Edgar Filing: TRANSMONTAIGNE INC

Form 10-Q

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 December 31, 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

06-1052062

(State or other jurisdiction of

incorporation or organization)

(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 ¨

As of February 3, 2003 there were 40,550,169 shares of the Registrant’s Common Stock outstanding.

TABLE OF CONTENTS

		Page No.
PART I. FINANCIAL INFORMATION

Item 1. Unaudited Consolidated Financial Statements		3

Consolidated Balance Sheets as of December 31, 2002 and June 30, 2002		4

Consolidated Statements of Operations for the Three Months and Six Months Ended December 31, 2002 and 2001		5

Consolidated Statements of Preferred Stock and Common Stockholders’ Equity for the Year Ended June 30, 2002 and Six Months Ended December 31, 2002		7

Consolidated Statements of Cash Flows for the Three Months and Six Months Ended December 31, 2002 and 2001		8

Notes to Consolidated Financial Statements		10

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		27

Item 3. Qualitative and Quantitative Disclosures about Market Risk		46

Item 4. Controls and Procedures		46

PART II. OTHER INFORMATION

Item 4. Submission of Matters to a Vote of Security Holders		47

Item 6. Exhibits and Reports on Form 8-K		47

SIGNATURES		48

CERTIFICATIONS		49

PART I. FINANCIAL INFORMATION

ITEM 1. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

The interim consolidated financial statements of TransMontaigne Inc. as of and for the three months and six months ended December 31, 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 and six months ended December 31, 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

(In thousands)

	December 31, 2002			June 30, 2002
ASSETS
Current assets:
Cash and cash equivalents	$	5,964		30,852
Restricted cash held by commodity broker		41,100		4,577
Trade accounts receivable, net		211,531		173,736
Inventories—discretionary volumes		225,676		175,169
Unrealized gains on energy services and risk management contracts		47,895		26,334
Prepaid expenses and other		3,504		2,598

		535,670		413,266

Property, plant and equipment, net		248,288		251,431
Inventories—minimum volumes		45,298		45,298
Unrealized gains on energy services and risk management contracts		12,711		13,969
Investments in petroleum related assets		10,131		10,131
Deferred tax assets		17,311		7,882
Deferred debt issuance costs, net		2,340		2,729
Other assets		4,203		4,263

	$	875,952		748,969

LIABILITIES, PREFERRED STOCK, AND COMMON STOCKHOLDERS’ EQUITY
Current liabilities:
Commodity margin loan	$	9,841		11,312
Trade accounts payable		171,334		102,780
Unrealized losses on energy services and risk management contracts		72,891		22,163
Inventory due under exchange agreements		23,091		16,908
Excise taxes payable		77,003		72,045
Other accrued liabilities		19,888		24,242
Deferred revenue—energy services		5,523		1,600

		379,571		251,050
Other liabilities:
Long-term debt		200,000		187,000
Unrealized losses on energy services and risk management contracts		2,523		209

Total liabilities		582,094		438,259

Preferred stock:
Series A Convertible Preferred stock		24,421		24,421
Series B Redeemable Convertible Preferred stock		80,134		80,939

		104,555		105,360

Common stockholders’ equity:
Common stock		406		399
Capital in excess of par value		248,827		245,844
Deferred stock-based compensation		(4,725	)	(2,540	)
Accumulated deficit		(55,205	)	(38,353	)

		189,303		205,350

	$	875,952		748,969

See accompanying notes to consolidated financial statements.

TRANSMONTAIGNE INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

	Three Months Ended December 31,					Six Months Ended December 31,
	2002			2001		2002		2001
Net revenue from Product supply, distribution, and marketing:
Revenue, net of Product costs, before effects of gains on inventories-discretionary volumes	$	13,343		13,729		20,955		41,328
Gains recognized on beginning inventories-discretionary volumes		12,644		—		12,644		—
Gains deferred on ending inventories-discretionary volumes		(33,490	)	—		(33,490	)	—

Net revenue		(7,503	)	13,729		109		41,328

Lower of cost or market write-downs on inventories-minimum volumes		—		12,114		—		12,963

Net operating margin		(7,503	)	1,615		109		28,365

Terminal and pipelines
Revenue from storage and throughput		17,265		15,175		34,660		30,691
Direct operating costs and expenses		(6,520	)	(6,662	)	(12,987	)	(13,837	)

Net operating margin		10,745		8,513		21,673		16,854


Total net operating margins		3,242		10,128		21,782		45,219


Costs and expenses:
Selling, general and administrative		8,775		8,185		18,106		16,650
Depreciation and amortization		4,293		4,024		8,549		8,306
Corporate relocation and transition		365		—		1,449		—

		13,433		12,209		28,104		24,956

Operating income (loss)		(10,191	)	(2,081	)	(6,322	)	20,263


Other income (expense):
Dividend income from and equity in earnings of petroleum related investments		—		108		374		1,457
Interest income		99		159		168		423
Interest expense		(3,066	)	(2,918	)	(6,359	)	(5,971	)
Other financing costs:
Amortization of debt issuance costs		(233	)	(456	)	(462	)	(920	)
Unrealized gain (loss) on interest rate swap		1,199		447		1,274		(3,165	)
Loss on disposition of assets, net		—		—		—		(1,295	)

		(2,001	)	(2,660	)	(5,005	)	(9,471	)


Earnings (loss) before income taxes and cumulative effect of a change in accounting principle		(12,192	)	(4,741	)	(11,327	)	10,792
Income tax (expense) benefit		4,633		1,801		4,304		(4,101	)

Net earnings (loss) before cumulative effect of a change in accounting principle		(7,559	)	(2,940	)	(7,023	)	6,691
Cumulative effect of change in accounting principle of $12,644, net of income tax benefit of $4,805		(7,839	)	—		(7,839	)	—

Net earnings (loss)		(15,398	)	(2,940	)	(14,862	)	6,691
Preferred stock dividends		(995	)	(2,437	)	(1,990	)	(4,841	)

Net earnings (loss) attributable to common stockholders	$	(16,393	)	(5,377	)	(16,852	)	1,850

See accompanying notes to consolidated financial statements.

TRANSMONTAIGNE INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS—(Continued)

(In thousands, except per share amounts)

	Three Months Ended December 31,					Six Months Ended December 31,
	2002			2001		2002		2001
Net earnings (loss) after preferred stock dividends and before cumulative effect of a change in accounting principle	$	(8,554	)	(5,377	)	(9,013	)	1,850
Cumulative effect of a change in accounting principle		(7,839	)	—		(7,839	)	—

Net earnings (loss) attributable to common stockholders	$	(16,393	)	(5,377	)	(16,852	)	1,850

Basic net earnings (loss) per common share:
Net earnings (loss) after preferred stock dividends and before cumulative effect of a change in accounting principle	$	(0.22	)	(0.17	)	(0.23	)	0.06
Cumulative effect of a change in accounting principle		(0.20	)	—		(0.20	)	—

	$	(0.42	)	(0.17	)	(0.43	)	0.06

Diluted net earnings (loss) per common share:
Net earnings (loss) after preferred stock dividends and before cumulative effect of a change in accounting principle	$	(0.22	)	(0.17	)	(0.23	)	0.06
Cumulative effect of a change in accounting principle		(0.20	)	—		(0.20	)	—

	$	(0.42	)	(0.17	)	(0.43	)	0.06

Weighted average common shares outstanding:
Basic		39,127		31,201		39,079		31,176

Diluted		39,127		31,201		39,079		31,534

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 Six Months Ended December 31, 2002

(In thousands)

	Preferred stock					Common stock			Capital in excess of par value		Deferred stock-based compensation		Retained earnings (accumulated deficit)		Total common stockholders’ equity
	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 exercise		—		—			—		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		—		—			—		(161	)	—		—		(161	)
Net tax effect arising from stock-based compensation		—		—			—		97		—		—		97
Forfeiture of restricted stock awards prior to vesting		—		—			—		(225	)	225		—		—
Deferred compensation related to restricted stock awards		—		—			7		3,001		(3,008	)	—		—
Deferred compensation related to non-employee stock options		—		—			—		260		(260	)	—		—
Amortization of deferred stock-based compensation		—		—			—		—		858		—		858
Preferred stock dividends		—		—			—		—		—		(2,795	)	(2,795	)
Amortization of premium on Series B Redeemable Convertible Preferred stock		—		(805	)		—		—		—		805		805
Net loss		—		—			—		—		—		(14,862	)	(14,862	)

Balance at December 31, 2002	$	24,421		80,134		$	406		248,827		(4,725	)	(55,205	)	189,303

See accompanying notes to consolidated financial statements.

