Edgar Filing: TRANSMONTAIGNE INC

Three months ended

March 31,

Net earnings

Basic net earnings per common share

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)
x	Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
	For the quarterly period ended March 31, 2006
	OR
o	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		(I.R.S. Employer
of incorporation or organization)		Identification No.)

1670 Broadway
Suite 3100
Denver, Colorado 80202

(Address, including zip code, of principal executive offices)

(303) 626-8200

(Telephone number, including area code)

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o

Accelerated filer x

Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2) Yes o No x

As of April 24, 2006, there were 50,010,607 shares of the Registrant’s Common Stock outstanding.

TABLE OF CONTENTS

		Page No.
	Part I. Financial Information
Item 1.	Unaudited Consolidated Financial Statements		5
	Consolidated balance sheets as of March 31, 2006 and June 30, 2005		6
	Consolidated statements of operations for the three and nine months ended March 31, 2006 and 2005		7
	Consolidated statements of preferred stock and common stockholders’ equity for the year ended June 30, 2005 and nine months ended March 31, 2006		8
	Consolidated statements of cash flows for the three and nine months ended March 31, 2006 and 2005		9
	Notes to consolidated financial statements		10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		34
Item 3.	Qualitative and Quantitative Disclosures about Market Risk		68
Item 4.	Controls and Procedures		71
	Part II. Other Information
Item 5.	Other Information		72
Item 6.	Exhibits		72

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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

i. certain statements, including possible or assumed future results of operations, in “Management’s Discussion and Analysis of Financial Condition and Results of Operations;”

ii. any statements contained herein or therein regarding the prospects for our business or any of our services;

iii. any statements preceded by, followed by or that include the words “may,” “seeks,” “believes,” “expects,” “anticipates,” “intends,” “continues,” “estimates,” “plans,” “targets,” “predicts,” “attempts,” “is scheduled,” or similar expressions; and

iv. other statements contained herein or therein regarding matters that are not historical facts.

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

The following risk factors, discussed in more detail under the heading “Risk Factors” in our Annual Report on Form 10-K for the year ended June 30, 2005, filed on September 13, 2005, are important factors that could cause actual results to differ materially from our expectations and may adversely affect our business and results of operations, include, but are not limited to:

· the availability of adequate supplies of and demand for petroleum products in the areas in which we operate;

· the effects of competition and our ability to renew customer contracts;

· the impact of petroleum product price fluctuations on our sales margins and the effect of changes in commodity prices on our liquidity;

· the success of our risk management activities;

· volumes of refined petroleum product throughput or stored in our terminal facilities;

· TransMontaigne Partners’ inability to pay the minimum quarterly distribution on the subordinated units that we own;

· continued creditworthiness of, and performance by, contract counterparties;

· the tax and other effects of the exercise of TransMontaigne Partners’ options to purchase our fixed assets;

· operational hazards and availability and cost of insurance on our assets and operations;

· the impact of any failure of our information technology systems;

· the availability of acquisition opportunities and successful integration and future performance of acquired assets;

· the threat of terrorist attacks or war;

· the impact of current and future laws and governmental regulations;

· the failure of TransMontaigne Partners to avoid federal income taxation as a corporation or the imposition of state level taxation;

· liability for environmental claims;

· the impact of the departure of any key officers; and

· general economic, market or business conditions.

An additional risk factor that could cause actual results to differ materially from our expectations and may adversely affect our business and results of operations is the consummation of the pending merger with SemGroup, L.P. and its affiliates, which in turn is dependent upon, among other things:

· the ability of the parties to satisfy, or to cause the satisfaction of, the conditions to completion of the pending merger with SemGroup, L.P. and its affiliates, including receipt of stockholder approval;

· the actual terms of the financing transactions entered into in connection with funding the merger and other transactions contemplated by the merger agreement; and

· the occurrence of any event or change in circumstances that could give rise to termination of the merger agreement, or the failure of the merger to be completed for any other reason.

We believe the increase in our stock price subsequent to March 21, 2006, the last unaffected stock price prior to the press reports of a potential transaction, is largely attributable to the cash consideration investors expect to receive if the merger is consummated. Accordingly, if the merger is not completed, our stock price likely will decrease. We can provide no assurance that all conditions to the parties’ obligations to complete the merger will be satisfied. As a result, it is possible that the merger may not be completed even if approved by our stockholders. Please see our Preliminary Proxy Statement filed with the Securities and Exchange Commission on May 1, 2006 for a detailed description of the terms, conditions and provisions regarding the pending merger with SemGroup, L.P.

In addition, the following factors and circumstances under or related to the pending merger could have an adverse impact on our business and operations:

· as of March 31, 2006, we have incurred approximately $1.4 million in merger related expenses. Under the merger agreement, we are required to pay a termination fee of $15 million to SemGroup, L.P. under specified circumstances. The termination fee would be payable if we terminated the merger agreement with SemGroup, L.P. to enter into an agreement with Morgan Stanley Capital Group Inc.;

· the merger with SemGroup, L.P. places certain limitations on the manner in which we can conduct our ongoing operations. In addition, our management has devoted, and likely will continue to devote, a significant amount of time to the pending merger. These efforts have, and may continue to, temporarily distract management’s attention from our day-to-day business operations and other business opportunities;

· approvals, clearances or consents required to consummate the merger could also delay or jeopardize the completion of the merger, further impacting management’s ability to manage our day-to-day operations; and

· certain key employees may depart because of a desire not to remain with us after completion of the merger and we can make no assurances that we will be able to retain key employees to the same extent we have been able to do so in the past.

Part I. Financial Information

ITEM 1. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

The interim unaudited consolidated financial statements of TransMontaigne Inc. as of and for the three and nine months ended March 31, 2006, are included herein beginning on the following page. The accompanying unaudited interim consolidated financial statements should be read in conjunction with our annual consolidated financial statements and related notes for the year ended June 30, 2005, together with our discussion and analysis of financial condition and results of operations, included in our Annual Report on Form 10-K filed on September 13, 2005.

TransMontaigne Inc. is a holding company with the following active subsidiaries during the three and nine months ended March 31, 2006.

· TransMontaigne Product Services Inc. (“TPSI”)

· TransMontaigne Services Inc.

· TransMontaigne Transport Inc.

· Coastal Fuels Marketing, Inc.

· Coastal Tug and Barge, Inc.

· TransMontaigne Partners L.P.

· Radcliff/Economy Marine Services, Inc. (since August 1, 2005)

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

TransMontaigne Inc. and subsidiaries
Consolidated balance sheets
(In thousands)

	March 31, 2006		June 30, 2005
ASSETS
Current assets:
Cash and cash equivalents	$	9,494	$	29,721
Restricted cash held by commodity broker	11,411		10,436
Trade accounts receivable, net	422,250		381,771
Inventories—discretionary volumes	232,409		274,774
Unrealized gains on derivative contracts	18,992		7,620
Deferred tax assets	18,704		18,401
Prepaid expenses and other	6,393		6,767
	719,653		729,490
Property, plant and equipment, net	364,300		344,532
Product linefill and tank bottom volumes	21,626		24,325
Investment in Lion Oil Company	10,131		10,131
Deferred debt issuance costs, net	8,203		9,778
Other assets, net	40,206		23,725
	$	1,164,119	$	1,141,981
LIABILITIES, PREFERRED STOCK, AND COMMON STOCKHOLDERS’ EQUITY
Current liabilities:
Commodity margin loan	$	10,000	$	—
Working capital credit facility	17,500		—
Trade accounts payable	181,796		212,040
Income taxes payable	4,097		29,801
Unrealized losses on derivative contracts	13,725		47,215
Inventory due to others under exchange agreements	58,718		16,429
Excise taxes payable	85,291		79,597
Other accrued liabilities	24,302		20,791
Deferred revenue—supply chain management services	3,108		3,981
	398,537		409,854
Other liabilities:
Long-term debt	245,508		228,307
Deferred tax liabilities	49,880		46,413
Unrealized losses on derivative contracts	—		234
Total liabilities	693,925		684,808
Non-controlling interests in TransMontaigne Partners	82,566		81,440
Series B redeemable convertible preferred stock	20,608		49,249
Common stockholders’ equity:
Common stock	484		456
Capital in excess of par value	322,435		299,681
Deferred stock-based compensation	—		(7,042		)
Retained earnings	44,101		33,389
	367,020		326,484
	$	1,164,119	$	1,141,981

See accompanying notes to consolidated financial statements.

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

	Three months ended March 31,						Nine months ended March 31,
	2006			2005			2006			2005
Supply, distribution, and marketing:
Revenues	$	2,424,328		$	2,140,187		$	7,265,819		$	5,980,972
Cost of product sold and other direct costs and expenses	(2,375,217		)	(2,055,714		)	(7,208,986		)	(5,852,803		)
	49,111			84,473			56,833			128,169
Terminals, pipelines, and tugs and barges:
Revenues	32,369			29,254			94,430			83,248
Direct operating costs and expenses	(19,895		)	(15,447		)	(56,533		)	(45,308		)
	12,474			13,807			37,897			37,940
	61,585			98,280			94,730			166,109
Costs and expenses:
Selling, general and administrative expenses	(12,142		)	(9,885		)	(37,050		)	(32,120		)
Merger related expenses	(1,350		)	—			(1,350		)	—
Depreciation and amortization	(7,273		)	(6,274		)	(20,703		)	(17,808		)
Gain (loss) on disposition of assets, net	10,617			2,993			11,802			(606		)
Total costs and expenses	(10,148		)	(13,166		)	(47,301		)	(50,534		)
Operating income	51,437			85,114			47,429			115,575
Other income (expenses):
Dividend income	107			9			690			390
Interest income	169			149			626			250
Interest expense	(7,164		)	(6,375		)	(20,013		)	(19,316		)
Other financing costs:
Amortization of deferred debt issuance costs	(525		)	(455		)	(1,575		)	(1,603		)
Write-off of debt issuance costs related to former bank credit facility	—			—			—			(3,392		)
Total other expenses	(7,413		)	(6,672		)	(20,272		)	(23,671		)
Earnings before income taxes	44,024			78,442			27,157			91,904
Income tax expense	(16,729		)	(31,377		)	(10,320		)	(36,762		)
Non-controlling interests’ share in earnings of TransMontaigne Partners	(1,571		)	—			(5,425		)	—
Net earnings	25,724			47,065			11,412			55,142
Earnings allocable to preferred stock	(1,520		)	(10,344		)	(762		)	(12,148		)
Net earnings attributable to common stockholders	$	24,204		$	36,721		$	10,650		$	42,994
Earnings per share:
Basic net earnings per common share	$	0.50		$	0.92		$	0.22		$	1.08
Diluted net earnings per common share	$	0.48		$	0.90		$	0.21		$	1.07
Weighted average common shares outstanding:
Basic	48,404			39,793			47,890			39,672
Diluted	53,377			52,558			53,687			51,709

See accompanying notes to consolidated financial statements.

TransMontaigne Inc. and subsidiaries
Consolidated statements of preferred stock and common stockholders’ equity
Year ended June 30, 2005 and nine months ended March 31, 2006
(In thousands)

	Series B Preferred stock				Common stock				Capital in excess of par value				Deferred stock-based compensation				Retained earnings (accumulated deficit)				Total common stockholders’ equity
Balance at June 30, 2004		$	77,719			$	411			$	251,775			$	(4,129	)		$	(19,768	)		$	228,289
Common stock issued for options exercised		—				—				347				—				—				347
Common stock repurchased from employees for withholding taxes		—				(1		)		(816		)		—				—				(817		)
Net tax effect arising from stock-based compensation		—				—				272				—				—				272
Forfeiture of restricted stock awards prior to vesting		—				(2		)		(1,222		)		1,224				—				—
Deferred compensation related to restricted stock awards		—				7				4,163				(4,170		)		—				—
Amortization of deferred stock-based compensation		—				—				—				2,625				—				2,625
Warrant granted to MSCG in exchange for product supply agreements		—				—				14,600				—				—				14,600
Preferred stock dividends paid-in kind		1,087				—				—				—				—				—
Preferred stock dividends		—				—				—				—				(4,207		)		(4,207		)
Amortization of premium on Series B Redeemable Convertible Preferred stock		(1,546		)		—				—				—				1,546				1,546
Conversion of Series B Redeemable Convertible Preferred stock into common stock		(28,011		)		41				27,970				—				—				28,011
Deferred compensation related to restricted TransMontaigne Partners’ common unit awards		—				—				2,592				(2,592		)		—				—
Net earnings		—				—				—				—				55,818				55,818
Balance at June 30, 2005		$	49,249			$	456			$	299,681			$	(7,042	)		$	33,389			$	326,484
Elimination of deferred stock-based compensation due to adoption of SFAS 123(R)		—				(16		)		(7,026		)		7,042				—				—
Common stock issued for options exercised		—				—				224				—				—				224
Common stock repurchased from employees for withholding taxes		—				(1		)		(830		)		—				—				(831		)
Amortization of deferred stock-based compensation		—				4				2,154				—				—				2,158
Preferred stock dividends		—				—				—				—				(1,068		)		(1,068		)
Amortization of premium on Series B redeemable convertible preferred stock		(368		)		—				—				—				368				368
Conversion of Series B redeemable convertible preferred stock into common stock		(28,273		)		41				28,232				—				—				28,273
Net earnings		—				—				—				—				11,412				11,412
Balance at March 31, 2006		$	20,608			$	484			$	322,435			$	—			$	44,101			$	367,020

See accompanying notes to consolidated financial statements.

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

	Three months ended March 31,						Nine months ended March 31
	2006			2005			2006			2005
Cash flows from operating activities:
Net earnings	$	25,724		$	47,065		$	11,412		$	55,142
Adjustments to reconcile net earnings to net cash provided by (used in) operating activities:
Amortization of deferred revenue	(1,809		)	(2,376		)	(5,112		)	(5,065		)
Depreciation and amortization	7,273			6,274			20,703			17,808
Amortization of deferred stock-based compensation	641			697			2,158			1,972
Amortization of deferred debt issuance costs	525			455			1,575			1,603
Write-off of debt issuance costs	—			—			—			3,392
(Gain) loss on disposition of assets, net	(10,617		)	(2,993		)	(11,802		)	606
Net change in unrealized (gains) losses on long-term derivative contracts	—			(88		)	(235		)	452
Non-controlling interests’ share in earnings of TransMontaigne Partners	1,571			—			5,425			—
Changes in operating assets and liabilities, net of effects from acquisitions:
Trade accounts receivable, net	(56,749		)	(53,543		)	(19,873		)	(85,633		)
Inventories—discretionary volumes	(9,678		)	126,824			46,248			18,937
Prepaid expenses and other	620			466			(504		)	(2,056		)
Trade accounts payable	7,398			50,755			(33,218		)	83,619
Income taxes payable	16,727			31,375			(26,366		)	36,935
Inventory due to others under exchange agreements	4,644			7,621			42,289			(2,919		)
Unrealized (gains) losses on derivative contracts	20,734			26,546			(40,623		)	7,934
Excise taxes payable and other accrued liabilities	5,438			16,023			4,684			5,865
Net cash provided by (used in) operating activities	12,442			255,101			(3,239		)	138,592
Cash flows from investing activities:
Acquisition of Radcliff and Oklahoma City terminals, net of cash acquired	—			—			(53,911		)	—
Exchange of terminals	(5,910		)	—			(5,910		)	—
Acquisition of terminals, pipelines, tugs and barges	(573		)	—			(4,521		)	(7,947		)
Additions to property, plant and equipment—expansion of facilities	(2,295		)	(768		)	(6,220		)	(2,690		)
Additions to property, plant and equipment—maintain existing facilities	(822		)	(848		)	(2,397		)	(2,589		)
(Increase) decrease in restricted cash held by commodity broker	(10,028		)	1,310			(748		)	354
Proceeds from disposition of assets	16,938			5,757			18,525			5,757
Other	8			(5		)	(125		)	3
Net cash provided by (used in) investing activities	(2,682		)	5,446			(55,307		)	(7,112		)
Cash flows from financing activities:
Net borrowings (repayments) of commodity margin loan	10,000			(8,383		)	10,000			(1,923		)
Net borrowings (repayments) of debt	(21,092		)	(239,000		)	34,701			(110,000		)
Deferred debt issuance costs	—			(149		)	—			(3,517		)
Common stock issued for options exercised	19			41			224			119
Common stock repurchased from employees for withholding taxes	(59		)	(38		)	(831		)	(805		)
Distributions paid to non-controlling interests in TransMontaigne Partners	(1,721		)	—			(4,089		)	—
Common units repurchased by TransMontaigne Partners’ long-term incentive plan	(211		)	—			(211		)	—
Preferred stock dividends paid in cash	(301		)	(1,110		)	(1,475		)	(2,220		)
Net cash provided by (used in) financing activities	(13,365		)	(248,639		)	38,319			(118,346		)
Increase (decrease) in cash and cash equivalents	(3,605		)	11,908			(20,227		)	13,134
Cash and cash equivalents at beginning of period	13,099			7,384			29,721			6,158
Cash and cash equivalents at end of period	$	9,494		$	19,292		$	9,494		$	19,292
Supplemental disclosures of cash flow information:
Cash paid for (refund of) income taxes	$	2		$	2		$	36,686		$	(173	)
Cash paid for interest expense	$	2,755		$	2,094		$	15,069		$	15,143

See accompanying notes to consolidated financial statements.

TransMontaigne Inc. and subsidiaries
Notes to consolidated financial statements
March 31, 2006 and June 30, 2005

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a) Principles of Consolidation and Use of Estimates

The accompanying unaudited consolidated financial statements in this Quarterly Report on Form 10-Q have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, these statements reflect adjustments (consisting only of normal recurring entries), which are, in our opinion, necessary for a fair presentation of the financial results for the interim periods presented. Certain information and notes normally included in annual financial statements have been condensed in or omitted from these interim financial statements pursuant to such rules and regulations. These consolidated financial statements should be read in conjunction with the consolidated financial statements and related notes for the year ended June 30, 2005, together with our discussion and analysis of financial condition and results of operations, included in our Annual Report on Form 10-K filed on September 13, 2005.

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

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

(b) Nature of Business and Basis of Presentation

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

On May 27, 2005, TransMontaigne Partners L.P. (“TransMontaigne Partners”), a master limited partnership and consolidated subsidiary of ours, completed its initial public offering of common units.

TransMontaigne Partners received net proceeds of approximately $73.0 million for the issuance and sale of 3,852,500 common units, after giving effect to the exercise of the underwriters’ over-allotment option, at the initial public offering price of $21.40 per common unit, and the payment of the underwriting discount, structuring fee and other offering costs of approximately $9.5 million. TransMontaigne Partners also received approximately $7.9 million for the issuance and sale of 450,000 subordinated units to an affiliate of Morgan Stanley Capital Group Inc. (“MSCG”) in a separate private placement at a price of $17.65 per subordinated unit. We contributed seven refined products terminals located in Florida, the Razorback Pipeline, and two refined products terminals located in Mt. Vernon, Missouri and Rogers, Arkansas to TransMontaigne Partners in exchange for a 2% general partner interest, 2,872,266 subordinated units, and a distribution of $111.5 million. We also entered into an omnibus agreement and terminaling and transportation services agreement with TransMontaigne Partners. The omnibus agreement sets forth the terms on which we will provide TransMontaigne Partners with certain general and administrative services, insurance coverage and environmental and other indemnification, among other terms. We also have agreed to provide TransMontaigne Partners with certain options and rights of first refusal to purchase additional refined petroleum product terminal assets, and TransMontaigne Partners has agreed to provide us certain rights of first refusal with respect to its assets and additional terminal capacity added by TransMontaigne Partners in the future.

