Edgar Filing: TRANSMONTAIGNE INC

1st Quarter 10Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549

FORM 10-Q

(Mark One)

Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended September 30, 2002

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.)

2750 Republic Plaza, 370 Seventeenth Street
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 o

As of November 1, 2002 there were 40,586,959 shares of the Registrant’s Common Stock outstanding.

TABLE OF CONTENTS

			Page No.

PART I.	FINANCIAL INFORMATION

	Item 1.	Unaudited Consolidated Financial Statements

		Consolidated Balance Sheets	4
		September 30, 2002 and June 30, 2002

		Consolidated Statements of Operations	5
		Three Months Ended September 30, 2002 and 2001

		Consolidated Statements of Preferred Stock and Common Stockholders’ Equity	6
		Year Ended June 30, 2002 and Three Months Ended September 30, 2002

		Consolidated Statements of Cash Flows	7
		Three Months Ended September 30, 2002 and 2001

		Notes to Consolidated Financial Statements	9

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22

	Item 3.	Qualitative and Quantitative Disclosures about Market Risk	35

	Item 4.	Controls and Procedures	35



PART II.	OTHER INFORMATION

	Item 6.	Exhibits and Reports on Form 8-K	36



SIGNATURES	37



CERTIFICATIONS	38

PART I. FINANCIAL INFORMATION

ITEM 1.

UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

The interim consolidated financial statements of TransMontaigne Inc. for the three months ended September 30, 2002 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, together with our discussion and analysis of financial condition and results of operations, included in our Annual Report on Form 10-K for the year ended June 30, 2002.

TransMontaigne Inc. is a holding company with the following active subsidiaries during the three months ended September 30, 2002.

•

TransMontaigne Product Services Inc. (“TPSI”)

•

TransMontaigne Transport Inc.

•

Refined Solutions Inc.

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

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

TRANSMONTAIGNE INC.
AND SUBSIDIARIES

Consolidated Balance Sheets
September 30, 2002 and June 30, 2002
(In thousands)

	September 30, 2002			June 30, 2002


Assets
Current assets:
Cash and cash equivalents	$	15,645			30,852
Restricted cash held by commodity broker		10,266			4,577
Trade accounts receivable, net		199,689			173,736
Inventories – discretionary volumes		180,241			175,169
Unrealized gains on energy services and risk management contracts		28,350			26,334
Prepaid expenses and other		2,594			2,598

		436,785			413,266

Property, plant and equipment, net		249,155			251,431
Inventories – minimum volumes		45,298			45,298
Unrealized gains on energy services and risk management contracts		13,512			13,969
Investments in petroleum related assets		10,131			10,131
Deferred tax assets		7,639			7,882
Deferred debt issuance costs, net		2,529			2,729
Other assets		4,203			4,263


	$	769,252			748,969


Liabilities, Preferred Stock, and Common Stockholders’ Equity

Current liabilities:
Commodity margin loan	$	17,087			11,312
Trade accounts payable		138,552			102,780
Unrealized losses on energy services and risk management contracts		42,172			22,163
Inventory due under exchange agreements		33,924			16,908
Excise taxes payable		58,758			72,045
Other accrued liabilities		28,058			25,842

		318,551			251,050
Other liabilities:
Long-term debt		140,000			187,000
Unrealized losses on energy services and risk management contracts		426			209

Total liabilities		458,977			438,259


Preferred stock:
Series A Convertible Preferred stock		24,421			24,421
Series B Redeemable Convertible Preferred stock		80,537			80,939

		104,958			105,360


Common stockholders’ equity:
Common stock		399			399
Capital in excess of par value		245,818			245,844
Deferred stock-based compensation		(2,088	)		(2,540	)
Accumulated deficit		(38,812	)		(38,353	)

		205,317			205,350


	$	769,252			748,969

See accompanying notes to consolidated financial statements.

TRANSMONTAIGNE INC.
AND SUBSIDIARIES

Consolidated Statements of Operations
Three Months Ended September 30, 2002 and 2001
(In thousands, except per share amounts)

	Three Months Ended September 30,

	2002			2001


Revenues
Product supply, distribution, and marketing, net	$	7,612			27,599
Terminal and pipelines		17,395			15,516

		25,007			43,115


Direct operating costs and expenses:
Lower of cost or market write-downs on minimum inventory volumes		—			849
Terminals and pipelines		6,467			7,175

		6,467			8,024

Net operating margins		18,540			35,091


Costs and expenses:
Selling, general and administrative		9,331			8,465
Depreciation and amortization		4,256			4,282
Corporate relocation and transition		1,084			—

		14,671			12,747


Operating income		3,869			22,344

Other income (expense):
Dividend income from and equity in earnings of petroleum related investments		374			1,349
Interest income		69			264
Interest expense		(3,293	)		(3,053	)
Other financing costs:
Amortization of debt issuance costs		(229	)		(464	)
Unrealized gain (loss) on interest rate swap		75			(3,612	)
Loss on disposition of assets, net		—			(1,295	)

		(3,004	)		(6,811	)


Earnings before income taxes		865			15,533

Income tax expense		(329	)		(5,902	)


Net earnings		536			9,631

Preferred stock dividends		(995	)		(2,404	)


Net earnings (loss) attributable to common stockholders	$	(459	)		7,227


Earnings (loss) per common share
Basic	$	(0.01	)		0.23

Diluted	$	(0.01	)		0.17


Weighted average common shares outstanding:
Basic		39,031			31,150

Diluted		39,031			43,125

See accompanying notes to consolidated financial statements.

TRANSMONTAIGNE INC.
AND SUBSIDIARIES

Consolidated Statements of Preferred Stock and Common Stockholders’ Equity
Year Ended June 30, 2002 and Three Months Ended September 30, 2002
(In thousands)

	Preferred stock

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

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


Balance at June 30, 2002	$	24,421			80,939		$	399			245,844			(2,540	)		(38,353	)		205,350

Common stock issued for options exercised		—			—			—			11			—			—			11
Common stock repurchased from employees for withholding taxes		—			—			—			(50	)		—			—			(50	)
Net tax effect arising from stock- based compensation		—			—			—			64			—			—			64
Forfeiture of restricted stock awards prior to vesting		—			—			—			(51	)		51			—			—
Amortization of deferred stock- based compensation		—			—			—			—			401			—			401
Preferred stock dividends		—			—			—			—			—			(1,397	)		(1,397	)
Amortization of premium on Series B Redeemable Convertible Preferred stock		—			(402	)		—			—			—			402			402
Net earnings		—			—			—			—			—			536			536


Balance at September 30, 2002	$	24,421			80,537		$	399			245,818			(2,088	)		(38,812	)		205,317

See accompanying notes to consolidated financial statements.

TRANSMONTAIGNE INC.
AND SUBSIDIARIES

Consolidated Statements of Cash Flows
Three Months Ended September 30, 2002 and 2001
(In thousands)

	Three Months Ended September 30,

	2002			2001

Cash flows from operating activities:
Net earnings	$	536			9,631
Adjustments to reconcile net earnings to net cash provided (used) by operating activities:
Depreciation and amortization		4,256			4,282
Equity in earnings of petroleum related investments		—			(21	)
Deferred tax expense		243			5,855
Net tax effect arising from stock-based compensation		64			(43	)
Loss (gain) on disposition of assets, net		—			1,295
Amortization of deferred stock-based compensation		401			313
Amortization of debt issuance costs		229			464
Unrealized (gain) loss on interest rate swap		(75	)		3,612
Net change in unrealized gains/losses on long-term energy services and risk management contracts		674			2,611
Lower of cost or market write-down on minimum inventory volumes		—			849
Changes in operating assets and liabilities, net of non-cash activities:
Trade accounts receivable, net		(25,953	)		(29,783	)
Inventories – discretionary volumes		(5,072	)		10,373
Prepaid expenses and other		4			270
Trade accounts payable		35,772			(15,492	)
Inventory due under exchange agreements		17,016			(18,536	)
Unrealized (gain) loss on energy services and risk management contracts		17,993			13,274
Excise taxes payable and other accrued liabilities		(12,394	)		(12,636	)

Net cash provided (used) by operating activities		33,694			(23,682	)

Cash flows from investing activities:
Purchases of property, plant and equipment		(1,980	)		(345	)
Proceeds from sales of assets		—			94,109
Decrease (increase) in restricted cash held by commodity broker		(5,689	)		7,984
Increase in other assets		61			151

Net cash provided (used) by investing activities		(7,608	)		101,899

Cash flows from financing activities:
Net repayments of long-term debt		(47,000	)		(41,000	)
Net borrowings of commodity margin loan		5,775			—
Deferred debt issuance costs		(29	)		—
Common stock issued for options exercised		11			30
Common stock repurchased from employees for withholding taxes		(50	)		—
Preferred stock dividends paid in cash		—			—

Net cash used by financing activities		(41,293	)		(40,970	)


Increase (decrease) in cash and cash equivalents		(15,207	)		37,247

Cash and cash equivalents at beginning of period		30,852			9,346

Cash and cash equivalents at end of period	$	15,645			46,593

See accompanying notes to consolidated financial statements.

TRANSMONTAIGNE INC.
AND SUBSIDIARIES

Consolidated Statements of Cash Flows (continued)
Three Months Ended September 30, 2002 and 2001
(In thousands)

	Three Months Ended September 30,

	2002		2001

Supplemental disclosures of cash flow information:

Sale of West Shore shares on July 27, 2001:
Investment in West Shore	$	—		12,814
Loss on disposition		—		(9,896	)

Cash received from sale	$	—		2,918


Sale of NORCO system on July 31, 2001:
Assets disposed	$	—		49,733
Liabilities recorded upon sale		—		3,416
Gain on disposition		—		8,601

Cash received from sale	$	—		61,750


Other cash sales:
Cash received from sale of Little Rock facilities on June 30, 2001	$	—		29,033

Cash received from sales of other assets	$	—		408


Total cash received from sales of assets	$	—		94,109

See accompanying notes to consolidated financial statements.