TRANSMONTAIGNE INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Three Months Ended December 31,					Six Months Ended December 31,
	2002			2001		2002		2001
Cash flows from operating activities:
Net earnings (loss)	$	(15,398	)	(2,940	)	(14,862	)	6,691
Adjustments to reconcile net earnings to net cash provided (used) by operating activities:
Depreciation and amortization		4,293		4,024		8,549		8,306
Equity in earnings of petroleum related investments		—		14		—		(7	)
Deferred tax expense (benefit)		(9,672	)	(2,353	)	(9,428	)	3,502
Net tax effect arising from stock-based compensation		33		24		97		(19	)
Loss on disposition of assets, net		—		—		—		1,295
Amortization of deferred stock-based compensation		457		453		858		766
Amortization of debt issuance costs		233		456		462		920
Unrealized (gain) loss on interest rate swap		(1,199	)	(447	)	(1,274	)	3,165
Net change in unrealized gains/losses on long-term energy services and risk management contracts		2,899		(633	)	3,573		1,978
Lower of cost or market write-down on minimum inventory volumes		—		12,114		—		12,963
Changes in operating assets and liabilities, net of non-cash activities:
Trade accounts receivable, net		(11,842	)	(27,576	)	(37,795	)	(57,359	)
Inventories—discretionary volumes		(45,432	)	(71,037	)	(50,506	)	(60,664	)
Prepaid expenses and other		(910	)	(9	)	(906	)	261
Trade accounts payable		32,781		76,324		68,553		60,832
Inventory due under exchange agreements		(10,833	)	(58,218	)	6,183		(76,754	)
Unrealized (gain) loss on energy services and risk management contracts		11,174		(22,115	)	29,167		(8,841	)
Excise taxes payable and other accrued liabilities		17,101		32,306		4,708		19,670

Net cash provided (used) by operating activities		(26,315	)	(59,613	)	7,379		(83,295	)

Cash flows from investing activities:
Purchases of property, plant and equipment		(3,426	)	(765	)	(5,406	)	(1,110	)
Proceeds from sales of assets		—		23,128		—		117,237
Decrease (increase) in restricted cash held by commodity broker		(30,834	)	—		(36,523	)	7,984
(Decrease) increase in other assets		(2	)	(1,777	)	59		(1,626	)

Net cash provided (used) by investing activities		(34,262	)	20,586		(41,870	)	122,485

Cash flows from financing activities:
Net borrowings (repayments) of long-term debt		60,000		37,000		13,000		(4,000	)
Net repayments of commodity margin loan		(7,245	)	—		(1,470	)	—
Deferred debt issuance costs		(44	)	—		(73	)	—
Common stock issued for options exercised		—		—		11		30
Common stock repurchased from employees for withholding taxes		(111	)	(71	)	(161	)	(71	)
Preferred stock dividends paid in cash		(1,704	)	—		(1,704	)	—

Net cash provided (used) by financing activities		50,896		36,929		9,603		(4,041	)

Increase (decrease) in cash and cash equivalents		(9,681	)	(2,098	)	(24,888	)	35,149
Cash and cash equivalents at beginning of period		15,645		46,593		30,852		9,346

Cash and cash equivalents at end of period	$	5,964		44,495		5,964		44,495

See accompanying notes to consolidated financial statements.

TRANSMONTAIGNE INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS—(Continued)

(In thousands)

	Three Months Ended December 31,			Six Months Ended December 31,
	2002		2001	2002	2001
Supplemental disclosures of cash flow information:
Sale of West Shore shares on July 27, 2001 and October 29, 2001:
Investment in West Shore	$	—	23,128	—	35,952
Loss on disposition		—	—	—	(9,896	)

Cash received from sale	$	—	23,128	—	26,056

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

Cash received from sale	$	—	—	—	61,750
Other cash sales:
Cash received from sale of Little Rock facilities on June 30, 2001	$	—	—	—	29,033

Cash received from sales of other assets	$	—	—	—	398

Total cash received from sales of assets	$	—	23,128	—	117,237

See accompanying notes to consolidated financial statements.

TRANSMONTAIGNE INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 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 (for periods as of and prior to October 1, 2002) 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 in the United States primarily in the Mid-Continent, Gulf Coast, Southeast, Mid-Atlantic and Northeast regions. We provide 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

TRANSMONTAIGNE INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

accompanying consolidated balance sheet) our inventories—discretionary volumes (for periods as of and prior to October 1, 2002), energy services contracts, and risk management contracts. Changes in the fair value of our inventories—discretionary volumes (for periods as of and prior to October 1, 2002), energy services contracts, and risk management contracts are included in net revenues attributable to our Product supply, distribution, and marketing operations in the period of the change in value.

On October 25, 2002, the EITF reached a consensus on EITF 02-03, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities, that energy trading and risk management activities should no longer be marked to market pursuant to the guidance in EITF 98-10. Thus, the consensus on EITF 02-03 rescinded the guidance in EITF 98-10. The consensus on EITF 02-03 states that energy trading and risk management activities that qualify as derivative contracts pursuant to Statement of Financial Accounting Standards No. 133 (“SFAS No. 133”), Accounting for Derivative Instruments and Hedging Activities, be recognized as assets and liabilities at fair value. 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). Under SFAS No. 133, a derivative instrument is a financial instrument or other contract with all three of the following characteristics:

It has one or more underlyings (e.g., specified interest rate, security price, commodity price, index of prices or rates), and one or more notional amounts (e.g., number of currency units, shares, or other units specified in the contract) or payment provisions or both;

It requires no initial net investment or an initial net investment that is smaller than would be required for other types of contracts that would be expected to have a similar response to changes in market factors; and

Its terms require or permit net settlement, it can readily be settled net by a means outside the contract, or it provides delivery of an asset that puts the recipient in a position not substantially different from net settlement.

EITF 02-03 also concluded that all physical inventories, including inventory volumes associated with energy trading activities, be carried at the lower of cost or market pursuant to Accounting Research Bulletin (“ARB”) No. 43, Chapter 4—Inventory Pricing. The consensus is effective for new energy trading and risk management transactions initiated after October 25, 2002.

As a result of the consensus reached on EITF 02-03, we will no longer be permitted to carry our inventories—discretionary volumes at fair value effective October 1, 2002. The excess of the fair value of our inventories—discretionary volumes over their cost basis as of October 1, 2002 has been reflected in the accompanying consolidated statement of operations as a cumulative effect of a change in accounting principle. Our energy services and risk management contracts will continue to be marked to market (i.e., recorded at fair value in the accompanying consolidated balance sheet) because those contracts qualify as derivative instruments pursuant to the requirements of SFAS No. 133.

TRANSMONTAIGNE INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Our revenues from energy trading and risk management activities are presented in the accompanying consolidated statement of operations on a net basis (i.e., product costs are netted directly against gross revenues to arrive at net revenues). Product costs represent the cost of the Products sold, settlement of risk management contracts, transportation, storage, terminaling costs, and commissions. Net revenues attributable to our Product supply, distribution, and marketing operations are as follows (in thousands):

	Three Months Ended December 31,					Six Months Ended December 31,
	2002			2001		2002		2001
Gross revenues	$	2,003,212		1,148,936		3,729,710		2,676,554
Less cost of revenues		(2,010,715	)	(1,135,207	)	(3,729,601	)	(2,635,226	)

Net revenues	$	(7,503	)	13,729		109		41,328

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

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 based on commodity prices, stipulated volumes of Product, permit net settlement for differences between actual and stipulated volumes, and do not require an initial net investment. Therefore, our energy services contracts qualify as derivative instruments pursuant to SFAS No. 133. 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 December 31, 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 based on commodity prices, stipulated volumes of Product, permit net settlement for differences between actual and stipulated volumes, and do not require an initial net investment. Therefore, our risk management contracts qualify as derivative instruments pursuant to SFAS No. 133. Our risk management contracts are carried at fair value in the accompanying consolidated 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. Prior to October 1, 2002, our inventories—discretionary volumes were carried at fair value with the

TRANSMONTAIGNE INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

changes in the fair value included in net revenues attributable to our Product supply, distribution and marketing operations. Effective October 1, 2002, we adjusted the carrying amount of our inventories—discretionary volumes to the lower of cost or market pursuant to the requirements of EITF 02-03 through a cumulative effect adjustment for a change in accounting principle. The cumulative effect adjustment is presented in the accompanying consolidated statement of operations and is calculated as follows:


Inventories—discretionary volumes:
Fair value at October 1, 2002	$	180,241
Cost basis at October 1, 2002		(167,597	)

Excess of fair value over cost basis		12,644
Income tax effects at 38%		(4,805	)

Cumulative effect of a change in accounting principle	$	7,839

The risk management contracts entered into by us to minimize our risk to commodity price changes associated with our discretionary inventory volumes currently do not qualify as “fair value hedges” for financial reporting purposes. Therefore, at December 31, 2002, our inventories—discretionary volumes are recorded in the accompanying consolidated balance sheet at the lower of cost (first-in, first-out) or market (replacement cost).

