiaries that are inactive and have no assets or operations. We are a holding company for our subsidiaries, with no independent assets or operations. Accordingly, we are dependent upon the distribution of the earnings of our subsidiaries, whether in the form of dividends, advances or payments on account of inter-company obligations, to service our debt obligations. There are no restrictions on our ability or any subsidiary guarantor to obtain funds from our subsidiaries.

Scheduled maturities of debt at December 31, 2003 are as follows (in thousands):

Years ending June 30:

2004	$	9,696
2005		—
2006		215,500
2007		—
2008		—
Thereafter		200,000

	$	425,196

(10) PREFERRED STOCK

At December 31, 2003 and June 30, 2003, 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):

	December 31, 2003		June 30, 2003

Series B Redeemable Convertible Preferred stock, par value $0.01 per share, 100,000 shares authorized, 72,890 shares issued and outstanding, liquidation preference of $72,890	$	78,524	$	79,329

At December 31, 2003 and June 30, 2003, there are 72,890 shares of Series B Redeemable Convertible Preferred Stock outstanding. The Series B Redeemable Convertible Preferred Stock has a liquidation value of $1,000 per share, bears dividends at the rate of 6% per annum of the liquidation value, and is mandatorily redeemable between June 30, 2007 and December 31, 2007 for shares of common

stock and/or cash at our option, subject to limitations on the total number of common shares permitted to be used in the exchange and issued to any shareholder. Dividends are cumulative and payable quarterly. The dividends are payable in cash, unless precluded by contract or the Working Capital Credit Facility, in which case dividends are payable in additional shares of Series B Redeemable Convertible Preferred Stock. The Series B Redeemable Convertible Preferred Stock may be put to us, at the option of the holder, for cash equal to the greater of its liquidation value or conversion value upon the future occurrence of a fundamental change (including those relating to sale of substantially all of the assets, delisting of our common stock from a national exchange, change in control, bankruptcy filing, and an event of default that accelerates the repayment of our debt). We may call the outstanding shares of Series B Redeemable Convertible Preferred Stock after June 30, 2005 if certain specified conditions are met. The Series B Redeemable Convertible Preferred Stock is convertible, at the option of the holder, into common stock at $6.60 per share, subject to adjustment upon the occurrence of specified future events. The holders of the Series B Redeemable Convertible Preferred Stock have the right to vote on all matters (except the election of directors) with the holders of the common stock (voting collectively as a single class).

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

Preferred stock dividends on the Series A Convertible Preferred stock were $nil and $0.3 million for the three months ended December 31, 2003 and 2002, respectively. Preferred Stock dividends on the Series B Redeemable Convertible Preferred Stock were $0.7 million for each of the three months ended December 31, 2003 and 2002. The amount of the Series B Redeemable Convertible Preferred Stock dividend recognized for financial reporting purposes for each of the three months ended December 31, 2003 and 2002, is composed of the amount of the dividend payable and paid 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.

Preferred stock dividends on the Series A Convertible Preferred stock were $nil and $0.6 million for the six months ended December 31, 2003 and 2002, respectively. Preferred Stock dividends on the Series B Redeemable Convertible Preferred Stock were $1.4 million for each of the six months ended December 31, 2003 and 2002. The amount of the Series B Redeemable Convertible Preferred Stock dividend recognized for financial reporting purposes for each of the three months ended December 31, 2003 and 2002, is composed of the amount of the dividend payable and paid to the holders of the Series B Redeemable Convertible Preferred Stock of $2.2 million offset by the amortization of the premium on the carrying amount of the Series B Redeemable Convertible Preferred Stock of $0.8 million.

At its issuance date (June 28, 2002), the fair value of the Series B Redeemable Convertible Preferred stock exceeded its liquidation value. 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.

(11) COMMON STOCK

At December 31, 2003 and June 30, 2003, we were authorized to issue up to 80,000,000 shares of common stock with a par value of $0.01 per share. At December 31, 2003 and June 30, 2003, there were 41,100,961 shares and 40,685,690 shares issued and outstanding, respectively. Our Working Capital Credit Facility, Senior Subordinated Notes and the certificate of designations of our Series B Redeemable Convertible Preferred stock contain restrictions on the payment of dividends on our common stock.

We have a restricted stock plan that provides for awards of common stock to certain 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. Information about restricted common stock activity for the six months ended December 31, 2003, and the year ended June 30, 2003 is as follows:

	Total shares		Vested shares		Unvested shares

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

Outstanding at June 30, 2003	1,814,699		298,520		1,516,179
Granted	511,000		—		511,000
Cancelled	(37,290	)	—		(37,290	)
Repurchased	(82,739	)	(82,739	)	—
Vested	—		277,026		(277,026	)

Outstanding at December 31, 2003	2,205,670		492,807		1,712,863

On October 25, 2003, we granted approximately 511,000 shares of restricted common stock to employees, which resulted in approximately $3.1 million of deferred compensation that will be amortized to income over their four-year vesting period. Amortization of deferred compensation of approximately $0.7 million and $0.5 million is included in selling, general and administrative expense for the three months ended December 31, 2003 and 2002, respectively. Amortization of deferred compensation of approximately $1.3 million and $0.9 million is included in selling, general and administrative expense for the six months ended December 31, 2003 and 2002, respectively.

(12) STOCK OPTIONS

Information about stock option activity for the six months ended December 31, 2003 and the year ended June 30, 2003, is as follows:

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

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

Outstanding at June 30, 2003	—		—	1,004,500		4.51
Cancelled	—		—	(35,600	)	4.63
Exercised	—		—	(24,300	)	5.11

Outstanding at December 31, 2003	—		—	944,600		4.49

Exercisable at December 31, 2003	—		—	358,250		4.90

Information about stock options outstanding at December 31, 2003 is as follows:

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

1997 Plan	$ 3.75 - 7.25 $11.00 - 13.50 $ 17.25	932,100 11,500 1,000	6.9 5.0 3.7	$ $ $	4.39 11.65 17.25	345,750 11,500 1,000	$ $ $	4.64 11.65 17.25

		944,600				358,250

(13) COMMITMENTS AND CONTINGENCIES

Transportation and Deficiency Agreements. In connection with our sale of two product distribution facilities in Little Rock, Arkansas, we are potentially liable for payments of up to $725,000 per year for a five-year period through June 30, 2006. At June 30, 2003, we recognized an accrued liability of approximately $0.8 million representing our estimate of the future amounts we expect to pay for the shortfall in our actual volumes and our estimated shortfall in volumes for the remainder of the term of the agreement. During the six months ended December 31, 2003, we paid approximately $0.2 million as settlement for our shortfall in volumes for the year ended June 30, 2003. Based on actual throughput volumes for the six months ended December 31, 2003, we decreased our accrued liabilities by $0.2 million resulting in a total accrued liability of $0.4 million as of and for the six months ended December 31, 2003.

We also are subject to three transportation and deficiency agreements ("T&D's") with three separate interstate pipeline companies. At June 30, 2003, we recognized an accrued liability of approximately $1.2 million representing our estimate of the future amounts we expect to pay for our estimated shortfall in volumes for the remainder of the term of the agreements. During the six months ended

December 31, 2003, we recognized a reduction in our accrued liability of approximately $0.2 million representing a change in our estimate of the future amounts we expect to pay for the estimated shortfall in volumes for the remainder of the terms of the T&D agreements resulting in a total accrued liability of $1.0 million as of and for the six months ended December 31, 2003.

At December 31, 2003 and June 30, 2003, we included approximately $2.3 million and $3.0 million, respectively, of prepaid transportation in other assets since we have a contractual right, after the end of the term of the T&D agreements, to apply the amounts to charges for using the interstate pipeline in the future (see Note 6 of Notes to consolidated financial statements). During the three months ended December 31, 2003, we applied approximately $0.7 million of our prepaid transportation to charges for using the interstate pipeline during the period.

(in thousands)	June 30, 2003			Payments during the period		Amounts applied during the period			Change in estimate during the period		December 31, 2003

Other assets—prepaid transportation	$	3,021		$	—	$	(712	)	$	—	$	2,309

Accrued liability—T&D obligations	$	(2,013	)	$	238	$	—		$	391	$	(1,384	)

Operating Leases. At December 31, 2003, future minimum lease payments under our non-cancelable operating leases (exclusive of vacated office space) are as follows (in thousands):

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

2004 (Remainder of the year)	$	763	$	1,419	$	176
2005		1,558		2,318		157
2006		1,574		601		120
2007		1,541		162		58
2008		1,507		—		—
Thereafter		5,574		—		—

	$	12,517	$	4,500	$	511

Rental expense under operating leases was $2.1 million and $1.8 million for the six months ended December 31, 2003 and 2002, respectively.

(14) EARNINGS PER SHARE

The following table reconciles the computation of basic and diluted weighted average shares (in thousands):

		Three months ended December 31,		Six months ended December 31,
		2003	2002	2003	2002

Basic weighted average shares		39,364	39,127	39,271	39,079
Effect of dilutive securities:
	Restricted common stock subject to continuing vesting requirements	—	—	—	—
	Exercise of stock options	—	—	—	—
	Conversion of Series B Redeemable Convertible Preferred stock	—	—	—	—

Diluted weighted average shares		39,364	39,127	39,271	39,079

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 three months ended December 31, 2003, as their inclusion would have been anti-dilutive (in thousands):

		December 31, 2003

Restricted common stock subject to continuing vesting requirements		1,713
Common stock issuable upon exercise of stock options		945
Common stock issuable upon conversion of Series B Redeemable Convertible Preferred stock		11,044

		13,702

For the three months ended December 31, 2003, the stock options had a weighted average exercise price of $4.49 per share and the Series B Redeemable Convertible Preferred stock was convertible into shares of common stock at a conversion price of $6.60 per common share.