TRANSMONTAIGNE INC.
AND SUBSIDIARIES

Notes to Consolidated Financial Statements

September 30, 2002 and June 30, 2002

(1) Summary of Critical and Significant Accounting Policies

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, together with our discussion and analysis of financial condition and results of operations, included in our Annual Report on Form 10-K for the year ended June 30, 2002.

Our accounting and financial reporting policies conform to accounting principles and practices generally accepted in the United States of America. The accompanying consolidated financial statements include the accounts of TransMontaigne Inc. and its majority-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.

The preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. 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 and energy services contracts; accrued lease abandonment costs; accrued transportation and deficiency obligations; and accrued environmental obligations. Changes in these estimates and assumptions will occur as a result of the passage of time and the occurrence of future events. Actual results could differ from these estimates.

Nature of Business and Basis of Presentation

TransMontaigne Inc., a Delaware corporation (“TransMontaigne”), was formed in 1995 to create an independent petroleum products merchant based in Denver, Colorado. We are a holding company that conducts operations primarily in the Mid-Continent, Gulf Coast, Southeast, Mid-Atlantic and Northeast regions of the United States. We provide a broad range of integrated supply, distribution, marketing, terminal storage, and transportation services to refiners, distributors, marketers, and industrial/commercial end-users of refined petroleum products (e.g., gasoline, diesel fuel, and heating oil), chemicals, crude oil and other bulk liquids (collectively referred to as “Product”).

Our commercial operations currently are divided into two main operating segments: (i) Product supply, distribution, and marketing, and (ii) terminals and pipelines.

Accounting for Product Supply, Distribution, and Marketing Operations

Our Product supply, distribution, and marketing operations include energy trading and risk management activities. Our energy trading and risk management activities are marked to market (i.e., recorded at fair value in the accompanying consolidated balance sheets) in accordance with Emerging Issues Task Force Issue No. 98-10 (“EITF 98-10”), Accounting for Contracts Involved in Energy Trading and Risk Management Activities. The mark-to-market method of accounting requires that the effect of changes in the fair value of our energy trading and risk management activities be recognized as assets and liabilities and included in net revenues attributable to Product supply, distribution, and marketing in the period of the change in value.

The consensus on EITF 98-10 previously permitted revenues from energy trading and risk management activities to be presented on the face of the statement of operations on either a gross or net basis. We previously elected to present revenues

from our Product supply, distribution, and marketing operations on a gross basis with a separate line item entitled “Product costs” in the costs and expenses section of the accompanying consolidated statements of operations. Product costs represent the cost of the Products sold, settlement of risk management contracts, transportation, storage, terminaling costs, and commissions. At its June 2002 meeting, the EITF amended its consensus on EITF 98-10 to require that revenues from energy trading and risk management activities be reported on a net basis (i.e., product costs are required to be netted directly against gross revenues to arrive at net revenues). That amended guidance is effective for financial statements issued for periods ending after July 15, 2002. We have adopted that amended guidance for all periods presented. Therefore, for the three months ended September 30, 2002 and 2001, we have presented revenues from our Product supply, distribution and marketing operations on a net basis in the accompanying consolidated statements of operations. Net earnings (loss) have not been affected by this change in presentation. Net revenues attributable to our Product supply, distribution, and marketing operations are as follows (in thousands):

	Three Months ended September 30,

	2002			2001

Gross revenues	$	1,718,186			1,527,618
Less cost of revenues		(1,710,574	)		(1,500,019	)


Net revenues	$	7,612			27,599

Our energy trading and risk management activities include our inventories—discretionary volumes, energy services contracts, and risk management contracts.

Energy Services Contracts. We enter into energy services contracts that require us to deliver physical quantities of Product over a specified term at a specified price. The pricing of the Product delivered under energy services contracts may be fixed at a stipulated price per gallon, or it may vary based on changes in published indices (e.g., Platt’s—Bulk and OPIS—Wholesale).

Our energy services contracts are carried at fair value in the accompanying consolidated financial statements. The fair value of our energy services contracts is included in “Unrealized gains or losses on energy services and risk management contracts” in the accompanying consolidated balance sheets. Changes in the fair value of our energy services contracts are included in net revenues attributable to our Product supply, distribution and marketing operations.

Risk Management Contracts. We enter into risk management contracts to minimize our exposure to changes in commodity prices. We evaluate our market risk exposure from an overall portfolio basis that considers changes in physical inventories—discretionary volumes, open positions in energy services contracts, and open positions in risk management contracts. We enter into risk management contracts that offset the changes in the values of our inventories—discretionary volumes and energy services contracts. At September 30, 2002, our open positions in risk management contracts include futures contracts (purchases and sales), over-the-counter forward contracts (purchases and sales), swaps, and other financial instruments to manage market exposure, primarily commodity price risk.

Our risk management contracts are carried at fair value in the accompanying consolidated financial statements. The fair value of our risk management contracts is included in “Unrealized gains or losses on energy services and risk management contracts” in the accompanying consolidated balance sheet. Changes in the fair value of our risk management contracts are included in net revenues attributable to our Product supply, distribution and marketing operations.

Inventories—Discretionary Volumes. Our inventories—discretionary volumes are held for sale or exchange in the ordinary course of business and consist of refined petroleum products, primarily gasoline and distillates. Our inventories—discretionary volumes are carried at fair value in the accompanying consolidated financial statements. Changes in the fair value of our inventories—discretionary volumes are included in net revenues attributable to our Product supply, distribution and marketing operations.

Inventories—Minimum Volumes. Our inventories—minimum volumes are required to be held for operating balances in the conduct of our overall operating activities. We do not consider our inventories—minimum volumes to be a component of our energy trading and risk management activities. We do not intend to sell or exchange these inventories in the ordinary course

of business and, therefore, we do not hedge the market risks associated with this minimum inventory. Currently, we have designated 2.0 million barrels of refined petroleum products as inventories—minimum volumes.

Our inventories—minimum volumes are presented in the accompanying consolidated balance sheets as non-current assets and are carried at the lower of cost or market (replacement cost).

Accounting for Terminal and Pipeline Activities

In connection with our terminal and pipeline operations, we utilize the accrual method of accounting for revenue and expenses. At our terminals and pipelines, we provide throughput, storage, and transportation related services to distributors, marketers, and industrial/commercial end-users of Products. Throughput revenue is recognized when the Product is delivered to the customer; storage revenue is recognized ratably over the term of the storage contract; transportation revenue is recognized when the Product has been delivered to the customer at the specified delivery location.

Cash and Cash Equivalents

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

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

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.

Adoption of New Accounting Pronouncements

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

In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which addresses the financial accounting and reporting for long-lived assets to be disposed of by sale and broadens the presentation of discontinued operations to include more disposal transactions. SFAS No. 144 also provides guidance that will eliminate inconsistencies in accounting for the impairment or disposal of long-lived assets under existing accounting pronouncements. We adopted the provisions of SFAS No. 144 effective July 1, 2002. The adoption of SFAS No. 144 did not have an impact on our consolidated financial statements.

Reclassifications

Certain amounts in the prior years have been reclassified to conform to the current year’s presentation. We have classified inventories—minimum volumes as a non-current asset in the accompanying consolidated balance sheet (see Note 8 of Notes to Consolidated Financial Statements). We also have presented separately the current and non-current unrealized gains/losses on open energy services and risk management contracts in the accompanying consolidated balance sheet (see Note 6 of Notes to Consolidated Financial Statements).

(2) Dispositions

On July 31, 2001, we sold the NORCO Pipeline system and related terminals (“NORCO”) for cash consideration of approximately $62.0 million and recognized a net gain of approximately $8.6 million on the sale. For the month ended July 31, 2001, we recognized net revenues of approximately $1.2 million, direct operating costs and expenses of approximately $0.6 million, and depreciation and amortization expense of approximately $0.3 million related to the operations of the NORCO system.

On July 27, 2001, we sold a portion of our investment in the common stock of West Shore Pipeline Company (“West Shore”) for cash consideration of approximately $2.9 million. We recognized a net loss of approximately $1.1 million on this sale. We also recognized an impairment loss on our remaining investment in West Shore of approximately $8.8 million. On October 29, 2001, we sold our remaining investment in West Shore for cash consideration of approximately $23.1 million, which approximated our adjusted cost basis. For the three months ended September 30, 2001, we recognized dividend income from West Shore of approximately $0.6 million.

(3) Acquisitions of Terminals and Pipelines

Effective June 30, 2002, we acquired for cash consideration of approximately $7.2 million the remaining 40% interest that we previously did not own in the Razorback Pipeline system (“Razorback”), a 67 mile petroleum products pipeline between Mount Vernon, Missouri and Rogers, Arkansas with approximately .4 million barrels of storage capacity.

On July 31, 2002, we acquired for cash consideration of approximately $.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 allocated as follows (in thousands):

	Razorback			Brownsville

Prepaid expenses and other current assets	$	2			—
Property, plant and equipment		7,188			630
Other accrued liabilities assumed		(75	)		—


Cash paid, net of cash acquired of $85 and $0, respectively	$	7,115			630

We accounted for the step-acquisition of Razorback using the purchase method of accounting as of the effective date of the transaction. The proforma combined results of operations including Razorback as if the step-acquisition of Razorback had occurred on July 1, 2001 would not have been materially different from the results of operations reported in the accompanying consolidated statements of operations.