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

TRANSMONTAIGNE INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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.

(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 December 31, 2001, we recognized dividend income from West Shore of approximately $0.1 million. For the six months ended December 31, 2001, we recognized dividend income from West Shore of approximately $0.7 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

TRANSMONTAIGNE INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

petroleum products pipeline between Mount Vernon, Missouri and Rogers, Arkansas with approximately 0.4 million barrels of storage capacity.

On July 31, 2002, we acquired for cash consideration of approximately $0.6 million a Products terminal in Brownsville, Texas. The 25,000-barrel terminal provides us with additional storage and rail car handling facilities in Brownsville, Texas.

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

	December 31, 2002			June 30, 2002
Trade accounts receivable	$	213,397		174,986
Less allowance for doubtful accounts		(1,866	)	(1,250	)

	$	211,531		173,736

(5) Inventories—Discretionary Volumes

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

	December 31, 2002		June 30, 2002
Products held for sale or exchange	$	202,585	158,261
Products due to others under exchange agreements		23,091	16,908

Inventories—discretionary volumes	$	225,676	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. Our inventories—discretionary volumes are presented in the accompanying consolidated balance sheet as current assets and are carried at the lower of cost or market at December 31, 2002 and at fair value at June 30, 2002. Products due to others under

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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 December 31, 2002 and June 30, 2002, we held for sale or exchange approximately 6.5 million and 5.2 million barrels of discretionary inventory, net of 0.7 million and 0.5 million barrels due under exchange agreements, at a weighted average fair value of approximately $0.87 (cost basis of $0.75) and $0.72 per gallon, respectively. At December 31, 2002, the fair value of our inventories—discretionary volumes exceeded their cost basis by approximately $33.5 million.

(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):

	December 31, 2002			June 30, 2002
Unrealized gains—current	$	47,895		26,334
Unrealized gains—long-term		12,711		13,969

Unrealized gains—asset		60,606		40,303

Unrealized losses—current		(72,891	)	(22,163	)
Unrealized losses—long-term		(2,523	)	(209	)

Unrealized losses—liability		(75,414	)	(22,372	)

Net asset (liability) position	$	(14,808	)	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):

	December 31, 2002			June 30, 2002
Land	$	14,125		14,125
Terminals, pipelines, and equipment		281,963		276,559
Technology and equipment		13,212		12,645
Furniture, fixtures, and equipment		6,002		5,732
Construction in progress		2,456		3,291

		317,758		312,352
Less accumulated depreciation		(69,470	)	(60,921	)

	$	248,288		251,431

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(8) Inventories—Minimum Volumes

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

	December 31, 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 December 31, 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 December 31, 2001, we recognized an impairment loss of approximately $12.1 million due to lower of cost or market write-downs on our inventories—minimum volumes. During the six months ended December 31, 2001, we recognized an impairment loss of approximately $13.0 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):

	December 31, 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 15 of Notes to Consolidated Financial Statements).

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(10) Accrued Liabilities

Accrued liabilities are as follows (in thousands):

	December 31, 2002		June 30, 2002
Interest rate swap, at fair value	$	4,155	5,429
Accrued environmental obligations		2,096	2,329
Accrued corporate relocation and transition		1,023	2,029
Accrued lease abandonment		3,014	3,110
Accrued indemnities—NORCO		1,300	1,300
Accrued transportation and deficiency obligations		2,819	2,839
Accrued expenses		2,383	5,080
Dividend payable—preferred stock		1,093	—
Deposits and other accrued liabilities		2,005	2,126

	$	19,888	24,242

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, 35 employees chose to relocate to Denver, Colorado. Those employees are entitled to receive a transition bonus and a relocation package payable upon transfer to the Denver office. The transition bonus is being accrued over the period from date of acceptance by the employee to the expected date of arrival in Denver, Colorado. The relocation costs are being accrued as incurred/earned by the employee. Ultimately, 37 employees chose not to relocate and those employees are entitled to receive special termination benefits upon their termination date as determined by us. The special termination benefits were accrued upon receipt of the notification from the employee that they did not intend to accept the offer to relocate to Denver, Colorado.

During the three months ended December 31, 2002, we paid special termination benefits to 6 employees and we paid transition bonuses to 6 employees. During the six months ended December 31, 2002, we paid special termination benefits to 17 employees and we paid transition bonuses to 33 employees. We expect to pay the remaining special termination benefits and transition bonuses before March 31, 2003.

	Accrued liability at June 30, 2002		Amounts incurred/accrued during the period	Amounts paid during the period		Accrued liability at December 31, 2002
Accrued special termination benefits to employees not relocating to Denver, Colorado	$	1,428	—	(682	)	746
Accrued transition benefits payable to employees relocating to Denver, Colorado		501	225	(686	)	40
Relocation costs incurred during the period		100	1,224	(1,087	)	237

	$	2,029	1,449	(2,455	)	1,023

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

expect to vacate our existing office space in Denver, Colorado during May 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 December 31, 2002 and June 30, 2002, the accrued liability for lease abandonment costs was approximately $3.0 million and $3.1 million, respectively.

		Accrued liability at June 30, 2002			Amounts paid during the period			Accrued liability at December 31, 2002
Accrued lease abandonment		$	3,110		(96	)		3,014

We expect to pay the accrued liability of approximately $3.0 million, net of estimated sublease rentals, as follows:

	Lease payments		Estimated sublease rentals		Accrued liability
Years ending June 30:
2003	$	649	(97	)	552
2004		991	(562	)	429
2005		1,020	(565	)	455
2006		1,045	(569	)	476
2007		948	(508	)	440
Thereafter		1,243	(581	)	662

	$	5,896	(2,882	)	3,014

(11) Deferred Revenue—Energy Services

In connection with providing fixed-price supply contracts to industrial/commercial end-users, we commit to provide our customers with supply chain management services over the term of their respective supply contracts. At June 30, 2002, our deferred revenue associated with the supply chain management services was approximately $1.6 million. During the three months ended December 31, 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. During the six months ended December 31, 2002, we recognized approximately $300,000 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 December 31, 2002, we originated risk management contracts with an estimated fair value of approximately $3.4 million, 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. During the six months ended December 31, 2002, we originated risk management contracts with an estimated fair value of approximately $4.2 million, 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 December 31, 2002, we deferred the fair value of the contracts because our estimate of the fair value is not evidenced by quoted market prices or current market transactions for the contracts in their

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

entirety. 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 as the Products are delivered to the industrial/commercial end-users.

	Deferred Revenue at June 30, 2002		Additions during the period	Amounts amortized during the period		Deferred Revenue at December 31, 2002
Supply chain management services	$	1,600	—	(300	)	1,300
Risk management contracts		—	4,223	—		4,223

	$	1,600	4,223	(300	)	5,523

(12) Debt

Debt is as follows (in thousands):

	December 31, 2002			June 30, 2002
Commodity margin loan	$	9,841		11,312
Bank credit facility		200,000		187,000

		209,841		198,312
Less current debt		(9,841	)	(11,312	)

Long-term debt	$	200,000		187,000

Commodity Margin Loan. We currently have a commodity margin loan agreement with Salomon Smith Barney that allows us to borrow up to $20.0 million to fund certain initial and variation margin requirements in commodities accounts maintained by us with Salomon Smith Barney. The entire unpaid principal amount of the loan, together with accrued interest, is due and payable on demand. Outstanding loans bear interest at the average 90-day Treasury Bill rate plus 1.75% (2.93% at December 31, 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; $355 million at December 31, 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 December 31, 2002, we were in compliance with all covenants included in the New Facility.