(15) BUSINESS SEGMENTS

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

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

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

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

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

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

						Three months ended December 31,						Six months ended December 31,
						2003			2002			2003			2002

	Terminals, pipelines, and tugs and barges:
		Historical facilities				$	10,852		$	10,745		$	21,985		$	21,673
		Coastal Fuels assets					4,313			—			7,875			—

			Adjusted net operating margins				15,165			10,745			29,860			21,673

	Supply, distribution and marketing:
		Light oil margins					7,580			9,545			12,440			15,370
		Heavy oil margins					3,425			—			4,866			—
		Supply management services margins					4,110			3,158			6,480			7,540
		Trading margins, net					457			640			2,588			(1,955	)

			Adjusted net operating margins				15,572			13,343			26,374			20,955

				Total adjusted net operating margins		$	30,737		$	24,088		$	56,234		$	42,628

Reconciliation to Earnings (Loss) Before Income Taxes:
	Adjusted net operating margins					$	30,737		$	24,088		$	56,234		$	42,628
	Inventory Adjustments:
		Gains recognized on beginning inventories—discretionary volumes held for immediate sale or exchange					3,067			12,644			5,855			12,644
		Gains deferred on ending inventories—discretionary volumes held for immediate sale or exchange					(15,469	)		(33,490	)		(15,469	)		(33,490	)
		Change in FIFO cost basis of base operating inventory volumes					5,504			(1,421	)		5,718			(1,421	)
		Lower of cost or market write-downs on base operating inventory volumes					(271	)		—			(2,333	)		—

			Total net operating margins				23,568			1,821			50,005			20,361
	Other Items:
		Selling, general and administrative expenses					(10,944	)		(8,775	)		(21,315	)		(18,106	)
		Depreciation and amortization					(5,932	)		(4,293	)		(11,469	)		(8,549	)
		Lower of cost or market write-downs on product linefill and tank bottom volumes					(17	)		—			(49	)		—
		Corporate relocation and transition					—			(365	)		—			(1,449	)

					Operating income (loss)		6,675			(11,612	)		17,172			(7,743	)
		Other income (expense), net					(8,247	)		(2,001	)		(15,450	)		(5,005	)

					Earnings (loss) before income taxes	$	(1,572	)	$	(13,613	)	$	1,722		$	(12,748	)

Supplemental information regarding our revenues for our business segments is as follows:

			Three months ended December 31,				Six months ended December 31,
			2003		2002		2003		2002

Terminals, pipelines, and tugs and barges:
	Revenues from external customers		$	9,746	$	7,957	$	21,378	$	15,748
	Inter-segment revenues			16,051		9,308		31,440		18,912

		Total revenues	$	25,797	$	17,265	$	52,818	$	34,660

Supply, distribution and marketing:
	Revenues from external customers		$	2,148,365	$	2,006,592	$	4,671,918	$	3,733,934
	Inter-segment revenues			—		—		—		—

		Total revenues	$	2,148,365	$	2,006,592	$	4,671,918	$	3,733,934

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

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

A summary of the significant accounting policies that we have adopted and followed in the preparation of our consolidated financial statements is detailed in our consolidated financial statements for the year ended June 30, 2003 included in our Annual Report on Form 10-K, as amended (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 held for immediate sale or exchange (as of and for periods prior to October 1, 2002); fair value of derivative contracts; prepaid transportation costs; accrued lease abandonment costs; accrued transportation and deficiency obligations; and accrued environmental obligations. These estimates are based on our knowledge and understanding of current conditions and actions we may take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our financial condition and results of operations.

SIGNIFICANT DEVELOPMENTS DURING THE SIX MONTHS ENDED DECEMBER 31, 2003

On October 1, 2003, we acquired for cash consideration of approximately $3.1 million a 900,000-barrel terminal, including product inventory, in Norfolk, Virginia. The acquired terminal provides us with additional storage, a docking facility that permits us to receive and deliver shipments off the water, and operating synergies with our existing facility in Norfolk, Virginia.

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

SUBSEQUENT EVENTS

On May 30, 2003, we sold the Senior Subordinated Notes in a private placement transaction that was exempt from registration under the Federal Securities Act of 1933. We also entered into a registration rights agreement requiring us to make an exchange offer. On July 22, 2003, we filed a registration statement on Form S-4 with the Securities and Exchange Commission to effect the exchange offer. The registration rights agreement also requires us to use our best efforts to cause the registration statement filed with respect to the exchange offer to be declared effective by October 27, 2003 and consummate the exchange offer no later than December 26, 2003. If we do not do so, additional interest payments will be payable on the Senior Subordinated Notes. The exchange offer was not consummated as of December 26, 2003 and, therefore, we are accruing additional interest of 0.5% on the Senior Subordinated Notes until the exchange offer is consummated (resulting in a total coupon rate of 9.625%). As of February 17, 2004, the registration statement on Form S-4 has not been declared effective by the staff of the Securities and Exchange Commission.

RESULTS OF OPERATIONS—BUSINESS SEGMENTS

Under SFAS No. 131, we are required to report measures of profit and loss that are used by our chief operating decision maker (our CEO) in assessing the financial performance of our business segments. Our CEO assesses the financial performance of each of our reportable segments using a financial performance measure, which we refer to as "adjusted net operating margins." There are no differences between the financial performance measure, "adjusted net operating margin," used by our CEO in evaluating the performance of our terminals, pipelines, and tugs and barges segment and the net operating margins reported for that segment in our accompanying historical financial statements. Our CEO assesses the "adjusted net operating margins" of our supply, distribution, and marketing segment using financial information that is prepared pursuant to the mark-to-market method of accounting. "Adjusted net operating margins" for the supply, distribution and marketing segment differs from net operating margins for that segment as presented in our accompanying historical statement of operations due to the treatment of our inventories—discretionary volumes. In determining our "adjusted net operating margins" for our supply, distribution and marketing segment, inventories—discretionary volumes held for immediate sale or exchange are reflected at fair value, which matches the treatment of our derivative and risk management contracts. Therefore, the effects of changes in the fair value of our inventories—discretionary volumes held for immediate sale or exchange are included in "adjusted net operating margins" attributable to our supply, distribution and marketing segment in the period in which the fair value actually changes. "Adjusted net operating margins" also excludes the lower of cost or market write-downs on our inventories—base operating volumes from our net operating margins attributable to our supply, distribution and marketing segment.

Because our inventories—discretionary volumes are composed of refined petroleum products, which are commodities with established trading markets and readily ascertainable market prices, we believe that the financial performance of our supply, distribution and marketing segment can be appropriately evaluated using the mark-to-market method rather than the lower-of-cost-or-market method of accounting for our inventories—discretionary volumes held for immediate sale or exchange. As a result of the implementation of EITF 02-03, our inventories—discretionary volumes are carried at the lower of cost or market, while our derivative and risk management contracts are carried at fair value. As a result, if commodity prices are increasing during the end of a quarter, we may report significant losses on derivative and risk management contracts and significant deferred gains on discretionary inventory volumes held for immediate sale or exchange at the end of that quarter and report significant gains on our beginning inventories—discretionary volumes held for immediate sale or exchange when they are sold in the following quarter.

Supply, distribution and marketing—adjusted net operating margins

Selected quarterly adjusted net operating margins for the supply, distribution and marketing segment for each of the three months ended December 31, 2003 and 2002, are summarized below (in thousands):

		Three months ended December 31,
		2003			2002

Supply, distribution and marketing:
Light oil margins		$	7,580		$	9,545
Heavy oil margins			3,425			—
Supply management services margins			4,110			3,158
Trading margins, net			457			640

	Adjusted net operating margins	$	15,572		$	13,343

Reconciliation to net operating margins:
Adjusted net operating margins		$	15,572		$	13,343
Gains recognized on beginning inventories—discretionary volumes held for immediate sale or exchange			3,067			12,644
Gains deferred on ending inventories—discretionary volumes held for immediate sale or exchange			(15,469	)		(33,490	)
Change in FIFO cost basis of base operating inventory volumes			5,504			(1,421	)
Lower of cost or market write-downs on base operating inventory volumes			(271	)		—

Net operating margins—Historical financial statements		$	8,403		$	(8,924	)

The adjusted net operating margins attributable to our supply, distribution and marketing segment increased to $15.6 million for the three months ended December 31, 2003 from $13.3 million for the three months ended December 31, 2002. The Coastal Fuels assets, which we acquired on February 28, 2003, contributed heavy oil margins of approximately $3.4 million for the three months ended December 31, 2003.