(4) Trade Accounts Receivable

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

	September 30, 2002			June 30, 2002

Trade accounts receivable	$	201,239			174,986
Less allowance for doubtful accounts		(1,550	)		(1,250	)


	$	199,689			173,736

(5) Inventories—Discretionary Volumes

Inventories—discretionary volumes are as follows (in thousands):

	September 30, 2002		June 30, 2002

Products held for sale or exchange	$	146,317		158,261
Products due under exchange agreements		33,924		16,908


Inventories—discretionary volumes	$	180,241		175,169

Our inventories—discretionary volumes are an integral component of our overall energy trading and risk management activities. Our inventories—discretionary volumes are held for sale or exchange in the ordinary course of business and consist of Products, primarily gasolines and distillates. Products due under exchange agreements represent physical Products in our possession that we owe to counterparties pursuant to an exchange agreement in which we exchange Product in a specified delivery location for Product in a different delivery location.

At September 30, 2002 and June 30, 2002, we held for sale or exchange approximately 4.2 million and 5.2 million barrels of discretionary inventory, net of 1.0 million and .5 million barrels due under exchange agreements, at a weighted average value of approximately $0.83 and $0.72 per gallon, respectively.

(6) Unrealized Gains and Losses on Energy Services and Risk Management Contracts

Unrealized gains and losses on energy services and risk management contracts are as follows (in thousands):

	September 30, 2002			June 30, 2002

Unrealized gains—current	$	28,350			26,334
Unrealized gains—long-term		13,512			13,969


Unrealized gains—asset		41,862			40,303


Unrealized losses—current		(42,172	)		(22,163	)
Unrealized losses—long-term		(426	)		(209	)


Unrealized losses—liability		(42,598	)		(22,372	)


Net asset (liability) position	$	(736	)		17,931

Our energy services contracts are primarily “fixed-price” sales commitments to industrial/commercial end users, logistical service contracts, and swap contracts.

Our risk management contracts include forward purchases and sales, swaps, and other financial instruments to offset market exposure, primarily commodity price risk, on our energy trading contracts and inventories—discretionary volumes. In managing market risks on these contracts and inventories, we evaluate the market exposure from an overall portfolio basis that considers both the open position in the energy services contracts and the related movement of certain physical inventory balances (see Note 5 of Notes to Consolidated Financial Statements).

(7) Property, Plant, and Equipment

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

	September 30, 2002			June 30, 2002

Land	$	14,125			14,125
Terminals, pipelines, and equipment		277,163			276,559
Technology and equipment		12,672			12,645
Furniture, fixtures, and equipment		5,732			5,732
Construction in progress		4,640			3,291


		314,332			312,352
Less accumulated depreciation		(65,177	)		(60,921	)


	$	249,155			251,431

(8) Inventories—Minimum Volumes

Inventories—minimum volumes are as follows (in thousands):

	September 30, 2002			June 30, 2002

Products:
At original cost basis	$	76,579			76,579
Adjustment for write-downs to lower of cost or market		(31,281	)		(31,281	)


Inventories—minimum volumes	$	45,298			45,298

Our inventories—minimum volumes are required to be held for operating balances in the conduct of our overall operating activities. We do not consider our inventories—minimum volumes to be a component of our energy trading and risk management activities. We do not intend to sell or exchange these inventories in the ordinary course of business and, therefore, we do not hedge the market risks associated with this minimum inventory. Our inventories—minimum volumes are presented in the accompanying consolidated balance sheets as non-current assets and are carried at the lower of cost or market. At September 30, 2002 and June 30, 2002, the weighted average adjusted cost basis of our inventories—minimum volumes was $0.54 per gallon.

During the three months ended September 30, 2001, we recognized an impairment loss of approximately $.8 million due to lower of cost or market write-downs on our inventories—minimum volumes.

(9) Other Assets

Other assets are as follows (in thousands):

	September 30, 2002		June 30, 2002

Prepaid transportation	$	2,644		2,644
Commodity trading membership		1,500		1,500
Deposits and other assets		59		119


	$	4,203		4,263

Prepaid transportation relates to our contractual transportation and deficiency agreements with three interstate Product pipelines (see Note 14 of Notes to Consolidated Financial Statements).

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

(10) Accrued Liabilities

Accrued liabilities are as follows (in thousands):

	September 30, 2002		June30, 2002

Interest rate swap, at fair value	$	5,354		5,429
Accrued environmental obligations		2,198		2,329
Accrued corporate relocation and transition		1,640		2,029
Accrued lease abandonment		3,110		3,110
Accrued indemnities—NORCO		1,300		1,300
Accrued transportation and deficiency obligations		2,620		2,839
Deferred revenue—energy services		2,293		1,600
Accrued expenses		5,947		5,080
Dividend payable—preferred stock		1,397		—
Deposits and other accrued liabilities		2,199		2,126


	$	28,058		25,842

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

During the three months ended September 30, 2002, we paid special termination benefits to 10 employees and we paid transition bonuses to 28 employees. We expect to pay the remaining special termination benefits before March 31, 2003, and the remaining transition bonuses during the three months ending December 31, 2002.

	Accrued liability at June 30, 2002		Amounts incurred/accrued during the period		Amounts paid during the period			Accrued liability at September 30, 2002

Accrued special termination benefits to employees not relocating to Denver , Colorado	$	1,428		—		(488	)		940
Accrued transition benefits payable to employees relocating to Denver, Colorado		501		225		(526	)		200
Relocation costs incurred during the period		100		859		(459	)		500


	$	2,029		1,084		(1,473	)		1,640

Accrued Lease Abandonment. In connection with our corporate relocation and transition, we entered into an operating lease for new office space in Denver, Colorado. The new lease was executed on April 19, 2002. We expect to vacate our existing office space in Denver, Colorado during February 2003 and we vacated our excess space in Atlanta, Georgia during October 2002. The accrual for the abandonment of the office leases represents the excess of the remaining lease payments subsequent to vacancy of the space by us over the estimated sublease rentals to be received based on current market conditions. At September 30, 2002 and June 30, 2002, the accrued liability for lease abandonment costs was approximately $3.1 million.

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

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

2003	$	745		(97	)		648
2004		991		(562	)		429
2005		1,020		(565	)		455
2006		1,045		(569	)		476
2007		948		(508	)		440
Thereafter		1,243		(581	)		662


	$	5,992		(2,882	)		3,110

Deferred Revenue—Energy Services. In connection with a fixed-price supply contract with a large industrial/commercial end-user, we committed to provide this customer with supply chain management services over the term of the supply contract. At June 30, 2002, our deferred revenue associated with the supply chain management services was approximately $1.6 million. During the three months ended September 30, 2002, we recognized approximately $150,000 in net revenues attributable to our Product supply, distribution and marketing operations from the amortization of the deferred revenues—energy services.

We enter into risk management contracts with industrial/commercial end-users that permit industrial/commercial end-users to fix the price of their fuel purchases. These contracts provide for industrial/commercial end-users to pay to us a fixed price per gallon in exchange for receiving from us a variable price per gallon based upon published prices. During the three months ended September 30, 2002, we originated risk management contracts with an estimated fair value of approximately $840,000, representing the excess of the amounts we expect to receive from the industrial/commercial end-users over our estimate of the forward price curve of the underlying commodity adjusted for basis (geographical location) differentials. At September 30, 2002, we deferred the fair value of the contracts. We will amortize the deferred revenue—energy services into net revenues attributable to our Product supply, distribution, and marketing operations over the respective terms of the contracts.

(11) Debt

Debt is as follows (in thousands):

	September 30, 2002			June 30, 2002

Commodity margin loan	$	17,087			11,312
Bank credit facility		140,000			187,000


		157,087			198,312
Less current debt		(17,087	)		(11,312	)


Long-term debt	$	140,000			187,000

Commodity Margin Loan. We currently have a commodity margin loan agreement with Salomon Smith Barney that allows us to borrow up to $20.0 million to fund certain initial and variation margin requirements in commodities accounts maintained by us with Salomon Smith Barney. The entire unpaid principal amount of the loan, together with accrued interest, is due and payable on demand. Outstanding loans bear interest at the average 90-day Treasury Bill rate plus 1.75% (3.38% at September 30, 2002).

Bank Credit Facility. On June 28, 2002, we executed an amended and restated Senior Secured Credit Facility (“New Facility”) with a syndication of banks. The New Facility provides for a maximum borrowing line of credit that is the lesser of (i) $300 million and (ii) the borrowing base (as defined; $274 million at September 30, 2002). Borrowings under the New Facility bear interest (at our option) based on the lender’s base rate plus a specified margin, or LIBOR plus a specified margin; the specified margins are a function of our leverage ratio (as defined). Borrowings under the New Facility are secured by substantially all of our assets. The terms of the New Facility include financial covenants relating to fixed charge coverage, current ratio, maximum leverage ratio, consolidated tangible net worth, capital expenditures, cash distributions and open inventory positions that are tested on a quarterly and annual basis. As of September 30, 2002, we were in compliance with all covenants included in the New Facility.

Maturities of debt at September 30, 2002 are as follows (in thousands):

Years ending:
June 30, 2003	$	17,087
June 30, 2004		—
June 30, 2005		140,000


	$	157,087

(12) Preferred Stock

At September 30, 2002 and June 30, 2002, we have authorized the issuance of up to 2,000,000 shares of preferred stock. Preferred stock is as follows (in thousands, except per share data):

	September 30, 2002		June 30, 2002

Series A Convertible Preferred stock, par value $0.01 per share, 250,000 shares authorized, 24,421 shares issued and outstanding, liquidation preference of $24,421	$	24,421	$	24,421


Series B Redeemable Convertible Preferred stock, par value $0.01 per share, 100,000 shares authorized, 72,890 shares issued and outstanding, liquidation preference of $72,890	$	80,537	$	80,939

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

Preferred stock dividends on the Series A Convertible Preferred Stock were $0.3 million and $2.4 million for the three months ended September 30, 2002 and 2001, respectively. Preferred stock dividends on the Series B Redeemable Convertible Preferred stock were $0.7 million for the three months ended September 30, 2002. The amount of the Series B Redeemable Convertible Preferred stock dividend recognized for financial reporting purposes is composed of the amount of the dividend payable 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.