Effective January 1, 2006, we contributed the Mobile, Alabama terminal, which we acquired from Radcliff/Economy Marine Services, Inc. on August 1, 2005 (see Note 2 to Notes to consolidated financial statements), to TransMontaigne Partners for approximately $17.9 million.

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

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

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

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

In our supply, distribution and marketing operations, we purchase refined petroleum products, schedule them for delivery to our terminals, as well as terminals owned by third parties, and then sell those products to our customers through rack spot sales, contract sales, and bulk sales. Revenues from our sales of physical inventory are recognized pursuant to the accrual method of accounting (i.e., when cash becomes due and payable to us pursuant to the terms of the sales contracts). Revenues from rack spot sales and contract sales are recognized when the product is delivered to the customer through a truck loading rack or marine fueling equipment. Revenues from bulk sales are recognized when the title to the product is transferred to the customer, which generally occurs upon confirmation of the terms of the sale.

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

(e) Accounting for Supply Chain Management Services Activities

We provide supply chain management services to companies and governmental entities that desire to outsource their fuel supply function and to reduce the price volatility associated with their fuel supplies. We offer three types of supply chain management services: delivered fuel price management, retail price management, and logistical supply chain management services.

Delivered fuel price management contracts involve the sales of committed quantities of specific motor fuels delivered to our customer’s proprietary fleet refueling locations at fixed prices for terms up to three years. Under retail price management contracts, customers commit for terms up to 18 months to a specific monthly quantity of product within one or more metropolitan areas and agree to a net settlement with us for the difference between a stipulated retail price index and our fixed contract price. Our logistical supply chain management arrangements permit our customers to use our proprietary web-based inventory management system for a fee, which typically is charged on a per gallon basis.

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

(f) Accounting for Risk Management Activities

We enter into risk management contracts, principally NYMEX futures contracts, to manage our exposure to changes in commodity prices. We evaluate our market risk exposure from an overall portfolio basis that considers changes in physical inventories—discretionary volumes held for immediate sale or exchange, inventory due to others under exchange agreements, open positions in derivative contracts, and open positions in risk management contracts. We enter into risk management contracts that offset the changes in the values of our inventories—discretionary volumes held for immediate sale or exchange and derivative contracts. At March 31, 2006 and June 30, 2005, our open positions in risk management contracts principally were NYMEX futures contracts (purchases and sales) and NYMEX options (calls and puts).

(g) Accounting for Derivative Contracts

Our contract sales, bulk sales, delivered fuel price management, retail price management, risk management contracts and product supply contracts qualify as derivative instruments pursuant to the requirements of Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities. All derivative contracts are required to be reported as assets and liabilities at fair value in the accompanying consolidated balance sheet in accordance with SFAS No. 133. The fair value of our derivative contracts is included in “Unrealized gains or losses on derivative contracts” in the accompanying consolidated balance sheets. Changes in the fair value of our derivative contracts are included in net operating margins attributable to our supply, distribution and marketing operations.

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

(h) Presentation of Revenues

We present revenue from our rack spot sales, contract sales, certain bulk sales, and delivered fuel price management contracts on a gross basis in the accompanying consolidated statements of operations because our obligations under these arrangements are settled via transfer of title and risk of loss of the product to the customer. Revenue from our retail price management contracts and risk management contracts are presented on a net basis (i.e., product costs are required to be netted directly against gross revenues to arrive at net revenues) in the accompanying consolidated statements of operations because our obligations under these arrangements are settled on a net cash basis. The logistical supply chain management services fees do not involve the sale of inventory and, therefore, only the service fee is presented in the accompanying consolidated statements of operations.

We have presented bulk transactions that were “booked out” on a net basis in the consolidated statements of operations (i.e., product costs are netted directly against gross revenues to arrive at net revenues). A “book out” occurs when one party appears more than once for the sale and purchase of a specific grade of refined product for a specific scheduling date to transport product on a particular common carrier pipeline. In that instance, we and other pipeline shippers agree not to schedule or deliver the refined product that originates and ends with the same counterparty, but rather settle in cash the amounts due to or from each intervening counterparty, thus booking out the transaction. We also present “buy/sell” transactions on a net basis in the consolidated statements of operations. A “buy/sell” transaction is a purchase and sale of inventory with the same counterparty, provided that the purchase transaction and the sale transaction are entered into in contemplation of one another. For the three months ended March 31, 2006 and 2005, we reduced revenues and cost of product sold by approximately $458.3 million and $499.0 million, respectively, for book outs and buy/sell transactions. For the nine months ended March 31, 2006 and 2005, we reduced revenues and cost of product sold by approximately $1,360.8 million and $2,175.3 million, respectively, for book outs and buy/sell transactions. The presentation of book outs and buy/sell transactions on a net basis has no effect on our operating income or net earnings.

(i) Accounting for Inventories—Discretionary Volumes

Our inventories—discretionary volumes consist of refined petroleum products, primarily gasolines, distillates, and No. 6 oil. Inventories—discretionary volumes are presented in the accompanying consolidated balance sheets as current assets and are carried at the lower of cost (first-in, first-out) or market (replacement cost). Inventories—discretionary volumes are as follows (in thousands):

	March 31, 2006			June 30, 2005
	Amount		Bbls	Amount		Bbls
Volumes held for immediate sale or exchange	$	128,529	1,955	$	153,123	2,415
Volumes held for base operations	103,880		1,487	121,651		2,011
Inventories—discretionary volumes	$	232,409	3,442	$	274,774	4,426

At March 31, 2006 and June 30, 2005, the market value of our volumes held for immediate sale or exchange exceeded their cost basis by approximately $8.5 million and $2.1 million, respectively. At March 31, 2006 and June 30, 2005, the market value of our volumes held for base operations exceeded their cost basis by approximately $6.9 million and $0.2 million, respectively.

During the three months ended March 31, 2006, we decreased our volumes held for base operations by approximately 0.5 million barrels as a result of leasing our light oil River terminal capacity to Valero Energy Corporation. During the year ended June 30, 2005, we decreased our volumes held for base operations by approximately 2.0 million barrels as a result of our product supply agreement with Morgan Stanley Capital Group Inc.

(j) Inventory Due to Others Under Exchange Agreements

We enter into exchange agreements generally with major oil companies and independent marketing and trading companies. Exchange agreements generally are fixed-term agreements that involve our receipt of a specified volume of product at one location in exchange for delivery by us of product at a different location. At March 31, 2006 and June 30, 2005, current liabilities included inventory due to others under exchange agreements of approximately 738,000 barrels and 296,000 barrels, respectively, with a fair value of approximately $58.7 million and $16.4 million, respectively. The amount recorded represents the fair value of inventory due to others under exchange agreements at the respective balance sheet date.

(k) Accounting for Product Linefill and Tank Bottom Volumes

Our product linefill and tank bottom 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 generally do not manage the commodity price risks associated with these volumes.

At March 31, 2006 and June 30, 2005, our product linefill and tank bottom volumes are presented in the accompanying consolidated balance sheets as non-current assets and are carried at the lower of cost (weighted average) or market (replacement cost). The replacement cost of our product linefill and tank bottom volumes is based on the nearest quoted wholesale market price. At March 31, 2006 and June 30, 2005, we had approximately 808,000 barrels and 925,000 barrels, respectively, of product reflecting tank bottoms and linefill in our proprietary terminal connections with an adjusted cost basis of approximately $21.6 million and $24.3 million, respectively. At March 31, 2006 and June 30, 2005, the market value of our product linefill and tank bottom volumes exceeded their cost basis by approximately $43.4 million and $34.8 million, respectively.

During the three months ended March 31, 2006, we decreased our product linefill and tank bottom volumes by approximately 0.1 million barrels as a result of leasing our light oil River terminal capacity to Valero Energy Corporation. We sold these product linefill and tank bottom volumes for approximately $9.9 million resulting in a gain on sale of approximately $6.8 million.

(l) Restricted Cash Held by Commodity Broker

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

(m) Deferred Debt Issuance Costs

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

	June 30, 2005			Additions			Amortization				March 31, 2006
Senior secured working capital credit facility		$	3,422		$	—		$	(606	)		$	2,816
Senior subordinated notes		5,455			—			(831		)		4,624
TransMontaigne Partners’ credit facility		901			—			(138		)		763
		$	9,778		$	—		$	(1,575	)		$	8,203

(n) Environmental Obligations

At March 31, 2006 and June 30, 2005, we had accrued environmental obligations of approximately $7.1 million and $6.1 million, respectively, representing our best estimate of our remediation obligations (see Note 10 of Notes to consolidated financial statements). During the nine months ended March 31, 2006, we made payments of approximately $1.5 million towards our environmental remediation obligations. During the nine months ended March 31, 2006, we charged to income approximately $0.7 million to increase our estimate of our future environmental remediation obligations. During the nine months ended March 31, 2006, we assumed approximately $1.2 million of environmental remediation obligations in connection with our acquisition of the Radcliff and Oklahoma City terminals (see Note 2 of Notes to consolidated financial statements). During the nine months ended March 31, 2006, we assumed net environmental remediation obligations of approximately $0.6 million in connection with our exchange of terminals with BP Plc (see Note 3 of Notes to consolidated financial statements). During the nine months ended March 31, 2006 and 2005, we received insurance recoveries of approximately $265,000 and $1.6 million, respectively, which have been recognized as a reduction of direct operating costs and expenses in the accompanying consolidated statements of operations.

(o) Equity-Based Compensation Plans

For periods ending prior to July 1, 2005, we accounted for our employee stock option plans and restricted stock awards using the intrinsic value method pursuant to APB Opinion No. 25, Accounting for Stock Issued to Employees. If compensation cost for our stock-based compensation plans had been determined based on the fair value at the grant dates for awards under those plans pursuant to Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation, our net earnings and earnings per common share would have been reduced to the pro forma amounts indicated below (in thousands, except for per share amounts):

	Three months ended March 31, 2005				Nine months ended March 31, 2005
Net earnings attributable to common stockholders:
As reported		$	36,721			$	42,994
Amortization of the fair value of stock options granted to employees		(24		)		(75		)
Pro forma		$	36,697			$	42,919
Earnings per share:
As reported
Basic		$	0.92			$	1.08
Diluted		$	0.90			$	1.07
Pro forma
Basic		$	0.92			$	1.08
Diluted		$	0.90			$	1.06

There were no options granted during the nine months ended March 31, 2006 and the years ended June 30, 2005, 2004 and 2003. The weighted average fair value at grant dates for options granted during the year ended June 30, 2002 was $3.08. The primary assumptions used to estimate the fair value of options granted on the date of grant using the Black-Scholes option-pricing model during the year ended June 30, 2002 were as follows: no dividend yield, expected volatility of 79%, risk-free rate of 4.49%, and expected life of 4 years.

Effective July 1, 2005, we adopted the provisions of Statement of Financial Accounting Standards No. 123 (R), Share-Based Payment. This Statement requires us to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award.

That cost will be recognized over the period during which an employee is required to provide service in exchange for the award. We are required to estimate the number of equity instruments that are expected to vest in measuring the total compensation cost to be recognized over the related service period.

For awards granted prior to July 1, 2005, we are required to measure compensation cost for the portion of outstanding awards for which the requisite service has not yet been rendered (i.e., the unvested portion of the award as of July 1, 2005). The compensation cost for these awards is based on their relative grant-date fair values.

For awards granted on or after July 1, 2005, compensation cost will be recognized over the service period on a straight-line basis. For awards granted before July 1, 2005, compensation cost is recognized over the related service period on an accelerated basis pursuant to FASB Interpretation No. 28.

(p) Earnings Per Common Share

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

In the event dividends on a per share equivalent basis are declared on our common stock in excess of the dividends declared on the Series B redeemable convertible preferred stock, the Series B redeemable convertible preferred stock will participate as if the Series B redeemable convertible preferred stock was converted into common stock. Accordingly, the Series B redeemable convertible preferred stock has been determined to be a “participating” security for purposes of computing earnings per share.

(q) Reclassifications

Certain amounts in the prior period have been reclassified to conform to the current period’s presentation. Net earnings and stockholders’ equity have not been affected by these reclassifications.

(2) ACQUISITIONS

On August 1, 2005, we acquired all the outstanding shares of capital stock of Radcliff/Economy Marine Services, Inc. (“Radcliff”) for a purchase price of approximately $52.1 million, net of cash acquired of approximately $2.1 million. The purchase price is composed of approximately $41.8 million paid in cash plus the assumption of Radcliff’s existing outstanding debt of approximately $12.4 million. The acquisition includes two petroleum products terminals, one in Mobile, Alabama and one in Pensacola, Florida, with combined aggregate storage capacity of approximately 350,000 barrels, two tugboats, six barges, and twelve tractors and associated trailers. The consolidated financial statements include the results of operations of the Radcliff facilities from the closing date of the transaction (August 1, 2005). The purchase price was allocated to the assets and liabilities acquired based upon the estimated fair value of the assets and liabilities as of the acquisition date.

Effective October 31, 2005, TransMontaigne Partners purchased a refined product terminal with approximately 150,000 barrels of aggregate storage capacity in Oklahoma City, Oklahoma from Magellan Pipeline Company, L.P. for approximately $1.9 million. The Oklahoma City terminal currently provides integrated terminaling services to a major oil company. The accompanying consolidated financial statements include the results of operations of the Oklahoma City terminal from the closing date of the acquisition (October 31, 2005).

The purchase price was allocated as follows (in thousands):

	Radcliff			Oklahoma City
Restricted cash	$	228			$	—
Trade accounts receivable, net of allowance for doubtful accounts of $47	20,097				—
Discretionary inventory, product linefill and tank bottom volumes	4,259				—
Prepaid expenses and other	292				—
Property, plant and equipment	16,779				2,493
Deferred tax assets	303				—
Goodwill	19,384				—
Trade accounts payable	(3,304		)		—
Accrued environmental obligations	(605		)		(625		)
Deferred tax liabilities	(4,130		)		—
Due to former Radcliff stockholders	(1,000		)		—
Other assumed liabilities	(250		)		(10		)
Cash paid, net of cash acquired	$	52,053			$	1,858

The unaudited pro forma combined results of operations as if the acquisition of the Radcliff and Oklahoma City terminals had occurred on July 1, 2004 are as follows (in thousands, except per share data):

	Nine months ended			Nine months ended
	March 31,			March 31,
	2006			2005
Revenue		$	7,381,755		$	6,212,504
Net earnings		$	11,377		$	59,327
Basic net earnings per common share		$	0.22		$	1.17

(3) EXCHANGE OF TERMINALS

On February 1, 2006, we transferred to BP Plc (“BP”) approximately $5.9 million and six of our Southeast terminals with an aggregate storage capacity of approximately 0.8 million barrels in exchange for nine BP terminals with an aggregate storage capacity of approximately 1.2 million barrels. The BP terminals we received in the exchange are adjacent to certain of our other Southeast terminals. Under the terms of the exchange agreement, we and BP agreed to throughput refined products at the facilities to be owned and operated by the other party. We currently are obligated to throughput approximately 21,000 barrels per day through BP-owned facilities and BP currently is obligated to throughput approximately 26,000 barrels per day through our facilities. The respective throughput obligations are terminal specific and are in effect for the next one to five years.

The exchange of terminals with BP has been reflected in the accompanying financial statements based on the fair value of the terminals received. Included in gain (loss) on disposition of assets, net for the three months ended March 31, 2006, is a loss of approximately $(1.7) million on the exchange of the terminals. The loss on the exchange of the terminals is as follows:

Fair value of net assets received in the exchange:
Land	$	2,389
Terminals, pipelines and equipment	21,775
Environmental obligations assumed	(1,163		)	23,001
Carrying amount of net assets transferred in the exchange:
Cash paid	$	(5,910	)
Land	(1,221		)
Terminals, pipelines and equipment	(18,157		)
Environmental obligations transferred	543			(24,745		)
Loss on exchange of terminals				$	(1,744	)

(4) DISPOSITION OF ASSETS

Gain (loss) on disposition of assets, net for the three months ended March 31, 2006, reflects approximately $(1.7) million loss on the exchange of terminals with BP, approximately $5.5 million gain on the sale of our NYMEX seats, and approximately $6.8 million gain on the sale of product linefill and tank bottom volumes. Gain (loss) on disposition of assets, net for the three months ended March 31, 2005, consists principally of an approximately $2.7 million gain on the sale of land held for investment purposes in Miami, Florida.

Gain (loss) on disposition of assets, net for the nine months ended March 31, 2006, reflects approximately $(1.7) million loss on the exchange of terminals with BP, approximately $5.5 million gain on the sale of our NYMEX seats, approximately $6.8 million gain on the sale of product linefill and tank bottom volumes, approximately $1.1 million gain from the final insurance recovery on the involuntary conversion of our historical Pensacola terminal facilities and approximately $0.1 million gain on the sale of the Wisconsin terminal. Gain (loss) on disposition of assets, net for the nine months ended March 31, 2005, consists principally of an approximately $(3.6) million loss on the involuntary conversion of our historical Pensacola terminal facilities due to the damage caused by Hurricane Ivan offset by an approximately $2.7 million gain on the sale of land held for investment purposes in Miami, Florida.

(5) TRADE ACCOUNTS RECEIVABLE

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

	March 31,			June 30,
	2006			2005
Trade accounts receivable	$	423,116		$	382,324
Less allowance for doubtful accounts	(866		)	(553		)
	$	422,250		$	381,771

(6) UNREALIZED GAINS AND LOSSES ON DERIVATIVE CONTRACTS

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

	March 31,			June 30,
	2006			2005
Unrealized gains—current asset	$	18,992		$	7,620
Unrealized losses—current	(13,725		)	(47,215		)
Unrealized losses—long-term	—			(234		)
Unrealized losses—liability	(13,725		)	(47,449		)
Net asset (liability)	$	5,267		$	(39,829	)

At March 31, 2006 and June 30, 2005, there were no unrealized gains or losses on NYMEX futures contracts because NYMEX futures contracts require daily settlement for changes in commodity prices on open futures contracts.

At March 31, 2006, included in unrealized gains—current asset is an unrealized gain of approximately $1.1 million related to certain short positions taken in the NYMEX options market. At June 30, 2005, included in unrealized losses—current is an unrealized loss of approximately $3.6 million related to certain short positions taken in the NYMEX options market.

(7) PREPAID EXPENSES AND OTHER CURRENT ASSETS

Prepaid expenses and other are as follows (in thousands):

	March 31,			June 30,
	2006			2005
Prepaid insurance		$	2,296		$	2,246
Amounts due from insurance carrier		—			954
Asset held for sale		—			1,200
Prepaid business taxes		1,000			552
Additive detergent		1,170			985
Prepaid software maintenance fees		167			105
Amounts due from Rio Vista/Penn Octane		1,300			—
Other		460			725
		$	6,393		$	6,767

Amounts due from insurance carrier represents our remaining estimated proceeds to be received on insurance claims related to the involuntary conversion of our historical Pensacola terminal facilities due to the damage caused by Hurricane Ivan. During the three months ended December 31, 2005, we collected the final insurance recovery.

During the six months ended December 31, 2005, we decided to retain the land at our historical Pensacola terminal facilities to augment the Pensacola terminal facilities that we acquired from Radcliff (see Note 2 of Notes to consolidated financial statements). In prior periods, asset held for sale was carried at the lower of cost or fair value less costs of disposition and consisted of the land held for sale at our historical Pensacola terminal facilities.