Prior to October 1, 2002, our inventories—discretionary volumes held for immediate sale or exchange were carried at fair value. Effective October 1, 2002, we adjusted the carrying amount of inventories—discretionary volumes held for immediate sale or exchange to the lower of cost or market pursuant to the requirements of EITF 02-03. During the last half of September 2003, we experienced increases in certain commodity prices and locations, which resulted in the fair value of our inventories—discretionary volumes held for immediate sale or exchange at September 30, 2003 exceeding their cost basis by approximately $3.1 million. The "Gains recognized on beginning inventories—discretionary volumes held for immediate sale or exchange" represents the net operating margins recognized for financial reporting purposes on the subsequent sale of those inventories to customers during the three months ended December 31, 2003. During the last half of December 2003, we experienced increases in certain commodity prices at certain locations, which resulted in the fair value of our inventories—discretionary volumes held for immediate sale or exchange at December 31, 2003 exceeding their cost basis by approximately $15.5 million. That excess is expected to be recognized in net operating margins for financial reporting purposes during the three months ended March 31, 2004, which is the period in which those discretionary inventory volumes are expected to be sold to customers.

For the three months ended December 31, 2003, we increased the carrying amount of our base operating inventory volumes by approximately $5.5 million due to higher commodity prices during December 2003 as compared to September 2003. For the three months ended December 31, 2002, we decreased the carrying amount of our base operating inventory volumes by approximately $1.4 million due to lower commodity prices during December 2002 as compared to September 2002. During the three months ended December 31, 2003, we reduced the carrying amount of our base operating inventory volumes by approximately $271,000 due to the application of the lower of cost or market rule.

Selected quarterly adjusted net operating margins for the supply, distribution and marketing segment for each of the six months ended December 31, 2003 and 2002, are summarized below (in thousands):

	Six months ended December 31,
	2003			2002

Supply, distribution and marketing:
Light oil margins	$	12,440		$	15,370
Heavy oil margins		4,866			—
Supply management services margins		6,480			7,540
Trading margins, net		2,588			(1,955	)

Adjusted net operating margins	$	26,374		$	20,955

Adjusted net operating margins	$	26,374		$	20,955
Gains recognized on beginning inventories—discretionary volumes held for immediate sale or exchange		5,855			12,644
Gains deferred on ending inventories—discretionary volumes held for immediate sale or exchange		(15,469	)		(33,490	)
Change in FIFO cost basis of base operating inventory volumes		5,718			(1,421	)
Lower of cost or market write-downs on base operating inventory volumes		(2,333	)		—

Net operating margins—Historical financial statements	$	20,145		$	(1,312	)

The adjusted net operating margins attributable to our supply, distribution and marketing segment increased to $26.4 million for the six months ended December 31, 2003 from $21.0 million for the three months ended December 31, 2002. The Coastal Fuels assets, which we acquired on February 28, 2003, contributed heavy oil margins of approximately $4.9 million for the six months ended December 31, 2003.

Prior to October 1, 2002, our inventories—discretionary volumes held for immediate sale or exchange were carried at fair value. Effective October 1, 2002, we adjusted the carrying amount of inventories—discretionary volumes held for immediate sale or exchange to the lower of cost or market pursuant to the requirements of EITF 02-03. During the last half of June 2003, we experienced increases in certain commodity prices and locations, which resulted in the fair value of our inventories—discretionary volumes held for immediate sale or exchange at June 30, 2003 exceeding their cost basis by approximately $5.9 million. The "Gains recognized on beginning inventories—discretionary volumes held for immediate sale or exchange" represents the net operating margins recognized for financial reporting purposes on the subsequent sale of those inventories to customers during the six months ended December 31, 2003. During the last half of December 2003, we experienced increases in certain commodity prices at certain locations, which resulted in the fair value of our inventories—discretionary volumes held for immediate sale or exchange at December 31, 2003 exceeding their cost basis by

approximately $15.5 million. That excess is expected to be recognized in net operating margins for financial reporting purposes during the three months ended March 31, 2004, which is the period in which those discretionary inventory volumes are expected to be sold to customers.

For the six months ended December 31, 2003, we increased the carrying amount of our base operating volumes by approximately $5.7 million due to higher commodity prices during December 2003 as compared to June 2003. For the six months ended December 31, 2003, we reduced the carrying amount of our base operating volumes by approximately $2.3 million due to the application of the lower of cost or market rule.

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

Our adjusted net operating margins for the terminal, pipelines, tugs and barges segment are identical to the net operating margins for such segment described below under "Results of Operations—Historical Financial Statements." Selected quarterly adjusted net operating margins for the terminal, pipelines, tugs and barges segment for the three and six months ended December 31, 2003 and 2002, are summarized below (in thousands):

		Three months ended December 31,				Six months ended December 31,
		2003		2002		2003		2002

Terminals and pipelines:
	Historical facilities	$	10,852	$	10,745	$	21,985	$	21,673
	Coastal Fuels assets		4,313		—		7,875		—

		$	15,165	$	10,745	$	29,860	$	21,673

RESULTS OF OPERATIONS—HISTORICAL FINANCIAL STATEMENTS

The following selected historical financial statement measures are derived from our unaudited interim financial statements for the three and six months ended December 31, 2003 and 2002 (in thousands):

		Three months ended December 31,						Six months ended December 31,
		2003			2002			2003			2002

Historical Financial Statement Measures:
Net operating margins:
	Terminals, pipelines, tugs and barges	$	15,165		$	10,745		$	29,860		$	21,673
	Supply, distribution, and marketing	$	8,403		$	(8,924	)	$	20,145		$	(1,312	)
Operating income (loss)		$	6,675		$	(11,612	)	$	17,172		$	(7,743	)
Earnings (loss) before income taxes		$	(1,572	)	$	(13,613	)	$	1,722		$	(12,748	)
Net earnings (loss)		$	(943	)	$	(9,737	)	$	1,033		$	(9,201	)
Net cash used by operating activities		$	(23,799	)	$	(46,979	)	$	(40,673	)	$	(18,240	)
Net cash used by investing activities		$	(5,981	)	$	(13,598	)	$	(13,400	)	$	(16,251	)
Net cash provided by financing activities		$	28,372		$	50,896		$	42,640		$	9,603

THREE MONTHS ENDED DECEMBER 31, 2003 AS COMPARED TO THREE MONTHS ENDED DECEMBER 31, 2002

We reported a net loss of $(0.9) million for the three months ended December 31, 2003, compared to a net loss of $(9.7) million for the three months ended December 31, 2002. After preferred stock dividends, the net loss attributable to common stockholders was $(1.6) million for the three months ended December 31, 2003, compared to $(10.7) million for the three months ended December 31, 2002. Basic loss per common share for the three months ended December 31, 2003 and 2002, was $(0.04) and $(0.27), respectively, based on 39.4 million and 39.1 million weighted average common shares outstanding, respectively. Diluted loss per share for the three months ended December 31, 2003 and 2002, was $(0.04) and $(0.27), respectively, based upon 39.4 million and 39.1 million weighted average diluted shares outstanding, respectively.

Terminals, pipelines, and tugs and barges

In our terminals, pipelines, and tugs and barges operations, we provide distribution related services to wholesalers, distributors, marketers, retail gasoline station operators, cruise-ship operators and industrial and commercial end-users of refined petroleum products and other commercial liquids. The net operating margins from our terminals, pipelines, and tugs and barges operations for the three months ended December 31, 2003 were $15.2 million, compared to $10.7 million for the three months ended December 31, 2002. The increase of $4.5 million in net operating margins was due principally to the addition of the Coastal Fuels assets. On February 28, 2003, we acquired the Coastal Fuels assets, which include five terminals, a hydrant delivery system, and a tug and barge operation. The results of operations of the Coastal Fuels assets are included from the closing date of the transaction (February 28, 2003). For the three months ended December 31, 2003, the Coastal Fuels assets generated net operating margins of approximately $4.3 million attributable to our terminals, pipelines, and tugs and barges operations. The net operating margins from our terminals, pipelines, and tugs and barges operations are as follows (in thousands):

			Three months ended December 31,
			2003			2002

Throughput fees			$	7,886		$	7,023
Storage fees				8,883			5,164
Additive injection fees, net				1,996			1,820
Pipeline transportation fees				2,277			1,238
Tugs and barges				2,794			—
Other				1,961			2,020

	Revenue			25,797			17,265
	Less direct operating costs and expenses			(10,632	)		(6,520	)

		Net operating margins	$	15,165		$	10,745

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 December 31, 2003 and 2002, we averaged approximately 56,000 and 43,000 barrels per day, respectively, of delivered volumes under exchange agreements.

Terminal throughput fees were approximately $7.9 million and $7.0 million for the three months ended December 31, 2003 and 2002, respectively. For the three months ended December 31, 2003 and 2002, we averaged approximately 420,000 barrels and 325,000 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 of approximately $0.7 million as a result of our acquisition of the Coastal Fuels assets, approximately $0.2 million at our historical Florida facilities, approximately $0.2 million at our Baton Rouge dock and approximately $0.5 million at our Southeast facilities offset by a decrease of approximately $0.6 million at our Upper River facilities.

Included in the terminal throughput fees for the three months ended December 31, 2003 and 2002 are fees charged to TransMontaigne's supply, distribution and marketing segment of approximately $7.0 million and $5.0 million, respectively.

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

Terminal storage fees were approximately $8.9 million and $5.2 million for the three months ended December 31, 2003 and 2002, respectively. The increase of $3.7 million in storage fees was due principally to an increase of approximately $4.1 million from our acquisition of the Coastal Fuels assets offset by a decrease of approximately $0.4 million at our Brownsville, Texas facilities.