(13) Common Stock

At September 30, 2002 and June 30, 2002, we were authorized to issue up to 80,000,000 shares of common stock with a par value of $0.01 per share. At September 30, 2002 and June 30, 2002, there were 39,925,043 shares and 39,942,658 shares issued and outstanding, respectively. Our bank credit facility and the certificates of designations of our preferred stock contain restrictions on the payment of dividends on our common stock.

We have a restricted stock plan that provides for awards of common stock to certain key employees, subject to forfeiture if employment terminates prior to the vesting dates. The market value of shares awarded under the plan is recorded in common stockholders’ equity as deferred stock-based compensation. Amortization of deferred compensation of approximately $0.4 million and $0.3 million is included in selling, general and administrative expense for the three months ended September 30, 2002 and 2001, respectively.

On October 25, 2002, we granted awards of 690,000 shares of restricted common stock to certain key employees. The deferred-stock based compensation associated with those awards was approximately $3.0 million, which will be amortized to income over their respective four-year vesting period.

(14) Commitments and Contingencies

Transportation and Deficiency Agreements. In connection with our sale of two Product distribution facilities in Little Rock, Arkansas, we are potentially liable for payments of up to $725,000 per year for a five-year period through June 30, 2006. The potential liability for each year is based on the actual throughput volumes of the facility for each year as compared to the contractual thresholds of 20,000 and 32,500 barrels per day (“BPD”). If actual volumes exceed 32,500 BPD, we will not be obligated to pay any of the $725,000 for that given year. If actual volumes are between 20,000 and 32,500 BPD, we will be obligated to pay a prorated portion of the $725,000 for that given year. If actual volumes are less than 20,000 BPD, we are obligated to pay the entire $725,000 for that given year. At June 30, 2002, we recognized an accrued liability of approximately $1.0 million (see Note 10 of Notes to Consolidated Financial Statements) representing our estimate of the future payments we expect to pay for the shortfall in our actual volumes and our estimated shortfall in volumes for the remainder of the term of the agreement. During the three months ended September 30, 2002, we paid approximately $0.2 million as settlement for our shortfall in volumes for the year ended June 30, 2002. Based on actual throughput volumes for the three months ended September 30, 2002, we made no additional adjustments to the accrued liability as of and for the three months ended September 30, 2002.

We also are subject to three transportation and deficiency agreements (“T&D’s”) with three separate Product interstate pipeline companies. Each agreement calls for guaranteed minimum shipping volumes over the term of the agreements. If actual volumes shipped are less than the guaranteed minimum volumes, we must make payment to the counterparty for any shortfall at the contracted pipeline tariff. Such payments are accounted for as prepaid transportation, since we have a contractual right to apply the amounts to charges for using the interstate pipeline after the end of the term of the T&D.

At June 30, 2002, prepaid transportation of approximately $2.6 million is included in other assets and our accrued liability, representing our estimate of the future payments we expect to pay for the estimated shortfall in volumes for the remainder of the terms of the T&D agreements, is approximately $1.8 million. Based on actual volumes shipped during the three months ended September 30, 2002, we made no adjustments to the prepaid transportation or accrued liability as of and for the three months ended September 30, 2002.

(15) Earnings Per Share

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

	Three Months ended September 30,

	2002			2001

Net earnings	$	536			9,631
Preferred stock dividends		(995	)		(2,404	)


Net earnings (loss) attributable to common stockholders for basic and diluted EPS	$	(459	)		7,227


Basic weighted average shares		39,031			31,150
Effect of dilutive securities:
Restricted common stock subject to continuing vesting requirements		—			63
Stock options		—			252
Common stock issuable upon conversion of:
Series A Convertible Preferred stock		—			11,660
Series B Redeemable Convertible Preferred stock		—			—

Diluted weighted average shares		39,031			43,125


Earnings (loss) per share:
Basic	$	(0.01	)		0.23


Diluted	$	(0.01	)		0.17

We exclude potentially dilutive securities from our computation of diluted earnings per share when their effect would be anti-dilutive. The following securities were excluded from the earnings per share computation as of and for the three months ended September 30, 2002, as their inclusion would have been anti-dilutive:

	September 30, 2002

Restricted common stock subject to continuing vesting requirements		873,428
Common stock issuable upon exercise of stock options		1,271,940
Common stock issuable upon exercise of stock purchase warrants		900,045
Common stock issuable upon conversion of:
Series A Convertible Preferred stock		1,628,082
Series B Redeemable Convertible Preferred stock		11,043,928


		15,717,423

For the three months ended September 30, 2002, all potentially dilutive securities were excluded because we reported a net loss attributable to common stockholders. For the three months ended September 30, 2002, the stock options had a weighted average exercise price of $4.69 per share, the stock purchase warrants had a weighted average exercise price of $14.00 per share, the Series A Convertible Preferred stock had a conversion price of $15.00, and the Series B Redeemable Convertible Preferred stock had a conversion price of $6.60.

(16) Business Segments

We provide a broad range of integrated supply, distribution, marketing, terminal storage and transportation services to refiners, distributors, marketers and industrial/commercial end-users of Products in the midstream sector of the petroleum and chemical industries. We conduct business in the following segments:

•

Product supply, distribution, and marketing—consists of services for the supply and distribution of Products through Product exchanges, and bulk purchases and sales in the physical and derivative markets, and the marketing of Products to retail, wholesale and industrial/commercial customers at truck terminal rack locations, and providing related value-added fuel procurement and management services.

•

Terminals and pipelines—consists of an extensive terminal and pipeline infrastructure that handles Products with transportation connections via pipelines, barges, rail cars and trucks to our facilities or to third-party facilities with an emphasis on transportation connections primarily through the Colonial, Plantation, Texas Eastern, Explorer and Williams pipeline systems.

•

Corporate—consists of our investments in non-controlled business ventures and general corporate items that are not allocated to specific segments (e.g., financing costs and income taxes).

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

	Three Months ended September 30, 2002

	Product supply, distribution, and marketing			Terminals and pipelines			Corporate			Total consolidated

Revenues from external customers	$	7,612			8,239			—			15,851
Inter-segment revenues		—			9,156			—			9,156


Revenues, net		7,612			17,395			—			25,007

Direct operating costs and expenses		—			(6,467	)		—			(6,467	)

Net operating margins		7,612			10,928			—			18,540


Selling, general and administrative		(5,287	)		(2,191	)		(1,853	)		(9,331	)
Depreciation and amortization		(258	)		(3,783	)		(215	)		(4,256	)
Corporate relocation and transition		(1,084	)		—			—			(1,084	)

		(6,629	)		(5,974	)		(2,068	)		(14,671	)


Operating income (loss)	$	983			4,954			(2,068	)		3,869


Capital expenditures	$	—			1,980			—			1,980

	Three Months ended September 30, 2002

	Product supply, distribution, and marketing			Terminals and pipelines			Corporate			Total consolidated

Revenues from external customers	$	27,599			8,042			—			35,641
Inter-segment revenues		—			7,474			—			7,474


Revenues, net		27,599			15,516			—			43,115

Lower of cost or market write-downs on minimum inventories		(849	)		—			—			(849	)
Direct operating costs and expenses		—			(7,175	)					(7,175	)

Net operating margins		26,750			8,341			—			35,091


Selling, general and administrative		(5,183	)		(1,888	)		(1,394	)		(8,465	)
Depreciation and amortization		—			(3,760	)		(522	)		(4,282	)

		(5,183	)		(5,648	)		(1,916	)		(12,747	)


Operating income (loss)	$	21,567			2,693			(1,916	)		22,344


Capital expenditures	$	62			283			—			345

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

GENERAL

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

TransMontaigne Inc. (“TransMontaigne”) was formed in 1995 to create an independent refined petroleum products merchant based in Denver, Colorado. We are a holding company that conducts our commercial activities primarily in the Mid-Continent, Gulf Coast, Southeast, Mid-Atlantic and Northeast regions of the United States. We supply, distribute, transport, store, and market refined petroleum products, chemicals, crude oil, and other bulk liquids (collectively referred to as “Products”) to refiners, distributors, marketers, and industrial/commercial end-users.

Our commercial activities currently are divided into two main operating segments: (i) Product supply, distribution, and marketing services, and (ii) terminal and pipeline operations. Our Product supply, distribution and marketing operations generally utilize our terminal and pipeline infrastructure to market and trade various Products and provide specialized supply, logistical, and risk management services to our customers.

Product Supply, Distribution, and Marketing Operations

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

Our Product supply, distribution, and marketing operations typically purchase Products at prevailing prices from refiners and producers at production points and common trading locations. When we purchase Products, we simultaneously sell the Products for physical delivery to third party users or by entering into future delivery obligations, such as futures contracts on the NYMEX. These futures contracts minimize or eliminate our exposure to fluctuations in the quoted price of the commodity, but do not minimize exposure to basis (geographical location) differentials. These Products are then shipped via barge, pipelines we own, or third party-owned pipelines to terminals we own or to third-party terminal locations. From these terminal locations, the Products are made available to our customers either through contract sales, exchange agreements or daily-priced rack sales.