Maturities of debt at December 31, 2002 are as follows (in thousands):


Years ending:
June 30, 2003	$	9,841
June 30, 2004		—
June 30, 2005		200,000

	$	209,841

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(13) Preferred Stock

At December 31, 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):

	December 31, 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	$	80,134	$	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 December 31, 2002 and 2001, respectively. Preferred stock dividends on the Series A Convertible Preferred Stock were $0.6 million and $4.8 million for the six months ended December 31, 2002 and 2001, respectively. Preferred stock dividends on the Series B Redeemable Convertible Preferred stock were $0.7 million for the three months ended December 31, 2002. Preferred stock dividends on the Series B Redeemable Convertible Preferred stock were $1.4 million for the six months ended December 31, 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 and paid to the holders of the Series B Redeemable Convertible Preferred stock of $2.2 million offset by the amortization of the premium on the carrying amount of the Series B Redeemable Convertible Preferred stock of $0.8 million.

(14) Common Stock

At December 31, 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 December 31, 2002 and June 30, 2002, there were 40,550,169 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

TRANSMONTAIGNE INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

compensation of approximately $0.5 million is included in selling, general and administrative expense for the three months ended December 31, 2002 and 2001, respectively. Amortization of deferred compensation of approximately $0.9 million and $0.8 million is included in selling, general and administrative expense for the six months ended December 31, 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.

During the three months ended December 31, 2002, two employees experienced a change in employment status. Following the change in employment status, the former employees began to provide consulting services. Pursuant to the existing terms of our stock option plans, the employees were permitted to retain their original grants of stock options and awards of restricted stock. In accordance with FASB Interpretation No. 44, Accounting for Certain Transactions involving Stock Compensation, we recognized deferred-stock based compensation of approximately $0.3 million, which will be amortized to income over their respective vesting periods. The deferred-stock based compensation was calculated using the Black-Scholes model and the unvested portion of the original grants at the date of change in employment status.

(15) 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 six months ended December 31, 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 December 31, 2002, we recorded an additional $0.2 million resulting in an accrued liability of $1.0 million as of and for the six months ended December 31, 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 (see Note 9 of Notes to Consolidated Financial Statements) and our accrued liability, representing our estimate of the future payments we expect to pay for the estimated shortfall in volumes for the remainder of the terms of the T&D agreements, is approximately $1.8 million (see Note 10 of Notes to Consolidated Financial Statements). Based on actual volumes shipped during the six months ended December 31, 2002, we made no adjustments to the prepaid transportation or accrued liability as of and for the six months ended December 31, 2002.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(16) Earnings Per Share

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

	Three Months Ended December 31,		Six Months Ended December 31,
	2002	2001	2002	2001
Basic weighted average shares	39,127	31,201	39,079	31,176
Effect of dilutive securities:
Restricted common stock subject to continuing vesting requirements	—	—	—	89
Stock options	—	—	—	269
Common stock issuable upon conversion of:
Series A Convertible Preferred stock	—	—	—	—
Series B Redeemable Convertible Preferred stock	—	—	—	—

Diluted weighted average shares	39,127	31,201	39,079	31,534

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 six months ended December 31, 2002, as their inclusion would have been anti-dilutive:

		Six Months Ended December 31, 2002
Restricted common stock subject to continuing vesting requirements		1,414,279
Common stock issuable upon exercise of stock options		1,238,000
Common stock issuable upon exercise of stock purchase warrants		900,045
Common stock issuable upon conversion of:
Series A Convertible Preferred stock		1,628,082
Series B Redeemable Convertible Preferred stock		11,043,928

		16,224,334

For the three and six months ended December 31, 2002, all potentially dilutive securities were excluded because we reported a net loss attributable to common stockholders for those periods. For the three and six months ended December 31, 2002, the stock options had a weighted average exercise price of $4.70 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.

(17) Business Segments

We provide 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

TRANSMONTAIGNE INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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 December 31, 2002
	Product supply, distribution, and marketing			Terminals and pipelines		Corporate		Total consolidated
Revenue, net of Product costs, before effects of gains on inventories-discretionary volumes	$	13,343		—		—		13,343
Gains recognized on beginning inventories-discretionary volumes		12,644		—		—		12,644
Gains deferred on ending inventories-discretionary volumes		(33,490	)	—		—		(33,490	)
Revenue from storage and throughput		—		8,170		—		8,170
Inter-segment revenues		—		9,095		—		9,095

Revenues, net		(7,503	)	17,265		—		9,762
Direct operating costs and expenses		—		(6,520	)	—		(6,520	)

Net operating margins		(7,503	)	10,745		—		3,242
Selling, general and administrative		(4,853	)	(2,028	)	(1,894	)	(8,775	)
Depreciation and amortization		(276	)	(3,797	)	(220	)	(4,293	)
Corporate relocation and transition		(365	)	—		—		(365	)

		(5,494	)	(5,825	)	(2,114	)	(13,433	)

Operating income (loss)	$	(12,997	)	4,920		(2,114	)	(10,191	)

Capital expenditures	$	433		2,694		299		3,426

TRANSMONTAIGNE INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

	Three Months Ended December 31, 2001
	Product supply, distribution, and marketing			Terminals and pipelines		Corporate		Total consolidated
Revenues from external customers	$	13,729		7,279		—		21,008
Inter-segment revenues		—		7,896		—		7,896

Revenues, net		13,729		15,175		—		28,904
Lower of cost or market write-downs on inventories-minimum volumes		(12,114	)	—		—		(12,114	)
Direct operating costs and expenses		—		(6,662	)	—		(6,662	)

Net operating margins		1,615		8,513		—		10,128
Selling, general and administrative		(4,733	)	(1,744	)	(1,708	)	(8,185	)
Depreciation and amortization		—		(3,499	)	(525	)	(4,024	)

		(4,733	)	(5,243	)	(2,233	)	(12,209	)

Operating income (loss)	$	(3,118	)	3,270		(2,233	)	(2,081	)

Capital expenditures	$	—		630		135		765

	Six Months Ended December 31, 2002
	Product supply, distribution, and marketing			Terminals and pipelines		Corporate		Total consolidated
Revenue, net of Product costs, before effects of gains on inventories-discretionary volumes	$	20,955				—		20,955
Gains recognized on beginning inventories-discretionary volumes		12,644				—		12,644
Gains deferred on ending inventories-discretionary volumes		(33,490	)			—		(33,490	)
Revenue from storage and throughput		—		16,409		—		16,409
Inter-segment revenues		—		18,251		—		18,251

Revenues, net		109		34,660		—		34,769
Direct operating costs and expenses		—		(12,987	)	—		(12,987	)

Net operating margins		109		21,673		—		21,782
Selling, general and administrative		(10,140	)	(4,219	)	(3,747	)	(18,106	)
Depreciation and amortization		(534	)	(7,580	)	(435	)	(8,549	)
Corporate relocation and transition		(1,449	)	—		—		(1,449	)

		(12,123	)	(11,799	)	(4,182	)	(28,104	)

Operating income (loss)	$	(12,014	)	9,874		(4,182	)	(6,322	)

Capital expenditures	$	433		4,674		299		5,406

TRANSMONTAIGNE INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

	Six Months Ended December 31, 2001
	Product supply, distribution, and marketing			Terminals and pipelines		Corporate		Total consolidated
Revenues from external customers	$	41,328		15,321		—		56,649
Inter-segment revenues		—		15,370		—		15,370

Revenues, net		41,328		30,691		—		72,019
Lower of cost or market write-downs on inventories-minimum volumes		(12,963	)	—		—		(12,963	)
Direct operating costs and expenses		—		(13,837	)	—		(13,837	)

Net operating margins		28,365		16,854		—		45,219
Selling, general and administrative		(9,916	)	(3,632	)	(3,102	)	(16,650	)
Depreciation and amortization		—		(7,259	)	(1,047	)	(8,306	)
Corporate relocation and transition		—		—		—		—

		(9,916	)	(10,891	)	(4,149	)	(24,956	)

Operating income (loss)	$	18,449		5,963		(4,149	)	20,263

Capital expenditures	$	62		913		135		1,110

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 in the United States primarily in the Mid-Continent, Gulf Coast, Southeast, Mid-Atlantic and Northeast regions. 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 supply and market various Products and provide specialized supply, logistical, and risk management services to our customers.

Product Supply, Distribution, and Marketing Operations

Our product supply, distribution and marketing operations are composed of 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.