Included in the terminal storage fees for the three months ended December 31, 2003 and 2002 are fees charged to TransMontaigne's supply, distribution and marketing segment of approximately $2.7 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 $1.8 million for the three months ended December 31, 2003 and 2002, respectively. The increase of $0.2 million in additive injection fees, net was due principally to an increase of approximately $0.2 million from our acquisition of the Coastal Fuels assets and approximately $0.1 million at our Southeast facilities offset by a decrease of approximately $0.1 million at our Upper River facilities.

Included in additive injection fees, net for the three months ended December 31, 2003 and 2002 are fees charged to TransMontaigne's supply, distribution and marketing segment of approximately $1.9 million and $1.5 million, respectively.

Texas (the "CETEX pipeline"). On December 30, 2003, we sold our CETEX pipeline system. 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 December 31, 2003 and 2002, we earned pipeline transportation fees of approximately $2.3 million and $1.2 million, respectively. The increase of $1.1 million in pipeline transportation fees was due principally to an increase of approximately $0.5 million from our acquisition of the Coastal Fuels assets, $0.3 million at our Brownsville, Texas facilities for services rendered in connection with the construction of a products pipeline from the U.S./Mexican border to our Brownsville, Texas facilities, $0.1 million on our CETEX pipeline system, and $0.1 million on our Razorback pipeline.

Included in the pipeline transportation fees for the three months ended December 31, 2003 and 2002 are fees charged to TransMontaigne's supply, distribution and marketing segment of approximately $1.8 million and $1.1 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 December 31, 2003, we earned bunkering fees, transportation fees, and other ship-assist services fees of approximately $2.8 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 months ended December 31, 2003 are fees charged to TransMontaigne's supply, distribution and marketing segment of approximately $1.8 million.

Other Revenue. In addition to providing storage and distribution services at our terminal facilities, we also provide ancillary services including heating and mixing of stored products and product transfer services. We also recognize gains from the sale of product to our supply, distribution and marketing operation resulting from the excess of product deposited by third parties into our terminals over the amount of product that the customer is contractually permitted to withdraw from those terminals. For the three months ended December 31, 2003 and 2002, other revenue from our terminals, pipelines, and tugs and barges operations was approximately $2.0 million and $2.0 million, respectively. Other revenue for 2003 as compared to 2002 included an increase of approximately $0.5 million from our acquisition of the Coastal Fuels assets and approximately $0.3 million at our Southeast facilities, offset by decreases of approximately $0.8 million at our Brownsville, Texas facilities and approximately $0.1 million at our historical Florida facilities.

Included in other revenue for the three months ended December 31, 2003 and 2002, are fees charged to TransMontaigne's supply, distribution and marketing segment of approximately $1.0 million and $0.8 million, respectively.

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 December 31, 2003 and 2002, the direct operating costs and expenses of the terminals, pipelines, and tugs and

barges were approximately $10.6 million and $6.5 million, respectively. The direct operating costs and expenses of our terminals, pipelines, and tugs and barges operations are as follows (in thousands):

		Three months ended December 31,
		2003			2002

Wages and employee benefits		$	5,512		$	3,131
Utilities and communication charges			920			745
Repairs and maintenance			2,626			2,209
Office, rentals and property taxes			1,157			799
Vehicles and fuel costs			332			134
Environmental compliance costs			692			473
Other			386			130
Less—reimbursed costs and expenses			(993	)		(1,101	)

	Direct operating costs and expenses	$	10,632		$	6,520

The increase of $4.1 million in direct operating costs and expenses was due principally to the addition of the Coastal Fuels assets which resulted in approximately $4.5 million of additional direct operating costs and expenses offset by a decrease of approximately $0.4 million in repairs and maintenance expense incurred at our historical facilities.

Supply, distribution and marketing

The net operating margins (deficiencies) from our supply, distribution and marketing operations for the three months ended December 31, 2003 were $8.4 million, compared to $(8.9) million for the three months ended December 31, 2002. The net operating margins from our supply, distribution and marketing operations are as follows (in thousands):

			Three months ended December 31,
			2003			2002

Rack sales			$	388,924		$	376,808
Bulk sales				1,018,630			1,264,415
Contract sales				663,507			328,831
Supply management services				77,304			36,538

		Total revenue		2,148,365			2,006,592
Cost of product sold				(2,116,729	)		(1,990,801	)

		Net margin before other direct costs and expenses		31,636			15,791
Other direct costs and expenses:
	Net losses on risk management activities			(18,112	)		(26,392	)
	Change in unrealized gains (losses) on derivative contracts			(10,354	)		3,098
	Change in FIFO cost basis of base operating inventory volumes			5,504			(1,421	)
	Lower of cost or market write-downs on base operating inventory volumes			(271	)		—

		Net operating margins (deficiencies)	$	8,403		$	(8,924	)

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 spot 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 $388.9 million and $376.8 million for the three months ended December 31, 2003 and 2002, respectively. For the three months ended December 31, 2003 and 2002, we averaged approximately 116,000 and 122,000 barrels per day, respectively, of delivered volumes under rack sales.

Bulk Sales. Bulk sales are 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 $1,018.6 million and $1,264.4 million for the three months ended December 31, 2003 and 2002, respectively. For the three months ended December 31, 2003 and 2002, we averaged approximately 309,000 and 412,000 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 $663.5 million and $328.8 million for the three months ended December 31, 2003 and 2002, respectively. For the three months ended September 30, 2003 and 2002, we averaged approximately 204,000 and 106,000 barrels per day, respectively, of delivered volumes under contract sales.

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.

Sales pursuant to supply management services contracts were approximately $77.3 million and $36.5 million for the three months ended December 31, 2003 and 2002, respectively. For the three

months ended December 31, 2003 and 2002, we averaged approximately 24,000 barrels and 12,000 barrels per day, respectively, of delivered volumes under supply management services contracts.

Cost of Product Sold. The cost of product sold includes the cost of the product inventory sold on a first-in, first-out basis, pipeline transportation and other freight costs, terminal throughput, additive and storage costs, and commissions. Cost of product sold is approximately $2,116.7 million and $1,990.8 million for the three months ended December 31, 2003 and 2002, respectively. Cost of product sold is as follows (in thousands):

		Three months ended December 31,
		2003		2002

Inventory product costs		$	2,063,526	$	1,957,671
Transportation and related charges			38,487		23,606
Throughput, storage and related charges			14,198		8,968
Other			518		556

	Cost of product sold	$	2,116,729	$	1,990,801

Net Losses on Risk Management Activities. Our risk management strategy generally is intended to maintain a balanced position of forward sale and purchase commitments against our discretionary inventories held for immediate sale or exchange and future contractual delivery obligations, thereby reducing exposure to commodity price fluctuations. We evaluate our exposure to commodity price risk from an overall portfolio basis that considers the continuous movement of discretionary inventory volumes held for immediate sale or exchange and our obligations to deliver products at fixed prices through our sales contracts and supply management contracts. Our physical inventory position, which includes firm commitments to buy and sell product, is offset with risk management contracts, principally futures contracts on the NYMEX.

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

Net losses on risk management activities were approximately $18.1 million and $26.4 million for the three months ended December 31, 2003 and 2002, respectively.

Change in Unrealized Gains (Losses) on Derivative Contracts. During the three months ended December 31, 2003 and 2002, we increased (decreased) the financial statement carrying amount of our derivative contracts by approximately $(10.4) million and $3.1 million, respectively. The change in the financial statement carrying amount is due principally to (rising) declining commodity prices as compared to the prices stipulated in our derivative contracts.

Change in FIFO Cost Basis of Base Operating Inventory Volumes. During the three months ended December 31, 2003, we increased the financial statement carrying amount of the base operating inventory volumes by approximately $5.5 million due to higher commodity prices during December 2003 as compared to September 2003. During the three months ended December 31, 2002, we decreased the financial statement carrying amount of the base operating inventory volumes by approximately $1.4 million due to lower commodity prices during December 2002 as compared to September 2002.

Lower of Cost or Market Write-Downs on Base Operating Inventory Volumes. During the three months ended December 31, 2003, we recognized impairment losses of approximately $271,000 million due to lower of cost or market write-downs on the base operating volumes due principally to declining prices at the end of the period. During the three months ended December 31, 2002, we did not report any of our inventory volumes as base operating volumes as our base operating volumes were a component of our product linefill and tank bottom volumes.

Costs and expenses

Selling, general and administrative expenses for the three months ended December 31, 2003 were $10.9 million, compared to $8.8 million for the three months ended December 31, 2002. Selling, general and administrative expenses are as follows (in thousands):

		Three months ended December 31,
		2003		2002

Wages and employee benefits		$	7,483	$	6,618
Office costs, utilities and communication charges			1,636		802
Accounting and legal expenses			281		295
Property and casualty insurance			918		622
Other			626		438

	Selling, general and administrative expenses	$	10,944	$	8,775

Depreciation and amortization for the three months ended December 31, 2003 and 2002, was $5.9 million and $4.3 million, respectively. The increase of $1.6 million in depreciation and amortization for 2003 as compared to 2002 is principally related to depreciation and amortization on recent additions to property, plant, and equipment.

During the three months ended December 31, 2003 and 2002, we recognized impairment losses of approximately $17,000 and $nil, respectively, due to write-downs on certain of our product linefill and tank bottom volumes.