Rack Sales. We manage the physical quantity of our discretionary inventories of Product through daily-priced rack sales. On a daily basis we establish the selling price for each Product for each of our delivery locations/terminals. We announce or “post” those selling prices to independent local jobbers via facsimile, website, email, and telephone communications. Our selling price of a particular Product on a particular day is a function of our supply at that delivery location/terminal and our estimate of the costs to replenish the Product at that delivery location. The demand for a particular Product is sensitive to changes in pricing. If our objective is to increase demand for a particular Product at a specific delivery location, we would post the selling price of that Product at the low end of the range of prices being offered at that location to increase our local demand. If our objective is to decrease demand for a particular Product at a specified delivery location, we would post a selling price at the high end of the range of prices being offered at that location to reduce our local demand. For the three months ended September 30, 2002 and 2001, we averaged approximately 124,000 and 75,000 barrels per day, respectively, of delivered volumes under daily-priced rack sales.

Exchanges. Exchange agreements are entered into with major oil companies and independent refiners. These agreements provide for the exchange of Product at one delivery location for Product at a different location. We generally receive a fee based on the volume of the Product exchanged. That fee takes into account the cost of transportation from the receipt location to the exchange delivery location. For the three months ended September 30, 2002 and 2001, we averaged approximately 98,000 and 142,000 barrels per day, respectively, of delivered volumes under exchange agreements.

Bulk and Cycle Sales. Bulk and cycle sales of Products are entered into with major oil companies and independent refiners. These transactions involve the sale of Products in large quantities in liquid bulk markets (Pasadena, TX, New York Harbor, Chicago, IL, Tulsa, OK refining area, and Los Angeles, CA). These transactions also involve the sale of Products in large quantities prior to scheduled delivery to us by producers and refiners for transportation by pipelines, barges, vessels, or rail cars to our terminals. These transactions may occur while the Products are in transit prior to reaching our terminals. For the three months ended September 30, 2002 and 2001, we averaged approximately 475,000 and 364,000 barrels per day, respectively, of delivered volumes under bulk and cycle sales.

Contract Sales. Contract sales of Products are conducted from our own and third-party terminal, storage, and delivery locations with independent local jobbers, industrial/commercial end users, and governmental agencies. Contract sales provide these customers with a specified volume of Product over a specified term at a specified price. The terms of these contracts range from as short as one month to terms that span up to three years. 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 (e.g., OPIS and Platts). For the three months ended September 30, 2002 and 2001, we averaged approximately 97,000 and 75,000 barrels per day, respectively, of delivered volumes under contract sales.

Energy Services. We provide “supply chain management” services to our industrial/commercial end-users downstream of the truck loading rack location. Fuel and risk management logistical services provide our large and small volume customers an assured, cost effective delivered source of Products supply through our pipelines and terminals, as well as through third-party pipeline, terminal, truck, rail and barge distribution channels. Customers of our “supply chain management” services receive the benefits of our web-based technology systems enabling the customers to minimize their total Product costs while meeting their volumetric needs. We generally receive a fee based on the volume of the Products we originate for the customer in exchange for providing our supply chain management services.

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

Our energy trading and risk management activities include our inventories—discretionary volumes, energy services contracts, and risk management contracts. Our inventories—discretionary volumes are held for sale or exchange in the ordinary course of business and consist of refined petroleum products, primarily gasoline and distillates. Our energy services contracts require us to deliver physical quantities of Products over specified terms at specified prices. Our risk management contracts (e.g., forward sales contracts, forward purchase contracts, and swaps) minimize our exposure to changes in commodity prices. We enter into risk management contracts with the objective of offsetting the changes in the values of our inventories—discretionary volumes and energy services contracts. It is our policy not to acquire Products, futures contracts or other derivative products for the purpose of speculating on the flat price associated with the underlying commodity. Risk

management policies have been established by our Risk Management Committee to monitor and control these price risks. Our Risk Management Committee is composed of our senior executives.

Our inventories—discretionary volumes are carried at fair value in the accompanying consolidated financial statements. Our energy services and risk management contracts also are carried at fair value in the accompanying consolidated financial statements. The fair value of our energy services and risk management contracts are presented as “Unrealized gains or losses on energy services and risk management contracts” in the accompanying consolidated balance sheet.

Terminals and Pipelines

We own and operate a terminal infrastructure that handles Products with transportation connections via pipelines, barges, rail cars and trucks to our facilities and to third-party facilities. As of September 30, 2002, we owned and operated the following facilities: 30 delivery locations/terminals with approximately 9.9 million barrels of tank space capacity along the Colonial and Plantation pipeline systems; 3 delivery locations/terminals with approximately 500,000 barrels of tank space capacity along the Explorer/Williams pipeline systems; 3 delivery locations/terminals with approximately 1.0 million barrels of tank capacity along the Florida coast; 1 delivery location/terminal with approximately 2.2 million barrels of tank capacity in Brownsville, Texas; and 12 delivery locations/terminals with approximately 2.9 million barrels of tank capacity along the Mississippi and Ohio rivers.

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. The Razorback Pipeline is the only Products pipeline providing transportation services to northwest Arkansas. Effective June 30, 2002, we acquired for cash consideration of approximately $7.2 million the remaining 40% interest in the Razorback Pipeline system that we did not previously own. We also own and operate a small intrastate crude oil gathering pipeline system, located in east Texas (the “CETEX pipeline”).

The success of our terminal and pipeline operations depends in large part on the level of demand for Products by end users in the geographic locations served by such facilities and the ability and willingness of our customers to supply such demand by utilizing our terminals and pipelines as opposed to the terminals and pipelines of other companies. At our terminals and pipelines, we provide throughput, storage, and transportation related services to distributors, marketers and industrial/commercial end-users of Products.

Throughput and Storage Revenues. Terminal throughput fees are based on the volume of Products handled at the facility’s truck loading racks, generally at a standard rate per gallon. Terminal storage fees generally are based on a per barrel rate or tank space capacity committed and will vary with the duration of the arrangement, the Product stored and special handling requirements, particularly when certain types of chemicals and other bulk liquids are involved. For the three months ended September 30, 2002 and 2001, we averaged approximately 480,000 and 515,000 barrels per day, respectively, of throughput and storage volumes at our terminals.

Transportation Revenues. Pipeline transportation fees are based on the volume of Products transported and the distance from the origin point to the delivery point. For the three months ended September 30, 2002 and 2001, we averaged approximately 27,000 and 33,000 barrels per day, respectively, of transported volumes through our pipelines.

The direct operating costs and expenses of the terminals and pipelines 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. We cannot predict the impact of future fuel conservation measures, alternate fuel requirements, governmental regulation, technological advances in fuel economy, demographic changes, weather conditions, crop prices, and energy-generation devices, all of which could reduce the demand for Products in the areas we serve.

CRITICAL ACCOUNTING ESTIMATES

A summary of the significant accounting policies that we have adopted and followed in the preparation of our consolidated financial statements is detailed in our Annual Report on Form 10-K for the year ended June 30, 2002 (see Note 1 of Notes to the Consolidated Financial Statements). Certain of these accounting policies require the use of estimates. The following estimates, in our opinion, are subjective in nature, require the exercise of judgment, and involve complex analysis: allowance for doubtful accounts; fair value of inventories—discretionary volumes and energy services contracts; accrued lease abandonment costs; accrued transportation and deficiency obligations; and accrued environmental obligations. These

estimates are based on our knowledge and understanding of current conditions and actions we may take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our financial condition and results of operations.

SIGNIFICANT DEVELOPMENTS

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

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

SUBSEQUENT EVENTS

Corporate Relocation and Transition. During the three months ended September 30, 2002, we relocated our Product supply, distribution, and marketing operations from Atlanta, Georgia to our existing office space at 370 17^th Street in Denver, Colorado. During October and November 2002, our Product supply, distribution, and marketing operations moved into our new office space at 1670 Broadway in Denver, Colorado. Our executive and administrative operations expect to vacate our existing office space at 370 17^th Street and join our Product supply, distribution, and marketing operaitons at 1670 Broadway during March 2003.

New Accounting Pronouncements with Delayed Effective Dates. On October 25, 2002, the EITF reached a consensus that energy trading and risk management activities should no longer be marked to market pursuant to Issue No. 98-10. Rather, energy trading and risk management activities that qualify as derivative contracts pursuant to SFAS No. 133 will be recognized as assets and liabilities at fair value and energy trading and risk management activities that do not qualify as derivative contracts will be treated as executory contracts and recognized pursuant to the accrual method of accounting (see New Accounting Pronouncements with Delayed Effective Dates, on page 34 of this Quarterly Report on Form 10-Q).