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 our 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 our 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 December 31, 2002 and 2001, we averaged approximately 121,000 and 101,000 barrels per day, respectively, of delivered volumes under daily-priced rack sales. For the six months ended December 31, 2002 and 2001, we averaged approximately 122,000 and 88,000 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 December 31, 2002 and 2001, we averaged approximately 98,000 and 110,000 barrels per day, respectively, of delivered volumes under exchange agreements. For the six months ended December 31, 2002 and 2001, we averaged approximately 98,000 and 126,000 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 December 31, 2002 and 2001, we averaged approximately 420,000 and 309,000 barrels per day, respectively, of delivered volumes under bulk and cycle sales. For the six months ended December 31, 2002 and 2001, we averaged approximately 448,000 and 336,000 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 December 31, 2002 and 2001, we averaged approximately 105,000 and 86,000 barrels per day, respectively, of

delivered volumes under contract sales. For the six months ended December 31, 2002 and 2001, we averaged approximately 101,000 and 80,000 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 in Emerging Issues Task Force No. 98-10 (“EITF 98-10”), Accounting for Contracts Involved in Energy Trading and Risk Management Activities. Our energy trading and risk management activities are composed of our inventories—discretionary volumes, energy services contracts, and risk management contracts. In accordance with the guidance in EITF 98-10, we mark to market (i.e., record at fair value in the accompanying consolidated balance sheet) our inventories—discretionary volumes (for periods as of and prior to October 1, 2002) , energy services contracts, and risk management contracts. Changes in the fair value of our inventories—discretionary volumes (for periods as of and prior to October 1, 2002) , energy services contracts, and risk management contracts are included in net revenues attributable to our Product supply, distribution, and marketing operations in the period of the change in value.

On October 25, 2002, the EITF reached a consensus on EITF 02-03, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities, that energy trading and risk management activities should no longer be marked to market pursuant to the guidance in EITF 98-10. Thus, the consensus on EITF 02-03 rescinded the guidance in EITF 98-10. The consensus on EITF 02-03 states that energy trading and risk management activities that qualify as derivative contracts pursuant to Statement of Financial Accounting Standards No. 133 (“SFAS No. 133”), Accounting for Derivative Instruments and Hedging Activities, be recognized as assets and liabilities at fair value. 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). EITF 02-03 also concluded that all physical inventories, including inventory volumes associated with energy trading activities, be carried at the lower of cost or market pursuant to Accounting Research Bulletin (“ARB”) No. 43, Chapter 4—Inventory Pricing. The consensus is effective for new energy trading and risk management transactions initiated after October 25, 2002.

As a result of the consensus reached on EITF 02-03, we will no longer be permitted to carry our inventories—discretionary volumes at fair value effective October 1, 2002. Our energy services and risk management contracts will continue to be marked to market (i.e., recorded at fair value in the accompanying consolidated balance sheet) because those contracts qualify as derivative instruments pursuant to the requirements of SFAS No. 133. The risk management contracts entered into by us to minimize our risk to commodity price changes associated with our discretionary inventory volumes do not currently qualify as “fair value hedges” for financial reporting purposes. Therefore, at December 31, 2002, our inventories—discretionary volumes are recorded in the accompanying consolidated balance sheet at the lower of cost (first-in, first-out) or market (replacement cost). The excess of the fair value of our inventories—discretionary volumes over their cost basis as of October 1, 2002 has been reflected in the accompanying consolidated statement of operations as a cumulative effect adjustment for a change in accounting principle. The change in accounting for our discretionary inventory volumes will create volatility in our reported net operating margins.

During a period of rising commodity prices, our risk management contracts (i.e., “short futures”) that minimize our risk to commodity price changes associated with our discretionary inventory volumes will decline in value resulting in a loss. The loss is reflected as a reduction of our net revenues attributable to our Product

supply, distribution, and marketing operations in the period of the decline in value. Prior to October 1, 2002, that reduction in net revenues was offset by an increase in the fair value of the discretionary inventory volumes due to rising commodity prices. Subsequent to October 1, 2002, the increase in the value of the discretionary inventory volumes above their cost basis will be recognized in net revenues attributable to our Product supply, distribution, and marketing operations in the period that the discretionary inventory volumes are sold to customers.

During a period of declining commodity prices, the gains on risk management contracts will be recognized in the same period as the impairment losses on the discretionary inventory volumes (the impairment losses are the result of lower of cost or market adjustments to the inventory volumes).

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 December 31, 2002, we held approximately 3.1 million barrels in our terminals for future delivery.

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 December 31, 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 and six months ended December 31, 2002, we averaged approximately

480,000 barrels per day of throughput and storage volumes at our terminals. For the three months and six months ended December 31, 2001, we averaged approximately 500,000 and 508,000 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 December 31, 2002 and 2001, we averaged approximately 25,000 and 17,000 barrels per day, respectively, of transported volumes through our pipelines. For the six months ended December 31, 2002 and 2001, we averaged approximately 26,000 and 25,000 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 (for periods as of and prior to October 1, 2002) 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.

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 17th 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 17th Street and join our Product supply, distribution, and marketing operations at 1670 Broadway during May 2003.

On January 14, 2003, we announced the purchase of the Florida petroleum terminals and tug and barge operations from El Paso Corporation. The transaction has an estimated value of $155 million, including an

estimated $35 million of product inventory value at closing. Closing of the transaction is expected in the first quarter of 2003 and is subject to customary regulatory approvals. The Florida petroleum terminals provide bunker fuel, residual fuel, diesel and gasoline at Jacksonville, Cape Canaveral, Port Manatee/Tampa, Port Everglades and Fisher Island, Florida, with aggregate storage capacity of approximately 5 million barrels. Last year, these facilities sold an average of 29,000 barrels per day of bunker fuel, primarily to the cruise-ship industry, utilizing its tug and barge and hydrant delivery systems, and supplied approximately 28,000 barrels per day of gasoline and distillates over its petroleum products racks. In addition, the facilities provide a variety of third party lease capacity to the asphalt, jet fuel (commercial and government), power generation, and crude oil industries.

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

Results of Operations

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

	Three Months Ended December 31,					Six Months Ended December 31,
	2002			2001		2002		2001
Product supply, distribution, and marketing:
Revenue, net of Product costs, before effects of gains on inventories-discretionary volumes	$	13,343		13,729		20,955		41,328
Gains recognized on beginning inventories-discretionary volumes		12,644		—		12,644		—
Gains deferred on ending inventories-discretionary volumes		(33,490	)	—		(33,490	)	—

Revenues, net		(7,503	)	13,729		109		41,328
Lower of cost or market write-downs on inventories-minimum volumes		—		(12,114	)	—		(12,963	)

Net operating margins (1)		(7,503	)	1,615		109		28,365

Terminals and pipelines:
Revenues from storage and throughput		17,265		15,175		34,660		30,691
Direct operating costs and expenses		(6,520	)	(6,662	)	(12,987	)	(13,837	)

Net operating margins (1)		10,745		8,513		21,673		16,854

Total net operating margins (1)		3,242		10,128		21,782		45,219
Selling, general and administrative expenses		(8,775	)	(8,185	)	(18,106	)	(16,650	)
Depreciation and amortization		(4,293	)	(4,024	)	(8,549	)	(8,306	)
Corporate relocation and transition		(365	)	—		(1,449	)	—

Operating income (loss)	$	(10,191	)	(2,081	)	(6,322	)	20,263

(1)

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

The following summary reflects our comparative EBITDA, adjusted EBITDA, and net cash flows for the three months and six months ended December 31, 2002 and 2001 (in thousands):

	Three Months Ended December 31,					Six Months Ended December 31,
	2002			2001		2002		2001
EBITDA(1)	$	(5,898	)	2,051		2,601		30,026
Adjusted EBITDA(2)	$	14,948		14,165		23,447		42,989
Net cash provided (used) by operating activities	$	(26,315	)	(59,613	)	7,379		(83,295	)
Net cash provided (used) by investing activities	$	(34,262	)	20,586		(41,870	)	122,485
Net cash provided (used) by financing activities	$	50,896		36,929		9,603		(4,041	)
Calculation of EBITDA and Adjusted EBITDA:
Net operating margins:
Product supply, distribution, and marketing	$	(7,503	)	1,615		109		28,365
Terminals and pipelines		10,745		8,513		21,673		16,854

Total net operating margins		3,242		10,128		21,782		45,219
Selling, general and administrative expenses		(8,775	)	(8,185	)	(18,106	)	(16,650	)
Corporate relocation and transition		(365	)	—		(1,449	)	—
Dividend income		—		108		374		1,457

EBITDA(1)		(5,898	)	2,051		2,601		30,026
Plus gains deferred on ending inventories-discretionary volumes		33,490		—		33,490		—
Plus lower of cost or market write-downs on inventories-minimum volumes		—		12,114		—		12,963
Minus gains recognized on beginning inventories-discretionary volumes		(12,644	)	—		(12,644	)	—

Adjusted EBITDA(2)	$	14,948		14,165		23,447		42,989

(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 (a) gains deferred on ending inventories-discretionary volumes and (b) the lower of cost or market write-downs on the inventories-minimum volumes and minus gains recognized on beginning inventories-discretionary volumes inventories—discretionary volumes.