We recognized special charges of $0.4 million during the three months ended December 31, 2002, related to our corporate relocation and transition. As of June 30, 2003 we had completed the relocation of our employees from Atlanta, Georgia to Denver, Colorado and paid the remaining special termination benefits and transition bonuses.

Other income and expenses

Interest income for the three months ended December 31, 2003 was $80,000, as compared to $99,000 for the three months ended December 31, 2002. Pursuant to our cash management practices, excess cash balances are used to pay down our outstanding borrowings under our working capital credit facility and commodity margin loan.

Interest expense for the three months ended December 31, 2003 was $6.7 million, compared to $3.1 million during the three months ended December 31, 2002. Interest expense is as follows (in thousands):

		Three months ended December 31,
		2003		2002

Working capital credit facility		$	1,906	$	—
Senior subordinated notes			4,646		—
Former bank credit facility			—		1,466
Letters of credit			99		99
Commodity margin loan			52		56
Interest rate swap			—		1,443
Other			—		2

	Interest expense	$	6,703	$	3,066

Loss on disposition of assets for the three months ended December 31, 2003 was approximately $0.8 million. On December 30, 2003, we sold our CETEX pipeline system for approximately $0.4 million, resulting in a loss on disposition of assets of approximately $0.7 million.

Other financing (costs) income, net for the three months ended December 31, 2003 were $(0.8) million, compared to $1.0 million for the three months ended December 31, 2002. The increase of $1.8 million in other financing costs, net was due principally to an increase of approximately $0.6 million in amortization of deferred debt issuance costs and the absence of a gain on interest rate swap. During the three months ended December 31, 2002, we recognized an unrealized gain of $1.2 million on our interest rate swap. On February 28, 2003, we settled our obligations under the swap agreement when we repaid our former bank revolving credit facility.

Income taxes

Income tax benefit was $0.6 million and $5.2 million for the three months ended December 31, 2003 and 2002, respectively, which represents an effective combined federal and state income tax rate of 40.0% and 38.0%, respectively. Cash paid for income taxes for the three months ended December 31, 2003 and 2002 was approximately $4,000 and $234,000, respectively.

Preferred stock dividends

Preferred stock dividends on our Series A Convertible Preferred stock were $nil and $0.3 million for the three months ended December 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 30, 2003, we redeemed the remaining 24,421 shares of Series A Convertible Preferred stock and warrants that were outstanding for a cash payment of approximately $24.4 million.

Preferred stock dividends on our Series B Redeemable Convertible Preferred Stock were $0.7 million for each of the three months ended December 31, 2003 and 2002. At its issuance (June 28, 2002), the fair value of the Series B Redeemable Convertible Preferred stock exceeded its liquidation value. 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. For each of the three months ended December 31, 2003 and 2002, 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.

SIX MONTHS ENDED DECEMBER 31, 2003 AS COMPARED TO SIX MONTHS ENDED DECEMBER 31, 2002

We reported net earnings of $1.0 million for the six months ended December 31, 2003, compared to a net loss of $(9.2) million for the six months ended December 31, 2002. After preferred stock dividends, the net loss attributable to common stockholders was $(0.3) million for the six months ended December 31, 2003, compared to $(11.2) million for the six months ended December 31, 2002. Basic loss per common share for the six months ended December 31, 2003 and 2002, was $(0.01) and $(0.28), respectively, based on 39.3 million and 39.1 million weighted average common shares outstanding, respectively. Diluted loss per share for the six months ended December 31, 2003 and 2002, was $(0.01) and $(0.28), respectively, based upon 39.3 million and 39.1 million weighted average diluted shares outstanding, respectively.

Terminals, pipelines, and tugs and barges

In our terminals, pipelines, and tugs and barges operations, we provide distribution related services to wholesalers, distributors, marketers, retail gasoline station operators, cruise-ship operators and industrial and commercial end-users of refined petroleum products and other commercial liquids. The net operating margins from our terminals, pipelines, and tugs and barges operations for the six months ended December 31, 2003 were $29.9 million, compared to $21.7 million for the six months ended December 31, 2002. The increase of $8.2 million in net operating margins was due principally to the addition of the Coastal Fuels assets. On February 28, 2003, we acquired the Coastal Fuels assets, which include five terminals, a hydrant delivery system, and a tug and barge operation. The results of operations of the Coastal Fuels assets are included from the closing date of the transaction (February 28, 2003). For the six months ended December 31, 2003, the Coastal Fuels assets generated net operating margins of approximately $7.9 million attributable to our terminals, pipelines, and tugs

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

			Six months ended December 31,
			2003			2002

Throughput fees			$	16,352		$	14,194
Storage fees				18,527			10,450
Additive injection fees, net				3,956			3,726
Pipeline transportation fees				3,973			2,704
Tugs and barges				5,607			—
Other				4,403			3,586

	Revenue			52,818			34,660
	Less direct operating costs and expenses			(22,958	)		(12,987	)

		Net operating margins	$	29,860		$	21,673

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 six months ended December 31, 2003 and 2002, we averaged approximately 57,000 and 45,000 barrels per day, respectively, of delivered volumes under exchange agreements.

Terminal throughput fees were approximately $16.4 million and $14.2 million for the six months ended December 31, 2003 and 2002, respectively. For the six months ended December 31, 2003 and 2002, we averaged approximately 440,000 barrels and 333,000 barrels per day of throughput volumes at our terminals, including volumes under exchange agreements. The increase of $2.2 million in throughput fees was due principally to increases of approximately $1.3 million as a result of our acquisition of the Coastal Fuels assets, approximately $0.5 million at our historical Florida facilities, approximately $0.7 million at our Baton Rouge dock and approximately $0.7 million at our Southeast facilities offset by a decrease of approximately $1.1 million at our Upper River facilities.

Included in the terminal throughput fees for the six months ended December 31, 2003 and 2002 are fees charged to TransMontaigne's supply, distribution and marketing segment of approximately $14.3 million and $10.1 million, respectively.

Terminal storage fees were approximately $18.5 million and $10.5 million for the six months ended December 31, 2003 and 2002, respectively. The increase of $8.0 million in storage fees was due

principally to an increase of approximately $8.4 million from our acquisition of the Coastal Fuels assets offset by a decrease on approximately $0.4 million at our Brownsville, Texas facilities.

Included in the terminal storage fees for the six months ended December 31, 2003 and 2002 are fees charged to TransMontaigne's supply, distribution and marketing segment of approximately $5.4 million and $1.8 million, respectively.

Additive injection fees, net were approximately $4.0 million and $3.7 million for the six months ended December 31, 2003 and 2002, respectively. The increase of $0.3 million in additive injection fees, net was due principally to an increase of approximately $0.3 million from our acquisition of the Coastal Fuels assets and approximately $0.1 million at our Southeast facilities offset by a decrease of approximately $0.1 million at our Upper River facilities.

Included in additive injection fees, net for the six months ended December 31, 2003 and 2002 are fees charged to TransMontaigne's supply, distribution and marketing segment of approximately $3.7 million and $3.0 million, respectively.

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. 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"). On December 30, 2003, we sold our CETEX pipeline system. 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 six months ended December 31, 2003 and 2002, we earned pipeline transportation fees of approximately $4.0 million and $2.7 million, respectively. The increase of $1.3 million in pipeline transportation fees was due principally to an increase of approximately $0.7 million from our acquisition of the Coastal Fuels assets, $0.4 million at our Brownsville, Texas facilities for services rendered in connection with the construction of a products pipeline from the U.S./Mexican border to our Brownsville, Texas facilities, and $0.1 million on our CETEX pipeline system.

For the six months ended December 31, 2003, we earned bunkering fees, transportation fees, and other ship-assist services fees of approximately $5.6 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 six months ended December 31, 2003 are fees charged to TransMontaigne's supply, distribution and marketing segment of approximately $3.3 million.

Other Revenue. In addition to providing storage and distribution services at our terminal facilities, we also provide ancillary services including heating and mixing of stored products and product transfer services. We also recognize gains from the sale of product to our supply, distribution and marketing operation resulting from the excess of product deposited by third parties into our terminals over the amount of product that the customer is contractually permitted to withdraw from those terminals. For the six months ended December 31, 2003 and 2002, other revenue from our terminals, pipelines, and tugs and barges operations was approximately $4.4 million and $3.6 million, respectively. The increase of approximately $0.8 million in other revenue for 2003 as compared to 2002 was due principally to an increase of approximately $1.9 million from our acquisition of the Coastal Fuels assets and approximately $0.3 million at our Southeast facilities offset by decreases of approximately $1.1 million at our Brownsville, Texas facilities, approximately $0.2 million at our Upper River facilities, and approximately $0.1 million at our historical Florida facilities.

Included in other revenue for the six months ended December 31, 2003 and 2002, are fees charged to TransMontaigne's supply, distribution and marketing segment of approximately $1.6 million and $1.6 million, respectively.

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 six months ended December 31, 2003 and 2002, the direct operating costs and expenses of the terminals, pipelines, and tugs and barges were approximately $23.0 million and $13.0 million, respectively. The direct operating costs and expenses of our terminals, pipelines, and tugs and barges operations are as follows (in thousands):

		Six months ended December 31,
		2003			2002

Wages and employee benefits		$	11,565		$	6,637
Utilities and communication charges			2,126			1,497
Repairs and maintenance			6,069			3,976
Office, rentals and property taxes			2,813			1,633
Vehicles and fuel costs			740			264
Environmental compliance costs			649			994
Other			961			215
Less—reimbursed costs and expenses			(1,965	)		(2,229	)

	Direct operating costs and expenses	$	22,958		$	12,987

The increase of $10.0 million in direct operating costs and expenses was due principally to the addition of the Coastal Fuels assets which resulted in approximately $10.5 million of additional direct operating costs and expenses offset by approximately $0.8 million of insurance recoveries received on claims for reimbursement of environmental remediation costs in excess of the amount received during the six months ended December 31, 2002.

Supply, distribution and marketing

The net operating margins (deficiencies) from our supply, distribution and marketing operations for the six months ended December 31, 2003 were $20.1 million, compared to $(1.3) million for the

six months ended December 31, 2002. The net operating margins (deficiencies) from our supply, distribution and marketing operations are as follows (in thousands):

			Six months ended December 31,
			2003			2002

Rack sales			$	871,758		$	765,616
Bulk sales				2,388,046			2,257,130
Contract sales				1,262,567			639,495
Supply management services				149,547			71,693

		Total revenue		4,671,918			3,733,934
Cost of product sold				(4,628,619	)		(3,677,584	)

		Net margin before other direct costs and expenses		43,299			56,350
Other direct costs and expenses:
	Net losses on risk management activities			(18,496	)		(44,900	)
	Change in unrealized gains (losses) on derivative contracts			(8,043	)		(11,341	)
	Change in FIFO cost basis of base operating inventory volumes			5,718			(1,421	)
	Lower of cost or market write-downs on base operating inventory volumes			(2,333	)		—

		Net operating margins	$	20,145		$	(1,312	)

Rack sales were approximately $871.8 million and $765.6 million for the six months ended December 31, 2003 and 2002, respectively. For the six months ended December 31, 2003 and 2002, we averaged approximately 129,000 and 125,000 barrels per day, respectively, of delivered volumes under rack sales.

Bulk sales were approximately $2,388.0 million and $2,257.1 million for the six months ended December 31, 2003 and 2002, respectively. For the six months ended December 31, 2003 and 2002,

we averaged approximately 355,000 and 375,000 barrels per day, respectively, of delivered volumes under bulk sales.

Contract sales were approximately $1,262.6 million and $639.5 million for the six months ended December 31, 2003 and 2002, respectively. For the six months ended December 31, 2003 and 2002, we averaged approximately 191,000 and 105,000 barrels per day, respectively, of delivered volumes under contract sales.

Sales pursuant to supply management services contracts were approximately $149.5 million and $71.7 million for the six months ended December 31, 2003 and 2002, respectively. For the six months ended December 31, 2003 and 2002, we averaged approximately 24,000 barrels and 12,000 barrels per day, respectively, of delivered volumes under supply management services contracts.

Cost of Product Sold. The cost of product sold includes the cost of the product inventory sold on a first-in, first-out basis, pipeline transportation and other freight costs, terminal throughput, additive and storage costs, and commissions. Cost of product sold is approximately $4,628.6 million and $3,677.6 million for the six months ended December 31, 2003 and 2002, respectively. Cost of product sold is as follows (in thousands):

		Six months ended December 31,
		2003		2002

Inventory product costs		$	4,527,979	$	3,613,252
Transportation and related charges			70,411		44,209
Throughput, storage and related charges			29,116		19,073
Other			1,113		1,050

	Cost of product sold	$	4,628,619	$	3,677,584

Net losses on risk management activities were approximately $18.5 million and $44.9 million for the six months ended December 31, 2003 and 2002, respectively.

Change in Unrealized Gains (Losses) on Derivative Contracts. During the six months ended December 31, 2003 and 2002, we decreased the financial statement carrying amount of our derivative contracts by approximately $(8.0) million and $(11.3) million, respectively. The change in the financial statement carrying amount is due principally to rising commodity prices as compared to the prices stipulated in our derivative contracts.

Change in FIFO Cost Basis of Base Operating Inventory Volumes. During the six months ended December 31, 2003, we increased the financial statement carrying amount of the base operating inventory volumes by approximately $5.7 million due to higher commodity prices during December 2003 as compared to June 2003. During the six months ended December 31, 2002, we decreased the financial statement carrying amount of the base operating inventory volumes by approximately $1.4 million due to lower commodity prices during December 2002.

Lower of Cost or Market Write-Downs on Base Operating Inventory Volumes. During the six months ended December 31, 2003, we recognized impairment losses of approximately $2.3 million due to lower of cost or market write-downs on the base operating inventory volumes due principally to declining prices at the end of the period.

Costs and expenses

Selling, general and administrative expenses for the six months ended December 31, 2003 were $21.3 million, compared to $18.1 million for the six months ended December 31, 2002. Selling, general and administrative expenses are as follows (in thousands):

		Six months ended December 31,
		2003		2002

Wages and employee benefits		$	14,621	$	13,037
Office costs, utilities and communication charges			2,939		2,261
Accounting and legal expenses			673		1,065
Property and casualty insurance			2,014		1,128
Other			1,068		615

	Selling, general and administrative expenses	$	21,315	$	18,106

Depreciation and amortization for the six months ended December 31, 2003 and 2002, was $11.5 million and $8.5 million, respectively. The increase of $3.0 million in depreciation and

amortization for 2003 as compared to 2002 is principally related to depreciation and amortization on recent additions to property, plant, and equipment.

During the six months ended December 31, 2003 and 2002, we recognized impairment losses of approximately $49,000 and $nil, respectively, due to write-downs on certain of our product linefill and tank bottom volumes.

We recognized special charges of $1.4 million during the six months ended December 31, 2002, related to our corporate relocation and transition. As of June 30, 2003 we had completed the relocation of our employees from Atlanta, Georgia to Denver, Colorado and paid the remaining special termination benefits and transition bonuses.

Other income and expenses

Dividend income for the six months ended December 31, 2003 was $6,000 compared to $374,000 for the six months ended December 31, 2002.

Interest income for the six months ended December 31, 2003 was $108,000 compared to $168,000 for the six months ended December 31, 2002. Pursuant to our cash management practices, excess cash balances are used to pay down our outstanding borrowings under our working capital credit facility and commodity margin loan.

Interest expense for the six months ended December 31, 2003 was $13.1 million, compared to $6.4 million during the six months ended December 31, 2002. Interest expense is as follows (in thousands):

		Six months ended December 31,
		2003		2002

Working capital credit facility		$	3,729	$	—
Senior subordinated notes			9,199		—
Former bank credit facility			—		3,211
Letters of credit			129		180
Commodity margin loan			70		121
Interest rate swap			—		2,845
Other			—		2

	Interest expense	$	13,127	$	6,359

Loss on disposition of assets for the six months ended December 31, 2003 was approximately $0.8 million. On December 30, 2003, we sold our Cetex pipeline system for approximately $0.4 million, resulting in a loss on disposition of assets of approximately $0.7 million.

Other financing (costs) income, net for the six months ended December 31, 2003 were $(1.6) million, compared to $0.8 million for the six months ended December 31, 2002. The decrease of $(2.4) million in other financing costs, net was due principally to an increase of approximately $1.2 million in amortization of deferred debt issuance costs and the absence of a gain on interest rate swap. During the six months ended December 31, 2002, we recognized an unrealized gain of $1.3 million on our interest rate swap. On February 28, 2003, we settled our obligations under the swap agreement when we repaid our former bank revolving credit facility.

Income taxes

Income tax (expense) benefit was $(0.7) million and $4.8 million for the six months ended December 31, 2003 and 2002, respectively, which represents an effective combined federal and state income tax rate of 40.0% and 38.0%, respectively. Cash paid for income taxes for the six months ended December 31, 2003 and 2002 was approximately $8,000 and $320,000, respectively.

Preferred stock dividends

Preferred stock dividends on our Series A Convertible Preferred stock were $nil and $0.6 million for the six months ended December 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 30, 2003, we redeemed the remaining 24,421 shares of Series A Convertible Preferred stock and warrants that were outstanding for a cash payment of approximately $24.4 million.

Preferred stock dividends on our Series B Redeemable Convertible Preferred Stock were $1.4 million for each of the six months ended December 31, 2003 and 2002. At its issuance (June 28, 2002), the fair value of the Series B Redeemable Convertible Preferred stock exceeded its liquidation value. 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. For each of the six months ended December 31, 2003 and 2002, 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 $2.2 million, offset by the amortization of the premium on the carrying amount of the Series B Redeemable Convertible Preferred Stock of $0.8 million.

LIQUIDITY, CAPITAL RESOURCES, AND COMMODITY PRICE RISK

At December 31, 2003, our current assets exceeded our current liabilities by $69.4 million, compared to $63.9 million at June 30, 2003. The increase of $5.5 million in working capital is due principally to an increase in inventories—discretionary volumes offset by an increase in trade accounts payable and additional borrowings under our working capital credit facility.

Our inventories—discretionary volumes are presented in the accompanying consolidated balance sheet as current assets and are carried at the lower of cost or market at December 31, 2003 and June 30, 2003. Inventories—discretionary volumes are as follows (in thousands):

	December 31, 2003			June 30, 2003
	Amount		Bbls	Amount		Bbls

Volumes held for immediate sale or exchange	$	225,467	6,487	$	130,492	3,890
Volumes held for base operations		99,811	2,922		96,426	2,922

Inventories—discretionary volumes	$	325,278	9,409	$	226,918	6,812

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

	December 31, 2003			June 30, 2003
	Amount		Bbls	Amount		Bbls

Gasolines	$	63,227	1,729	$	71,147	2,007
Distillates		146,272	4,093		53,495	1,683
No. 6 oil		15,968	665		5,850	200

Volumes held for immediate sale or exchange	$	225,467	6,487	$	130,492	3,890

During the six months ended December 31, 2003, we increased our volumes held for immediate sale or exchange by approximately 2.6 million barrels principally to take advantage of favorable market conditions for distillate products.

Our base operating inventory volumes, representing in-transit volumes on common carrier pipelines, generally are not subject to price risk management. Based on the level of our current operations, we have established our base operating inventory volumes, exclusive of product linefill and tank bottom volumes, at approximately 2.9 million barrels. Changes in our operation, such as the acquisition of additional terminals, may result in changes in the volume of our base operating inventory volumes. The activity in our volumes held for base operations, exclusive of product linefill and tank bottom volumes, is summarized as follows (in thousands):

	Amount			Barrels

As of June 30, 2003	$	96,426		2,922
Change in FIFO cost basis		5,718		—
Lower of cost or market write-down		(2,333	)	—

As of December 31, 2003	$	99,811		2,922

Our product linefill and tank bottom volumes are not held for sale or exchange in the ordinary course of business and, therefore, we do not manage the commodity price risks associated with these volumes. Our product linefill and tank bottom volumes are presented in the accompanying consolidated balance sheet as non-current assets and are carried at the lower of cost or market. Product linefill and tank bottom volumes are as follows (in thousands):

	December 31, 2003			June 30, 2003
	Amount		Bbls	Amount		Bbls

Gasolines	$	12,994	497	$	13,020	497
Distillates		7,449	319		7,449	319
No. 6 oil		1,525	61		1,548	61

Product linefill and tank bottom volumes	$	21,968	877	$	22,017	877

At December 31, 2003 and June 30, 2003, the weighted average adjusted cost basis of our product linefill and tank bottom volumes was $0.60 per gallon. The activity in our product linefill and tank bottom volumes is summarized as follows (in thousands):

	Amount			Barrels

As of June 30, 2003	$	22,017		877
Lower of cost or market write-down		(49	)	—

As of December 31, 2003	$	21,968		877

The following table indicates the maturities of our derivative contracts, including the credit quality of our counterparties to those contracts with unrealized gains at December 31, 2003.

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

Unrealized gain position—asset
	Investment grade	$	2,795		$	—		$	—	$	2,795
	Non-investment grade		908			565			—		1,473
	No external rating		15,632			221			—		15,853

			19,335			786			—		20,121
Unrealized loss position—liability			(27,444	)		(668	)		—		(28,112	)

Net unrealized loss position—liability		$	(8,109	)	$	118		$	—	$	(7,991	)

At December 31, 2003, the unrealized gain on our derivative contracts with non-investment grade counterparties was approximately $1.5 million. A single customer represented approximately $0.1 million of that unrealized gain. At December 31, 2003, we also had derivative contracts with that customer that were in an unrealized loss position of approximately $6.9 million. Therefore, the net unrealized loss on all of our derivative contracts with that customer was approximately $6.8 million at December 31, 2003.

The following table includes information about the changes in the fair value of our derivative contracts with that customer for the six months ended December 31, 2003 (in thousands):


Fair value at June 30, 2003	$	(1,682	)
Amounts realized or otherwise settled during the year		2,252
Change in fair value attributable to change in commodity prices		(7,339	)

Fair value at December 31, 2003	$	(6,769	)

Capital expenditures for the six months ended December 31, 2003 were $11.1 million for terminal and pipeline facilities and assets to support these facilities. Excluding acquisitions, capital expenditures for the remainder of the year ending June 30, 2004, are estimated to be less than $7.0 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.

On May 30, 2003, we consummated the sale and issuance of $200 million aggregate principal amount of 9¹/8% Senior Subordinated Notes due 2010 ("Notes") and received proceeds of $194.5 million (net of underwriters' discounts of $5.5 million). We used the net proceeds from the offering of the Notes to repay the Term Loan. The Notes mature on June 1, 2010 and interest is payable semi-annually in arrears on each June 1 and December 1 commencing on December 1, 2003. The Notes are unsecured and subordinated to all of our existing and future senior debt. Upon certain change of control events, each holder of the Notes may require us to repurchase all or a portion of its notes at a purchase price equal to 101% of the principal amount thereof, plus accrued interest.

On June 25, 2003, we amended and restated the Working Capital Credit Facility in connection with the syndication of the facility. Our Working Capital Credit Facility currently provides for a maximum borrowing line of credit that was the lesser of (i) $275 million and (ii) the borrowing base (as defined; $444.0 million at December 31, 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 supply management services and risk management contracts, outstanding letters of credit, and outstanding indebtedness as defined in the facility. At December 31, 2003, we had borrowings of $215.5 million outstanding and letters of credit of $22.3 million outstanding under the Working Capital Credit Facility. We also had the ability to borrow an additional $37.2 million under the facility based on the borrowing base computation at December 31, 2003. All outstanding borrowings under the Working Capital Credit Facility are due and payable on February 28, 2006.

The Working Capital Credit Facility is our primary means of short-term liquidity to finance our working capital requirements and, as such, it is material to our operations. The Working Capital Credit Facility contains affirmative and negative covenants (including limitations on indebtedness, limitations on dividends and other distributions, limitations on certain inter-company transactions, limitations on mergers, consolidation and the disposition of assets, limitations on investments and acquisitions and limitations on liens). The Working Capital Credit Facility also contains customary representations and warranties (including those relating to due organization and authorization, compliance with laws, absence of defaults, material agreements and litigation) and events of default (including those relating to monetary defaults, covenant defaults, cross defaults and bankruptcy events). It also contains certain financial covenants that are tested on a quarterly basis including a minimum fixed charge coverage ratio of 150%, a maximum funded senior debt leverage ratio of 4.5 times the last twelve months' operating results for debt covenant compliance (as defined in the credit agreement), a minimum current ratio of 120% (which excludes borrowings under the Working Capital Credit Facility from the definition of current liabilities) and a minimum consolidated tangible net worth test. In addition, we may not make aggregate expenditures in excess of $80.0 million with respect to general corporate purposes (including capital expenditures, cash paid for acquisitions, and redemption of the Series A Redeemable Convertible Preferred stock) over the term of the agreement; however, such limit shall be increased by certain cash flow amounts generated after February 28, 2003. As of December 31, 2003, we were in compliance with all covenants included in the Working Capital Credit Facility.

We believe that the fixed charge coverage test is the most important and, potentially, restrictive of our financial covenants included in the Working Capital Credit Facility. The fixed charge coverage ratio is based on a defined financial performance measure within the Working Capital Credit Facility known as "fixed charges EBITDA." We refer to fixed charges EBITDA as "operating results for debt covenant compliance." The fixed charge coverage ratio states that for each fiscal quarter of the Company, the ratio (expressed as a percentage) of the "operating results for debt covenant compliance" of the Company and its subsidiaries for the period of four consecutive fiscal quarters then ended to consolidated fixed charges of the Company and its subsidiaries for such period shall equal or exceed 150%. If we were to fail the fixed charge ratio covenant, or any other covenant contained in the Working Capital Credit Facility, we would seek a waiver from our lenders under such facility. If we were unable to obtain a waiver from our lenders, we would be in breach of the Working Capital Credit Facility and the lenders would be entitled to declare all outstanding borrowings immediately due and payable. In addition, a default under the Working Capital Credit Facility would trigger a cross-default provision in the indenture covering our Senior Subordinated Notes. We therefore believe

that information about our covenant compliance generally and our fixed charge coverage ratio covenant in particular is material to an understanding of our liquidity position.

The "operating results for debt covenant compliance," fixed charges and fixed charge coverage ratio for each of the three-month periods in the six months ended December 31, 2003 and the year ended June 30, 2003, are summarized below (in thousands):

			Three months ended September 30, 2003			Three months ended December 31, 2003

Financial performance debt covenant test:
Operating results for debt covenant compliance			$	16,201		$	20,843

Fixed charges for the period			$	8,589			8,850

Fixed charge coverage ratio based on rolling four consecutive quarters				227	%		226	%

Reconciliation of operating results for debt covenant compliance to cash flows used in operations:
	Operating results for debt covenant compliance		$	16,201		$	20,843
	Rental expense			(1,069	)		(1,050	)
	Inventory adjustments			3,002			(6,898	)
	Interest expense, net			(6,396	)		(6,623	)
	Current tax expense			(4	)		(4	)
	Amortization of deferred revenue			(1,212	)		(1,315	)
	Amortization of deferred stock-based compensation			604			662
	Net change in unrealized gains/losses on long-term derivative contracts			1,389			876
	Change in operating assets and liabilities, net of effects from acquisitions			(29,389	)		(30,290	)

		Cash flows used in operating activities	$	(16,874	)	$	(23,799	)

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

Financial performance debt covenant test:
	Operating results for debt covenant compliance	$	9,425		$	15,796		$	17,226		$	23,114		$	65,561

	Fixed charges	$	5,740		$	6,579		$	9,581		$	7,173		$	29,073

	Fixed charge coverage ratio														226	%

Reconciliation of operating results for debt covenant compliance to cash flows used in operations:
Operating results for debt covenant compliance		$	9,425		$	15,796		$	17,226		$	23,114		$	65,561
Rental expense			(926	)		(848	)		(958	)		(1,289	)		(4,021	)
Inventory adjustments			—			(22,267	)		43,213			(13,742	)		7,204
Interest expense, net			(3,224	)		(2,967	)		(3,759	)		(4,469	)		(14,419	)
Repayment of interest rate swap			—			—			(3,205	)		—			(3,205	)
Current tax expense			(86	)		(234	)		16			(11	)		(315	)
Net tax effect arising from stock-based compensation			64			33			(7	)		(20	)		70
Amortization of deferred revenue			(150	)		(150	)		(1,041	)		(1,144	)		(2,485	)
Amortization of deferred stock-based compensation			401			457			704			670			2,232
Net change in unrealized gains/losses on long-term derivative contracts			406			1,548			2,089			2,635			6,678
Change in operating assets and liabilities, net of effects from acquisitions			22,829			(38,347	)		69,186			(77,645	)		(23,977	)

	Cash flows used in operating activities	$	28,739		$	(46,979	)	$	123,464		$	(71,901	)	$	33,323

We believe that our current working capital position; future cash expected to be provided by operating activities; available borrowing capacity under our working capital credit facility and commodity margin loan; and our relationship with institutional lenders and equity investors should enable us to meet our planned capital and liquidity requirements through at least the maturity date of our Working Capital Credit Facility (February 2006).

We utilize borrowings under our working capital credit facility and margin loan to fund our working capital requirements. During periods in which we increase the carrying amount of our inventories—discretionary volumes held for immediate sale or exchange, we also will increase our outstanding borrowings under our working capital credit facility and margin loan. For financial reporting purposes, increases in our inventories—discretionary volumes held for immediate sale or exchange are reported as cash flows used in operating activities, whereas, increased borrowings under our working capital credit facility and margin loan are reported as cash flows provided by financing activities. Conversely, during periods in which we decrease the carrying amount of our inventories—discretionary volumes held for immediate sale or exchange, we also will decrease our outstanding borrowings under our working capital credit facility and margin loan. For financial reporting purposes, decreases in our inventories—discretionary volumes held for immediate sale or exchange are reported as cash flows provided by operating activities, whereas, repayments of our working capital credit facility and margin loan are reported as cash flows used in financing activities. Therefore, we believe that analyses of our

cash flows provided by (used in) operating activities should include analyses of our borrowings (repayments) under our working capital credit facility and margin loan. For the three months ended December 31, 2003 and 2002, cash flows used in operating activities was approximately $(23.8) million and $(47.0) million, respectively, whereas borrowings under our working capital credit facility and margin loan were approximately $30.2 million and $52.8 million, respectively. For the six months ended December 31, 2003 and 2002, cash flows used in operating activities was approximately $(40.7) million and $(18.2) million, respectively, whereas borrowings under our working capital credit facility and margin loan were approximately $45.7 million and $11.5 million, respectively.

ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

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, as amended, for the year ended June 30, 2003, 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, as amended, for the year ended June 30, 2003.

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

	Crude oil		Heating oil		Gasoline

6/30/01	$	.625	$	.709	$	.721
7/31/01	$	.627	$	.697	$	.732
8/31/01	$	.648	$	.766	$	.806
9/30/01	$	.558	$	.664	$	.680
10/31/01	$	.504	$	.598	$	.552
11/30/01	$	.463	$	.532	$	.534
12/31/01	$	.472	$	.551	$	.573
1/31/02	$	.464	$	.523	$	.559
2/28/02	$	.518	$	.563	$	.581
3/31/02	$	.626	$	.669	$	.825
4/30/02	$	.650	$	.689	$	.823
5/31/02	$	.603	$	.630	$	.738
6/30/02	$	.640	$	.680	$	.794
7/31/02	$	.643	$	.676	$	.830
8/31/02	$	.690	$	.748	$	.814
9/30/02	$	.725	$	.802	$	.814
10/31/02	$	.648	$	.744	$	.864
11/30/02	$	.640	$	.757	$	.734
12/31/02	$	.743	$	.866	$	.865
1/31/03	$	.798	$	.959	$	.976
2/28/03	$	.871	$	1.256	$	1.038
3/31/03	$	.739	$	.792	$	.944
4/30/03	$	.614	$	.761	$	.843
5/31/03	$	.704	$	.754	$	.868
6/30/03	$	.719	$	.781	$	.870
7/31/03	$	.727	$	.793	$	.902
8/31/03	$	.752	$	.819	$	1.093
9/30/03	$	.695	$	.778	$	.887
10/31/03	$	.693	$	.786	$	.803
11/30/03	$	.724	$	.835	$	.837
12/31/03	$	.774	$	.913	$	.949

Our risk management policy currently allows our management team the discretion to manage the commodity price risk relating to up to 500,000 barrels of our base operating inventory volumes, which would reduce the total unmanaged inventory (base operating volumes and product linefill and tank bottom volumes) to approximately 3.3 million barrels, or to leave unmanaged up to 500,000 barrels of our discretionary inventory held for immediate sale or exchange, which would increase our total unmanaged inventory to approximately 4.3 million barrels. We decide whether to manage the

commodity price risk relating to a portion of our base operating inventory or to leave a portion of our discretionary inventory unmanaged depending on our expectations of future market changes. To the extent that we do not manage the commodity price risk relating to a portion of our inventory and commodity prices move adversely, we could suffer losses on that inventory. If, however, prices move favorably, we would realize a gain on the sale of the inventory that we would not realize if substantially all of our inventory was managed. At December 31, 2003, we were subject to commodity price risk on approximately 513,000 barrels of discretionary inventories held for immediate sale or exchange because those barrels were not offset with risk management contracts or future contractual delivery obligations.

When we purchase refined petroleum products, we generally enter into NYMEX futures contracts to protect against price fluctuations for the underlying commodity. Futures contracts are obligations to purchase or sell a specific volume of inventory at a fixed price at a future date. The NYMEX requires an initial margin deposit to open a futures contract. At December 31, 2003 and June 30, 2003, we had approximately $8.5 million and $5.2 million, respectively, on deposit to cover our initial margin requirements on open NYMEX futures contracts. NYMEX futures contracts also require daily settlements for changes in commodity prices. Unfavorable commodity price changes subject us to variation margin calls that require us to make cash payments to the NYMEX in amounts that may be material. At December 31, 2003, a $0.05 per gallon unfavorable change in commodity prices would have required us to make a cash payment of approximately $3.9 million to cover the variation margin. Conversely, a $0.05 per gallon favorable change in commodity prices would have permitted us to receive approximately $3.9 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.

At December 31, 2003 and June 30, 2003, a $0.05 per gallon unfavorable change in commodity prices relative to our open positions in derivative sales and purchase contracts and risk management contracts would have resulted in the recognition of a loss (realized and unrealized) of approximately $12.1 million and $6.0 million, respectively. However, the fair value of our discretionary inventory held for immediate sale or exchange would have increased by approximately $13.2 million and $6.1 million at December 31, 2003 and June 30, 2003, respectively. The gain from the increase in the fair value of our discretionary inventory volumes held for immediate sale or exchange may not be recognized for financial reporting purposes until those volumes have been sold to customers, which may be in an accounting period subsequent to the accounting period in which the losses on derivative contracts and risk management contracts are recognized.

ITEM 4. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the Commission's rules and forms, and that information is accumulated and communicated to our management, including our principal executive and principal financial officers (whom we refer to as our Certifying Officers), as appropriate to allow timely decisions regarding required disclosure. Our management evaluated, with the participation of our Certifying Officers, the effectiveness of our disclosure controls and procedures as of December 31, 2003, pursuant to Rule 13a-15(b) under the Exchange Act. Based upon that evaluation, our Certifying Officers concluded that, as of December 31, 2003, our disclosure controls and procedures were effective.

There were no changes in our internal control over financial reporting that occurred during our most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Part II. Other information

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a): Exhibits:


31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(b): Reports on Form 8-K:

A Current Report on Form 8-K filed on October 7, 2003 contained disclosures under Item 7, Financial Statements, Pro Forma Financial Information and Exhibits, Item 9, Regulation FD Disclosure, and Item 12, Results of Operations and Financial Condition, reporting the Company's September 29, 2003 earnings press release for its fiscal year ended June 30, 2003.

A Current Report on Form 8-K filed on November 17, 2003 contained disclosures under Item 7, Financial Statements, Pro Forma Financial Information and Exhibits, Item 9, Regulation FD Disclosure, and Item 12, Results of Operations and Financial Condition, reporting the Company's November 14, 2003 earnings press release for its first fiscal quarter ended September 30, 2003.

SIGNATURES

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.

Dated February 17, 2004	TRANSMONTAIGNE INC. (Registrant)
	By:	/s/ DONALD H. ANDERSON Donald H. Anderson President and Chief Executive Officer
		/s/ RANDALL J. LARSON Randall J. Larson Executive Vice President, Chief Financial Officer, and Chief Accounting Officer

EXHIBIT INDEX

Exhibit Number		Description of Exhibits
31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.