RESULTS OF OPERATIONS

Selected financial data regarding our operating income is summarized below (in thousands):

	Three Months Ended September 30,

	2002			2001


Product supply, distribution, and marketing:
Revenues, net	$	7,612			27,599
Lower of cost or market write-downs on inventories – minimum volumes		—			(849	)

Net operating margins		7,612			26,750


Terminals and pipelines:
Revenues		17,395			15,516
Direct operating costs and expenses		(6,467	)		(7,175	)

Net operating margins		10,928			8,341


Total net operating margins		18,540			35,091

Selling, general and administrative expenses		(9,331	)		(8,465	)
Depreciation and amortization		(4,256	)		(4,282	)
Corporate relocation and transition		(1,084	)		—

Operating income	$	3,869			22,344

(1)

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

Selected volumetric data:

	Three Months Ended September 30,

	2002		2001

Terminal Volumes – bbls/day		480,422		515,035
Terminal net operating margin per bbl	$	0.220	$	0.162

Pipeline Volumes – bbls/day		27,129		32,674
Pipeline net operating margin per bbl	$	0.480	$	0.288

The following summary reflects our comparative EBITDA, adjusted EBITDA, and net cash flows for the three months ended September 30, 2002 and 2001 (in thousands):

	Three Months Ended September 30,

	2002			2001


EBITDA (1)	$	8,499			27,975
Adjusted EBITDA (2)	$	8,499			28,824

Net cash provided (used) by operating activities	$	33,694			(23,682	)

Net cash provided (used) by investing activities	$	(7,608	)		101,899

Net cash (used) by financing activities	$	(41,293	)		(40,970	)

Calculation of EBITDA and Adjusted EBITDA:
Net operating margins:
Product supply, distribution, and marketing	$	7,612			26,750
Terminals and pipelines		10,928			8,341

Total net operating margins		18,540			35,091

Selling, general and administrative expenses		(9,331	)		(8,465	)
Corporate relocation and transition		(1,084	)		—
Dividend income		374			1,349

EBITDA (1)		8,499			27,975
Plus write-downs on minimum inventory		—			849

Adjusted EBITDA (2)	$	8,499			28,824

(1)

EBITDA is defined as total net operating margin, less selling, general and administrative expenses, less corporate relocation and transition, plus dividend income from petroleum related investments. We believe that, in addition to cash flow from operating activities and net earnings (loss), EBITDA is a useful financial performance measurement for assessing operating performance since it provides an additional basis to evaluate our ability to incur and service debt and to fund capital expenditures. In evaluating EBITDA, we believe that consideration should be given, among other things, to the amount by which EBITDA exceeds interest costs for the period; how EBITDA compares to principal repayments on debt for the period; and how EBITDA compares to capital expenditures for the period. To evaluate EBITDA, the components of EBITDA such as revenue and direct operating expenses and the variability of such components over time, also should be considered. EBITDA should not be construed, however, as an alternative to operating income (loss) (as determined in accordance with GAAP) as an indicator of our operating performance, or to cash flows from operating activities (as determined in accordance with GAAP) as a measure of liquidity. Our method of calculating EBITDA may differ from methods used by other companies and, as a result, EBITDA measures disclosed herein might not be comparable to other similarly titled measures used by other companies.

(2)

Adjusted EBITDA is defined as EBITDA plus lower of cost or market write-downs on the inventories – minimum volumes. We believe that Adjusted EBITDA is the most useful measure in evaluating our performance because it eliminates the impact on operating results from the impairment of our inventories - minimum volumes.

THREE MONTHS ENDED SEPTEMBER 30, 2002 COMPARED TO THREE MONTHS ENDED SEPTEMBER 30, 2001

We reported net earnings of $0.5 million for the three months ended September 30, 2002, compared to net earnings of $9.6 million for the three months ended September 30, 2001. After preferred stock dividends, the net (loss) attributable to common stockholders was $(0.5) million for the three months ended September 30, 2002, compared to net earnings of $7.2 million for the three months ended September 30, 2001. Basic and diluted loss per common share for the three months ended September 30, 2002 was $(0.01) based on 39.0 million weighted average common shares outstanding. Basic and diluted earnings per share for the three months ended September 30, 2001 was $0.23 per share and $0.17 per share, respectively, based upon 31.1 million weighted average common shares outstanding and 43.1 million weighted average diluted shares outstanding.

Product Supply, Distribution and Marketing

During a “contango” or “carry” market structure, we utilize our and third-party terminals to store Products to capture commodity price differentials between current and future months. Mark-to-market accounting will create volatility in our net operating margins due to either the widening or narrowing of these pricing spreads from the original spread relationship. If the spreads widen (narrow), marking these storage volumes and the related forward contracts to market will produce unrealized losses (gains) in interim reporting periods. These negative (positive) results will reverse and the originally anticipated spread will be recognized during the future periods when the physical Product inventory is delivered against the short future position. At September 30, 2002, we held approximately 1.3 million barrels of distillates in our terminals for future delivery.

The net revenues reported for the Product supply, distribution and marketing operations include amounts realized on Product sales, exchanges and arbitrage. The net revenues from our Product supply, distribution, and marketing operations for the three months ended September 30, 2002 were $7.6 million compared to $27.6 million for the three months ended September 30, 2001. Net revenues from our Product supply, distribution, and marketing operations are affected by our ability to take advantage of volatility in basis (geographical location) differentials that are caused by market imbalances. We experienced a lack of sustained volatility in basis (geographical location) differentials during the three months ended September 30, 2002, which prevented us from taking advantage of the opportunities that are created by selling Product in the highest value location; whereas, during the three months ended September 30, 2001, we were able to increase our net operating margins by taking advantage of the price volatility in the gasoline market. A disruption at a Chicago refinery in August 2001 resulted in supply and demand imbalances that increased volatility in basis (geographical location) differentials. This disruption increased the basis (geographical location) differentials for both gasoline and distillates between the Gulf Coast, Chicago and Group (Mid-Continent) regions, which created significant margin opportunities in arbitraging the basis (geographical location) differentials between those markets. The decrease in net revenues during the three months ended September 30, 2002 also was due, in part, to the recognition of unrealized losses on energy trading activities of approximately $2.5 million, which resulted from a decline in the value of crude oil options, and an unfavorable relationship between crude oil and refined product prices.

During the three months ended September 30, 2002, no impairment losses were recognized due to lower of cost or market write-downs on minimum inventory volumes. During the three months ended September 30, 2001, we recognized impairment

losses of approximately $0.8 million due to lower of cost or market write-downs on the minimum inventory volumes. This write-down is included in net operating margins attributable to our Product supply, distribution, and marketing operations.

Terminals and Pipelines

The revenues from our terminal and pipeline operations for the three months ended September 30, 2002 were $17.4 million, compared to $15.5 million for the three months ended September 30, 2001. The increase of $1.9 million in revenues was due principally to increases in storage revenues of $0.8 million at our Brownsville, Texas facilities and $0.5 million at our Selma, North Carolina facilities, increases in throughput and storage revenues of $1.4 million due to increased volumes at our marketing and supply terminals, increases in transportation revenues of $0.4 million due to increased volumes through our pipelines, offset by a decrease in revenues of $1.2 million associated with the NORCO system, which was disposed on July 31, 2001. The net operating margins from our terminal and pipeline operations for the three months ended September 30, 2002 were $10.9 million, compared to $8.3 million for the three months ended September 30, 2001. The increase of $2.6 million in net operating margins was due principally to an increase in throughput and storage volumes at our terminals without a corresponding increase in direct operating costs and expenses, offset by the absence of the net operating margins from the NORCO system. For the month ended July 31, 2001, the net operating margins from the NORCO system were $0.6 million.

Our pipeline net operating margins per barrel of transported volumes were approximately $0.48 and $0.29 for the three months ended September 30, 2002 and 2001, respectively. The increase in net operating margins per barrel is due principally to the higher unit tariff being realized on one of our joint tariffs, as compared to the lower unit tariff associated with our NORCO system, which was disposed of in July 2001.

Costs and Expenses

Selling, general and administrative expenses for the three months ended September 30, 2002 were $9.3 million, compared to $8.5 million for the three months ended September 30, 2001. The increase of $0.8 million was due principally to compensation and travel expenses incurred for redundant employees involved in our corporate relocation and transition during the three months ended September 30, 2002.

Depreciation and amortization for the three months ended September 30, 2002 and 2001, was $4.3 million. The effects on depreciation and amortization associated with the disposition of the NORCO system were offset by depreciation and amortization on new additions to property, plant, and equipment.

We recognized special charges of $1.1 million during the three months ended September 30, 2002 related to the corporate relocation and transition. We expect to recognize an additional special charge of $1.0 million during the remainder of the year ending June 30, 2003 to complete the corporate relocation and transition. The additional special charges principally will consist of additional transition benefits, employee relocation costs, and moving costs related to the relocation of the corporate headquarters to the new office space.

Other Income and Expenses

Dividend income from and equity in earnings of petroleum related investments for the three months ended September 30, 2002 was $0.4 million, compared to $1.3 million for the three months ended September 30, 2001. The decrease of $0.9 million in dividend income was due principally to a decrease of $0.3 million in dividends received from Lion Oil Company and the absence of $0.6 million in dividends received from West Shore. We sold a portion of our investment in West Shore on July 27,2001 and our remaining investment on October 29, 2001.

Interest income for the three months ended September 30, 2002 was $0.1 million, compared to $0.3 million for the three months ended September 30, 2001. The decrease of $0.2 million was due primarily to a decrease in interest bearing cash balances and lower interest rates during the three months ended September 30, 2002. Pursuant to our cash management practices, excess cash balances are used to pay down our outstanding borrowings under our bank credit facility and commodity margin loan.

Interest expense for the three months ended September 30, 2002 was $3.3 million, compared to $3.1 million during the three months ended September 30, 2001. The increase of $0.2 million in interest expense was primarily attributable to an increase in the amount of debt outstanding during the current period, offset by lower interest rates during the three months ended September 30, 2002, as the average interest rate under our bank credit facility was 4.3% and 5.7% for the three months ended September 30, 2002 and 2001, respectively. For the three months ended September 30, 2002, our interest expense resulted from $1.6 million for outstanding borrowings under our bank credit facility, $0.1 million for outstanding letters of credit, $0.1 million for outstanding borrowings under our commodity margin loan, and $1.5 million in net payments for the interest rate swap. For the three months ended September 30, 2001, our interest expense resulted from $2.1 million for outstanding borrowings under our bank credit facility and Senior Notes, $0.1 million for outstanding letters of credit, $0.2 million for outstanding borrowings under our commodity margin loan, and $0.7 million in net payments for the interest rate swap.