Three Months Ended December 31, 2002 Compared to Three Months Ended December 31, 2001

We reported a net loss of $(15.4) million for the three months ended December 31, 2002, compared to a net loss of $(2.9) million for the three months ended December 31, 2001. After preferred stock dividends, the net loss attributable to common stockholders was $(16.4) million for the three months ended December 31, 2002, compared to a net loss of $(5.4) million for the three months ended December 31, 2001. Basic and diluted loss per common share for the three months ended December 31, 2002 was $(0.42), based on 39.1 million weighted average common shares outstanding. Basic and diluted loss per share for the three months ended December 31, 2001 was $(0.17) per share, based upon 31.2 million weighted average common shares outstanding.

Product Supply, Distribution and Marketing

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 the Product supply, distribution and marketing operations are as follows:

	Three Months Ended December 31,
	2002			2001
Revenue, net of Product costs, before effects of gains on inventories—discretionary volumes	$	13,343		13,729
Gains recognized on beginning inventories—discretionary volumes		12,644		—
Gains deferred on ending inventories—discretionary volumes		(33,490	)	—

Net revenue	$	(7,503	)	13,729

Revenue, net of Product costs, before effects of gains on inventories—discretionary volumes. We attempt to exploit the price relationships between various delivery locations (referred to as “basis (geographical locations) differentials”). 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. These differentials create opportunities for increased operating margins when we predict the most beneficial location (highest value location) for sales of our discretionary inventory volumes of Product. However, the margins created from exploiting these market inefficiencies do not occur ratably over our reporting periods.

During October 2002, we were able to take advantage of sustained volatility in basis (geographical location) differentials in the Gulf Coast resulting from hurricane-influenced crude oil supply disruptions, which reduced Products output. This market imbalance lasted through mid-October 2002. During late November 2002 through mid-December, we exploited market imbalances in the Gulf Coast by accumulating discretionary inventory volumes (principally gasoline) at favorable prices relative to other bulk markets. During the last half of December 2002, we experienced significant increases in commodity prices, which resulted in the realization of favorable margins on the sales of our discretionary inventory volumes of Products to customers during this period.

Gains recognized on beginning inventories—discretionary volumes. Effective October 1, 2002, we are no longer permitted to carry our inventories—discretionary volumes at fair value. As of October 1, 2002, we reduced the carrying amount of our inventories—discretionary volumes from fair value to the lower of cost or market. As of October 1, 2002, the fair value of our inventories—discretionary volumes exceeded their cost basis by approximately $12.6 million. This change in accounting has been reflected in the accompanying consolidated statements of operations as “Gains recognized on beginning inventories—discretionary volumes” with an offsetting “Cumulative effect of change in accounting principle,” before considering income tax effects. The “Gains recognized on beginning inventories—discretionary volumes” represents the net revenues recognized on the sale of the inventories held as of October 1, 2002 to customers.

Gains deferred on ending inventories—discretionary volumes. During the last half of December 2002, we experienced significant increases in commodity prices, which resulted in the fair value of our inventories—discretionary volumes at December 31, 2002 exceeding their cost basis by approximately $33.5 million. At December 31, 2002, the excess of the fair value of the discretionary inventory volumes over their cost basis was deferred. That excess has been reflected in the accompanying consolidated statements of operations as “Gains deferred on ending inventories—discretionary volumes” with an offsetting reduction to inventories—discretionary volumes to present these inventories at lower of cost or market in the accompanying consolidated balance sheet. That excess will be recognized in net revenues attributable to our Product supply, distribution and marketing operations in the period that the discretionary inventory volumes are sold to customers.

During the three months ended December 31, 2002, no impairment losses were recognized due to lower of cost or market write-downs on minimum inventory volumes. During the three months ended December 31, 2001, we recognized impairment losses of approximately $12.1 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 December 31, 2002 were $17.3 million, compared to $15.2 million for the three months ended December 31, 2001. The increase of $2.1 million in revenues was due principally to increases in storage and steam revenues of $1.2 million at our Brownsville, Texas facilities, increases in throughput and storage revenues of $0.6 million due to increased volumes at our marketing and supply terminals, increases in storage revenues of $0.2 million at our Selma, North Carolina facilities, and increases in transportation revenues of $0.1 million due to increased volumes through our pipelines. The net operating margins from our terminal and pipeline operations for the three months ended December 31, 2002 were $10.7 million, compared to $8.5 million for the three months ended December 31, 2001. The increase of $2.2 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.

Our pipeline net operating margins per barrel of transported volumes were approximately $0.41 and $0.59 for the three months ended December 31, 2002 and 2001, respectively. The decrease in net operating margins per barrel is due principally to volumes being shipped by customers over a shorter distance on the pipeline during the three months ended December 31, 2002 as compared to the three months ended December 31, 2001.

Costs and Expenses

Selling, general and administrative expenses for the three months ended December 31, 2002 were $8.8 million, compared to $8.2 million for the three months ended December 31, 2001. The increase of $0.6 million was due principally to compensation and travel expenses incurred for redundant employees involved in our corporate relocation and transition and travel costs to investigate certain potential acquisition targets during the three months ended December 31, 2002.

Depreciation and amortization for the three months ended December 31, 2002 and 2001, was $4.3 million, compared to $4.0 million. The increase of $0.3 million in depreciation and amortization is principally related to depreciation and amortization on new additions to property, plant, and equipment.

We recognized special charges of $0.4 million during the three months ended December 31, 2002 related to the corporate relocation and transition. We expect to recognize an additional special charge of $0.6 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 December 31, 2002 was $nil, compared to $0.1 million for the three months ended December 31, 2001. The decrease of $0.1 million in dividend income was due principally to the absence of dividends received from Lion Oil Company and 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 December 31, 2002 was $0.1 million, as compared to $0.2 million for the three months ended December 31, 2001. The decrease of $0.1 million was due primarily to a decrease in interest bearing cash balances and lower interest rates during the three months ended December 31, 2002. Pursuant to our cash management practices, excess cash balances are used to pay down our outstanding borrowings under our bank credit facility and commodity margin loan.

Interest expense for the three months ended December 31, 2002 was $3.1 million, compared to $2.9 million during the three months ended December 31, 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 December 31, 2002, as the average interest rate under our bank credit facility was 4.0% and 5.2% for the three months ended December 31, 2002 and 2001, respectively. For the three months ended December 31, 2002, our interest expense resulted from $1.5 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 $1.4 million in net payments for the interest rate swap. For the three months ended December 31, 2001, our interest expense resulted from $1.5 million for outstanding borrowings under our bank credit facility and Senior Notes, $0.1 million for outstanding letters of credit, $0.1 million for outstanding borrowings under our commodity margin loan, and $1.2 million in net payments for the interest rate swap.

Other financing costs (income) for the three months ended December 31, 2002 were $(1.0) million, compared to $nil for the three months ended December 31, 2001. The increase of $1.0 million in other financing (income) was due principally to an unrealized gain on an interest rate swap of $1.2 million during the three months ended December 31, 2002, as compared to an unrealized gain on an interest rate swap of $0.4 million during the three months ended December 31, 2001 as well as a reduction in the amortization of deferred financing costs of $0.2 million. 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 December 31, 2002 and 2001, the one-month LIBOR rate was 1.4% and 1.9%, respectively. This swap agreement expires in August 2003.

Income Taxes

Income tax benefit was $4.6 million for the three months ended December 31, 2002, which represents an effective combined federal and state income tax rate of 38.0%. Income tax benefit was $1.8 million for the three months ended December 31, 2001, which represents an effective combined federal and state income tax rate of 38.0%.

Cumulative Effect Adjustment for a Change in Accounting Principle

As a result of the guidance reached on EITF 02-03, we are no longer permitted to carry our inventories—discretionary volumes at fair value effective October 1, 2002. The excess of the fair value of our inventories—discretionary volumes over their cost basis as of October 1, 2002 has been reflected in the accompanying consolidated statement of operations as a cumulative effect adjustment for a change in accounting principle.

Preferred Stock Dividends

Preferred stock dividends on our Series A Convertible Preferred Stock were $0.3 million and $2.4 million for the three months ended December 31, 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 December 31, 2002. There were no shares of Series B Redeemable Convertible Preferred stock outstanding during the three months ended December 31, 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.

Six Months Ended December 31, 2002 Compared to Six Months Ended December 31, 2001

We reported a net loss of $(14.9) million for the six months ended December 31, 2002, compared to net earnings of $6.7 million for the six months ended December 31, 2001. After preferred stock dividends, net loss attributable to common stockholders was $(16.9) million for the six months ended December 31, 2002, compared to net earnings of $1.9 million for the six months ended December 31, 2001. Basic and diluted loss per common share for the six months ended December 31, 2002 was $(0.43) based on 39.1 million weighted average common shares outstanding. Basic and diluted earnings per share for the six months ended December 31, 2001 was $0.06 per share, based upon 31.2 million weighted average common shares outstanding and 31.5 million weighted average diluted shares outstanding.

Product Supply, Distribution and Marketing

	Six Months Ended December 31,
	2002			2001
Revenue, net of Product costs, before effects of gains on inventories—discretionary volumes	$	20,955		41,328
Gains recognized on beginning inventories—discretionary volumes		12,644		—
Gains deferred on ending inventories—discretionary volumes		(33,490	)	—

Net revenue	$	109		41,328

We experienced a lack of sustained volatility in basis (geographical location) differentials during the first half of the six months ended December 31, 2002, which prevented us from taking advantage of the opportunities that are created by selling Products in the highest value location. However, during October 2002, we were able to take advantage of sustained volatility in basis (geographical location) differentials in the Gulf Coast resulting from hurricane-influenced crude oil supply disruptions, which reduced Products output. This market imbalance lasted through mid-October 2002. During late November 2002 through mid-December, we exploited market imbalances in the Gulf Coast by accumulating discretionary inventory volumes (principally gasoline) at favorable prices relative to other bulk markets. During the last half of December 2002, we experienced significant increases in commodity prices, which resulted in the realization of favorable margins on the sales of our discretionary inventory volumes of Products to customers during this period.

During the six months ended December 31, 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 six months ended December 31, 2002 also was due, in part, to the recognition of unrealized losses on energy trading activities of approximately $2.0 million.

During the six months ended December 31, 2002, no impairment losses were recognized due to lower of cost or market write-downs on minimum inventory volumes. During the six months ended December 31, 2001,

we recognized impairment losses of approximately $13.0 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 six months ended December 31, 2002 were $34.7 million, compared to $30.7 million for the six months ended December 31, 2001. The increase of $4.0 million in revenues was due principally to increases in storage and steam revenues of $2.0 million at our Brownsville, Texas facilities, increases in storage revenues of $0.7 million at our Selma, North Carolina facilities, increases in throughput and storage revenues of $2.0 million due to increased volumes at our marketing and supply terminals, increases in transportation revenues of $0.5 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 six months ended December 31, 2002 were $21.7 million, compared to $16.9 million for the six months ended December 31, 2001. The increase of $4.8 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 $0.45 and $0.39 for the six months ended December 31, 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. This increase is offset by the decline in tariff revenue realized on one of our joint tariffs due principally to volumes being shipped by customers over a shorter distance on the pipeline during the six months ended December 31, 2002 as compared to the six months ended December 31, 2001.

Costs and Expenses

Selling, general and administrative expenses for the six months ended December 31, 2002 were $18.1 million, compared to $16.7 million for the six months ended December 31, 2001. The increase of $1.4 million was due principally to compensation and travel expenses incurred for redundant employees involved in our corporate relocation and transition and travel costs to investigate certain potential acquisition targets during the six months ended December 31, 2002.

Depreciation and amortization for the six months ended December 31, 2002 and 2001, was $8.5 million and $8.3 million, respectively. The increase of $0.2 million in depreciation and amortization is principally related to depreciation and amortization on new additions to property, plant, and equipment offset by depreciation and amortization associated with the disposition of the NORCO system.

We recognized special charges of $1.4 million during the six months ended December 31, 2002 related to the corporate relocation and transition. We expect to recognize an additional special charge of $0.6 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 six months ended December 31, 2002 was $0.4 million, compared to $1.5 million for the six months ended December 31, 2001. The decrease of $1.1 million in dividend income was due principally to a decrease of $0.3 million in dividends received from Lion Oil Company and the absence of $0.8 million in dividends received from West Shore. 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 six months ended December 31, 2002 was $0.2 million, compared to $0.4 million for the six months ended December 31, 2001. The decrease of $0.2 million was due primarily to a decrease in interest bearing cash balances and lower interest rates during the six months ended December 31, 2002. Pursuant to our cash management practices, excess cash balances are used to pay down our outstanding borrowings under our bank credit facility and commodity margin loan.

Interest expense for the six months ended December 31, 2002 was $6.4 million, compared to $6.0 million during the six months ended December 31, 2001. The increase of $0.4 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 six months ended December 31, 2002, as the average interest rate under our bank credit facility was 4.2% and 5.5% for the six months ended December 31, 2002 and 2001, respectively. For the six months ended December 31, 2002, our interest expense resulted from $3.1 million for outstanding borrowings under our bank credit facility, $0.2 million for outstanding letters of credit, $0.2 million for outstanding borrowings under our commodity margin loan, and $2.9 million in net payments for the interest rate swap. For the six months ended December 31, 2001, our interest expense resulted from $3.7 million for outstanding borrowings under our bank credit facility and Senior Notes, $0.2 million for outstanding letters of credit, $0.3 million for outstanding borrowings under our commodity margin loan, and $1.8 million in net payments for the interest rate swap.

Other financing costs (income) for the six months ended December 31, 2002 were $(0.8) million, compared to $4.1 million for the six months ended December 31, 2001. The decrease of $4.9 million in other financing costs was due principally to a reduction in the amortization of deferred financing costs of $0.4 million and an unrealized gain on an interest rate swap of $1.3 million during the six months ended December 31, 2002, as compared to an unrealized loss on an interest rate swap of $3.2 million during six months ended December 31, 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 December 31, 2002 and 2001, the one-month LIBOR rate was 1.4% and 1.9%, respectively. This swap agreement expires in August 2003.

Loss on the disposition of assets, net for the six months ended December 31, 2001, consists of an $8.6 million gain on the sale of the NORCO system offset by a $9.9 million loss on the sale of West Shore shares.

Income Taxes

Income tax benefit was $4.3 million for the six months ended December 31, 2002, which represents an effective combined federal and state income tax rate of 38.0%. Income tax expense was $4.1 million for the six months ended December 31, 2001, which represents an effective combined federal and state income tax rate of 38.0%.

Cumulative Effect Adjustment for a Change in Accounting Principle

As a result of the guidance reached on EITF 02-03, we are no longer permitted to carry our inventories—discretionary volumes at fair value effective October 1, 2002. The excess of the fair value of our inventories— discretionary volumes over their cost basis as of October 1, 2002 has been reflected in the accompanying consolidated statement of operations as a cumulative effect adjustment for a change in accounting principle.

Preferred Stock Dividends

Preferred stock dividends on our Series A Convertible Preferred Stock were $0.6 million and $4.8 million for the six months ended December 31, 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 $1.4 million for the six months ended December 31, 2002. There were no shares of Series B Redeemable Convertible Preferred stock outstanding during the six months ended December 31, 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 $2.2 million, offset by the amortization of the premium on the carrying amount of the Series B Redeemable Convertible Preferred stock of $0.8 million.

Liquidity, Capital Resources, and Commodity Price Risk

At December 31, 2002, our current assets exceeded our current liabilities by $156.1 million, compared to $162.2 million at June 30, 2002. The decrease of $6.1 million in working capital is due principally to an increase in trade accounts payable and unrealized losses on energy services and risk management contracts offset by an increase in trade accounts receivable, inventories—discretionary volumes and an increase in unrealized gains on energy services and risk management contracts.

The increase in accounts receivable of $37.8 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 $2.0 billion and $1.1 billion for the three months ended December 31, 2002 and 2001, respectively. Our gross revenues for the Product supply, distribution, and marketing operations were approximately $3.7 billion and $2.7 billion for the six months ended December 31, 2002 and 2001, respectively.

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 the lower of cost or market at December 31, 2002, and at fair value at June 30, 2002. At December 31, 2002, the fair value of our inventories—discretionary volumes exceeded their cost basis by approximately $33.5 million. Inventories—discretionary volumes are as follows (in thousands):

	December 31, 2002			June 30, 2002
	Amount		Bbls	Amount		Bbls
Products held for sale or exchange	$	202,585	6,472	$	158,261	5,224
Products due to others under exchange agreements, net		23,091	664		16,908	525

Inventories—discretionary volumes	$	225,676	7,136	$	175,169	5,749

We have accumulated discretionary inventory volumes 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 December 31, 2002, we held approximately 3.1 million barrels 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):

	December 31, 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 December 31, 2001, we recognized an impairment loss of approximately $12.1 due to lower of cost or market write-downs on this minimum inventory. During the six months ended December 31, 2001, we recognized an impairment loss of approximately $13.0 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 December 31, 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 December 31, 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
10/31/02		27.22	.744	.864
11/30/02		26.89	.757	.734
12/31/02		31.20	.866	.865

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 December 31, 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	$	3,888		683		—	—	4,571
Non-investment grade		4,477		7,602		—	—	12,079
No external rating		16,401		168		—	—	16,569

		24,766		8,453		—	—	33,219
Risk management contracts—NYMEX futures contracts		23,129		4,258		—	—	27,387

	$	47,895		12,711		—	—	60,606

Unrealized loss position—liability
Energy services contracts	$	(23,928	)	(2,523	)	—	—	(26,451	)
Risk management contracts—NYMEX futures contracts		(48,963	)	—		—	—	(48,963	)

	$	(72,891	)	(2,523	)	—	—	(75,414	)

Net unrealized gain (loss) position—asset (liability)	$	(24,996	)	10,188		—	—	(14,808	)

At December 31, 2002, the unrealized gain on our energy services contracts with non-investment grade counterparties was approximately $12.1 million. A single industrial/commercial end-user represented approximately $8.9 million of that unrealized gain. At December 31, 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 $6.0 million at December 31, 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 six months ended December 31, 2002 (in thousands):

Fair value at June 30, 2002	$	11,041
Amounts realized or otherwise settled during the year		(2,861	)
Change in fair value attributable to change in commodity prices		(4,130	)
Other changes in fair value		1,895

Fair value at December 31, 2002	$	5,945

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 December 31, 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 December 31, 2002 we had $41.1 million on deposit to cover our margin requirements on open risk management contracts, which consisted of an initial margin deposit of $19.5 million and a variation margin deposit of $21.6 million. 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 December 31, 2002, a $0.05 per gallon unfavorable change in commodity prices would have required us to deposit approximately $5.1 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 $5.1 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 and six months ended December 31, 2002 were $3.4 million and $4.8 million, respectively, for terminal and pipeline facilities and assets to support these facilities. Excluding acquisitions, capital expenditures for the remainder of the year ending June 30, 2003, are estimated to be approximately $5.0 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 ($355 million at December 31, 2002). 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. 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 December 31, 2002, we were in compliance with all covenants included in the facility. At December 31, 2002, we had borrowings of $200 million outstanding and letters of credit of $29.5 outstanding under the bank credit facility. We also had the ability to borrow an additional $70.0 million under the facility based on the borrowing base computation at December 31, 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 used by operating activities of $(26.3) million for the three months ended December 31, 2002 was due principally to increases in trade accounts receivable and inventories—discretionary volumes, offset by increases in trade accounts payable, unrealized losses on energy service and risk management contracts and excise taxes payable and other accrued liabilities. The net cash used by operating activities of $(59.6) million for the three months ended December 31, 2001 was due principally to an increase in trade accounts receivable,

inventories—discretionary volumes, unrealized gain on energy services and risk management contracts and decrease in inventory due under exchange agreements, offset by an increase in trade accounts payable and excise taxes payable and other accrued liabilities.

Net cash provided by operating activities of $7.4 million for the six months ended December 31, 2002 was due principally to increases in trade accounts payable and unrealized losses on energy service and risk management contracts, offset by increases in trade accounts receivable and inventories—discretionary volumes. The net cash used by operating activities of $(83.3) million for the six months ended December 31, 2001 was due principally to an increase in trade accounts receivable and inventories—discretionary volumes and decreases in inventory due under exchange agreements, offset by an increase in trade accounts payable and excise taxes payable and other accrued liabilities.

Net cash used by investing activities of $(34.3) million for the three months ended December 31, 2002 was due principally to capital expended for construction and improvements to existing operating facilities and acquisitions of $3.4 million and additional restricted cash of $30.8 million to cover required margin deposits on risk management contracts. Net cash provided by investing activities of $20.6 million during the three months ended December 31, 2001 was due principally to proceeds received from the sale of assets of $23.1 million, offset by capital expended for construction and improvements to existing operating facilities and acquisitions of $0.8 million and the $1.8 million decrease in other assets.

Net cash used by investing activities of $(41.9) million for the six months ended December 31, 2002 was due principally to capital expended for construction and improvements to existing operating facilities and acquisitions of $5.4 million and additional restricted cash of $36.5 million to cover required margin deposits on risk management contracts. Net cash provided by investing activities of $122.5 million during the six months ended December 31, 2001 was due principally to proceeds received from the sale of assets of $117.2 million.

Net cash provided by financing activities of $50.9 million for the three months ended December 31, 2002 was due principally to proceeds from additional borrowings under our bank credit facility of $60.0 million offset by repayments of borrowings under our commodity margin loan of $7.2 million and payment of preferred stock dividends of $1.7 million. Net cash provided by financing activities of $36.9 million for the three months ended December 31, 2001 was due principally to proceeds from additional borrowings under our bank credit facility and master shelf facility of $37.0 million.

Net cash provided by financing activities of $9.6 million for the six months ended December 31, 2002 was due principally to proceeds from additional borrowings under our bank credit facility of $13.0 million offset by repayments of borrowings under our commodity margin loan of $1.5 million and payment of preferred stock dividends of $1.7 million. Net cash used by financing activities of $(4.0) million for the six months ended December 31, 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.

In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based Compensation—Transition and Disclosure—an amendment of FASB Statement No. 123 (“SFAS No. 123), which addresses alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. We are required to adopt the provisions of SFAS No. 148 after December 31, 2002.

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 significantly affect these internal controls subsequent to the date of our most recent evaluation.

PART II. OTHER INFORMATION

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

At the TransMontaigne Annual Meeting of Stockholders held on November 21, 2002, the stockholders of TransMontaigne elected nine directors to serve until the next Annual Meeting of Stockholders and until their successors have been elected and qualified and approved the amendment of the TransMontaigne Inc. Equity Incentive Plan, as amended (the “1997 Incentive Plan”) to provide for the grant of equity-based awards to non-employee Directors of TransMontaigne Inc. from time to time.

The following persons were elected as directors:

	Votes For	Votes Against	Abstentions
Cortlandt S. Dietler	31,994,720	467,422	0
Donald H. Anderson	31,716,777	745,365	0
Peter B. Griffin	31,997,720	464,422	0
Ben A. Guill	31,987,520	474,622	0
John A. Hill	31,997,720	464,422	0
Bryan H. Lawrence	31,543,938	918,204	0
Harold R. Logan, Jr.	31,715,177	746,965	0
Edwin H. Morgens	31,543,938	918,204	0
Walter P. Schuetze	31,977,720	464,422	0

A total of 34,883,895 votes were cast in favor of the proposal to amend the 1997 Incentive Plan, while 2,301,285 votes were cast against the proposal and 72,195 abstained.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits:


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 October 3, 2002 contained certifications under Item 9, Regulation FD Disclosure, 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.

TRANSMONTAIGNE INC.
(Registrant)

/s/ DONALD H. ANDERSON
Donald H. Anderson
President, Chief Executive Officer,
Chief Operating Officer and Vice Chairman

/s/ RANDALL J. LARSON
Randall J. Larson
Executive Vice President, Chief Financial Officer,
Chief Accounting Officer and Controller

Dated February 14, 2003

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;

5. 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

6. 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.

/s/ DONALD H. ANDERSON

Donald H. Anderson

President, Chief Executive Officer, Chief

Operating Officer and Vice Chairman

Date: February 14, 2003

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

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

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;

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


								/s/ RANDALL J. LARSON
								Randall J. Larson
								Executive Vice President, Chief Financial Officer, Chief Accounting Officer and Controller

Date: February 14, 2003