In connection with our due diligence review of certain assets and operations of Rio Vista and Penn Octane, we advanced approximately $1.3 million. The advance is due and payable on demand and is secured by certain terminaling assets in Brownsville, Texas.

(8) PROPERTY, PLANT AND EQUIPMENT

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

	March 31,			June 30,
	2006			2005
Land	$	44,341		$	38,710
Terminals, pipelines and equipment	396,644			374,213
Technology and equipment	14,751			14,751
Tugs and barges	33,708			27,277
Furniture, fixtures and equipment	6,806			6,784
Construction in progress	5,427			1,747
	501,677			463,482
Less accumulated depreciation	(137,377		)	(118,950		)
	$	364,300		$	344,532

(9) OTHER ASSETS

Other assets, net are as follows (in thousands):

	March 31,			June 30,
	2006			2005
Prepaid transportation		$	737	$	326
Goodwill		26,237		6,853
Product supply agreement, net of accumulated amortization of $2,607 and $1,043, respectively		11,993		13,557
Acquired intangible, net of accumulated amortization of $1,542 and $1,167, respectively		958		1,333
Commodity trading membership		—		1,500
Deposits and other assets		281		156
		$	40,206	$	23,725

Prepaid transportation relates to our contractual transportation and deficiency agreement with an interstate product pipeline. The agreement calls for a guaranteed minimum shipping volume over the term of the agreement. If actual volumes shipped are less than the guaranteed minimum volumes, we must make a payment to the interstate pipeline company for any shortfall at the contracted pipeline tariff. Such payments are accounted for as prepaid transportation, since we have a stated time period, after the end of the term of the agreement, to apply the amounts to charges for using the interstate pipeline in the future.

	June 30, 2005			Payments during the period			Amounts applied during the period			Change in estimate during the period			March 31, 2006
	(in thousands)
Prepaid transportation		$	326		$	411		$	—		$	—		$	737

Goodwill represents the excess of the aggregate purchase price over the fair value of the identifiable assets acquired. Goodwill is not amortized, but instead tested for impairment on an annual basis during the three months ended June 30. We carry approximately $6.9 million of goodwill related to our November 1997 acquisition of the ITAPCO terminals and approximately $19.4 million of goodwill related to our August 2005 acquisition of Radcliff.

On November 23, 2004, we granted to MSCG warrants to acquire 5.5 million shares of our common stock at an exercise price of $6.60 per share as partial consideration for agreeing to enter into a 7-year product supply agreement (see Note 16 of Notes to consolidated financial statements). The value ascribed to the product supply agreement is being amortized to income over the 7-year term of the agreement, commencing in January 2005.

Acquired intangible represents the right to use the Coastal Fuels trade name for a period of five years commencing February 28, 2003. The cost of the acquired intangible is being amortized on a straight-line basis over five years.

Commodity trading membership represents the purchase price we paid to acquire two seats on the NYMEX. During the three months ended March 31, 2006, we sold the two seats on the NYMEX for approximately $7.0 million resulting in a gain on sale of approximately $5.5 million.

(10) OTHER ACCRUED LIABILITIES

Other accrued liabilities are as follows (in thousands):

	March 31,			June 30,
	2006			2005
Accrued environmental obligations		$	7,130	$	6,148
Accrued lease abandonment		1,265		1,798
Accrued indemnities—NORCO		1,000		1,000
Accrued transportation and deficiency obligations		393		640
Accrued property taxes		1,237		2,245
Assumed litigation costs—Coastal Fuels assets		325		325
Dividend payable—preferred stock		301		708
Accrued interest payable		6,323		1,521
Customer advances and deposits		873		1,773
Accrued compensation and benefits		2,059		3,004
Due to former owners of Radcliff		1,000		—
Accrued expenses and other		2,396		1,629
		$	24,302	$	20,791

Accrued Lease Abandonment. We vacated certain office space in Denver, Colorado during June 2003 and we vacated certain excess space in Atlanta, Georgia during October 2002. In connection with our acquisition of the Coastal Fuels assets during February 2003, we vacated a sales office in Coral Gables, Florida. The accrual for the abandonment of the office leases represents the excess of the remaining lease payments subsequent to vacancy of the space by us over the estimated sublease rentals to be received based on current market conditions. At March 31, 2006 and June 30, 2005, the accrued liability for lease abandonment costs was approximately $1.3 million and $1.8 million, respectively.

	Accrued liability at June 30, 2005			Change in estimate charged to expense			Amounts paid during the period				Accrued liability at March 31, 2006
	(in thousands)
Accrued lease abandonment		$	1,798		$	—		$	(533	)		$	1,265

We expect to pay the accrued liability of approximately $1.3 million, net of estimated sublease rentals, as follows (in thousands):

Years ending June 30:	Lease payments			Estimated sublease rentals				Accrued liability
2006 (Remainder of the year)		$	265		$	(92	)		$	173
2007		995			(346		)		649
2008		306			(159		)		147
2009		313			(165		)		148
2010		318			(170		)		148
		$	2,197		$	(932	)		$	1,265

(11) DEFERRED REVENUE—SUPPLY CHAIN MANAGEMENT SERVICES

We enter into price management contracts with ground fleet customers and jobbers that permit them to fix the price of their fuel purchases. During the nine months ended March 31, 2006, we originated retail and delivered fuel price management contracts with an estimated fair value of approximately $4.2 million, representing the excess of the amounts we expect to receive from the ground fleet customers and jobbers over our estimate of the forward price curve of the underlying commodity adjusted for location differentials. We have deferred the estimated fair value of these contracts at origination because our estimate of the fair value is not evidenced by quoted market prices or current market transactions for the contracts in their entirety. We amortize the deferred revenue into net revenues attributable to our supply, distribution, and marketing operations over the respective terms of the contracts as the products are delivered. During the nine months ended March 31, 2006, we recognized approximately $5.1 million in revenues attributable to our supply, distribution and marketing operations from the amortization of the deferred revenue from these contracts.

	Deferred revenue at June 30, 2005			Additions during the period			Amounts amortized during the period				Deferred revenue at March 31, 2006
	(in thousands)
Retail price management contracts		$	968		$	3,311		$	(1,790	)		$	2,489
Delivered fuel price management contracts		3,013			928			(3,322		)		619
		$	3,981		$	4,239		$	(5,112	)		$	3,108

(12) DEBT

Debt is as follows (in thousands):

	March 31, 2006			June 30, 2005
Commodity margin loan	$	10,000		$	—
Senior secured working capital credit facility	17,500			—
Senior subordinated notes	200,000			200,000
	227,500			200,000
TransMontaigne Partners’ credit facility	45,508			28,307
	273,008			228,307
Less debt classified as current	(27,500		)	—
Long-term debt	$	245,508		$	228,307

Commodity Margin Loan. We currently have a commodity margin loan agreement with our commodity broker that allows us to borrow up to $10 million to fund certain initial and variation margin requirements in commodities accounts maintained by us with our commodity broker. 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 1.50% (6.1% at March 31, 2006).

Senior Secured Working Capital Credit Facility. The senior secured working capital credit facility provides for a maximum borrowing line of credit equal to the lesser of (i) $400 million and (ii) the borrowing base ($460 million at March 31, 2006), which is a function, among other things, of our cash, accounts receivable, inventory, exchanges, margin deposits and certain reserve adjustments as defined in the facility. Outstanding letters of credit ($115 million at March 31, 2006) are counted against the maximum borrowing capacity available at any time. Borrowings under the senior secured working capital credit facility bear interest (at our option) based on a base rate plus an applicable margin, or LIBOR plus an applicable margin; the applicable margins are a function of the average excess borrowing base availability (as defined therein). Interest on loans under the senior secured working capital credit facility is due and payable periodically, based on the applicable interest rate and related interest period, generally each one, two or three months. The weighted average interest rate on borrowings under the senior secured working capital credit facility was 6.3% during the nine months ended March 31, 2006. In addition, we pay a commitment fee ranging from 0.25% to 0.50% per annum on the total amount of the unused commitments. Borrowings under the senior secured working capital credit facility are secured by, among other things, our cash, accounts receivable, inventories, certain terminal facilities with an orderly liquidation value of not less than $100 million, and certain other current assets. The only financial covenant contained in the senior secured working capital credit facility is a minimum fixed charge coverage ratio test that is computed on a quarterly basis and it is applicable whenever the average availability falls below $50 million for the last month of any quarter (average availability was $189 million for the month ended March 31, 2006). In that event, we must satisfy a minimum fixed charge coverage ratio requirement of 110%. The principal balance of loans and any accrued and unpaid interest is due and payable in full on the maturity date, September 13, 2009.

TransMontaigne Partners’ Credit Facility. On May 9, 2005, TransMontaigne Partners entered into a $75 million senior secured credit facility. The credit facility provides for a maximum borrowing line of credit equal to the lesser of (i) $75 million and (ii) four times Consolidated EBITDA of TransMontaigne Partners (as defined; $86.9 million at March 31, 2006). Borrowings under the credit facility bear interest (at TransMontaigne Partners’ option) based on a base rate plus an applicable margin, or LIBOR plus an applicable margin; the applicable margins are a function of the total leverage ratio (as defined). Interest on loans under the credit facility is due and payable periodically, based on the applicable interest rate and related interest period, generally either one, two or three months. The weighted average interest rate on borrowings under the TransMontaigne Partners’ credit facility was 5.9% during the nine months ended March 31, 2006. In addition, TransMontaigne Partners pays a commitment fee ranging from 0.375% to 0.50% per annum on the total amount of the unused commitments. Borrowings under the TransMontaigne Partners’ credit facility are secured by a lien on TransMontaigne Partners’ assets, including cash, accounts receivable, inventory, general intangibles, investment property, contract rights and real property, except for TransMontaigne Partners’ real property located in Florida. The terms of the credit facility include covenants that restrict TransMontaigne Partners’ ability to make capital expenditures and cash distributions. The primary financial covenants contained in the TransMontaigne Partners’ credit facility are a total leverage ratio test (not to exceed four times) and an interest coverage ratio test (not to be less than three times). The principal balance of loans and any accrued and unpaid interest are due and payable in full on the maturity date, May 9, 2010.

Senior Subordinated Notes. On May 30, 2003, we consummated the sale and issuance of $200 million aggregate principal amount of 91¤8% Senior Subordinated Notes due 2010 and received proceeds of $194.5 million (net of underwriters’ discounts of $5.5 million). The Senior Subordinated Notes mature on June 1, 2010 and interest is payable semi-annually in arrears on each June 1 and December 1 commencing on December 1, 2003. The Senior Subordinated Notes are unsecured and subordinated to all of our existing and future senior debt. Upon the occurrence of certain events, each holder of the Senior Subordinated Notes may require us to repurchase all or a portion of its notes at a purchase price equal to 101% of the principal amount thereof, plus accrued interest. The indenture governing the Senior Subordinated Notes contains covenants that, among other things, limit our ability to incur additional indebtedness, pay dividends on, redeem or repurchase our common stock, make investments, make certain dispositions of assets, engage in transactions with affiliates, create certain liens, and consolidate, merge, or transfer all or substantially all of our assets. The Senior Subordinated Notes are fully and unconditionally guaranteed on a joint and several basis by our subsidiaries other than (1) minor subsidiaries that are inactive and have no assets or operations and (2) since May 27, 2005, TransMontaigne Partners L.P. and its general partner and the wholly-owned subsidiaries of TransMontaigne Partners L.P.

We are a holding company for our subsidiaries, with no independent assets or operations. Accordingly, we are dependent upon the distribution of the earnings of our subsidiaries, whether in the form of dividends, advances or payments on account of inter-company obligations, to service our debt obligations. There are no restrictions on our ability to obtain funds from our subsidiaries other than TransMontaigne Partners L.P. TransMontaigne Partners L.P. is not a party to the indenture governing the Senior Subordinated Notes and, therefore, TransMontaigne Partners L.P. and its subsidiaries are not guarantors of the Senior Subordinated Notes.

Summarized consolidating financial information for TransMontaigne Inc. and the guarantor subsidiaries and TransMontaigne Partners and the non-guarantor subsidiaries as of and for the three months ended March 31, 2006 is as follows (in thousands):

	TransMontaigne Inc. and guarantor subsidiaries				TransMontaigne Partners and non-guarantor subsidiaries				Eliminations				Consolidated
Assets
Current assets		$	716,921			$	2,828			$	(96	)	$	719,653
Property, plant and equipment, net		238,849				125,451				—			364,300
Other assets		78,435				1,731				—			80,166
		$	1,034,205			$	130,010			$	(96	)	$	1,164,119
Liabilities and Equity
Current liabilities		$	395,744			$	2,889			$	(96	)	$	398,537
Long-term debt		200,000				45,508				—			245,508
Other liabilities		50,833				—				(953		)	49,880
Non-controlling interests		—				—				82,566			82,566
Preferred stock		20,608				—				—			20,608
Partners’ equity		—				81,613				(81,613		)	—
Common stockholders’ equity		367,020				—				—			367,020
		$	1,034,205			$	130,010			$	(96	)	$	1,164,119
Statement of Operations
Revenues		$	2,444,607			$	12,090			$	—		$	2,456,697
Cost of product sold and direct operating costs and expenses		(2,390,417		)		(4,695		)		—			(2,395,112		)
Costs and expenses		(6,212		)		(3,936		)		—			(10,148		)
Other income (expenses)		(5,525		)		(740		)		(1,148		)	(7,413		)
Income tax expense		(16,729		)		—				—			(16,729		)
Non-controlling interests’ share in earnings		—				—				(1,571		)	(1,571		)
Net earnings		$	25,724			$	2,719			$	(2,719	)	$	25,724
Statement of Cash Flows
Net cash provided by operating activities		$	7,371			$	5,071			$	—		$	12,442
Net cash provided by (used in) investing activities		16,087				(18,769		)		—			(2,682		)
Net cash provided by (used in) financing activities		(26,976		)		13,611				—			(13,365		)
(Decrease) in cash and cash equivalents		(3,518		)		(87		)		—			(3,605		)
Cash and cash equivalents at beginning of period		12,401				698				—			13,099
Cash and cash equivalents at end of period		$	8,883			$	611			$	—		$	9,494

Summarized consolidating financial information for TransMontaigne Inc. and the guarantor subsidiaries and TransMontaigne Partners and the non-guarantor subsidiaries for the nine months ended March 31, 2006 is as follows (in thousands):

	TransMontaigne Inc. and guarantor subsidiaries				TransMontaigne Partners and non-guarantor subsidiaries				Eliminations				Consolidated
Statement of Operations
Revenues		$	7,325,251			$	34,998			$	—		$	7,360,249
Cost of product sold and direct operating costs and expenses		(7,252,575		)		(12,944		)		—			(7,265,519		)
Costs and expenses		(36,723		)		(10,578		)		—			(47,301		)
Other income (expenses)		(14,221		)		(1,797		)		(4,254		)	(20,272		)
Income tax expense		(10,320		)		—				—			(10,320		)
Non-controlling interests’ share in earnings		—				—				(5,425		)	(5,425		)
Net earnings		$	11,412			$	9,679			$	(9,679	)	$	11,412
Statement of Cash Flows
Net cash provided by (used in) operating activities		$	(16,144	)		$	12,905			$	—		$	(3,239	)
Net cash (used in) investing activities		(33,495		)		(21,812		)		—			(55,307		)
Net cash provided by financing activities		29,042				9,277				—			38,319
Increase (decrease) in cash and cash equivalents		(20,597		)		370				—			(20,227		)
Cash and cash equivalents at beginning of period		29,480				241				—			29,721
Cash and cash equivalents at end of period		$	8,883			$	611			$	—		$	9,494

For all periods ended after the issuance of the Senior Subordinated Notes (May 30, 2003) and before the closing of TransMontaigne Partners’ initial public offering (May 27, 2005), we had no subsidiaries that had not guaranteed the Senior Subordinated Notes on a full and unconditional, joint and several basis, other than subsidiaries that were minor. Accordingly, we have not presented consolidating financial information as of and for the three and nine months ended March 31, 2005, because such information would be substantially duplicative with the accompanying consolidated financial statements. TransMontaigne Partners completed its initial public offering and commenced operations on May 27, 2005.

Scheduled maturities of debt at March 31, 2006 are as follows (in thousands):

Years ending June 30:
2006	$	10,000
2007	—
2008	—
2009	—
2010	263,008
	$	273,008

(13) PREFERRED STOCK

At March 31, 2006 and June 30, 2005, we have authorized the issuance of up to 2,000,000 shares of preferred stock. Preferred stock is as follows (in thousands, except share data):

	March 31, 2006			June 30, 2005
Series B redeemable convertible preferred stock, par value $0.01 per share, 100,000 shares authorized, 20,063 and 47,195 shares issued and outstanding, liquidation preference of $20,063 and $47,195		$	20,608	$	49,249

At March 31, 2006 and June 30, 2005, there were 20,063 and 47,195 shares, respectively, of Series B redeemable convertible preferred stock outstanding. During the nine months ended March 31, 2006, 27,132 shares of Series B redeemable convertible preferred stock were converted into approximately 4.1 million shares of common stock at the request of the holder.

The Series B redeemable convertible preferred stock has a liquidation value of $1,000 per share, bears dividends at the rate of 6% per annum of the liquidation value, and is mandatorily redeemable between June 30, 2007 and December 31, 2007 for shares of common stock and/or cash at our option, subject to limitations on the total number of shares of common stock permitted to be used in the exchange and issued to any stockholder. Dividends are cumulative and payable quarterly. The dividends are payable in cash, unless precluded by contract or the senior secured working capital credit facility, in which case dividends are payable in additional shares of Series B redeemable convertible preferred stock. The Series B redeemable convertible preferred stock may be put to us, at the option of the holder, for cash equal to the greater of its liquidation value or conversion value upon the future occurrence of a fundamental change (including those relating to sale of substantially all of the assets, delisting of our common stock from a national exchange, change in control, bankruptcy filing, and an event of default that accelerates the repayment of our debt). We may call the outstanding shares of Series B redeemable convertible preferred stock after June 30, 2005 if certain specified conditions are met. The Series B redeemable convertible preferred stock is convertible, at the option of the holder, into common stock at $6.60 per share, subject to adjustment upon the occurrence of specified future events. The holders of the Series B redeemable convertible preferred stock have the right to vote on all matters (except the election of directors) with the holders of the common stock (voting collectively as a single class).

Preferred stock dividends on the Series B redeemable convertible preferred stock were $0.7 million and $2.1 million for the nine months ended March 31, 2006 and 2005, respectively. The amount of the Series B redeemable convertible preferred stock dividend recognized for financial reporting purposes for the nine months ended March 31, 2006 and 2005, is composed of the amount of the dividend payable and paid to the holders of the Series B redeemable convertible preferred stock of $1.1 million and $3.3 million, respectively, offset by the amortization of the premium on the carrying amount of the Series B redeemable convertible preferred stock of $0.4 million and $1.2 million, respectively.

At its issuance date (June 28, 2002), the fair value of the Series B redeemable convertible preferred stock exceeded its liquidation value. The carrying amount of the Series B redeemable convertible preferred stock will be decreased ratably over its 5-year term until it equals its liquidation value with an equal reduction in the amount of preferred stock dividends recorded for financial reporting purposes.

(14) COMMON STOCK

At March 31, 2006 and June 30, 2005, we were authorized to issue up to 150,000,000 shares of common stock with a par value of $0.01 per share. At March 31, 2006 and June 30, 2005, there were 50,010,607 shares and 45,586,475 shares issued and outstanding, respectively. Our senior secured working capital credit facility, senior subordinated notes and the certificate of designations of our Series B

redeemable convertible preferred stock contain restrictions on the payment of dividends on our common stock.

We have a restricted stock plan that provides for awards of common stock to certain key employees, subject to forfeiture if employment terminates prior to the applicable vesting dates. Information about restricted common stock activity for the nine months ended March 31, 2006 and the year ended June 30, 2005 is as follows:

	Total shares			Vested shares			Unvested shares
Outstanding at June 30, 2004		2,178,003			553,795			1,624,208
Granted		689,200			—			689,200
Cancelled		(229,350	)		—			(229,350	)
Repurchased from employees for withholding taxes		(131,625	)		(131,625	)		—
Vested		—			446,758			(446,758	)
Outstanding at June 30, 2005		2,506,228			868,928			1,637,300
Granted		478,000			—			478,000
Cancelled		(90,895	)		—			(90,895	)
Repurchased from employees for withholding taxes		(133,022	)		(133,022	)		—
Vested		—			428,280			(428,280	)
Outstanding at March 31, 2006		2,760,311			1,164,186			1,596,125

During the nine months ended March 31, 2006, we granted awards of 478,000 shares of restricted common stock to key employees. The deferred stock based compensation associated with those awards was approximately $4.6 million, which is being amortized into income over their four-year vesting period.

Amortization of deferred compensation of approximately $2.2 million and $2.0 million is included in selling, general and administrative expense for the nine months ended March 31, 2006 and 2005, respectively.

(15) STOCK OPTIONS

Information about stock option activity for the nine months ended March 31, 2006 and the year ended June 30, 2005, is as follows:

	Shares		Weighted average exercise price
Outstanding at June 30, 2004	885,500			$	4.48
Cancelled	(31,600	)		3.75
Exercised	(85,998	)		4.05
Outstanding at June 30, 2005	767,902			4.55
Cancelled	(3,000	)		11.00
Exercised	(59,800	)		3.75
Outstanding at March 31, 2006	705,102			$	4.59
Exercisable at March 31, 2006	675,102			$	4.57

Information about stock options outstanding under the 1997 Plan at March 31, 2006, is as follows:

								Options exercisable
Range of exercise prices	Number outstanding		Weighted average remaining life in years		Weighted average exercise prices			Number exercisable		Weighted average exercise prices
$3.75—7.25		695,602		4.8		$	4.49		665,602		$	4.46
$11.00—13.50		8,500		2.7		$	11.88		8,500		$	11.88
$17.25		1,000		1.4		$	17.25		1,000		$	17.25
		705,102							675,102

(16) WARRANTS

On November 23, 2004, we granted to MSCG warrants to acquire 5.5 million shares of our common stock at an exercise price of $6.60 per share as partial consideration for agreeing to enter into a 7-year product supply agreement. The fair value of the warrants at the grant date of approximately $14.6 million was recorded as an increase to other assets (product supply agreement—see Note 9 of Notes to consolidated financial statements) and additional paid-in capital. The primary assumptions used to estimate the fair value of the warrants using the Black-Scholes option-pricing model were as follows: no dividend yield, expected volatility of 41%, risk-free interest rate of 3.62%, and a contractual life of 5.3 years.

(17) COMMITMENTS AND CONTINGENCIES

Legal Proceedings. We have been named as a defendant in various lawsuits and a party to various other legal proceedings, in the ordinary course of business, some of which are covered in whole or in part by insurance. We believe that the outcome of such lawsuits and other proceedings will not individually or in the aggregate have a material adverse effect on our consolidated financial condition, results of operations, or cash flows. At March 31, 2006 and June 30, 2005, we have accrued obligations for legal settlements of approximately $0.3 million and $0.3 million, respectively, representing our best estimate of our loss contingencies that are probable of occurrence (see Note 10 of Notes to consolidated financial statements).

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 approximately $0.7 million per year for a five-year period through June 30, 2006. At June 30, 2005, we had an accrued liability of approximately $0.6 million representing our estimate of the future amounts we expect to pay for the shortfall in volumes for the remainder of the term of the agreement. During the nine months ended March 31, 2006, we paid approximately $0.4 million as settlement for our shortfall in volumes for the year ended June 30, 2005. Based on actual throughput volumes for the nine months ended March 31, 2006, we increased our estimate of the liability by approximately $0.1 million resulting in a remaining accrued liability of approximately $0.4 million at March 31, 2006.

	June 30, 2005				Payments during the period			Amounts applied during the period			Change in estimate during the period				March 31, 2006
	(in thousands)
Accrued liability—T&D obligations		$	(640	)		$	386		$	—		$	(139	)		$	(393	)

Operating Leases. Future minimum lease payments under our non-cancelable operating leases are as follows (in thousands):

Years ending June 30:	Office space		Vessel charters		Terminal and pipeline capacity			Property and equipment
2006 (Remainder of the year)	$	373	$	3,665		$	590		$	125
2007	1,490		9,347			2,494			429
2008	1,648		—			2,413			354
2009	1,630		—			807			231
2010	1,695		—			92			110
Thereafter	2,573		—			5			194
	$	9,409	$	13,012		$	6,401		$	1,443

Rental expense under operating leases is as follows (in thousands):

	Nine months ended March 31,
	2006		2005
Office space	$	1,060	$	1,277
Vessel charters	11,295		9,023
Terminal and pipeline capacity	2,798		3,650
Property and equipment	560		392
	$	15,713	$	14,342

(18) EARNINGS PER SHARE

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

	Three months ended March 31,		Nine months ended March 31,
	2006	2005	2006	2005
Basic weighted average shares	48,404	39,793	47,890	39,672
Effect of dilutive securities:
Restricted common stock subject to continuing vesting requirements	806	505	923	314
Stock options	295	346	326	282
Series B redeemable convertible preferred stock	3,040	11,209	3,427	11,209
MSCG warrants	832	705	1,121	232
Diluted weighted average shares	53,377	52,558	53,687	51,709

We exclude potentially dilutive securities from our computation of diluted earnings per share when their effect would be anti-dilutive. The following securities were excluded from the dilutive earnings per share computation for the three and nine months ended March 31, 2006, as their inclusion would have been anti-dilutive (in thousands):

	March 31,
	2006
Restricted common stock subject to continuing vesting requirements		464
Stock options		10

For the three months ended March 31, 2006, certain shares of restricted common stock were excluded because the unamortized deferred compensation exceeded the average quoted market price of our common stock and certain stock options were excluded because their exercise prices exceeded the average quoted market price of our common stock during the period. The excluded shares of restricted common stock had unamortized deferred compensation of $9.72 per share. The excluded stock options had a weighted average exercise price of $12.45 per share.

(19) BUSINESS SEGMENTS

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

· Terminals, pipelines, and tugs and barges—consists of an extensive terminal and pipeline infrastructure that handles refined petroleum products with transportation connections via pipelines, barges, vessels, rail cars and trucks to our facilities or to TransMontaigne Partners’ facilities with an emphasis on transportation connections primarily through the Colonial, Plantation, TEPPCO, Explorer and Magellan pipeline systems.

· Supply, distribution and marketing—consists of services for the supply and distribution of refined petroleum products through rack spot sales, contract sales, and bulk sales in the physical and derivative markets, with retail, wholesale, industrial and commercial customers using our terminal racks and marine refueling equipment, and providing related value-added fuel procurement and supply chain management services.

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

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

Our CEO assesses the “margins and inventory management” of our supply, distribution, and marketing segment using financial information that is prepared pursuant to the mark-to-market method of accounting. Our presentation of “margins and inventory procurement” for the supply, distribution and marketing segment differs from “margins” for that segment as presented in our accompanying historical consolidated statements of operations due to the treatment of our inventories—discretionary volumes (which includes both volumes held for immediate sale or exchange and volumes held for base operating requirements). Inventories—discretionary volumes are reflected at fair value, which matches the treatment of our derivative contracts (e.g., volumes due to others under exchange agreements, forward purchase and sale agreements) and risk management contracts (principally NYMEX futures contracts). Because our inventories—discretionary volumes are composed of refined petroleum products, which are commodities with established trading markets and readily ascertainable market prices, we believe that the financial performance of our supply, distribution and marketing segment can be appropriately evaluated using the mark-to-market method. Our inventories—discretionary volumes are carried at the lower of cost or market in the accompanying historical consolidated balance sheets, while our derivative and risk management contracts are carried at fair value. As a result, if refined petroleum product prices are increasing during the end of a quarter, we may report in the accompanying historical statements of operations significant losses on derivative and risk management contracts and significant deferred gains on discretionary inventory

volumes at the end of that quarter and report significant gains on our beginning inventories—discretionary volumes when they are sold in the following quarter. Therefore, the effects of changes in the fair value of our inventories—discretionary volumes are included in “margins and inventory management” attributable to our supply, distribution and marketing segment in the period in which the fair value actually changes.

The differences between “margins and inventory management” used by our CEO in reviewing the financial performance of our business segments and the “margins” reported in our accompanying historical financial statements are presented as “Inventory adjustments” in the accompanying “Reconciliation to earnings before income taxes.”

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

	Three months ended March 31,						Nine months ended March 31,
	2006			2005			2006			2005
Terminals, pipelines, and tugs and barges:
TransMontaigne Partners L.P. facilities	$	7,395		$	5,655		$	22,054		$	14,274
Brownsville facilities	1,644			1,230			4,467			3,284
Southeast facilities	3,765			5,442			11,381			16,251
River facilities	(835		)	1,145			(212		)	2,098
Other	505			335			207			2,033
Margins	12,474			13,807			37,897			37,940
Supply, distribution and marketing:
Light oils—marketing margins:
TransMontaigne Partners L.P. facilities	5,231			1,666			20,404			8,612
Southeast facilities	187			2,744			(11,897		)	11,340
River facilities	1,170			525			3,864			2,043
Other	800			60			429			232
	7,388			4,995			12,800			22,227
Heavy oils—marketing margins	2,445			2,980			13,254			10,956
Supply chain management services margins	2,469			6,067			3,458			12,715
Margins	12,302			14,042			29,512			45,898
Inventory procurement and management:
Gains (losses) from risk management of light oil volumes to be liquidated upon commencement of MSCG product supply agreement	—			(181		)	—			9,437
Increase in value of light oil volumes nominated under the MSCG product supply agreement prior to receipt of the product at our terminals	24,314			36,632			51,720			36,632
Increase in value of base operating inventory	13,967			39,871			30,997			42,980
(Losses) from risk management of base operating inventory and light oil volumes nominated under the MSCG product supply agreement	(7,409		)	—			(9,069		)	—
Storage fees for light oil tank capacity	(457		)	(857		)	(1,371		)	(5,302		)
Other financial and costing variances, net	8,268			6,286			(31,884		)	16,314
Trading activities, net	—			—			—			28
Inventory management	38,683			81,751			40,393			100,089
Margins and inventory management	$	63,459		$	109,600		$	107,802		$	183,927

Reconciliation to earnings before income taxes:
Margins and inventory management	$	63,459		$	109,600		$	107,802		$	183,927
Inventory adjustments:
Gains recognized on beginning inventories—discretionary volumes	13,567			10,210			2,369			3,712
Gains deferred on ending inventories—discretionary volumes	(15,441		)	(21,530		)	(15,441		)	(21,530		)
Total margins	61,585			98,280			94,730			166,109
Other items:
Selling, general and administrative expenses	(12,142		)	(9,885		)	(37,050		)	(32,120		)
Merger related expenses	(1,350		)	—			(1,350		)	—
Depreciation and amortization	(7,273		)	(6,274		)	(20,703		)	(17,808		)
Gain (loss) on disposition of assets, net	10,617			2,993			11,802			(606		)
Operating income	51,437			85,114			47,429			115,575
Other expense, net	(7,413		)	(6,672		)	(20,272		)	(23,671		)
Earnings before income taxes	$	44,024		$	78,442		$	27,157		$	91,904

Supplemental information regarding our revenues for our business segments is summarized below (in thousands):

	Three months ended March 31,				Nine months ended March 31,
	2006		2005		2006		2005
Terminals, pipelines, and tugs and barges:
Revenues from external customers	$	14,135	$	11,244	$	41,144	$	33,540
Inter-segment revenues	18,234		18,010		53,286		49,708
Total revenues	$	32,369	$	29,254	$	94,430	$	83,248
Supply, distribution and marketing:
Revenues from external customers	$	2,424,328	$	2,140,187	$	7,265,819	$	5,980,972
Inter-segment revenues	—		—		—		—
Total revenues	$	2,424,328	$	2,140,187	$	7,265,819	$	5,980,972

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

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

POTENTIAL CHANGE IN CONTROL OF TRANSMONTAIGNE INC.

On March 27, 2006, we entered into a definitive agreement with SemGroup, L.P. and its affiliates, which we refer to, individually and collectively, as “SemGroup,” to exchange all of our outstanding shares of common stock, including shares of our common stock issuable upon conversion of our outstanding Series B redeemable convertible preferred stock, for $9.75 per share in cash. The consummation of the merger is subject to, among other things: (i) approval of a majority of the outstanding shares of common stock and Series B preferred stock, on an as-converted basis, voting as a single class at a special meeting of stockholders, (ii) receipt by SemGroup of proceeds of the financings substantially upon the terms set forth in the commitment letters and (iii) receipt of customary approvals, including the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (“HSR Act”).

On April 21, 2006, we filed with the Federal Trade Commission and the Department of Justice the notification and report forms required by the HSR Act with respect to the proposed merger with SemGroup. Unless it is extended, the waiting period under the HSR Act currently is expected to end on or before May 22, 2006.

On April 26, 2006, we received a proposal from Morgan Stanley Capital Group Inc. (“Morgan Stanley”) to acquire us at a price of $10.50 per share, in cash, and otherwise on substantially the same terms as our pending sale to SemGroup. Morgan Stanley’s proposal is subject only to (i) satisfactory review and approval of the disclosure schedule and other schedules and exhibits to the SemGroup merger agreement, (ii) satisfactory completion of confirmatory due diligence, which Morgan Stanley is prepared to commence immediately and which they believe can be completed, with our cooperation, in five days, and (iii) execution of a definitive merger agreement. On April 28, 2006, our board of directors authorized our senior management to meet with representatives of Morgan Stanley to negotiate a definitive merger agreement in accordance with the terms of the Morgan Stanley offer. On May 8, 2006 we approved the terms of a definitive merger agreement with Morgan Stanley. SemGroup has until the close of business on Thursday, May 11, 2006, to provide our board of directors with a revised merger agreement that our board of directors determines is at least as favorable to our stockholders as the Morgan Stanley merger agreement.

On May 1, 2006, we filed with the Securities and Exchange Commission preliminary proxy materials regarding the proposed merger with SemGroup.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

A summary of the significant accounting policies that we have adopted and followed in the preparation of our consolidated financial statements is detailed in our consolidated financial statements for the year ended June 30, 2005, included in our Annual Report on Form 10-K filed on September 13, 2005 (see Note 1 of Notes to 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 (used to evaluate the financial performance of our business segments); fair value of derivative contracts; and accrued environmental obligations. These estimates are based on our knowledge and understanding of current conditions and actions we may take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events.

Subsequent changes in these estimates may have a significant impact on our financial condition and results of operations.

SIGNIFICANT DEVELOPMENTS DURING THE NINE MONTHS ENDED MARCH 31, 2006

On July 20, 2005, TransMontaigne Partners announced that it declared a distribution of $0.15 per unit payable on August 9, 2005 to unitholders of record on July 29, 2005.

On August 1, 2005, we announced the closing of the acquisition of Radcliff/Economy Marine Services, Inc. (“Radcliff”) for a purchase price of approximately $52.1 million, net of cash acquired of approximately $2.1 million. The purchase price is composed of approximately $41.8 million paid in cash plus the assumption of Radcliff’s existing outstanding debt of approximately $12.4 million. The acquisition includes two petroleum products terminals, one in Mobile, Alabama and one in Pensacola, Florida, with combined aggregate storage capacity of approximately 350,000 barrels. In addition, we acquired two tugboats, six barges, twelve tractors and associated trailers and approximately $22.0 million in net working capital.

On August 16, 2005, we announced the signing of purchase agreements to acquire certain LPG assets and refined petroleum products tank capacity in Brownsville, Texas and Matamoros, Mexico from Rio Vista Energy Partners L.P. and Penn Octane Corporation for a total purchase price of approximately $27.5 million. The closing of the acquisition is subject to our completion of additional due diligence.

During the three months ended September 30, 2005, approximately 27,132 shares of Series B redeemable convertible preferred stock were converted into approximately 4.1 million shares of common stock.

On August 29, 2005 and September 24, 2005, Hurricane Katrina and Hurricane Rita caused severe damage along the United States Gulf Coast and into the southern United States. There was no significant long-term damage to our facilities caused by these hurricanes.

On October 20, 2005, TransMontaigne Partners announced that it declared a distribution of $0.40 per unit payable on November 8, 2005 to the unitholders of record on October 31, 2005.

On October 24, 2005, Hurricane Wilma struck Florida. There was no significant long-term damage to our facilities caused by Hurricane Wilma.

On January 12, 2006, we announced the signing of a terminal exchange agreement with BP affecting seventeen terminals located in the Southeast, which were formerly operated by us pursuant to an informal joint venture with BP. The transaction closed on January 31, 2006. Under the terms of the agreement, BP owns and operates six terminals and we own and operate nine terminals, while the remaining two terminals are supplied separately and operated by us for the benefit of both companies. BP is obligated to throughput approximately 26,000 barrels per day through our owned facilities and we are obligated to throughput approximately 21,000 barrels per day through BP’s owned facilities.

On January 19, 2006, TransMontaigne Partners announced a distribution of $0.40 per unit payable on February 8, 2006 to unitholders of record on January 31, 2006.

On January 19, 2006, TransMontaigne Partners announced that it had authorized a program for the repurchase, from time to time, of outstanding common units of the Partnership for purposes of making subsequent grants of restricted units under the Partnership’s Long-Term Incentive Plan to key employees and executive officers of TransMontaigne Services Inc., and the non-employee directors of its general

partner. TransMontaigne Partners anticipates repurchasing annually up to approximately $1.2 million of aggregate market value of its outstanding common units for this purpose. However, there is no guarantee as to the exact number of units or dollar amount that will be repurchased, and the purchases may be discontinued at any time.

On February 23, 2006, TransMontaigne Partners announced the execution of a new five-year terminaling services agreement with Marathon Petroleum Company LLC regarding approximately 1.0 million barrels of asphalt storage capacity throughout its Florida terminal facilities. The terminaling services agreement became effective on February 20, 2006 at the Jacksonville and Port Manatee, Florida terminal facilities and became effective on May 1, 2006 at the Cape Canaveral and Port Everglades, Florida terminal facilities. Simultaneous with the effective dates of the Marathon agreement, the existing agreement with TransMontaigne Partners’ current asphalt customer expired.

On March 3, 2006, we announced the execution of a new seven-year terminaling services agreement with a subsidiary of Valero Energy Corporation regarding approximately 1.0 million barrels of gasoline and distillate storage capacity throughout our River terminal facilities. The terminaling services agreement became effective April 1, 2006.

SUBSEQUENT EVENTS

On April 19, 2006, TransMontaigne Partners announced a distribution of $0.43 per unit payable on May 9, 2006 to unitholders of record on April 28, 2006.

RESULTS OF OPERATIONS—MARKET CONDITIONS

During September and through October 10, 2005, we witnessed substantial price disparities and market disruptions in the wholesale markets. The major refiners were pricing their branded products substantially below the price at which they were offering unbranded products in the wholesale market. The price of product in the wholesale market generally reflects the cost of product at the tailgate of the refinery adjusted for the cost of transportation to the wholesale market. In effect, the major refiners were subsidizing the price of product in the wholesale markets; major refiners were charging their branded customers wholesale market prices that were below the cost of product in the bulk markets. For example, the low branded and unbranded price of unleaded gasoline in the Charlotte, North Carolina wholesale market from August 1, 2005 through March 31, 2006 are as follows ($/gallon):

From August 29, 2005 through September 7, 2005, we sold product to our contract customers at our Southeast facilities based on the subsidized prices being offered by major refiners to their branded customers in the wholesale market, resulting in realized losses on our light oil marketing margins of approximately $12 million. We historically sell approximately 80,000 barrels per day of unbranded product at our Southeast facilities under contracts with OPIS indexes. On September 7, 2005, we informed our contract customers at our Southeast facilities that we were exercising our rights under our sales contracts to temporarily cease selling them product under the OPIS-based pricing provisions in their contracts with us. However, we offered to sell product to these customers under interim pricing provisions that would stay in effect until the pricing disparities in the wholesale market subsided. From September 8, 2005 to October 10, 2005, we averaged approximately 45,000 barrels per day under contracts with interim pricing provisions. The interim pricing provisions were intended to reflect the cost of product in the bulk markets and the cost of transportation from the bulk markets to the wholesale markets. To the extent that contract customers at our Southeast facilities submit to us notices of dispute claiming that we did not have the right to suspend the OPIS-pricing provisions in our sales contracts and such disputes are not resolved directly with our customers, we will resolve such disputes through mediation and arbitration provisions of the applicable contracts. We continue to believe that we were within our rights under the contracts to impose interim pricing provisions during the period of price disparities and market disruptions in the wholesale

markets. During December 2005, we renegotiated the contract with our largest Southeast contract customer and the customer waived any rights it may have had for claims against us. We believe that the outcome of the disputes with our customers will not individually or in the aggregate have a material adverse effect on our consolidated financial condition, results of operations, or cash flows. At March 31, 2006, we have not accrued any reserves for potential loss contingencies resulting from the disputes with our customers because such a loss, in our view, is not probable of occurrence.

Prices for refined petroleum products were higher during the three and nine months ended March 31, 2006, as compared to the same period in 2005, resulting in higher per unit revenues from the sales of refined petroleum products. Prices for gasoline and heating oil for the three and nine months ended March 31, 2006 and 2005 are as follows (in $/gallon):

	Three months ended March 31,		Nine months ended March 31,
	2006	2005	2006	2005
Unleaded gasoline:
High	2.0375	1.6170	3.1165	1.6170
Low	1.4385	1.1078	1.3605	0.9325
Average	1.6955	1.3219	1.7503	1.2472
Heating oil:
High	1.8708	1.5948	2.5675	1.5948
Low	1.5480	1.1008	1.5295	1.0253
Average	1.7176	1.3587	1.7816	1.2770

Relative month-end commodity prices per gallon from June 30, 2004 to March 31, 2006 (near-month NYMEX close on the last day of the month) are as follows ($/gallon):

Our light oil marketing margins are affected by the supply and demand for light oil products in the wholesale delivery locations (e.g., terminal truck racks). While demand for light oil products may be influenced by seasonality (e.g., higher demand for gasoline during the summer driving season and higher demand for heating oil during the winter heating season), we believe that the availability of supply of light oil products in the wholesale delivery markets has the most significant impact on our ability to generate favorable light oil marketing margins. The availability of supply of light oil products in the wholesale delivery markets is impacted by a variety of factors, including the availability of crude oil supplies, current utilization of refining capacity, the shape of the forward price curve in the futures market, refinery crack spreads, and availability of pipeline and vessel shipping capacity. For example, adequate crude oil supplies, high utilization of refining capacity, an increasing forward price curve, favorable refinery crack spreads and available shipping capacity would likely result in an abundance of light oil products in the wholesale delivery markets. An abundance of light oil products in the wholesale delivery locations generally produces lower marketing margins. Conversely, tight crude oil supplies, refinery outages, a decreasing forward price curve, moderate refinery crack spreads and limited shipping capacity would likely result in tight supply of light oil products in the wholesale delivery markets. A tight supply of light oil products in the wholesale delivery locations generally produces higher marketing margins.

During the three months ended March 31, 2006, the NYMEX futures market initially anticipated rising gasoline and heating oil prices as the prices in the prompt month (i.e., the immediately succeeding month) were slightly higher than the prices in the current month. At the end of March 2006, the NYMEX futures market anticipated declining gasoline and heating oil prices as the prices in the prompt month were slightly lower that the prices in the current month. A combination of anticipated higher future prices (referred to as a “contango” market) and favorable refinery crack spreads encouraged refiners to maximize production and ship their gasoline and distillate production to the wholesale delivery markets. An increase in gasoline and distillate inventories in the wholesale delivery markets generally results in limited margin opportunities on wholesale deliveries.

The value of petroleum products in any local delivery market is the sum of the commodity price as reflected on the NYMEX and the basis differential for that local delivery market. The basis differential for any local delivery market is the spread between the cash price in the physical market and the quoted price in the futures markets for the prompt month. For those physical and derivative positions as to which we choose to manage the associated commodity price risk, the primary objective of our risk management strategy is to minimize the financial impact on us from changes in petroleum commodity prices affected by world-wide crude oil and petroleum products supply and demand disruptions (e.g., the Iraq war, OPEC production quotas, disruptions due to hurricanes and other weather-related occurrences, foreign country work stoppages, and major refinery outages). We utilize NYMEX futures contracts to manage the financial impact on us from changes in commodity prices due to “world-wide” events. NYMEX futures contracts are obligations to purchase or sell a specific volume of inventory at a fixed price at a future date. We believe that the utilization of NYMEX futures contracts to manage commodity price risk minimizes the financial impact on us from changes in “world-wide” commodity prices. We generally do not manage the financial impact on us from changes in basis differentials affected by local market supply and demand disruptions (e.g., local pipeline delivery disruptions, local refinery outages, periodic change in local government specifications for gasolines and distillates, local seasonality in product demand, and

disruptions due to local weather related occurrences). The impacts on us from changes in basis differentials are as follows:

Basis Differential

Change in Basis
Differential

Net
Position

Financial
Impact

Futures price in excess of physical market price (“negative basis differential”)

Increasing

Long

Loss

Futures price in excess of physical market price

Increasing

Short

Gain

Futures price in excess of physical market price

Decreasing

Long

Gain

Futures price in excess of physical market price

Decreasing

Short

Loss

Physical market price in excess of futures price (“positive basis differential”)

Increasing

Long

Gain

Physical market price in excess of futures price

Increasing

Short

Loss

Physical market price in excess of futures price

Decreasing

Long

Loss

Physical market price in excess of futures price

Decreasing

Short

Gain

The spread between the month-end basis differential (quoted near-month NYMEX futures price and the cash price in the United States Gulf Coast market) and the monthly average basis differential from June 30, 2004 to March 31, 2006 are as follows ($/gallon):

When we nominate refined petroleum products to be supplied by third parties at our terminals, we enter into futures contracts (i.e., short futures contracts) to sell a corresponding amount of product to protect against price fluctuations for the underlying commodity. When we ultimately sell the underlying inventory to a customer, we unwind the related risk management contract. In order to effectively manage commodity price risk, we must predict when we will sell the underlying product. When we enter into a forward sale commitment to deliver product to a customer in the future at a fixed price, we enter into a futures contract (i.e., a long futures contract) to purchase a corresponding amount of product to protect against price fluctuations for the underlying commodity. When we ultimately deliver the underlying

product to a customer, we unwind the related risk management contract. We believe that the uncertainties of crude oil supply caused in part by the Iraq war, the possibility of unplanned refinery outages and the increased participation of hedge funds in the futures markets periodically results in a lack of correlation between the cash market and the futures market (i.e., the physical cash markets are driven by supply and demand, whereas, the futures markets are driven by geopolitical events and expectations). When there is a lack of correlation between the cash market and the futures market, the cost of managing our commodity price risk may increase. Because of the overall high level of commodity prices combined with the possibility of an increase in the cost of managing the commodity price risk associated with our discretionary inventories, we distributed and transported fewer barrels of discretionary inventories through our terminal infrastructure during the year ended June 30, 2005 and the nine months ended March 31, 2006, which resulted in lower inventory volumes available for rack spot sales.

RESULTS OF OPERATIONS—BUSINESS SEGMENTS

We are required to report measures of profit and loss that are used by our chief operating decision maker (our Chief Executive Officer or CEO) in assessing the financial performance of our reportable segments. Our CEO assesses the financial performance of each of our reportable segments using a financial performance measure, which we refer to as “margins and inventory management.”

Terminals, pipelines, tugs and barges—margins

Our “margins” for the terminal, pipelines, tugs and barges segment are identical to the “margins” for such segment described under “Results of Operations—Historical Financial Statements.” Selected quarterly “margins” for the terminal, pipelines, tugs and barges segment for each of the three and nine months ended March 31, 2006 and 2005 are summarized below (in thousands):

	Three months ended March 31,						Nine months ended March 31,
	2006			2005			2006			2005
Terminals, pipelines, tugs and barges:
TransMontaigne Partners L.P. facilities:
Revenues	$	12,090		$	9,714		$	34,998		$	26,406
Direct operating costs and expenses	(4,695		)	(4,059		)	(12,944		)	(12,132		)
Net operating margins	7,395			5,655			22,054			14,274
Brownsville facilities:
Revenues	3,045			2,462			8,703			7,133
Direct operating costs and expenses	(1,401		)	(1,232		)	(4,236		)	(3,849		)
Net operating margins	1,644			1,230			4,467			3,284
Southeast facilities:
Revenues	8,468			9,640			25,750			28,655
Direct operating costs and expenses	(4,703		)	(4,198		)	(14,369		)	(12,404		)
Net operating margins	3,765			5,442			11,381			16,251
River facilities:
Revenues	2,468			2,668			6,868			7,142
Direct operating costs and expenses	(3,303		)	(1,523		)	(7,080		)	(5,044		)
Net operating margins	(835		)	1,145			(212		)	2,098
Other:
Revenues	6,298			4,770			18,111			13,912
Direct operating costs and expenses	(5,793		)	(4,435		)	(17,904		)	(11,879		)
Net operating margins	505			335			207			2,033
Margins	$	12,474		$	13,807		$	37,897		$	37,940

Supply, distribution and marketing—margins and inventory management

Our presentation of “margins and inventory management” for the supply, distribution and marketing segment differs from “margins” for that segment as presented in our accompanying historical consolidated statements of operations due to the treatment of our inventories—discretionary volumes (which includes both volumes held for immediate sale or exchange and volumes held for base operating requirements). Inventories—discretionary volumes are reflected at fair value, which matches the treatment of our derivative contracts (e.g., volumes due to others under exchange agreements, forward purchase and sale agreements) and risk management contracts (principally NYMEX futures contracts). Because our inventories—discretionary volumes are composed of refined petroleum products, which are commodities with established trading markets and readily ascertainable market prices, we believe that the financial performance of our supply, distribution and marketing segment can be appropriately evaluated using the mark-to-market method. Our inventories—discretionary volumes are carried at the lower of cost or market in the accompanying historical consolidated balance sheets, while our derivative and risk management contracts are carried at fair value. As a result, if refined petroleum product prices are increasing during the end of a quarter, we may report in the accompanying historical statement of operations significant losses on derivative and risk management contracts and significant deferred gains on discretionary inventory volumes at the end of that quarter and report significant gains on our beginning inventories—discretionary volumes when they are sold in the following quarter. Therefore, the effects of changes in the fair value of our inventories—discretionary volumes are included in “margins and inventory management” attributable to our supply, distribution and marketing segment in the period in which the fair value actually changes.

Marketing margins. Light oil and heavy oil marketing margins are based on the actual selling price to the customer, the cost of product sold and the standard cost of transportation and throughput. For purposes of computing our light oil margins, the cost of product sold is based on the prior day’s market value of the product as determined in the United States Gulf Coast bulk market for all facilities except TransMontaigne Partners’ Florida facilities. For TransMontaigne Partners’ Florida facilities, the cost of product sold is based on an OPIS index.

Supply chain management services margins include margins from the sale of refined petroleum products under delivered fuel price management contracts, net gains and losses from the settlement of retail price management contracts and fees from logistical supply chain management services. Margins under delivered fuel price management contracts are based on the relationship of the spread between the futures price and the physical wholesale market price at the date the contract was executed with the customer (referred to as “basis sold”) and the spread between the futures price and the physical wholesale market price at the date the product was lifted by the customer (referred to as “basis bought”). Net gains and losses from the settlement of retail price management contracts are based on basis sold and basis bought in the retail market. Fees from logistical supply chain management services are charged on a per gallon basis for the use of our proprietary web-based inventory management system.

Inventory procurement and management. During the three months ended March 31, 2005, we commenced purchasing light oil product from MSCG for our Florida and Southeast marketing activities. Pursuant to the terms of the MSCG supply agreement, the unit cost of the products is determined prior to their actual delivery to our terminals. Consequently, during rising commodity prices, we will recognize gains between the date the product is priced and the date of its receipt because the MSCG supply agreement qualifies as a derivative contract (see Note 1(g) of Notes to consolidated financial statements). During declining commodity prices, we will recognize losses between the pricing date and the date of receipt. Because of the significant increase in commodity prices experienced during the three and nine months ended March 31, 2006, we recognized approximately $24.3 million and $51.7 million, respectively, of gains on approximately 3.0 million barrels, which represents the average volume of barrels priced under the terms of the MSCG supply agreement but not yet delivered to our terminals. At March 31, 2006, we were managing the commodity price risk associated with approximately 3.0 million barrels of undelivered

in-transit volumes supplied to our terminals under the MSCG supply agreement. During the three and nine months ended March 31, 2006, we recognized (losses) of approximately $(7.4) million and $(9.1) million, respectively, from these risk management activities.

We currently maintain approximately 1.5 million barrels of base operating inventory in terminal facilities as safety stock to ensure an adequate supply of inventory to meet our delivery obligations to our customers. During periods of rising commodity prices, we will recognize increases in the value of these volumes, whereas during periods of declining commodity prices, we will recognize decreases in the value of these volumes. During the three and nine months ended March 31, 2006, the value of our base operating inventory increased by approximately $14.0 million and $31.0 million, respectively, due to rising commodity prices. At March 31, 2006, the commodity price risk associated with the approximately 1.5 million barrels of base operating inventory volumes was not managed.

Storage fees for light oil tank capacity decreased during the three and nine months ended March 31, 2006 as compared to 2005, due principally to the commencement of our terminaling services agreements with MSCG for tank capacity at our Southeast facilities that historically had been leased to our supply, distribution and marketing operations.

Other financial and costing variances, net include the financial variances (favorable and unfavorable) associated with the purchase price of our inventory volumes held for immediate sale or exchange, the correlation between the physical market and the futures market, the variance between our actual transportation and throughput charges and our standard costs, and the net margins generated from bulk transactions. During periods of strong correlation between the physical and futures markets, we will recognize nominal variances. During periods of expanding spreads between the cash price in the physical market and the quoted price in the futures markets for the prompt month, we will recognize gains (losses) if we are net short (long) in the physical market. During periods of contracting spreads between the cash price in the physical market and the quoted price in the futures markets for the prompt month, we will recognize gains (losses) if we are net long (short) in the physical market. For the nine months ended March 31, 2006, other financial and costing variances, net were unfavorably impacted by changes in the injection date of products into the Colonial pipeline caused by Hurricanes Katrina and Rita. The cost of product purchased under the MSCG product supply agreement is based on the actual injection date of products into the Colonial pipeline. We enter into risk management contracts to manage the commodity price risk associated with product purchased under the MSCG product supply agreement based on the expected injection date of products into the Colonial pipeline. When the cost of product purchased under the MSCG product supply agreement is determined by reference to a period of time other than the period of time in which we entered into the associated risk management contracts, we will recognize unfavorable variances during rising prices. We also recognize financial and costing variances based on the relationship of the spread between the futures price and the physical wholesale market price at the date product is priced under the MSCG product supply agreement (referred to as “basis bought”) and the spread between the futures price and the physical wholesale market price at the date the product was lifted by the customer (referred to as “basis sold”). During the three and nine months ended March 31, 2006,we recognized favorable (unfavorable) variances of approximately $8.3 million and $(31.9) million, respectively.

For the three months ended March 31, 2006 and 2005, the margins and inventory management attributable to our supply, distribution and marketing segment were $51.0 million and $95.8 million, respectively. For the nine months ended March 31, 2006 and 2005, the margins and inventory management attributable to our supply, distribution and marketing segment were $69.9 million and $146.0 million, respectively.

	Three months ended March 31,						Nine months ended March 31,
	2006			2005			2006			2005
Supply, distribution and marketing:
Light oils—marketing margins:
TransMontaigne Partners L.P. facilities	$	5,231		$	1,666		$	20,404		$	8,612
Southeast facilities	187			2,744			(11,897		)	11,340
River facilities	1,170			525			3,864			2,043
Other	800			60			429			232
	7,388			4,995			12,800			22,227
Heavy oils—marketing margins	2,445			2,980			13,254			10,956
Supply chain management services margins	2,469			6,067			3,458			12,715
Margins	12,302			14,042			29,512			45,898
Inventory procurement and management:
Gains from risk management of light oil volumes to be liquidated upon commencement of MSCG product supply agreement	—			(181		)	—			9,437
Increase in value of light oil volumes nominated under the MSCG product supply agreement prior to receipt of the product at our terminals	24,314			36,632			51,720			36,632
Increase in value of base operating inventory	13,967			39,871			30,997			42,980
(Losses) from risk management of base operating inventory and light oil volumes nominated under the MSCG product supply agreement	(7,409		)	—			(9,069		)	—
Storage fees for light oil tank capacity	(457		)	(857		)	(1,371		)	(5,302		)
Other financial and costing variances, net	8,268			6,286			(31,884		)	16,314
Trading activities, net	—			—			—			28
Inventory management	38,683			81,751			40,393			100,089
Margins and inventory management	$	50,985		$	95,793		$	69,905		$	145,987

Our light oil marketing margins in points ($0.0001) per gallon for the three and nine months ended March 31, 2006 and 2005 are as follows:

	Three months ended March 31,				Nine months ended March 31,
	2006		2005		2006			2005
Light oils—marketing margins:
TransMontaigne Partners’ facilities		150		64		199			117
Southeast facilities		4		51		(81	)		71
River facilities		354		196		372			200
Other		90		8		19			8
All facilities—weighted average		81		55		45			81

Our light oil marketing volumes in average barrels per day for the three and nine months ended March 31, 2006 and 2005 are as follows:

	Three months ended March 31,		Nine months ended March 31,
	2006	2005	2006	2005
Light oils—marketing volumes:
TransMontaigne Partners’ facilities	92,073	68,725	89,012	63,849
Southeast facilities	117,744	143,751	127,115	139,366
River facilities	8,748	7,091	9,012	8,987
Other	23,502	19,901	19,218	26,627

The differences between “margins and inventory management” used by our CEO in reviewing the financial performance of our business segments and the margins reported in our accompanying historical financial statements for the three and nine months ended March 31, 2006 and 2005, are as follows (in thousands):

	Three months ended March 31,						Nine months ended March 31,
	2006			2005			2006			2005
Reconciliation to margins:
Margins and inventory management	$	50,985		$	95,793		$	69,905		$	145,987
Gains recognized on beginning inventories—discretionary volumes	13,567			10,210			2,369			3,712
Gains deferred on ending inventories—discretionary volumes	(15,441		)	(21,530		)	(15,441		)	(21,530		)
Margins—historical financial statements	$	49,111		$	84,473		$	56,833		$	128,169

RESULTS OF OPERATIONS—HISTORICAL FINANCIAL STATEMENTS

The following selected historical financial statement measures are derived from our unaudited interim financial statements for the three and nine months ended March 31, 2006 and 2005 (in thousands):

	Three months ended March 31,						Nine months ended March 31,
	2006			2005			2006			2005
Margins(1):
Supply, distribution, and marketing	$	49,111		$	84,473		$	56,833		$	128,169
Terminals, pipelines, tugs and barges	12,474			13,807			37,897			37,940
Operating income	51,437			85,114			47,429			115,575
Earnings before income taxes	44,024			78,442			27,157			91,904
Net earnings	25,724			47,065			11,412			55,142
Net cash provided by (used in) operating activities	12,442			255,101			(3,239		)	138,592
Net cash provided by (used in) investing activities	(2,682		)	5,446			(55,307		)	(7,112		)
Net cash provided by (used in) financing activities	(13,365		)	(248,639		)	38,319			(118,346		)

(1) Margins represents revenues, less cost of product sold and other direct operating costs and expenses.

THREE MONTHS ENDED MARCH 31, 2006 AS COMPARED TO THREE MONTHS ENDED MARCH 31, 2005

We reported net earnings of $25.7 million for the three months ended March 31, 2006, compared to net earnings of $47.1 million for the three months ended March 31, 2005. After earnings allocable to preferred stock, the net earnings attributable to common stockholders was $24.2 million for the three months ended March 31, 2006, compared to net earnings of $36.7 million for the three months ended March 31, 2005. Basic earnings per common share for the three months ended March 31, 2006 and 2005, were $0.50 and $0.92, respectively, based on 48.4 million and 39.8 million weighted average common shares outstanding, respectively. Diluted earnings per common share for the three months ended March 31, 2006 and 2005, were $0.48 and $0.90, respectively, based upon 53.4 million and 52.6 million weighted average diluted shares outstanding, respectively.

Terminals, pipelines, and tugs and barges

In our terminals, pipelines, and tugs and barges operations, we provide distribution related services to wholesalers, distributors, marketers, retail gasoline station operators, cruise-ship operators and industrial and commercial end-users of refined petroleum products and other commercial liquids. The margins from our terminals, pipelines, and tugs and barges operations for the three months ended March 31, 2006 were $12.5 million, compared to $13.8 million for the three months ended March 31, 2005. On August 1, 2005, we acquired Radcliff, which includes two petroleum products terminals, two tugboats, six barges, and twelve tractors and associated trailers. The results of operations of Radcliff are included from the closing date of the transaction (August 1, 2005). For the three months ended March 31, 2006, Radcliff generated approximately $2.2 million in revenues and approximately $1.5 million in direct operating costs and expenses. The margins from our terminals, pipelines, and tugs and barges operations are as follows (in thousands):

	Three months ended March 31,
	2006			2005
Throughput and additive injection fees, net	$	14,539		$	10,688
Storage fees	6,613			9,296
Pipeline transportation fees	1,150			1,177
Tugs and barges	4,398			3,596
Management fees and cost reimbursements	946			1,112
Other	4,723			3,385
Revenues	32,369			29,254
Less direct operating costs and expenses	(19,895		)	(15,447		)
Margins	$	12,474		$	13,807

Throughput and additive injection fees, net. We own and operate a terminal infrastructure that handles products with transportation connections via pipelines, barges, rail cars and trucks. We earn throughput fees for each barrel of product that is distributed at our terminals through our supply and marketing efforts, through exchange agreements, or for third parties. Terminal throughput fees are based on the volume of products distributed at the facility’s truck loading racks, generally at a standard rate per barrel of product. We provide injection services in connection with the delivery of product at our terminals. These fees generally are based on the volume of product injected and delivered over the rack at our terminals.

location. For the three months ended March 31, 2006 and 2005, we averaged approximately 47,000 and 48,000 barrels per day, respectively, of delivered volumes under exchange agreements.

Terminal throughput and additive injection fees, net were approximately $14.5 million and $10.7 million for the three months ended March 31, 2006 and 2005, respectively. The increase of approximately $3.8 million in terminal throughput and additive injection fees, net is due principally to approximately $1.4 million of throughput fees charged on light oil volumes at the TransMontaigne Partners’ facilities of which approximately $0.6 million results from the acquisition of the Mobile terminal, approximately $2.0 million of throughput fees charged on heavy oil volumes at the TransMontaigne Partners’ facilities, approximately $0.3 million of throughput fees resulting from the acquisition of Radcliff’s Pensacola terminal, and an increase of approximately $0.7 million at our Brownsville facilities offset by a decrease of approximately $0.6 million at our Southeast facilities. For the three months ended March 31, 2006 and 2005, we averaged approximately 417,000 barrels and 326,000 barrels per day, respectively, of throughput volumes at our terminals, including volumes under exchange agreements.

Included in the terminal throughput and additive injection fees, net for the three months ended March 31, 2006 and 2005, are fees charged to TransMontaigne’s supply, distribution and marketing segment of approximately $10.8 million and $9.0 million, respectively.

Storage fees. We lease storage capacity at our terminals to third parties and, prior to May 27, 2005, our supply, distribution and marketing segment. Terminal storage fees generally are based on a per barrel of leased capacity per month and will vary with the duration of the storage agreement and the type of product stored.

Terminal storage fees were approximately $6.6 million and $9.3 million for the three months ended March 31, 2006 and 2005, respectively. The decrease of $2.7 million in storage fees was due principally to a decrease in storage fees of approximately $2.3 million resulting from the conversion of the fees charged on heavy oil volumes from a storage agreement to a throughput agreement at the TransMontaigne Partners’ facilities and a decrease of approximately $0.3 million in storage fees charged at our Southeast facilities resulting from the commencement of terminaling services agreements with MSCG.

Included in the terminal storage fees for the three months ended March 31, 2006 and 2005, are fees charged to TransMontaigne’s supply, distribution and marketing segment of approximately $nil and $3.3 million, respectively.

Pipeline transportation fees. We own an interstate products pipeline operating from Mt. Vernon, Missouri to Rogers, Arkansas (the “Razorback Pipeline”), together with associated terminal facilities at Mt. Vernon and Rogers. We earn pipeline transportation fees at our Razorback Pipeline based on the volume of product transported and the distance from the origin point to the delivery point. We also earn transportation fees at our Port Everglades pipeline hydrant system based on the volume of product delivered to cruise ships and freight vessels.

For the three months ended March 31, 2006 and 2005, we earned pipeline transportation fees of approximately $1.2 million and $1.2 million, respectively.

Included in the pipeline transportation fees for the three months ended March 31, 2006 and 2005, are fees charged to TransMontaigne’s supply, distribution and marketing segment of approximately $1.1 million and $1.2 million, respectively.

Tugs and barges. We currently own and operate 14 tugboats and 19 barges that deliver product to cruise ships and other marine vessels for refueling and to transport third-party product from our storage tanks to our customers’ facilities. Our tugboats earn fees for providing docking and other ship-assist services to cruise and cargo ships and other marine vessels. Bunkering fees are based on the volume and type of product sold, transportation fees are based on the volume of product that is shipped and the distance to the delivery point, and docking and other ship-assist services are based on a per docking per tugboat basis.

For the three months ended March 31, 2006 and 2005, we earned bunkering fees, transportation fees, and other ship-assist services fees of approximately $4.4 million and $3.6 million, respectively. The increase of $0.8 million in tug and barge fees is due principally to approximately $0.5 million of fees resulting from the acquisition of Radcliff.

Included in the tugs and barges fees for the three months ended March 31, 2006 and 2005, are fees charged to TransMontaigne’s supply, distribution and marketing segment of approximately $2.7 million and $2.2 million, respectively.

Management fees and cost reimbursements. We manage and operate for a major oil company certain tank capacity at TransMontaigne Partners’ Port Everglades (South) terminal and receive a reimbursement of costs. Subsequent to May 27, 2005, we manage and operate on behalf of our supply, distribution and marketing segment certain tank capacity owned by a utility and receive a management fee. We also manage and operate for a foreign oil company a bi-directional products pipeline connected to our Brownsville, Texas terminal facility. Prior to February 1, 2006, we managed and operated for BP 15 terminals that are adjacent to our Southeast facilities and received a reimbursement of costs. We continue to manage and operate for BP two terminals that are adjacent to our Southeast facilities and receive a reimbursement of costs. For the three months ended March 31, 2006 and 2005, we received from BP a reimbursement of costs of approximately $0.4 million and $0.8 million, respectively.

For the three months ended March 31, 2006 and 2005, we earned management fees and cost reimbursements from our terminal and pipeline operations of approximately $0.9 million and $1.1 million, respectively.

Included in the management fees and cost reimbursements for the three months ended March 31, 2006 and 2005, are fees charged to TransMontaigne’s supply, distribution and marketing segment of approximately $0.3 million and $nil, respectively.

Other revenues. In addition to providing storage and distribution services at our terminal facilities, we also provide ancillary services including heating and mixing of stored products and product transfer services. We also recognize gains from the sale of product to our supply, distribution and marketing operation resulting from the excess of product deposited by third parties into our terminals over the amount of product that the customer is contractually permitted to withdraw from those terminals.

For the three months ended March 31, 2006 and 2005, other revenues from our terminals, pipelines, and tugs and barges operations were approximately $4.7 million and $3.4 million, respectively. The increase of $1.3 million in other revenues is due principally to approximately $1.3 million in product gains and approximately $0.5 million from the acquisition of Radcliff offset by a decrease in ancillary services of approximately $0.5 million.

Included in other revenues for the three months ended March 31, 2006 and 2005, are fees charged to TransMontaigne’s supply, distribution and marketing segment of approximately $3.3 million and $2.3 million, respectively.

Direct operating costs and expenses. The direct operating costs and expenses of the terminals, pipelines, and tugs and barges operations include the directly-related wages and employee benefits, utilities, communications, maintenance and repairs, property taxes, rent, vehicle expenses, environmental compliance costs, materials and supplies. For the three months ended March 31, 2006 and 2005, the direct operating costs and expenses of the terminals, pipelines, and tugs and barges were approximately $19.9 million and $15.4 million, respectively. For the three months ended March 31, 2006, Radcliff generated approximately $1.5 million in direct operating costs and expenses. The direct operating costs and expenses of our terminals, pipelines, and tugs and barges operations are as follows (in thousands):

	Three months ended March 31,
	2006			2005
Wages and employee benefits	$	6,465		$	6,198
Utilities and communication charges	1,351			1,150
Repairs and maintenance	6,644			3,409
Property and casualty insurance costs	1,000			913
Office, rentals and property taxes	1,637			1,516
Vehicles and fuel costs	1,167			696
Environmental compliance costs	985			1,334
Other	761			375
Less—property and environmental insurance recoveries	(115		)	(144		)
Direct operating costs and expenses	$	19,895		$	15,447

During the three months ended March 31, 2006, we incurred repairs and maintenance of approximately $1.8 million throughout our River terminal facilities in preparation for the commencement of a seven-year terminaling services agreement with a subsidiary of Valero Energy Corporation regarding approximately 1.0 million barrels of gasoline and distillate storage capacity.

Supply, distribution and marketing

The margins from our supply, distribution and marketing operations for the three months ended March 31, 2006, were $49.1 million, compared to $84.5 million for the three months ended March 31, 2005. For the three months ended March 31, 2006, Radcliff generated approximately $54.6 million in revenues and approximately $1.0 million in margins. The margins from our supply, distribution and marketing operations are as follows (in thousands):

	Three months ended March 31,
	2006			2005
Rack spot sales	$	292,589		$	245,402
Contract sales	1,427,790			1,135,306
Bulk sales	506,351			606,257
Supply chain management services	197,598			153,222
Total revenues	2,424,328			2,140,187
Cost of product sold	(2,366,887		)	(2,042,299		)
Net margins before other direct costs and expenses	57,441			97,888
Other direct costs and expenses:
Net gains on risk management activities	5,848			13,042
Change in unrealized losses on derivative contracts	(14,178		)	(26,457		)
Margins	$	49,111		$	84,473

We sell our products to customers primarily through three types of arrangements: rack spot sales, contract sales and bulk sales.

Rack spot sales. Rack spot sales are sales to commercial and industrial end-users, independent retailers, cruise-ship operators and jobbers that do not involve continuing contractual obligations to purchase or deliver product. Rack spot sales are priced and delivered on a daily basis through truck loading racks or marine fueling equipment. Our selling price of a particular product on a particular day at a particular terminal is a function of our supply at that terminal, our estimate of the costs to replenish the product at that terminal, our desire to reduce inventory levels at that terminal that day, and other factors. Rack spot sales are recognized as revenues when the product is delivered to the customer through the truck loading rack or marine fueling equipment.

Rack spot sales were approximately $292.6 million and $245.4 million for the three months ended March 31, 2006 and 2005, respectively. The increase of approximately $47.2 million is due principally to higher commodity prices offset by a slight decline in delivered volumes under rack spot sales. For the three months ended March 31, 2006 and 2005, we averaged approximately 43,000 and 45,000 barrels per day, respectively, of delivered volumes under rack spot sales.

Contract sales. Contract sales are sales to commercial and industrial end users, independent retailers, cruise-ship operators, and jobbers that are made pursuant to negotiated contracts, generally ranging from one to six months in duration. Contract sales provide these customers with a specified volume of product during the agreement term. At the customer’s option, the pricing of the product delivered under a contract sale may be fixed at a stipulated price per gallon, or it may vary based on changes in published indices. Contract sales are recognized as revenues when the product is delivered to the customer through the truck loading rack or marine fueling equipment.

Contract sales were approximately $1,427.8 million and $1,135.3 million for the three months ended March 31, 2006 and 2005, respectively. The increase of approximately $292.5 million is due principally to higher commodity prices offset by a slight decline in delivered volumes under contract sales. For the three months ended March 31, 2006 and 2005, we averaged approximately 222,000 and 233,000 barrels per day, respectively, of delivered volumes under contract sales.

Bulk sales. Bulk sales are sales of large quantities of product to wholesalers, distributors, and marketers in major cash markets typically prior to the product being injected into the common carrier pipeline. We also make bulk sales of products prior to their scheduled delivery to us while the product is being transported in the common carrier pipelines or by barge or vessel.

Bulk sales were approximately $506.4 million and $606.3 million for the three months ended March 31, 2006 and 2005, respectively. The decrease of approximately $99.9 million is due principally to a decrease in volumes transferred to our bulk customers offset by higher commodity prices. We have decreased the volumes transferred to our bulk customers due principally to a reduction in the number of barrels we maintain in the bulk markets as a result of a change in business strategy caused in part by higher commodity prices and the cost of executing our risk management strategies. For the three months ended March 31, 2006 and 2005, we averaged approximately 80,000 and 106,000 barrels per day, respectively, of delivered volumes under bulk sales.

Supply chain management services contracts. We provide supply chain management services to companies and governmental entities that desire to outsource their fuel supply function and to reduce the price volatility associated with their fuel supplies. We offer three types of supply chain management services: delivered fuel price management, retail price management and logistical supply chain management services.

Sales pursuant to supply chain management services contracts were approximately $197.6 million and $153.2 million for the three months ended March 31, 2006 and 2005, respectively. The increase of

approximately $44.4 million is due principally to higher commodity prices offset by a decline in delivered volumes under supply chain management services contracts. For the three months ended March 31, 2006 and 2005, we averaged approximately 28,000 barrels and 31,000 barrels per day, respectively, of delivered volumes under supply chain management services contracts.

Cost of product sold. The cost of product sold includes the cost of the product inventory sold on a first-in, first-out basis, pipeline transportation and other freight costs, terminal throughput, additive and storage costs, and commissions. Cost of product sold is approximately $2,366.9 million and $2,042.3 million for the three months ended March 31, 2006 and 2005, respectively. Cost of product sold is as follows (in thousands):

	Three months ended March 31,
	2006		2005
Inventory product costs	$	2,331,732	$	2,005,166
Transportation and related charges	22,018		22,315
Throughput, storage and related charges	12,410		13,958
Other	727		860
Cost of product sold	$	2,366,887	$	2,042,299

Net gains (losses) on risk management activities. Our risk management strategy generally is intended to maintain a balanced position of forward sale commitments against our discretionary inventories held for immediate sale or exchange, inventory volumes due to others under exchange agreements, open positions in derivative contracts, and open positions in risk management contracts, thereby reducing exposure to commodity price fluctuations. We evaluate our exposure to commodity price risk from an overall portfolio basis and offset that position with risk management contracts, principally NYMEX futures contracts.

During a period of rising prices, long (short) futures contracts will increase (decrease) in value resulting in a gain (loss). During a period of declining prices, our long (short) futures contracts will decrease (increase) in value resulting in a loss (gain).

Net gains on risk management activities were approximately $5.8 million and $13.0 million for the three months ended March 31, 2006 and 2005, respectively.

Costs and expenses

Selling, general and administrative expenses for the three months ended March 31, 2006, were $12.1 million, compared to $9.9 million for the three months ended March 31, 2005. For the three months ended March 31, 2006, Radcliff incurred approximately $0.3 million in selling, general and administrative expenses. Selling, general and administrative expenses are as follows (in thousands):

	Three months ended March 31,
	2006		2005
Wages and employee benefits	$	8,810	$	7,768
Office costs, utilities and communication charges	1,125		1,076
Accounting expenses	850		128
Legal expenses	641		171
Property and casualty insurance	201		200
Other	515		542
Selling, general and administrative expenses	$	12,142	$	9,885

For the three months ended March 31, 2006, we incurred merger related expenses of approximately $1.4 million associated with our pending merger transaction with SemGroup. The merger related expenses are composed of $1.0 million for a fairness opinion and approximately $0.4 million in fees paid to legal advisors.

Depreciation and amortization for the three months ended March 31, 2006 and 2005, was $7.3 million and $6.3 million, respectively. The increase of $1.0 million in depreciation and amortization is due principally to the depreciation on current year additions.

Other income and expenses

Dividend income for the three months ended March 31, 2006, was $0.1 million, as compared to $9,000 for the three months ended March 31, 2005. During the three months ended March 31, 2006, we received approximately $82,000 in dividends from our commodity trading membership.

Interest income for the three months ended March 31, 2006, was $169,000, as compared to $149,000 for the three months ended March 31, 2005. Pursuant to our cash management practices, excess cash balances are used to pay down our outstanding borrowings, if any, under our senior secured working capital credit facility and commodity margin loan and, then invested in short-term investments.

Interest expense for the three months ended March 31, 2006, was $7.2 million, compared to $6.4 million during the three months ended March 31, 2005. Interest expense is as follows (in thousands):

	Three months ended March 31,
	2006		2005
TransMontaigne Partners’ credit facility	$	697	$	—
Senior secured working capital credit facility	1,230		1,446
Senior subordinated notes	4,563		4,563
Letters of credit	608		320
Commodity margin loan	66		46
Interest expense	$	7,164	$	6,375

Income taxes

Income tax expense was $16.7 million and $31.4 million for the three months ended March 31, 2006 and 2005, respectively, which represents an effective combined federal and state income tax rate of 38% and 40%, respectively.

Preferred stock dividends

Preferred stock dividends on our Series B redeemable convertible preferred stock were $0.2 million and $0.7 million for the three months ended March 31, 2006 and 2005, respectively. At its issuance (June 28, 2002), the fair value of the Series B redeemable convertible preferred stock exceeded its liquidation value. The initial carrying amount of the Series B redeemable convertible preferred stock will be decreased ratably over its 5-year term until it equals its liquidation value with an equal reduction in the amount of preferred stock dividends recorded for financial reporting purposes. For the three months ended March 31, 2006 and 2005, 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 $0.3 million and $1.1 million, respectively, offset by the amortization of the premium on the carrying amount of the Series B redeemable convertible preferred stock of $0.1 million and $0.4 million, respectively.

NINE MONTHS ENDED MARCH 31, 2006 AS COMPARED TO NINE MONTHS ENDED MARCH 31, 2005

We reported net earnings of $11.4 million for the nine months ended March 31, 2006, compared to net earnings of $55.1 million for the nine months ended March 31, 2005. After earnings allocable to preferred stock, the net earnings attributable to common stockholders was $10.7 million and $43.0 million for the nine months ended March 31, 2006 and March 31, 2005, respectively. Basic earnings per common share for the nine months ended March 31, 2006 and 2005, were $0.22 and $1.08, respectively, based on 47.9 million and 39.7 million weighted average common shares outstanding, respectively. Diluted earnings per common share for the nine months ended March 31, 2006 and 2005, were $0.21 and $1.07, respectively, based upon 53.7 million and 51.7 million weighted average diluted shares outstanding, respectively.

Terminals, pipelines, and tugs and barges

The net operating margins from our terminals, pipelines, and tugs and barges operations for the nine months ended March 31, 2006 were $37.9 million, compared to $37.9 million for the nine months ended March 31, 2005. On August 1, 2005, we acquired Radcliff, which includes two petroleum products terminals, two tugboats, six barges, and twelve tractors and associated trailers. The results of operations of Radcliff are included from the closing date of the transaction (August 1, 2005). For the nine months ended March 31, 2005, Radcliff generated approximately $6.2 million in revenues and approximately $4.3 million in direct operating costs and expenses. The net operating margins from our terminals, pipelines, and tugs and barges operations are as follows (in thousands):

	Nine months ended March 31,
	2006			2005
Throughput and additive injection fees, net	$	42,281		$	30,924
Storage fees	19,752			27,428
Pipeline transportation fees	3,032			2,982
Tugs and barges	12,993			10,395
Management fees and cost reimbursements	4,078			3,637
Other	12,294			7,882
Revenues	94,430			83,248
Less direct operating costs and expenses	(56,533		)	(45,308		)
Net operating margins	$	37,897		$	37,940

Throughput and additive injection fees, net. We earn throughput fees for each barrel of product that is distributed at our terminals through our supply and marketing efforts, through exchange agreements, or for third parties. Terminal throughput fees are based on the volume of products distributed at the facility’s truck loading racks, generally at a standard rate per barrel of product. We provide injection services in connection with the delivery of product at our terminals. These fees generally are based on the volume of product injected and delivered over the rack at our terminals.

Exchange agreements provide for the exchange of product at one delivery location for product at a different location. We generally receive a terminal throughput fee based on the volume of the product exchanged, in addition to the cost of transportation from the receipt location to the exchange delivery location. For the nine months ended March 31, 2006 and 2005, we averaged approximately 49,000 and 48,000 barrels per day, respectively, of delivered volumes under exchange agreements.

Terminal throughput and additive injection fees, net were approximately $42.3 million and $30.9 million for the nine months ended March 31, 2006 and 2005, respectively. The increase of approximately $11.4 million in terminal throughput and additive injection fees, net is due principally to

approximately $4.2 million of throughput fees charged on light oil volumes at the TransMontaigne Partners’ facilities of which approximately $2.0 million results from the acquisition of the Mobile terminal, approximately $5.9 million of throughput fees charged on heavy oil volumes at the TransMontaigne Partners’ facilities, approximately $0.8 million of throughput fees resulting from the acquisition of Radcliff’s Pensacola terminal and an increase of approximately $1.7 million at our Brownsville facilities offset by a decrease of approximately $1.0 million at our Southeast facilities. For the nine months ended March 31, 2006 and 2005, we averaged approximately 386,000 barrels and 323,000 barrels per day, respectively, of throughput volumes at our terminals, including volumes under exchange agreements.

Included in the terminal throughput and additive injection fees, net for the nine months ended March 31, 2006 and 2005, are fees charged to TransMontaigne’s supply, distribution and marketing segment of approximately $33.3 million and $26.2 million, respectively.

Terminal storage fees were approximately $19.8 million and $27.4 million for the nine months ended March 31, 2006 and 2005, respectively. The decrease of $7.6 million in storage fees was due principally to a decrease in storage fees of approximately $5.5 million resulting from the conversion of the fees charged on heavy oil volumes from a storage agreement to a throughput agreement and a decrease of approximately $1.7 million in storage fees charged at our Southeast facilities resulting from the commencement of terminaling services agreements with MSCG.

Included in the terminal storage fees for the nine months ended March 31, 2006 and 2005, are fees charged to TransMontaigne’s supply, distribution and marketing segment of approximately $nil and $10.3 million, respectively.

For the nine months ended March 31, 2006 and 2005, we earned pipeline transportation fees of approximately $3.0 million and $3.0 million, respectively.

Included in the pipeline transportation fees for the nine months ended March 31, 2006 and 2005, are fees charged to TransMontaigne’s supply, distribution and marketing segment of approximately $3.0 million and $3.0 million, respectively.

For the nine months ended March 31, 2006 and 2005, we earned bunkering fees, transportation fees, and other ship-assist services fees of approximately $13.0 million and $10.4 million, respectively. The

increase of $2.6 million in tug and barge fees is due principally to approximately $1.8 million of fees resulting from the acquisition of Radcliff.

Included in the tugs and barges fees for the nine months ended March 31, 2006 and 2005, are fees charged to TransMontaigne’s supply, distribution and marketing segment of approximately $7.9 million and $5.4 million, respectively.

Management fees and cost reimbursements. We manage and operate for a major oil company certain tank capacity at TransMontaigne Partners’ Port Everglades (South) terminal and receive a reimbursement of costs. Subsequent to May 27, 2005, we manage and operate on behalf of our supply, distribution and marketing segment certain tank capacity owned by a utility and receive a management fee. We also manage and operate for a foreign oil company a bi-directional products pipeline connected to our Brownsville, Texas terminal facility. Prior to February 1, 2006, we managed and operated for BP 15 terminals that are adjacent to our Southeast facilities and received a reimbursement of costs. We continue to manage and operate for BP two terminals that are adjacent to our Southeast facilities and receive a reimbursement of costs. For the nine months ended March 31, 2006 and 2005, we received from BP a reimbursement of costs of approximately $2.4 million and $2.7 million, respectively.

For the nine months ended March 31, 2006 and 2005, we earned management fees and cost reimbursements from our terminal and pipeline operations of approximately $4.1 million and $3.6 million, respectively.

Included in the management fees and cost reimbursements for the nine months ended March 31, 2006 and 2005, are fees charged to TransMontaigne’s supply, distribution and marketing segment of approximately $0.8 million and $nil, respectively.

For the nine months ended March 31, 2006 and 2005, other revenues from our terminals, pipelines, and tugs and barges operations were approximately $12.3 million and $7.9 million, respectively. The increase of $4.4 million in other revenues is due principally to approximately $3.9 million in product gains and approximately $1.4 million from the acquisition of Radcliff offset by a decrease in ancillary services of approximately $1.0 million.

Included in other revenues for the nine months ended March 31, 2006 and 2005, are fees charged to TransMontaigne’s supply, distribution and marketing segment of approximately $8.3 million and $4.8 million, respectively.

Direct operating costs and expenses. The direct operating costs and expenses of the terminals, pipelines, and tugs and barges operations include the directly related wages and employee benefits, utilities, communications, maintenance and repairs, property taxes, rent, vehicle expenses, environmental compliance costs, materials and supplies. For the nine months ended March 31, 2006 and 2005, the direct operating costs and expenses of the terminals, pipelines, and tugs and barges were approximately $56.5 million and $45.3 million, respectively. For the nine months ended March 31, 2006, Radcliff generated approximately $4.3 million in direct operating costs and expenses. The direct operating costs and expenses of our terminals, pipelines, and tugs and barges operations are as follows (in thousands):

	Nine months ended March 31,
	2006			2005
Wages and employee benefits	$	20,681		$	19,082
Utilities and communication charges	3,814			3,118
Repairs and maintenance	16,318			11,668
Property and casualty insurance costs	2,933			2,542
Office, rentals and property taxes	4,833			4,379
Vehicles and fuel costs	3,594			2,018
Environmental compliance costs	3,251			3,166
Other	1,374			923
Less—property and environmental insurance recoveries	(265		)	(1,588		)
Direct operating costs and expenses	$	56,533		$	45,308

Supply, distribution and marketing

The margins from our supply, distribution and marketing operations for the nine months ended March 31, 2006, were $56.8 million, compared to $128.2 million for the nine months ended March 31, 2005. For the nine months ended March 31, 2006, Radcliff generated approximately $163.7 million in revenues and approximately $5.3 million in margins. The margins from our supply, distribution and marketing operations are as follows (in thousands):

	Nine months ended March 31,
	2006			2005
Rack spot sales	$	883,376		$	643,606
Contract sales	4,298,524			3,156,725
Bulk sales	1,453,629			1,744,793
Supply chain management services	630,290			435,848
Total revenues	7,265,819			5,980,972
Cost of product sold	(7,241,388		)	(5,874,723		)
Margins before other direct costs and expenses	24,431			106,249
Other direct costs and expenses:
Net gains (losses) on risk management activities	(4,047		)	30,305
Change in unrealized losses on derivative contracts	36,449			(8,385		)
Margins	$	56,833		$	128,169

We sell our products to customers primarily through three types of arrangements: rack spot sales, contract sales and bulk sales.

loading racks or marine fueling equipment. Our selling price of a particular product on a particular day at a particular terminal is a function of our supply at that terminal, our estimate of the costs to replenish the product at that terminal, our desire to reduce inventory levels at that terminal that day, and other factors. Rack spot sales are recognized as revenues when the product is delivered to the customer through the truck loading rack or marine fueling equipment.

Rack spot sales were approximately $883.4 million and $643.6 million for the nine months ended March 31, 2006 and 2005, respectively. The increase of approximately $239.8 million is due principally to higher commodity prices. For the nine months ended March 31, 2006 and 2005, we averaged approximately 42,000 and 42,000 barrels per day, respectively, of delivered volumes under rack spot sales.

Contract sales were approximately $4,298.5 million and $3,156.7 million for the nine months ended March 31, 2006 and 2005, respectively. The increase of approximately $1,141.8 million is due principally to higher commodity prices offset by a slight decline in delivered volumes under contract sales. For the nine months ended March 31, 2006 and 2005, we averaged approximately 219,000 and 221,000 barrels per day, respectively, of delivered volumes under contract sales.

Bulk sales were approximately $1,453.6 million and $1,744.8 million for the nine months ended March 31, 2006 and 2005, respectively. The decrease of approximately $291.2 million is due principally to a decrease in volumes transferred to our bulk customers offset by higher commodity prices. We have decreased the volumes transferred to our bulk customers due principally to a reduction in the number of barrels we maintain in the bulk markets as a result of a change in business strategy caused in part by higher commodity prices and the cost of executing our risk management strategies. For the nine months ended March 31, 2006 and 2005, we averaged approximately 70,000 and 185,000 barrels per day, respectively, of delivered volumes under bulk sales.

Sales pursuant to supply chain management services contracts were approximately $630.3 million and $435.8 million for the nine months ended March 31, 2006 and 2005, respectively. The increase of approximately $194.5 million is due principally to higher commodity prices offset by a slight decline in delivered volumes under supply chain management services contracts. For the nine months ended March 31, 2006 and 2005, we averaged approximately 30,000 barrels and 31,000 barrels per day, respectively, of delivered volumes under supply chain management services contracts.

Cost of product sold. The cost of product sold includes the cost of the product inventory sold on a first-in, first-out basis, pipeline transportation and other freight costs, terminal throughput, additive and storage costs, and commissions. Cost of product sold is approximately $7,241.4 million and $5,874.7 million for the nine months ended March 31, 2006 and 2005, respectively. Cost of product sold is as follows (in thousands):

	Nine months ended March 31,
	2006		2005
Inventory product costs	$	7,130,444	$	5,753,609
Transportation and related charges	71,387		75,614
Throughput, storage and related charges	36,854		43,750
Other	2,703		1,750
Cost of product sold	$	7,241,388	$	5,874,723

Net gains (losses) on risk management activities were approximately $(4.0) million and $30.3 million for the nine months ended March 31, 2006 and 2005, respectively.

Costs and expenses

Selling, general and administrative expenses for the nine months ended March 31, 2006, were $37.1 million, compared to $32.1 million for the nine months ended March 31, 2005. For the nine months ended March 31, 2006, Radcliff incurred approximately $1.4 million in selling, general and administrative expenses. Selling, general and administrative expenses are as follows (in thousands):

	Nine months ended March 31,
	2006		2005
Wages and employee benefits	$	26,268	$	25,640
Office costs, utilities and communication charges	3,555		3,159
Accounting expenses	2,648		402
Legal expenses	1,910		884
Property and casualty insurance	625		640
Other	2,044		1,395
Selling, general and administrative expenses	$	37,050	$	32,120

Depreciation and amortization for the nine months ended March 31, 2006 and 2005, was $20.7 million and $17.8 million, respectively. The increase of $2.9 million in depreciation and amortization for the nine months ended March 31, 2006 as compared to 2005 is due principally to the depreciation on current year additions and the amortization of the product supply agreement.

Other income and expenses

Dividend income for the nine months ended March 31, 2006, was $0.7 million, as compared to $0.4 million for the nine months ended March 31, 2005. During the nine months ended March 31, 2006, we received approximately $0.3 million in dividends from our commodity trading membership. During the nine months ended March 31, 2006 and 2005, we received approximately $0.4 million and $0.4 million, respectively, in dividends from Lion Oil Company.

Interest income for the nine months ended March 31, 2006, was $0.6 million, as compared to $0.3 million for the nine months ended March 31, 2005. Pursuant to our cash management practices, excess cash balances are used to pay down our outstanding borrowings, if any, under our senior secured working capital credit facility and commodity margin loan and, then invested in short-term investments.

Interest expense for the nine months ended March 31, 2006, was $20.0 million, compared to $19.3 million during the nine months ended March 31, 2005. Interest expense is as follows (in thousands):

	Nine months ended March 31,
	2006		2005
TransMontaigne Partners’ credit facility	$	1,665	$	—
Senior secured working capital credit facility	3,095		3,245
Senior subordinated notes	13,687		13,687
Former credit facility	—		1,331
Letters of credit	1,411		947
Commodity margin loan	155		106
Interest expense	$	20,013	$	19,316

Other financing costs, net for the nine months ended March 31, 2006, were $1.6 million, compared to $5.0 million for the nine months ended March 31, 2005. During the nine months ended March 31, 2005, we wrote off the debt issuance costs of approximately $3.4 million associated with our former credit facility. On September 13, 2004, we repaid our former credit facility with proceeds from our senior secured working capital credit facility.

Income taxes

Income tax expense was $10.3 million and $36.8 million for the nine months ended March 31, 2006 and 2005, respectively, which represents an effective combined federal and state income tax rate of 38% and 40%, respectively.

Preferred stock dividends

Preferred stock dividends on our Series B redeemable convertible preferred stock were $0.7 million and $2.1 million for the nine months ended March 31, 2006 and 2005, respectively. At its issuance (June 28, 2002), the fair value of the Series B redeemable convertible preferred stock exceeded its liquidation value. The initial carrying amount of the Series B redeemable convertible preferred stock will be decreased ratably over its 5-year term until it equals its liquidation value with an equal reduction in the amount of preferred stock dividends recorded for financial reporting purposes. For the nine months ended March 31, 2006 and 2005, 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 and $3.3 million, respectively, offset by the amortization of the premium on the carrying amount of the Series B redeemable convertible preferred stock of $0.4 million and $1.2 million, respectively.

LIQUIDITY, CAPITAL RESOURCES, AND COMMODITY PRICE RISK

At March 31, 2006, our current assets exceeded our current liabilities by $321.1 million, as compared to $319.6 million at June 30, 2005.

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

	March 31, 2006			June 30, 2005
	Amount		Bbls	Amount		Bbls
Volumes held for immediate sale or exchange	$	128,529	1,955	$	153,123	2,415
Volumes held for base operations	103,880		1,487	121,651		2,011
Inventories—discretionary volumes	$	232,409	3,442	$	274,774	4,426

Our volumes held for immediate sale or exchange generally are subject to price risk management. Our base operating inventory volumes generally are not subject to price risk management. Based on the current level of our operations, we have established our base operating inventory volumes, exclusive of product linefill and tank bottom volumes, at approximately 1.5 million barrels. Changes in our operation, such as the acquisition of additional terminals, increases in our contract sales volumes, entering into product supply agreements or leasing tank capacity to third parties, may result in changes in the volume of our base operating inventory volumes. Inventories—discretionary volumes are composed of the following (in thousands):

	March 31, 2006			June 30, 2005
	Amount		Bbls	Amount		Bbls
Gasolines	$	82,788	1,071	$	136,247	2,123
Distillates	88,521		1,131	113,670		1,657
No. 6 oil and other	61,100		1,240	24,857		646
Inventories—discretionary volumes	$	232,409	3,442	$	274,774	4,426

Our product linefill and tank bottom volumes consist of refined products held in our proprietary terminal pipeline connections and tank bottoms. Our product linefill and tank bottom volumes are not held for sale or exchange in the ordinary course of business. Our product linefill and tank bottom volumes are presented in the accompanying consolidated balance sheet as non-current assets and are carried at original cost adjusted for impairment write-downs to current market values. Product linefill and tank bottom volumes consist of the following (in thousands):

	March 31, 2006				June 30, 2005
	Amount		Bbls		Amount		Bbls
Gasoline	$	12,805		465	$	14,267		522
Distillates	7,403			288	8,774			351
No. 6 oil and other	1,418			55	1,284			52
Product linefill and tank bottom volumes	$	21,626		808	$	24,325		925

The following table indicates the maturities of our derivative contracts, including the credit quality of our counterparties to those contracts with unrealized gains at March 31, 2006.

	Fair value of contracts
	Maturity less than 1 year				Maturity 1-3 years			Maturity in excess of 3 years			Total
	(in thousands)
Unrealized gain—asset
Investment grade		$	6,220			$	—		$	—	$	6,220
Non-investment grade		762				—			—		762
No external rating		12,010				—			—		12,010
		18,992				—			—		18,992
Unrealized loss—liability		(13,725		)		—			—		(13,725		)
Net unrealized gain—asset		$	5,267			$	—		$	—	$	5,267

At March 31, 2006, there were no unrealized gains or losses on NYMEX futures contracts because NYMEX futures contracts require daily settlement for changes in commodity prices on open futures contracts. At March 31, 2006, included in unrealized gain position—asset is an unrealized gain of approximately $1.1 million related to certain short positions taken in the NYMEX options market.

The following table includes information about the changes in the fair value of our derivative contracts for the nine months ended March 31, 2006 (in thousands):

Fair value at June 30, 2005	$	(39,829	)
Amounts realized or otherwise settled during the period	59,457
Fair value of contracts originated during the period, which are included in deferred revenue	4,239
Change in fair value attributable to change in commodity prices	(18,600		)
Fair value at March 31, 2006	$	5,267

Excluding acquisitions, capital expenditures for the three and nine months ended March 31, 2006, were $3.1 million and $8.6 million, respectively, for terminal and pipeline facilities and assets to support these facilities. Future capital expenditures will depend on numerous factors, including the availability, economics and cost of appropriate acquisitions which we identify and evaluate; the economics, cost and required regulatory approvals with respect to the expansion and enhancement of existing systems and facilities; customer demand for the services we provide; local, state and federal governmental regulations; environmental compliance requirements; and the availability of debt financing and equity capital on acceptable terms.

Our senior secured working capital credit facility as in effect at March 31, 2006 provides for a maximum borrowing line of credit that was the lesser of (i) $400 million and (ii) the borrowing base (as defined; $460 million at March 31, 2006). The borrowing base is a function of our cash, accounts receivable, inventory, exchanges, margin deposits, and certain reserve adjustments as defined in the facility. The maximum borrowing amount is reduced by the amount of letters of credit that are outstanding. At March 31, 2006, we had borrowings of $17.5 million outstanding and letters of credit of $115 million outstanding under the senior secured working capital credit facility. We also had the ability to borrow an additional $217.5 million under the facility based on the borrowing base computation at March 31, 2006. All outstanding borrowings under the senior secured working capital credit facility are due and payable on September 13, 2009.

The senior secured working capital credit facility is our primary means of short-term liquidity to finance working capital requirements. The senior secured working capital credit facility contains affirmative and negative covenants (including limitations on indebtedness, limitations on dividends and other distributions, limitations on certain inter-company transactions, limitations on mergers, consolidation and the disposition of assets, limitations on investments and acquisitions and limitations on liens) that are customary for a facility of this nature. The senior secured working capital credit facility also contains customary representations and warranties (including those relating to corporate organization and authorization, compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults, covenant defaults, cross defaults and bankruptcy events). The only financial covenant contained in the senior secured working capital credit facility is a minimum fixed charge coverage ratio test that is tested on a quarterly basis whenever the average availability falls below $50 million for the last month of any quarter (average availability was approximately $189 million for the month ended March 31, 2006). In that event, we must satisfy a minimum fixed charge coverage ratio requirement of 110%. The fixed charge coverage ratio is based on a defined financial performance measure within the senior secured working capital credit facility known as “fixed charges EBITDA.”

The computation of the fixed charge coverage ratio for the twelve months ended March 31, 2006, is as follows (in thousands):

	Three Months Ended															Twelve Months Ended
	June 30,			September 30,				December 31,				March 31,				March 31,
	2005			2005				2005				2006				2006
Financial performance debt covenant test:
Consolidated adjusted EBITDA	$	(980	)		$	13,087			$	(19,356	)		$	48,966			$	41,717
Capital expenditures	(3,361		)		(2,193		)		(3,307		)		(3,117		)		(11,978		)
TransMontaigne Partners’ capital expenditures	222				568				616				834				2,240
Cash (paid for) refund of income taxes	(29,704		)		(13,907		)		20,316				(16,729		)		(40,024		)
Preferred stock dividends paid in cash	(1,281		)		(301		)		(301		)		(301		)		(2,184		)
Fixed charges EBITDA	$	(35,104	)		$	(2,746	)		$	(2,032	)		$	29,653			$	(10,229	)
Fixed charges for the period	$	5,009			$	5,126			$	6,299			$	6,301			$	22,735
Fixed charge coverage ratio based on rolling four consecutive quarters																	(45		)%
Deficiency in fixed charges EBITDA to meet minimum fixed charge coverage ratio																	$	35,238
Reconciliation of consolidated adjusted EBITDA to cash flows provided by (used in) operating activities:
Consolidated adjusted EBITDA	$	(980	)		$	13,087			$	(19,356	)		$	48,966			$	41,717
TransMontaigne Partners’ operating income	1,364				3,635				4,089				3,459				12,547
TransMontaigne Partners’ depreciation and amortization	674				1,567				1,626				1,942				5,809
Cash distributions from TransMontaigne Partners	—				(453		)		(1,208		)		(1,208		)		(2,869		)
Gain on disposition of assets, net	(735		)		—				—				(10,617		)		(11,352		)
Gains recognized on beginning inventories—discretionary volumes held for immediate sale or exchange	10,311				2,125				10,576				4,311				10,311
Gains deferred on ending inventories—discretionary volumes held for immediate sale or exchange	(2,125		)		(10,576		)		(4,311		)		(8,502		)		(8,502		)
Increase in FIFO cost basis of base operating inventory volumes	8,339				39,601				(30,773		)		9,849				27,016
Lower of cost or market write-downs on base operating inventory volumes	(1,772		)		(809		)		—				—				(2,581		)
Interest expense, net	(5,011		)		(5,129		)		(6,299		)		(6,301		)		(22,740		)
TransMontaigne Partners’ interest expense, net	(167		)		(463		)		(501		)		(694		)		(1,825		)
Cash (paid for) refund of income taxes	(29,704		)		(13,907		)		20,316				(16,729		)		(40,024		)
Amortization of deferred revenue	(1,841		)		(1,572		)		(1,731		)		(1,809		)		(6,953		)
Amortization of deferred stock-based compensation	652				894				623				641				2,810
Net change in unrealized (gains) losses on long-term derivative contracts	296				(12		)		(223		)		—				61
Change in operating assets and liabilities	(67,173		)		(64,523		)		48,026				(10,866		)		(94,536		)
Cash flows provided by (used in) operating activities	$	(87,872	)		$	(36,535	)		$	20,854			$	12,442			$	(91,111	)

If we were to fail the fixed charge ratio covenant, or any other covenant contained in the senior secured working capital credit facility, we would seek a waiver from our lenders under such facility. If we were unable to obtain a waiver from our lenders, we would be in breach of the senior secured working capital credit facility and the lenders would be entitled to declare all outstanding borrowings immediately due and payable. In addition, a default under the senior secured working capital credit facility would trigger a cross-default provision in the indenture covering our senior subordinated notes.

If we are acquired by SemGroup or any other third party, the completion of such transaction would constitute a “change of control” under the senior secured working capital credit facility and, therefore, would require a waiver from the lenders. Alternatively, SemGroup or any other third party acquirer may elect to provide us with an alternative credit facility. The financing commitment letters provided to us by SemGroup provide for an alternative credit facility.

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

Off-balance sheet arrangements

We have outstanding letters of credit with third parties in the amount of $115 million, which expire within one year.

See Notes 3, 6, 10, 12, 13 and 17 of Notes to consolidated financial statements for additional information regarding our contractual obligations and off-balance sheet arrangements that may affect our results of operations and financial condition.

We believe that our current working capital position; future cash expected to be provided by operating activities; available borrowing capacity under our senior secured working capital credit facility and commodity margin loan; and our relationship with institutional lenders and equity investors should enable us to meet our planned capital and liquidity requirements through at least the maturity date of our senior secured working capital credit facility (September 2009).

NEW ACCOUNTING PRONOUNCEMENTS

In December 2004, the FASB issued FASB Statement No. 153 (“SFAS 153”), “Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29.” This Statement amends APB Opinion No. 29 to eliminate the exception for nonmonetary exchanges of similar productive assets. As a result, exchanges of similar productive assets are recognized at fair value with a resultant gain (loss) on disposition of assets unless exchanges of nonmonetary assets lack commercial substance. For TransMontaigne, SFAS 153 is effective for nonmonetary asset exchanges after July 1, 2005 (see Note 3 of Notes to consolidated financial statements).

In March 2005, the FASB issued FASB Interpretation No. 47 (“FIN 47”), “Accounting for Conditional Asset Retirement Obligations—an interpretation of SFAS 143,” which requires companies to recognize a liability for the fair value of a legal obligation to perform asset-retirement activities that are conditional on a future event, if the amount can be reasonably estimated. For TransMontaigne, FIN 47 is effective for annual reporting periods beginning after December 15, 2005. We are evaluating the

requirements under FIN 47 and do not anticipate the adoption will have a significant impact on our consolidated financial statements.

In September 2005, the Emerging Issues Task Force (EITF) reached a consensus with respect to EITF Issue No. 04-13 (“EITF 04-13”), “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” The EITF concluded that inventory purchase and sale transactions with the same counterparty that are entered into in contemplation of one another should be combined for purposes of applying APB Opinion No. 29, “Accounting for Nonmonetary Transactions.” We have presented “buy/sell” transactions on a net basis in the consolidated statements of operations (see Note 1(h) of Notes to consolidated financial statements).

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, 2005, in addition to the interim unaudited consolidated financial statements, accompanying notes and management’s discussion and analysis of financial condition and results of operations presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. There are no material changes in the market risks faced by us from those reported in our Annual Report on Form 10-K for the year ended June 30, 2005.

Commodity risk

Basis Differential

Change in Basis
Differential

Net
Position

Financial
Impact

Futures price in excess of physical market price (“negative basis differential”)

Increasing

Long

Loss

Futures price in excess of physical market price

Increasing

Short

Gain

Futures price in excess of physical market price

Decreasing

Long

Gain

Futures price in excess of physical market price

Decreasing

Short

Loss

Physical market price in excess of futures price (“positive basis differential”)

Increasing

Long

Gain

Physical market price in excess of futures price

Increasing

Short

Loss

Physical market price in excess of futures price

Decreasing

Long

Loss

Physical market price in excess of futures price

Decreasing

Short

Gain

The physical and derivative positions that expose us to commodity price risk and an indication of whether those positions were actively managed under the our risk management strategies during the three months ended March 31, 2006 are as follows:

Position

Derivative
Contract

Subject to
Commodity
Price Risk

Commodity
Price
Risk Actively
Managed

Long (Short)
Position at
March 31, 2006
(in 000’s barrels)

Fixed-price forward purchase commitments prior to receipt of the product at our terminal

Yes

3,000

Discretionary inventory held for immediate sale or exchange

Yes

1,955

Discretionary volumes held for base operations

Yes

1,487

Product linefill and tank bottom volumes

Yes

808

Fixed-price forward sale commitments

Yes

(1,927

)

Inventory due to others under exchange agreements

Yes

(738

)

Risk management contracts—NYMEX futures contracts

Yes

—

(516

)

Risk management contracts—NYMEX options

Yes

—

(1,302

)

Our risk management strategies and practices currently do not qualify for “hedge accounting” for financial reporting purposes because we do not designate and associate the risk management contracts as hedges of specific physical and derivative positions and we do not document and test the effectiveness of the relationship between the risk management contracts and the physical and derivative positions.

We evaluate our exposure to commodity price risk from an overall portfolio basis. Our risk management strategies are intended to maintain a balanced position of discretionary inventories held for immediate sale or exchange, fixed-price forward purchase commitments, inventory due to others under exchange agreements, fixed-price forward sale commitments and risk management contracts, thereby reducing exposure to commodity price fluctuations. To the extent that we do not manage the commodity price risk relating to a position that is subject to commodity price risk and commodity prices move adversely, we could suffer losses on that position. If, however, prices move favorably, we would realize a gain that we would not realize if substantially all of our positions were managed.

Our risk management policy permits management the discretion to manage the commodity price risk relating to all discretionary volumes, including those volumes designated as base operating inventory volumes and the undelivered in-transit volumes supplied to our terminals under the product supply agreement with MSCG. At March 31, 2006, we were managing the commodity price risk associated with approximately 2.3 million barrels of undelivered in-transit volumes supplied to our terminals under the product supply agreement with MSCG and with respect to our net position of discretionary inventory held for immediate sale or exchange, inventory due to others under exchange agreements and certain NYMEX futures contracts, our short positions exceeded our long positions by approximately (0.2) million barrels. At March 31, 2006, we did not manage the commodity price risk on approximately 2.8 million barrels composed of approximately 1.5 million barrels of discretionary inventories held for base operations, approximately 0.7 million barrels of undelivered in-transit volumes supplied to our terminals under the product supply agreement with MSCG and approximately 0.8 million barrels of product linefill and tank bottoms.

Except for our discretionary volumes held for base operations, when we take title and accept risk of loss on refined petroleum products supplied by third parties at our terminals, we enter into futures

contracts (i.e., short futures contracts) to sell a corresponding amount of product to protect against price fluctuations for the underlying commodity. In order to effectively manage commodity price risk, we must predict when we will sell the underlying product. When we ultimately sell the underlying inventory to a customer, we terminate the related futures contract. If there is correlation in price changes between the forward price curve in the futures market and the value of physical products in the cash market, the net changes in our variation margin position should be offset by the net operating margins we receive when we sell the underlying discretionary inventory. Therefore, in order to effectively manage commodity price risk, we must predict when we will sell the underlying product. If we fail to accurately predict the timing of those future sales, and the product remains in our inventory longer than the expiration date of the futures contract, we must settle the old futures contract and enter into a new futures contract to sell the product to manage the commodity price risk against the same inventory. Furthermore, we may be unable to precisely match the underlying product in our futures contracts with the exact type of product in our physical inventory. To the extent that price fluctuations of the product covered by the NYMEX futures contract do not match the price fluctuations of the product in our physical inventory, our exposure may not be mitigated.

When we enter into a forward sale commitment to deliver product to a customer in the future at a fixed price, we enter into a futures contract (i.e., a long futures contract) to purchase a corresponding amount of product to protect against price fluctuations for the underlying commodity. When we ultimately deliver the underlying product to a customer, we unwind the related risk management contract. We may be unable to precisely match the underlying product in our futures contracts with the exact type of product in our fixed-price forward sale commitment. To the extent that price fluctuations of the product covered by the NYMEX futures contract do not match the price fluctuations of the product in our fixed-price forward sale commitment, our exposure may not be mitigated.

When our discretionary inventory volumes held for immediate sale or exchange exceeds our fixed-price forward sale commitments, we will maintain a net short futures position. When our fixed-price forward sale commitments exceed our discretionary inventory volumes held for immediate sale or exchange, we will maintain a net long futures position. During a period of rising prices, long (short) futures contracts will increase (decrease) in value resulting in a gain (loss). During a period of declining prices, our long (short) futures contracts will decrease (increase) in value resulting in a loss (gain). Therefore, if we are in a net short futures position during periods of rising commodity prices, we expect to recognize significant net margin before other direct costs and expenses from the sale of the physical product offset by significant net losses on risk management activities resulting in overall net operating margins that are in line with expectations. Conversely, if we are in a net short futures position during periods of declining commodity prices, we expect to recognize minimal, if any, net margin before other direct costs and expenses from the sale of the physical product offset by significant net gains on risk management activities resulting in overall net operating margins that are, again, in line with expectations.

For the three months ended March 31, 2006 and 2005, we recognized net gains on risk management activities of approximately $5.8 million and $13.0 million, respectively. For the nine months ended March 31, 2006 and 2005, we recognized net gains (losses) on risk management activities of approximately $(4.0) million and $30.3 million, respectively.

The NYMEX requires an initial margin deposit to open a futures contract. At March 31, 2006 and June 30, 2005, we had approximately $11.4 million and $10.4 million, respectively, on deposit to cover our initial margin requirements on open NYMEX futures contracts. NYMEX futures contracts also require daily settlements for changes in commodity prices. Unfavorable commodity price changes subject us to variation margin calls that require us to make cash payments to the NYMEX in amounts that may be material. At March 31, 2006, a $0.05 per gallon unfavorable change in commodity prices would have required us to make a cash payment of approximately $3.8 million to cover the variation margin. Conversely, a $0.05 per gallon favorable change in commodity prices would have permitted us to receive

approximately $3.8 million. We use our available cash and credit lines to fund these margin calls, but such funding requirements could exceed our ability to access capital.

At March 31, 2006, a $0.05 per gallon unfavorable change in commodity prices relative to our open positions in derivative contracts and risk management contracts would have resulted in the recognition of a loss (realized and unrealized) of approximately $3.1 million. However, the fair value of our discretionary inventory held for immediate sale or exchange would have increased by approximately $4.1 million. The gain from the increase in the fair value of our discretionary inventory volumes held for immediate sale or exchange will not be recognized for financial reporting purposes until those volumes have been sold to customers, which may be in an accounting period subsequent to the accounting period in which the losses on derivative contracts and risk management contracts are recognized.

Interest rate risk

At March 31, 2006, we had outstanding borrowings of $17.5 million under our senior secured working capital credit facility and $45.5 million under TransMontaigne Partners’ credit facility. We are exposed to interest rate risk because our senior secured working capital credit facility and TransMontaigne Partners’ credit facility are variable-rate-based credit facilities. Based on the outstanding balance of our variable-interest-rate debt at March 31, 2006, and assuming market interest rates increase or decrease by 100 basis points, the potential annual increase or decrease in interest expense is approximately $0.6 million.

ITEM 4. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the Commission’s rules and forms, and that information is accumulated and communicated to our management, including our principal executive and principal financial officers (whom we refer to as our Certifying Officers), as appropriate to allow timely decisions regarding required disclosure. Our management evaluated, with the participation of our Certifying Officers, the effectiveness of our disclosure controls and procedures as of March 31, 2006, pursuant to Rule 13a-15(b) under the Exchange Act. Based upon that evaluation, our Certifying Officers concluded that, as of March 31, 2006, our disclosure controls and procedures were effective.

There were no changes in our internal control over financial reporting that occurred during the fiscal quarter ended March 31, 2006 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Part II. Other Information

ITEM 5. OTHER INFORMATION

In view of the pending transaction with SemGroup as discussed in more detail under the heading “Potential Change in Control of TransMontaigne Inc.” in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations to this report and as described in our reports on Form 8-K filed with the Securities and Exchange Commission (“SEC”) on March 29, 2006, April 6, 2006 and May 8, 2006, our board of directors has delayed calling the annual meeting of stockholders for the fiscal year ended June 30, 2005 in order to keep expenses at a minimum. We intend to hold an annual meeting in 2006 only if a merger is not completed. If we hold such an annual meeting, it will be more than 30 days after the anniversary date of the 2005 annual meeting. In order to be eligible for inclusion in our proxy materials for our 2006 annual meeting, if such meeting is held, written notice of any stockholder proposal must be received by us a reasonable time before we begin to print and mail our proxy materials for such annual meeting. If the annual meeting is held, as soon as the date for the annual meeting is determined we will advise our stockholders of the possible mailing date for our proxy materials in a periodic report filed with the SEC pursuant to the Securities Exchange Act of 1934 or by other appropriate notice.

ITEM 6. EXHIBITS

Exhibits:

2.1		Agreement and Plan of Merger, dated March 27, 2006, by and among SemGroup, L.P., SemGroup Subsidiary Holding, L.L.C., TMG Acquisition Company and TransMontaigne Inc. (incorporated by reference to Exhibit 2.1 of TransMontaigne Inc.’s Current Report on Form 8-K dated March 27, 2006, as filed with the SEC on March 29, 2006)
31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

SIGNATURES

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

Dated May 9, 2006	TRANSMONTAIGNE INC.
	(Registrant)
	By:	/s/ DONALD H. ANDERSON
		Donald H. Anderson
		*President and Chief Executive Officer*
		/s/ RANDALL J. LARSON
		Randall J. Larson
		*Executive Vice President, Chief Financial Officer, and Chief Accounting Officer*

EXHIBIT INDEX

Exhibit Number		Description of Exhibits
2.1		Agreement and Plan of Merger, dated March 27, 2006, by and among SemGroup, L.P., SemGroup Subsidiary Holding, L.L.C., TMG Acquisition Company and TransMontaigne Inc. (incorporated by reference to Exhibit 2.1 of TransMontaigne Inc.’s Current Report on Form 8-K dated March 27, 2006, as filed with the SEC on March 29, 2006)
31.1*		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed herewith.