Other financing costs for the three months ended September 30, 2002 were $0.2 million, compared to $4.1 million for the three months ended September 30, 2001. The decrease of $3.9 million in other financing costs was due principally to a reduction in the amortization of deferred financing costs of $0.2 million and an unrealized gain on an interest rate swap of $0.1 million during the three months ended September 30, 2002, as compared to an unrealized loss on an interest rate swap of $3.6 million during the three months ended September 30, 2001. The swap agreement provides that we pay a fixed interest rate of 5.48% on the notional amount of $150 million in exchange for receiving a variable rate based on LIBOR so long as the one-month LIBOR interest rate does not rise above 6.75%. If the one-month LIBOR rate rises above 6.75%, the swap knocks out and we will receive no payments under the agreement until such time as the one-month LIBOR rate declines below 6.75%. At September 30, 2002 and 2001, the one-month LIBOR rate was 1.8% and 2.6%, respectively. This swap agreement expires in August 2003.

Loss on the disposition of assets, net for the three months ended September 30, 2001, consists of an $8.6 million gain on the sale of the NORCO system and an $9.9 million loss on the sale of West Shore shares.

Income Taxes

Income tax expense was $0.5 million for the three months ended September 30, 2002, which represents an effective combined federal and state income tax rate of 38.0%. Income tax expense was $5.9 million for the three months ended September 30, 2001, which represents an effective combined federal and state income tax rate of 38.0%.

Preferred Stock Dividends

Preferred stock dividends on our Series A Convertible Preferred Stock were $0.3 million and $2.4 million for the three months ended September 30, 2002 and 2001, respectively. The decrease in the current year dividend resulted from a reduction in the number of shares of Series A Convertible Preferred Stock outstanding during the current period. On June 28, 2002, we entered into an agreement with the holders of the Series A Convertible Preferred Stock (the “Preferred Stock Recapitalization Agreement”) to redeem a portion of the outstanding Series A Convertible Preferred Stock and warrants in exchange for cash, shares of common stock, and shares of a newly created and designated preferred stock (“Series B Redeemable Convertible Preferred Stock”). The Preferred Stock Recapitalization Agreement resulted in the redemption of 157,715 shares of Series A Convertible Preferred Stock and warrants to purchase 9,841,493 shares of common stock in exchange for the (i) issuance of 72,890 shares of Series B Redeemable Convertible Preferred Stock with a fair value of approximately $80.9 million, (ii) issuance of 11,902,705 shares of common stock with a fair value of approximately $59.5 million, and (iii) a cash payment of approximately $21.3 million.

Preferred stock dividends on our Series B Redeemable Convertible Preferred stock were $0.7 million for the three months ended September 30, 2002. There were no shares of Series B Redeemable Convertible Preferred stock outstanding during the three months ended September 30, 2001. The initial carrying amount of the Series B Redeemable Convertible Preferred Stock of approximately $80.9 million will be decreased ratably over its 5-year term until it equals its liquidation value of approximately $72.9 million with an equal reduction in the amount of preferred stock dividends recorded for financial reporting purposes. The amount of the dividend recognized for financial reporting purposes is composed of the amount of the dividend payable to the holders of the Series B Redeemable Convertible Preferred stock of $1.1 million, offset by the amortization of the premium on the carrying amount of the Series B Redeemable Convertible Preferred stock of $0.4 million.

LIQUIDITY, CAPITAL RESOURCES, AND COMMODITY PRICE RISK

At September 30, 2002, our current assets exceeded our current liabilities by $118.5 million, compared to $162.2 million at June 30, 2002. The decrease of $44.0 million in working capital is due principally to an increase in trade accounts payable and an increase in unrealized losses on energy services and risk management contracts, offset by an increase in trade accounts receivable.

The increase in accounts receivable of $25.9 million is due principally to an increase in the volume of daily-priced rack sales, which are billed on a gross basis, compared to exchange transactions, which are billed on a net basis, and an increase in Product supply, distribution, and marketing volumes coupled with a corresponding increase in commodity prices. Our gross revenues for the Product supply, distribution, and marketing operations were approximately $1.7 billion for the three months ended September 30, 2002, compared to approximately $1.5 billion for the three months ended September 30, 2001.

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

	September 30, 2002				June 30, 2002

	Amount		Bbls		Amount		Bbls

Products held for sale or exchange	$	146,317		4,196	$	158,261		5,224
Products due to others under exchange agreements, net		33,924		1,019		16,908		525


Inventories—discretionary volumes	$	180,241		5,215	$	175,169		5,749

During the last six months of the year ended June 30, 2002, we increased our discretionary inventory of distillates to capitalize on the “carry” or “contango” market structure. During a “contango” market, we utilize our and third-party terminals to store Products to capture commodity price differentials between current and future months. At September 30, 2002, we held approximately 1.3 million barrels of distillates in our terminals for future delivery.

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

Our inventories—minimum volumes are required to be held for operating balances in the conduct of our overall operating activities. We do not intend to sell or exchange these inventories in the ordinary course of business and, therefore, we do not hedge the market risks associated with this minimum inventory. Our inventories—minimum volumes are presented in the accompanying consolidated balance sheet as non-current assets and are carried at the lower of cost or market. Inventories—minimum volumes are as follows (in thousands):

	September 30, 2002				June 30, 2002

	Amount		Bbls		Amount		Bbls

Gasolines	$	27,855		1,200	$	27,855		1,200
Distillates		17,443		800		17,443		800

Inventories—minimum volumes	$	45,298		2,000	$	45,298		2,000

During the three months ended September 30, 2001, we recognized an impairment loss of approximately $0.8 million due to lower of cost or market write-downs on this minimum inventory. This write-down is included in net operating margins attributable to our Product supply, distribution, and marketing operations. At September 30, 2002 and June 30, 2002, the weighted average adjusted cost basis of our inventories—minimum volumes was $0.54 per gallon.

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

	Crude		Heating Oil		Gasoline

6/30/01		$ 26.25		.709		.721
7/31/01		26.35		.697		.732
8/31/01		27.20		.766		.806
9/30/01		23.43		.664		.680
10/31/01		21.18		.598		.552
11/30/01		19.44		.532		.534
12/31/01		19.84		.551		.573
1/31/02		19.48		.523		.559
2/28/02		21.74		.563		.581
3/31/02		26.31		.669		.825
4/30/02		27.29		.689		.823
5/31/02		25.31		.630		.738
6/30/02		26.86		.680		.794
7/31/02		27.02		.676		.830
8/31/02		28.98		.748		.814
9/30/02		30.45		.802		.814

The following table indicates the maturities of our energy services and risk management contracts, including the credit quality of our counterparties to those contracts with unrealized gains at September 30, 2002.

	Fair value of contracts (in thousands)

	Maturity less than 1 year			Maturity 1-3 years			Maturity 4-5 years		Maturity in excess of 5 years		Total

Unrealized gain position—asset
Energy services contracts:
Investment grade	$	1,609			70			—		—		1,679
Non-investment grade		3,074			7,227			—		—		10,301
No external rating		5,506			588			—		—		6,094

		10,189			7,885			—		—		18,074
Risk management contracts— NYMEX futures contracts		18,161			5,627			—		—		23,788

	$	28,350			13,512			—		—		41,862

Unrealized loss position—liability
Energy services contracts	$	(17,492	)		(407	)		—		—		(17,899	)
Risk management contracts— NYMEX futures contracts		(24,680	)		(19	)		—		—		(24,699	)

	$	(42,172	)		(426	)		—		—		(42,598	)


Net unrealized gain (loss) position—asset (liability)	$	(13,822	)		13,086			—		—		(736	)

At September 30, 2002, the unrealized gain on our energy services contracts with non-investment grade counterparties was approximately $10.3 million. A single industrial/commercial end-user represented approximately $9.0 million of that unrealized gain. At September 30, 2002, we also had energy services contracts with that end-user that were in an unrealized loss position of approximately $2.9 million. Therefore, the fair value of our energy services contracts with that industrial/commercial end-user was approximately $6.1 million at September 30, 2002. The following table includes information about the changes in the fair value of our energy services contracts with that industrial/commercial end-user for the three months ended September 30, 2002 (in thousands):

Fair value at June 30, 2002	$	11,041
Amounts realized or otherwise settled during the year		(1,545	)
Change in fair value attributable to change in commodity prices		(3,942	)
Other changes in fair value		613

Fair value at September 30, 2002	$	6,167

We do not acquire or sell Products, futures contracts, or other financial instruments solely for the purpose of speculating on changes in commodity prices. Our Risk Management Committee reviews the discretionary inventory and related open positions in energy services and risk management contracts on a regular basis in order to ensure compliance with our inventory and risk management policies. We have adopted policies under which changes to our net risk position, which is subject to commodity price risk, requires the prior approval of our Audit Committee of the Board of Directors.

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

We principally utilize exchange-traded risk management contracts to manage our commodity price risk. These contracts require us to maintain initial and variation margin deposits with a third party financial intermediary. At September 30, 2002 we had $9.4 million on deposit to cover our margin requirements on open risk management contracts, which consisted solely of an initial margin deposit. At June 30, 2002, we had $8.6 million on deposit to cover our margin requirements on open risk management contracts, which consisted solely of an initial margin deposit. At September 30, 2002, a $0.05 per gallon unfavorable change in commodity prices would have required us to deposit approximately $3.6 million in variation margin. Conversely, a $0.05 per gallon favorable change in commodity prices would have permitted us to reduce the deposit in our margin account by approximately $3.6 million. We have the contractual right to request that the counterparties to our energy services contracts post additional letters of credit or make additional cash deposits with us to assist us in meeting our obligations to cover our margin requirements.

Excluding the acquisition of the Products terminal in Brownsville, Texas, capital expenditures for the three months ended September 30, 2002 were $1.4 million for terminal and pipeline facilities and assets to support these facilities. Capital expenditures for the remainder of the year ending June 30, 2003, are estimated to be approximately $4.0 million. Future capital expenditures will depend on numerous factors, including the availability, economics and cost of appropriate acquisitions which we identify and evaluate; the economics, cost and required regulatory approvals with respect to the expansion and enhancement of existing systems and facilities; customer demand for the services we provide; local, state and federal governmental regulations; environmental compliance requirements; and the availability of debt financing and equity capital on acceptable terms.

Our bank credit facility provides for a maximum borrowing line of credit that is the lesser of (i) $300 million and (ii) the borrowing base. The borrowing base is a function of our accounts receivable, inventory, exchanges, margin deposits, open positions of energy services and risk management contracts, outstanding letters of credit, and outstanding indebtedness as defined in the facility. The borrowing base was $274 million at September 30, 2002. Borrowings under the bank credit facility are secured by substantially all of our assets. The terms of the bank credit facility include financial covenants relating to fixed charge coverage, current ratio, maximum leverage ratio, consolidated tangible net worth, capital expenditures, cash distributions and open inventory positions that are tested on a quarterly and annual basis. As of September 30, 2002, we were in compliance with all covenants included in the facility. At September 30, 2002, we had borrowings of $140.0 million

outstanding and letters of credit of $15.7 outstanding under the bank credit facility. We also had the ability to borrow an additional $118.0 million under the facility based on the borrowing base computation at September 30, 2002.

We believe that our current working capital position; future cash expected to be provided by operating activities; available borrowing capacity under our bank credit facility and commodity margin loan; and our relationship with institutional lenders and equity investors should enable us to meet our planned capital and liquidity requirements.

Net cash provided by operating activities of $33.7 million for the three months ended September 30, 2002 was due principally to increases in trade accounts payable, inventory due under exchange agreements, and an increase in unrealized losses on energy services and risk management contracts, offset by an increase in trade accounts receivable. The net cash used by operating activities of $23.7 million for the three months ended September 30, 2001 was due principally to an increase in trade accounts receivable and decreases in trade accounts payable and inventory due under exchange agreements, offset by a decrease in unrealized gains on energy services and price risk management activities and inventories – discretionary volumes.

Net cash used by investing activities of $7.6 million for the three months ended September 30, 2002 was due principally to capital expended for construction and improvements to existing operating facilities and acquisitions of $2.0 million and additional restricted cash of $5.7 million to cover required margin deposits on risk management contracts. Net cash provided by investing activities of $101.9 million during the three months ended September 30, 2001 was due principally to proceeds received from the sale of assets of $94.1 million.

Net cash used by financing activities of $41.3 million for the three months ended September 30, 2002 was due principally to repayments of borrowings under our bank credit facility of $47.0 million offset by proceeds from additional borrowings under our commodity margin loan of $5.8 million. Net cash used by financing activities of $41.0 million for the three months ended September 30, 2001 was due principally to repayments of borrowings under our bank credit facility and master shelf facility.

NEW ACCOUNTING PRONOUNCEMENTS WITH DELAYED EFFECTIVE DATES

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

On October 25, 2002, the EITF reached a consensus that energy trading and risk management activities should no longer be marked to market pursuant to Issue No. 98-10. Rather, energy trading and risk management activities that qualify as derivative contracts pursuant to SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, will be recognized as assets and liabilities at fair value and energy trading and risk management activities that do not qualify as derivative contracts will be treated as executory contracts and recognized pursuant to the accrual method of accounting (i.e., when cash becomes due and payable to us or our customers pursuant to the terms of the contracts). That consensus also concluded that all physical inventories, including inventory volumes associated with energy trading activities, be carried at the lower of cost or market pursuant to Accounting Research Bulletin (“ARB”) No. 43, Chapter 4—Inventory Pricing. The consensus is effective for new energy trading and risk management activities commencing after October 25, 2002. Effective January 1, 2003 all energy trading and risk management activities that commenced on or before October 25, 2002, will be required to be adjusted through a cumulative effect adjustment retroactive to July 1, 2002. Therefore, we may be recasting our financial position and results of operations for the three months ended September 30, 2002 and the three months ending December 31, 2002 to adopt the new accounting requirements when we report our results for the three and nine months ending March 31, 2003. We currently are unable to determine the impact that the new accounting requirements will have on our financial position or results of operations due to (i) the complexities of determining which of our energy trading and risk management activities qualify as executory contracts or derivative contracts, (ii) whether any of the derivative contracts would qualify as “fair value” hedges of our inventories—discretionary volumes, and (iii) whether our inventories—discretionary volumes would qualify for the exception in ARB 43 to be carried at fair value. In the event that the new accounting requirements do not permit us to carry our inventories—discretionary volumes at fair value, we likely will recognize significant non-cash gains and losses associated with our risk management contracts that hedge those inventory volumes, resulting in significant fluctuations between periods in our reported net revenues attributable to our Product supply, distribution, and marketing operations.

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 for the year ended June 30, 2002, in addition to the interim consolidated financial statements and accompanying notes presented in Items 1 and 2 of this Quarterly Report on Form 10-Q.

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

ITEM 4.

CONTROLS AND PROCEDURES

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

PART II. OTHER INFORMATION

ITEM 6.

EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits:

3.2	Amended and Restated By-Laws of TransMontaigne Inc. as of October 1, 2002. FILED HEREWITH

10.1	Change in Control Agreement between TransMontaigne Inc. and Donald H. Anderson dated April 12, 2001. FILED HEREWITH

10.2	Change in Control Agreement between TransMontaigne Inc. and Erik B. Carlson dated April 12, 2001. FILED HEREWITH

10.3	Change in Control Agreement between TransMontaigne Inc. and Larry F. Clynch dated April 12, 2001. FILED HEREWITH

10.4	Change in Control Agreement between TransMontaigne Inc. and William S. Dickey dated April 12, 2001. FILED HEREWITH

10.5	Change in Control Agreement between TransMontaigne Inc. and Harold R. Logan, Jr. dated April 12, 2001. FILED HEREWITH

10.6	Change in Control Agreement between TransMontaigne Inc. and Randall J. Larson dated May 1, 2002. FILED HEREWITH

99.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. FILED HEREWITH

99.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. FILED HEREWITH

(b) Reports on Form 8-K:

A Current Report on Form 8-K filed on July 15, 2002 contained disclosures under Item 5, Other Events, and Item 7, Exhibits.

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: November 14, 2002			TRANSMONTAIGNE INC. (Registrant)
			/s/ DONALD H. ANDERSON

			Donald H. Anderson President, Chief Executive Officer, Chief Operating Officer and Vice Chairman


			/s/ HAROLD R. LOGAN, JR.

			Harold R. Logan, Jr. Executive Vice President, Chief Financial Officer and Treasurer

CERTIFICATIONS

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

	1.		I have reviewed this quarterly report on Form 10–Q of TransMontaigne Inc. (“Registrant”);

	2.		Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

	3.		Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this quarterly report;

	4.		The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a–14 and 15d–14) for the Registrant and we have:

	a)		designed such disclosure controls and procedures to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

	b)		evaluated the effectiveness of the Registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

	c)		presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the Registrant’s auditors and the audit committee of Registrant’s board of directors (or persons performing the equivalent function):

	a)		all significant deficiencies in the design or operation of internal controls which could adversely affect the Registrant’s ability to record, process, summarize and report financial data and have identified for the Registrant’s auditors any material weaknesses in internal controls; and

	b)		any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal controls; and

The Registrant’s other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.


Date: November 14, 2002			/s/ DONALD H. ANDERSON

			Donald H. Anderson President, Chief Executive Officer, Chief Operating Officer and Vice Chairman

I, Harold R. Logan, Jr, Executive Vice President, Chief Financial Officer and Treasurer of TransMontaigne Inc., certify that:

	1.		I have reviewed this quarterly report on Form 10–Q of TransMontaigne Inc. (“Registrant”);

	2.		Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

	3.		Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this quarterly report;

	4.		The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a–14 and 15d–14) for the Registrant and we have:

	a)		designed such disclosure controls and procedures to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

	b)		evaluated the effectiveness of the Registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

	c)		presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

	a)		all significant deficiencies in the design or operation of internal controls which could adversely affect the Registrant’s ability to record, process, summarize and report financial data and have identified for the Registrant’s auditors any material weaknesses in internal controls; and

	b)		any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal controls; and


Date: November 14, 2002			/s/ HAROLD R. LOGAN, JR.

			Harold R. Logan, Jr. Executive Vice President, Chief Financial Officer and Treasurer

Exhibit Index

3.2	Amended and Restated By-Laws of TransMontaigne Inc. as of October 1, 2002. FILED HEREWITH

10.1	Change in Control Agreement between TransMontaigne Inc. and Donald H. Anderson dated April 12, 2001. FILED HEREWITH

10.2	Change in Control Agreement between TransMontaigne Inc. and Erik B. Carlson dated April 12, 2001. FILED HEREWITH

10.3	Change in Control Agreement between TransMontaigne Inc. and Larry F. Clynch dated April 12, 2001. FILED HEREWITH

10.4	Change in Control Agreement between TransMontaigne Inc. and William S. Dickey dated April 12, 2001. FILED HEREWITH

10.5	Change in Control Agreement between TransMontaigne Inc. and Harold R. Logan, Jr. dated April 12, 2001. FILED HEREWITH

10.6	Change in Control Agreement between TransMontaigne Inc. and Randall J. Larson dated May 1, 2002. FILED HEREWITH

99.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. FILED HEREWITH

99.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. FILED HEREWITH

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents