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TABLE OF CONTENTS
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549



FORM 10-K

(Mark One)    

ý

 

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

for the fiscal year ended December 31, 2009

OR

o

 

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

For the transition period                                    to                                     

Commission File Number 001-32505



TRANSMONTAIGNE PARTNERS L.P.
(Exact name of registrant as specified in its charter)

Delaware   34-2037221
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
Identification No.)

Suite 3100, 1670 Broadway
Denver, Colorado 80202
(Address, including zip code, of principal executive offices)

(303) 626-8200
(Telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class   Name of Each Exchange
on Which Registered
Common Limited Partner Units   New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:
NONE



          Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o    No ý

          Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o    No ý

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

          Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o    No o

          Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

          Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer o   Accelerated filer ý   Non-accelerated filer o
(Do not check if a
smaller reporting company)
  Smaller reporting company o

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

          The aggregate market value of common limited partner units held by non-affiliates of the registrant on June 30, 2009 was $187,417,167.00, computed by reference to the last sale price ($21.00 per common unit) of the registrant's common limited partner units on the New York Stock Exchange on June 30, 2009.

          The number of the registrant's common limited partner units outstanding on February 26, 2010 was 14,457,066.

DOCUMENTS INCORPORATED BY REFERENCE

None.


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TABLE OF CONTENTS

Item
   
  Page No.  

 

Part I

     

1 and 2.

 

Business and Properties

    1  

1A.

 

Risk Factors

    25  

1B.

 

Unresolved Staff Comments

    40  

3.

 

Legal Proceedings

    40  

4.

 

Submission of Matters to a Vote of Security Holders

    40  

 

Part II

       

5.

 

Market for the Registrant's Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities

    40  

6.

 

Selected Financial Data

    44  

7.

 

Management's Discussion and Analysis of Financial Condition and Results of Operations

    45  

7A.

 

Quantitative and Qualitative Disclosures About Market Risks

    62  

8.

 

Financial Statements and Supplementary Data

    64  

9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

    99  

9A.

 

Controls and Procedures

    99  

9B.

 

Other Information

    101  

 

Part III

       

10.

 

Directors, Executive Officers of Our General Partner and Corporate Governance

    101  

11.

 

Executive Compensation

    107  

12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

    113  

13.

 

Certain Relationships and Related Transactions, and Director Independence

    117  

14.

 

Principal Accounting Fees and Services

    121  

 

Part IV

     

15.

 

Exhibits, Financial Statement Schedules

    121  

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        Our annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, and any amendments to such reports, will be available free of charge on our website at www.transmontaignepartners.com under the heading "Unitholder Information," "SEC Filings" as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission. A copy of this annual report on Form 10-K (without exhibits) will be furnished without charge to any unitholder who sends a written request to our offices, addressed as follows: TransMontaigne Partners L.P., Attention: Investor Relations, 1670 Broadway, Suite 3100, Denver, Colorado 80202.


CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

        This annual report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, including the following:

    certain statements, including possible or assumed future results of operations, in "Management's Discussion and Analysis of Financial Condition and Results of Operations;"

    any statements contained in this annual report regarding the prospects for our business or any of our services or our ability to pay distributions;

    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

    other statements contained in this annual report 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.

        Important factors, many of which are described in more detail in "Item 1A. Risk Factors" of this annual report, that could cause actual results to differ materially from our expectations include, but are not limited to:

    a reduction in revenue from any of our significant customers upon which we rely for a substantial majority of our revenue;

    failure by any of our significant customers to continue to engage us to provide services after the expiration of existing terminaling services agreements, or our failure to secure comparable alternative arrangements;

    debt levels and restrictions in our debt agreements that may limit our operational flexibility;

    we may have to refinance our existing debt in unfavorable market conditions;

    a lack of access to new capital would impair our ability to expand our operations;

    the impact of Morgan Stanley's status as a bank holding company on its ability to conduct certain nonbanking activities or retain certain investments, including control of our general partner;

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

    competition from other terminals and pipelines that may be able to supply our significant customers with terminaling services on a more competitive basis;

    the continued creditworthiness of, and performance by, our significant customers;

    a decrease in demand for products in areas served by our terminals and pipelines;

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    the ability of our significant customers to secure financing arrangements adequate to purchase their desired volume of product;

    the impact on our facilities or operations of extreme weather conditions, such as hurricanes, and other events, such as terrorist attacks or war and costs associated with environmental compliance and remediation;

    timing, cost and other economic uncertainties related to the construction of new tank capacity or facilities;

    the impact of current and future laws and governmental regulations, general economic, market or business conditions;

    the failure of our existing and future insurance policies to fully cover all risks incident to our business;

    the age and condition of many of our pipeline and storage assets may result in increased maintenance and remediation expenditures;

    our ability to generate sufficient cash from operations to enable us to maintain or grow the amount of the quarterly distribution to our unitholders;

    conflicts of interest and the limited fiduciary duties of our general partner, which is indirectly controlled by Morgan Stanley Capital Group;

    cost reimbursements, which are determined by our general partner, and fees paid to our general partner and its affiliates for services will continue to be substantial;

    the control of our general partner being transferred to a third party without unitholder consent;

    our general partners limited call right may require unitholders to sell their common units at an undesirable time or price;

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

    the impact of new IRS regulations or a challenge of our current allocation of income, gain, loss and deductions among our unitholders or our use of a calendar year end for federal income tax purposes; and

    the sale or exchange of 50% or more of our capital and profits interests within a 12-month period would result in a deemed termination of our partnership for income tax purposes.

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


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Part I

ITEMS 1 AND 2.    BUSINESS AND PROPERTIES

        TransMontaigne Partners L.P. is a publicly traded Delaware limited partnership formed in February 2005 by TransMontaigne Inc. We commenced operations upon the closing of our initial public offering on May 27, 2005. Effective December 31, 2005, we changed our year end for financial and tax reporting purposes from June 30 to December 31. Effective September 1, 2006, Morgan Stanley Capital Group Inc., which we refer to as Morgan Stanley Capital Group, purchased all of the issued and outstanding capital stock of TransMontaigne Inc. and, as a result, Morgan Stanley, the parent company of Morgan Stanley Capital Group, became the indirect owner of our general partner. Our common units are traded on the New York Stock Exchange under the symbol "TLP." Our principal executive offices are located at 1670 Broadway, Suite 3100, Denver, Colorado 80202; our telephone number is (303) 626-8200. Unless the context requires otherwise, references to "we," "us," "our," "TransMontaigne Partners," "Partners" or the "partnership" are intended to mean TransMontaigne Partners L.P. and our wholly owned and controlled operating subsidiaries. References to TransMontaigne Inc. are intended to mean TransMontaigne Inc. and its subsidiaries other than TransMontaigne GP L.L.C., our general partner, and TransMontaigne Partners and its subsidiaries. Unless otherwise indicated in this annual report, references to common units owned by Morgan Stanley or its percentage ownership interest in us do not include common units that may be held in client or customer accounts controlled by affiliates of Morgan Stanley, which Morgan Stanley may be deemed to beneficially own under the federal securities laws.

OVERVIEW

        We are a terminaling and transportation company with operations primarily in the United States along the Gulf Coast, in the Midwest, in Brownsville, Texas, along the Mississippi and Ohio Rivers, and in the Southeast. We provide integrated terminaling, storage, transportation and related services for customers engaged in the distribution and marketing of light refined petroleum products, heavy refined petroleum products, crude oil, chemicals, fertilizers and other liquid products. Light refined products include gasolines, diesel fuels, heating oil and jet fuels. Heavy refined products include residual fuel oils and asphalt. We do not purchase or market products that we handle or transport. Therefore, we do not have material direct exposure to changes in commodity prices, except for the value of refined product gains and losses arising from terminaling services agreements with certain customers.

        TransMontaigne Partners has no officers or employees and all of our management and operational activities are provided by officers and employees of TransMontaigne Services Inc. TransMontaigne Services Inc. is an indirect wholly owned subsidiary of TransMontaigne Inc. TransMontaigne Inc. is an indirect wholly owned subsidiary of Morgan Stanley. We are controlled by our general partner, TransMontaigne GP L.L.C., which is an indirect wholly owned subsidiary of TransMontaigne Inc. TransMontaigne GP L.L.C. is a holding company with no independent assets or operations other than its general partner interest in TransMontaigne Partners L.P. TransMontaigne GP L.L.C. is dependent

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upon the cash distributions it receives from TransMontaigne Partners L.P. to service any obligations it may incur. The following diagram depicts our current organization and structure:

GRAPHIC

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        TransMontaigne Inc. is a leading distributor of unbranded refined petroleum products to independent wholesalers and industrial and commercial end users, delivering approximately 0.3 million barrels per day throughout the United States, primarily in the Gulf Coast, Southeast and Midwest regions. TransMontaigne Inc. currently relies on us to provide substantially all of the integrated terminaling services it requires to support its operations in these geographic regions.

        Morgan Stanley is a leading global trading company with extensive trading activities focused on the energy markets, including crude oil and refined petroleum products. Morgan Stanley Capital Group is the principal commodities trading arm of Morgan Stanley. Morgan Stanley Capital Group's trading and risk management activities cover a broad spectrum of the energy industry with extensive resources dedicated to refined product supply and transportation. Morgan Stanley Capital Group engages in trading physical commodities, like the refined petroleum products that we handle in our terminals, and exchange or over-the-counter commodities derivative instruments. Morgan Stanley Capital Group has access to substantial strategic long-term storage capacity located on all three coasts of the United States, in Northwest Europe and Asia.

        Our existing facilities are located in five geographic regions, which we refer to as our Gulf Coast, Midwest, Brownsville, River and Southeast facilities.

    Gulf Coast.  Our Gulf Coast facilities consist of eight refined product terminals, seven of which are located in Florida and one of which is located in Mobile, Alabama. These facilities currently have approximately 7.3 million barrels of aggregate active storage capacity.

    Midwest.  Our Midwest facilities consist of a 67-mile, interstate refined products pipeline between Missouri and Arkansas, which we refer to as the Razorback pipeline, and three refined product terminals with approximately 0.6 million barrels of aggregate active storage capacity.

    Brownsville.  Our terminal in Brownsville, Texas has approximately 2.2 million barrels of aggregate active storage capacity, which includes a liquefied petroleum gas, or LPG, terminaling facility with aggregate active storage capacity of approximately 33,000 barrels. We operate a bi-directional refined products pipeline for an affiliate of Mexico's state-owned petroleum company for deliveries to and from Brownsville and Reynosa and Cadereyta, Mexico. We also own and operate an LPG pipeline from our Brownsville facilities to our terminal in Matamoros, Mexico which we refer to as the Diamondback pipeline. Our Matamoros terminal has approximately 7,000 barrels of aggregate active LPG storage capacity.

    River.  Our River facilities are composed of 12 refined product terminals located along the Mississippi and Ohio Rivers with approximately 2.5 million barrels of aggregate active storage capacity. Our River facilities also include a dock facility located in Baton Rouge, Louisiana that is connected to the Colonial pipeline.

    Southeast.  Our Southeast facilities consist of 22 refined petroleum products terminals located along the Colonial and Plantation pipelines in Alabama, Georgia, Mississippi, North Carolina, South Carolina, and Virginia with an aggregate active storage capacity of approximately 9.1 million barrels.

        The volume of product that is handled, transported, throughput or stored in our terminals and pipelines is directly affected by the level of supply and demand in the wholesale markets served by our terminals and pipelines. Overall supply of refined products in the wholesale markets is influenced by the products' absolute prices, the availability of capacity on delivering pipelines and vessels, fluctuating refinery margins and the markets' perception of future product prices. The demand for gasoline typically peaks during the summer driving season, which extends from April to September, and declines during the fall and winter months. The demand for marine fuels typically peaks in the winter months due to the increase in the number of cruise ships originating from Florida ports. Despite these

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seasonalities, the overall impact on the volume of product throughput at our terminals and pipelines is not material.

Industry Overview

        Refined product terminaling and transportation companies, such as TransMontaigne Partners, facilitate the movement of refined products to consumers around the country. Consumption of refined products in the United States exceeds domestic production, which necessitates the importing of refined products from other countries. Moreover, a substantial majority of the petroleum refining that occurs in the United States east of the Rocky Mountains is concentrated in the Gulf Coast region, which necessitates the transportation of domestic product to other areas, such as the East Coast, Florida, Southeast and Midwest regions of the country. Terminaling and transportation companies receive, store, blend, treat and distribute refined products, both domestic and imported, as they are transported from refineries to wholesalers, retailers and end-users.

        Refining.    Refineries in the Gulf Coast region refine crude oil into various light refined products and heavy refined products. Light refined products include gasolines, diesel fuels, heating oils and jet fuels. Heavy refined products include residual fuel oils and asphalt. Refined products of specific grade and characteristics are substantially identical in composition from one refinery to another and are referred to as being "fungible." The refined products initially are stored at the refineries' own terminal facilities. The refineries owned by major oil companies then schedule for delivery some of their refined product output to satisfy their own retail delivery obligations, for example, at branded gasoline stations, and sell the remainder of their refined product output to independent marketing and distribution companies or traders, such as TransMontaigne Inc. and Morgan Stanley Capital Group, for resale.

        Transportation.    Before an independent distribution and marketing company, such as TransMontaigne Inc. and Morgan Stanley Capital Group, distributes refined petroleum products in the wholesale markets, it must first schedule that product for shipment by tankers or barges or on common carrier pipelines to a terminal.

        Refined product is transported to marine terminals, such as our Gulf Coast terminals and Baton Rouge, Louisiana dock facility, by vessels or barges. Because there are economies of scale in transporting products by vessel, marine terminals with larger storage capacities for various commodities have the ability to offer their customers lower per-barrel freight costs to a greater extent than do terminals with smaller storage capacities.

        Refined product reaches inland terminals, such as our Southeast and Midwest terminals, by common carrier pipelines. Common carrier pipelines are pipelines with published tariffs that are regulated by the Federal Energy Regulatory Commission, or FERC, or state authorities. These pipelines ship fungible refined products in batches, with each batch generally consisting of product owned by several different companies. As a batch of product is shipped on a pipeline, each terminal operator along the way draws the volume of product that is scheduled for that facility as the batch passes in the pipeline. Consequently, each terminal operator must monitor the type of product in the common carrier pipeline to determine when to draw product scheduled for delivery to that terminal. In addition, both the common carrier pipeline and the terminal operator monitor the volume of product drawn to ensure that the amount scheduled for delivery at that location is actually received.

        At both inland and marine terminals, the various products are stored in tanks on behalf of our customers.

        Delivery.    Most terminals have a tanker truck loading facility commonly referred to as a "rack." Often, commercial and industrial end-users and independent retailers rely on independent trucking companies to pick up product at the rack and transport it to the end-user or retailer at its location. Each truck holds an aggregate of approximately 8,000 gallons (approximately 190 barrels) of various

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refined products in different compartments. To initiate the transfer of product, the driver uses an access control card that identifies the customer purchasing the refined product, the carrier and the driver as well as the type or grade of refined products to be pumped into the truck. A computerized system electronically reviews the credentials of the carrier, including insurance and certain mandated certifications, and confirms the customer is within product allocation limits. When all conditions are verified as being current and correct, the system authorizes the delivery of the refined product to the truck. As refined product is being loaded into the truck, additives are injected to conform to government specifications and individual customer requirements. If a truck is loading gasoline for retail sale by an independent gasoline station, generic additives will be added to the gasoline as it is loaded into the truck. If the gasoline is for delivery to a branded retail gasoline station, the proprietary additive compound of that particular retailer will be added to the gasoline as it is loaded. The type and amount of additive are electronically and mechanically controlled by equipment located at the truck loading rack. Generally one to two gallons of additive are injected into an 8,000 gallon truckload of gasoline.

        At marine terminals, the refined product is stored in tanks and may be delivered to tanker trucks over a rack in the same manner as at an inland terminal or to cruise ships and other vessels, known as bunkering, either at the dock, through a pipeline, or by truck or barge. Cruise ships typically purchase approximately 6,000 to 8,000 barrels, the equivalent of approximately 42 tanker truckloads, of bunker fuel per refueling. Bunker fuel is a mixture of residual fuel oil and diesel fuel. Each large vessel generally requires its own mixture of bunker fuel to match the distinct characteristics of that ship's engines and turbines. Because the mixture for each ship requires precision to mix and deliver, cruise ships often prefer to obtain their fuel from experienced companies.

Our Operations

        We are a terminaling and transportation company with operations primarily in the United States along the Gulf Coast, in the Midwest, in Brownsville, Texas, along the Mississippi and Ohio Rivers, and in the Southeast. We use our terminaling facilities to, among other things:

    receive refined products from the pipeline, ship, barge or railcar making delivery on behalf of our customers, and transfer those refined products to the tanks located at our terminals;

    store the refined products in our tanks for our customers;

    monitor the volume of the refined products stored in our tanks;

    distribute the refined products out of our terminals in truckloads using truck racks and other distribution equipment located at our terminals, including pipelines; and

    heat residual fuel oils and asphalt stored in our tanks, and provide other ancillary services related to the throughput process.

        We derive revenue from our terminal and pipeline transportation operations by charging fees for providing integrated terminaling, transportation and related services. The fees we charge and our other sources of revenue are composed of:

    Terminaling Services Fees.  We generate terminaling services fees by distributing and storing products for our customers. Terminaling services fees include throughput fees based on the volume of product distributed from the facility, injection fees based on the volume of product injected with additive compounds and storage fees based on a rate per barrel of storage capacity per month.

    Pipeline Transportation Fees.  We earn pipeline transportation fees at our Razorback pipeline and Diamondback pipeline based on the volume of product transported and the distance from the

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      origin point to the delivery point. The Federal Energy Regulatory Commission, or FERC, regulates the tariff on the Razorback pipeline and the Diamondback pipeline.

    Management Fees and Reimbursed Costs.  We manage and operate certain tank capacity at our Port Everglades (South) terminal for a major oil company and receive a reimbursement of its proportionate share of operating and maintenance costs. We manage and operate for an affiliate of Mexico's state-owned petroleum company a bi-directional products pipeline connected to our Brownsville, Texas terminal facility and receive a management fee and reimbursement of costs. We also manage and operate for another major oil company two terminals that are adjacent to our Southeast facilities and receive a reimbursement of its proportionate share of operating and maintenance costs.

    Other Revenue.  We provide ancillary services including heating and mixing of stored products, product transfer services, railcar handling, wharfage fees and vapor recovery fees. Pursuant to terminaling services agreements with our throughput customers, we are entitled to the volume of product gained resulting from differences in the measurement of product volumes received and distributed at our terminaling facilities. Consistent with recognized industry practices, measurement differentials occur as the result of the inherent variances in measurement devices and methodology. We recognize as revenue the net proceeds from the sale of the product gained.

        The locations and approximate aggregate active storage capacity at our terminal facilities as of December 31, 2009 are as follows:

Locations
  Active storage
capacity (shell bbls)
 

Gulf Coast Facilities

       
 

Florida

       
   

Port Everglades Complex

       
     

Port Everglades-North

    2,990,000  
     

Port Everglades-South(1)

    377,000  
   

Jacksonville

    271,000  
   

Cape Canaveral

    701,000  
   

Port Manatee

    1,385,000  
   

Fisher Island

    673,000  
   

Tampa

    694,000  
 

Alabama

       
   

Mobile

    163,000  
       

Gulf Coast Total

    7,254,000  
       

Midwest Facilities

       
 

Rogers and Mt. Vernon (aggregate amounts)

    406,000  
 

Oklahoma City

    158,000  
       

Midwest Total

    564,000  
       

Brownsville, Texas Facilities

       
 

Brownsville

    2,182,000  
 

Matamoros, Mexico

    7,000  
       

Brownsville Total

    2,189,000  
       

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Locations
  Active storage
capacity (shell bbls)
 

River Facilities

       
 

Arkansas City, AR

    418,000  
 

Evansville, IN

    245,000  
 

New Albany, IN

    201,000  
 

Greater Cincinnati, KY

    200,000  
 

Henderson, KY

    182,000  
 

Louisville, KY

    181,000  
 

Owensboro, KY

    157,000  
 

Paducah, KY Complex

    322,000  
 

Baton Rouge, LA Dock

     
 

Greenville, MS (Clay Street)

    189,000  
 

Greenville, MS (Industrial Road)

    56,000  
 

Cape Girardeau, MO

    140,000  
 

East Liverpool, OH

    203,000  
       

River Total

    2,494,000  
       

Southeast Facilities

       
 

Albany, GA

    203,000  
 

Americus, GA

    93,000  
 

Athens, GA

    203,000  
 

Bainbridge, GA

    261,000  
 

Belton, SC

     
 

Birmingham, AL

    178,000  
 

Charlotte, NC

    121,000  
 

Collins/Purvis, MS

    2,653,000  
 

Collins, MS

    141,000  
 

Doraville, GA

    438,000  
 

Fairfax, VA

    513,000  
 

Greensboro, NC

    479,000  
 

Griffin, GA

    107,000  
 

Lookout Mountain, GA

    221,000  
 

Macon, GA

    174,000  
 

Meridian, MS

    139,000  
 

Montvale, VA

    503,000  
 

Norfolk, VA

    1,336,000  
 

Richmond, VA

    478,000  
 

Rome, GA

    152,000  
 

Selma, NC

    529,000  
 

Spartanburg, SC

    166,000  
       

Southeast Total

    9,088,000  
       

TOTAL CAPACITY

    21,589,000  
       

(1)
Reflects our ownership interest net of a major oil company's ownership interest in certain tank capacity.

        Gulf Coast Operations.    Our Gulf Coast operations include eight refined product terminals located in Florida and Alabama. At our Gulf Coast terminals, we handle refined products and crude oil on behalf of, and provide integrated terminaling services to, customers engaged in the distribution and marketing of refined products and crude oil and the United States government. Our Gulf Coast

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terminals receive refined products from vessels on behalf of our customers. In addition, our Jacksonville terminal also receives asphalt by rail and our Port Everglades (North) terminal also receives product by truck. We distribute by truck or barge at all of our Gulf Coast terminals. In addition, we distribute products by pipeline at our Port Everglades and Tampa terminals and by rail at our Jacksonville terminal. A major oil company retains an ownership interest, ranging from 25% to 50%, in specific tank capacity at our Port Everglades (South) terminal. We manage and operate the Port Everglades (South) terminal, and we are reimbursed by the major oil company for its proportionate share of our operating and maintenance costs. Our Mobile, Alabama terminal facility receives and distributes refined product to trucks and barges.

        The principal customers at our Gulf Coast facilities are Marathon Petroleum Company LLC, which we refer to as Marathon, and Morgan Stanley Capital Group.

        Midwest Terminals and Pipeline Operations.    In Missouri and Arkansas we own and operate the Razorback pipeline and terminals in Mt. Vernon, Missouri, at the origin of the pipeline and in Rogers, Arkansas, at the terminus of the pipeline. The Razorback pipeline is a 67-mile, 8-inch diameter interstate common carrier pipeline that transports light refined product on behalf of Morgan Stanley Capital Group from our terminal at Mt. Vernon, where it is interconnected with a pipeline system owned by Magellan Midstream Partners, to our terminal at Rogers. The Razorback pipeline has a capacity of approximately 30,000 barrels per day. The FERC regulates the transportation tariffs for interstate shipments on the Razorback pipeline. Morgan Stanley Capital Group currently is the only shipper on the Razorback pipeline and our sole customer at our Rogers and Mt. Vernon terminals.

        We also own and operate a terminal facility at Oklahoma City, Oklahoma. Our Oklahoma City terminal receives gasolines and diesel fuels from a pipeline system owned by Magellan Midstream Partners for delivery via our truck rack to Shell Oil Products U.S., which we refer to as Shell, for redistribution to locations throughout the Oklahoma City region.

        Brownsville, Texas Operations.    In Brownsville, Texas, we own and operate two terminal facilities and the Diamondback pipeline which handle liquid product movements between Mexico and south Texas including refined petroleum products, chemicals, vegetable oils, naphtha, wax and propane on behalf of, and provide integrated terminaling services to, third parties engaged in the distribution and marketing of refined products and natural gas liquids. Our Brownsville facilities receive refined products on behalf of our customers from vessels, by truck or railcar. We also receive natural gas liquids by pipeline.

        The Diamondback pipeline consists of an 8" pipeline that transports LPG approximately 23 miles from our Brownsville facilities to our Matamoros terminal, with approximately 16 miles located in Texas and approximately 7 miles located in Mexico and a 6" pipeline, which runs parallel to the 8" pipeline, that can be used by us in the future to transport additional LPG or refined products to our Matamoros terminal. The 8" pipeline has a capacity of approximately 7,500 barrels per day. The 6" pipeline has a capacity of approximately 4,300 barrels per day.

        We also operate and maintain the United States portion of a 174-mile bi-directional refined products pipeline owned by PMI Services North America, Inc., an affiliate of Petroleos Mexicanos, or PEMEX, the state-owned, national petroleum company of Mexico. This pipeline connects our Brownsville terminal complex to a pipeline in Mexico that delivers to PEMEX's terminal located in Reynosa, Mexico and terminates at PEMEX's refinery, located in Cadereyta, Nuevo Leon, Mexico, a suburb of the large industrial city of Monterrey. The pipeline transports refined products and blending components. We operate and manage the approximately 18-mile portion of the pipeline located in the United States for a fee that is based on the average daily volume handled during the month. Additionally, we are reimbursed for non-routine maintenance expenses based on the actual costs plus a fee based on a fixed percentage of the expense.

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        The customers we serve at our Brownsville terminal facilities consist principally of wholesale and retail marketers of refined products and industrial and commercial end-users of refined products, waxes and industrial chemicals. Our principal customers are Valero Marketing and Supply Company, which we refer to as Valero, TransMontaigne Inc., Morgan Stanley Capital Group, and PMI Trading Limited.

        River Operations.    Our River facilities include 12 refined product terminals along the Mississippi and Ohio Rivers and the Baton Rouge, Louisiana dock facility. At our River terminals, we handle gasolines, diesel fuels, heating oil, chemicals and fertilizers on behalf of, and provide integrated terminaling services to, customers engaged in the distribution and marketing of refined products and industrial and commercial end-users. Our River terminals receive products from vessels and barges on behalf of our customers and distribute products primarily to trucks and barges. The principal customer at our River facilities is Valero.

        Southeast Operations.    Our Southeast facilities include 22 refined product terminals along the Plantation and Colonial pipelines. At our Southeast terminals, we handle gasolines, diesel fuels, jet fuel and heating oil on behalf of, and provide integrated terminaling services to customers engaged in the distribution and marketing of refined products and the United States Government. Our Southeast terminals primarily receive products from the Plantation and Colonial pipelines on behalf of our customers and distribute products primarily to trucks. The principal customers at our Southeast facilities are Morgan Stanley Capital Group and the United States government.

Business Strategies

        Our primary business objective is to increase distributable cash flow per unit. The most effective means of growing our business and increasing cash distributions to our unitholders is to expand our asset base and infrastructure, and to increase utilization of our existing infrastructure. We intend to accomplish this by executing the following strategies:

        Generate stable cash flows through the use of long-term contracts with our customers.    We intend to continue to generate stable cash flows by capitalizing on the fee-based nature of our business, our minimum revenue commitments from our customers and the long-term nature of our contracts with many of our customers. We generate revenue from customers who pay us fees based on the volume of storage capacity contracted for, volume of refined products throughput at our terminals or volume of refined products transported in the Razorback and Diamondback pipelines. We have long-term terminaling services agreements with, among others, Marathon, Morgan Stanley Capital Group, PMI Trading Limited, the United States government, TransMontaigne Inc. and Valero.

        Pursue strategic and accretive acquisitions in new and existing markets.    We plan to pursue acquisitions of energy-related terminaling and transportation facilities, including facilities that may be outside our existing areas of operation. In many cases, we would expect to pursue these acquisitions jointly with TransMontaigne Inc. and Morgan Stanley Capital Group. In light of the recent industry trend of large energy companies divesting their distribution and logistic assets, we believe there will continue to be significant acquisition opportunities.

        Maximize the benefits of our relationship with TransMontaigne Inc. and Morgan Stanley Capital Group.    TransMontaigne Inc. and Morgan Stanley Capital Group intend to use us as the primary vehicle for their energy-related terminaling and transportation businesses that support their physical trading, marketing and distribution businesses. We intend to capitalize on the strategic fit between our infrastructure with Morgan Stanley Capital Group's global supply capabilities and TransMontaigne Inc.'s marketing and distribution business. In addition, our relationship with TransMontaigne Inc. and Morgan Stanley Capital Group provides us with access to a significant pool of management talent and strong relationships throughout the energy industry, which we intend to utilize to implement our strategies.

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        Execute cost-effective expansion and asset enhancement opportunities.    We continually evaluate opportunities to expand our existing asset base. For example, in 2009 we placed newly constructed tanks into service at certain of our Gulf Coast terminals, added ethanol blending functionality at certain of our Southeast terminals and placed additional LPG tankage into service at our Brownsville terminals. We have additional projects in progress to expand our Gulf Coast terminaling capacity and to add additional ethanol blending functionality at certain of our Southeast terminals.

        Maintain a disciplined financial policy.    We will continue to pursue a disciplined financial policy by maintaining a prudent capital structure, managing our exposure to interest rate risk and conservatively managing our cash reserves.

Competitive Strengths

        We believe that we are well positioned to successfully execute our business strategies using the following competitive strengths:

        The terminaling services agreements we have with our existing customers provide us with stable cash flows.    Based on our terminaling services agreements in effect at January 1, 2010, we have contractual commitments from our customers that are expected to generate a substantial majority of our actual revenue for the year ending December 31, 2010. Of this firm commitment revenue, approximately 70% was generated under terminaling services agreements with remaining terms of greater than three years at December 31, 2009. We expect that our actual revenue for the year will be higher than our contractual commitments because certain of our terminaling services agreements with customers do not contain minimum revenue commitments and because our customers often use other services we provide that are in addition to the services covered by the minimum revenue commitments. We believe that the fee-based nature of our business, our minimum revenue commitments from our customers, the long-term nature of our contracts with many of our customers and our lack of material direct exposure to changes in commodity prices (except for the value of refined product gains and losses arising from terminaling services agreements with certain customers) will provide us with stable cash flows.

        We do not have material direct commodity price risk.    Because we do not purchase or market the products that we handle or transport, our cash flows are not subject to material direct exposure to changes in commodity prices, except for the value of refined product gains and losses arising from terminaling services agreements with certain customers.

        We benefit from the strategic fit between our operations and the operations of TransMontaigne Inc. and Morgan Stanley Capital Group.    The operations of TransMontaigne Inc. and Morgan Stanley Capital Group fit strategically with our broad geographical terminal and transportation distribution capability. Our terminaling service agreements with TransMontaigne Inc. and Morgan Stanley Capital Group enable them to support their refined product supply, risk management and marketing businesses and, at the same time, provide us with stable cash flows and help ensure that our facilities are more fully utilized.

        Our relationships with TransMontaigne Inc. and Morgan Stanley Capital Group enhance our ability to make strategic acquisitions.    Under the omnibus agreement with TransMontaigne Inc., we have the right to negotiate for the purchase of certain facilities that TransMontaigne Inc. purchases or constructs in the future. In addition, we believe that our relationships with TransMontaigne Inc. and Morgan Stanley Capital Group will provide us with an advantage in acquiring businesses that have an element of commodity price risk or product marketing and distribution risk inherent in their operations. In these circumstances, we expect that Morgan Stanley Capital Group will assume most or all of the direct commodity price exposure and that TransMontaigne Inc. will assume most or all of the risks related to distributing and marketing the product. As a result, we expect to operate the acquired asset infrastructure under terminaling services agreements that will provide us with stable cash flows. Moreover, we believe that the value of any terminaling facilities that we acquire will be enhanced if we can concurrently obtain a terminaling services agreement with TransMontaigne Inc. or Morgan Stanley Capital Group.

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        We have the ability to execute cost-effective expansion and asset enhancement opportunities.    We have high utilization of our existing storage capacity, which enables us to focus on expanding our terminal capacity and acquiring additional terminal capacity for our current and future customers. In addition, the current expansion of our waterborne terminal capacity at our Gulf Coast terminals may facilitate a significant reduction in freight costs for our customers.

        We have a substantial presence in Florida, which has significant demand for refined petroleum products, and is not currently served by any local refinery or interstate refined product pipeline.    Seven of our terminals serve our customers' operations in metropolitan areas in Florida, which we believe to be an attractive area for the following reasons:

    Refined products are largely distributed in Florida through terminals with waterborne access, such as our terminals, because Florida has no refineries or interstate refined product pipelines.

    The Florida market is attractive to physical commodity traders because they can originate product supplies from multiple locations, both domestically and overseas, and transport the product to the terminal by vessel.

    The ports served by our terminals are among the busiest cruise ship ports in the United States, with year-round demand.

        Through TransMontaigne Inc. and Morgan Stanley Capital Group, our general partner has access to a knowledgeable management team with significant experience in the energy industry and in executing acquisition and expansion strategies.    The members of our general partner's management team have significant experience with regard to the implementation of acquisition, operating and growth strategies in many facets of the energy industry, including:

    crude oil marketing and transportation;

    natural gas and natural gas liquid gathering, processing, transportation and marketing;

    propane storage, transportation and marketing; and

    refined product storage, transportation and marketing.

Over the course of their respective careers, members of our general partner's management team have established strong, long-standing relationships within the energy industry, which we believe will enable us to grow and expand our business through both acquisitions and internal expansion. In addition, through our affiliation with Morgan Stanley Capital Group, we have access to its strong relationships throughout the energy industry.

Competition

        We face competition from other terminals and pipelines that may be able to supply our customers with integrated terminaling and transportation services on a more competitive basis. We compete with national, regional and local terminal and transportation companies, including the major integrated oil companies, of widely varying sizes, financial resources and experience. These competitors include BP p.l.c., Chevron U.S.A. Inc., CITGO Petroleum Corporation, Conoco Phillips, Exxon Mobil Corporation, Amerada Hess Corporation, Holly Corporation and its affiliate Holly Energy Partners, L.P., Kinder Morgan, Inc. and its affiliate Kinder Morgan Energy Partners, L.P., Magellan Midstream Partners, L.P., Marathon Ashland Petroleum, LLC, Motiva Enterprises LLC, Murphy Oil Corporation, NuStar Energy L.P., Sunoco, Inc. and its affiliate Sunoco Logistics Partners L.P., and

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terminals in the Caribbean. In particular, our ability to compete could be harmed by factors we cannot control, including:

    price competition from terminal and transportation companies, some of which are substantially larger than we are and have greater financial resources, and control substantially greater storage capacity, than we do;

    the perception that another company can provide better service; and

    the availability of alternative supply points, or supply points located closer to our customers' operations.

        We also compete with national, regional and local terminal and transportation companies for acquisition and expansion opportunities. Some of these competitors are substantially larger than us and have greater financial resources and lower costs of capital than we do.

Significant Customer Relationships

        We have several significant customer relationships from which we expect to continue to derive a substantial majority of our revenue for the foreseeable future. These relationships include:

Customer
  Location
Morgan Stanley Capital Group   Gulf Coast, Midwest, Brownsville and Southeast facilities
TransMontaigne Inc   Gulf Coast and Brownsville facilities
Valero Marketing and Supply Company   River and Brownsville facilities
Marathon Petroleum Company LLC   Gulf Coast and River facilities
PMI Trading Limited, an affiliate of PEMEX   Brownsville facilities

Our Relationship With TransMontaigne Inc. And Morgan Stanley Capital Group

        General.    A majority of our business is devoted to providing integrated terminaling and transportation services to Morgan Stanley Capital Group. Pursuant to the terms of our terminaling services agreements with Morgan Stanley Capital Group, we expect to continue to derive a majority of our revenue from Morgan Stanley Capital Group for the foreseeable future.

        We are controlled by our general partner, TransMontaigne GP L.L.C., which is an indirect wholly owned subsidiary of TransMontaigne Inc. Formed in 1995, TransMontaigne Inc. is a terminaling, distribution and marketing company that markets refined petroleum products to wholesalers, distributors and industrial and commercial end users throughout the United States, primarily in the Gulf Coast, Southeast and Midwest regions. TransMontaigne Inc. also owns a 100% interest in Olco Petroleum Group Inc., a Canadian petroleum marketing and terminaling company. As of February 26, 2010, TransMontaigne Inc. owned six refined product terminals; one dry bulk product terminal; a hydrant system in Port Everglades; and its distribution and marketing business. TransMontaigne Inc.'s marketing operations generally consist of the distribution and marketing of refined products through contract and rack spot sales in the physical markets. On September 1, 2006, a wholly owned subsidiary of Morgan Stanley Capital Group purchased all of the issued and outstanding capital stock of TransMontaigne Inc. TransMontaigne Inc. and Morgan Stanley Capital Group have a significant interest in our partnership through their ownership of common units representing limited partner interests equal to approximately 22.1% of our aggregate outstanding limited and general partner interests, our sole general partner interest (representing 2% of our aggregate outstanding limited and general partner interests) and the incentive distribution rights.

        Morgan Stanley Capital Group is a leading global commodity trader involved in proprietary and counterparty-driven trading in numerous commodities markets including crude oil and refined products,

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natural gas and natural gas liquids, coal, electric power, base and precious metals and others. Morgan Stanley Capital Group has been actively trading crude oil and refined products for over 20 years and on a daily basis trades millions of barrels of physical crude oil and refined products and exchange-traded and over-the-counter crude oil and refined product derivative instruments. Morgan Stanley Capital Group also invests as principal in acquisitions that complement Morgan Stanley's commodity trading activities. Morgan Stanley Capital Group has substantial strategic long-term storage capacity located on all three coasts of the United States, in Northwest Europe and Asia.

Rights of First Offer and Refusal

        The omnibus agreement provides us with a right of first offer to purchase TransMontaigne Inc.'s and its subsidiaries' right, title and interest in the Pensacola, Florida refined petroleum products terminal and any assets acquired in an asset exchange transaction that replace the Pensacola assets. If we and TransMontaigne Inc. cannot agree on the terms of the purchase, TransMontaigne Inc. has the right during a six-month period following our offer to sell such assets to a third party bidder who pays at least 105% of the purchase price offered by us; provided that if TransMontaigne Inc. does not sell the assets to a third-party bidder during this period, we have the right to purchase the assets on the terms previously offered by us. This right of first offer is exercisable on or before December 15, 2010.

        The omnibus agreement also provides TransMontaigne Inc. a right of first refusal to purchase any assets that we propose to sell. Before we enter into any contract to sell such terminal or pipeline facilities to a third party, we must give written notice of all material terms of such proposed sale to TransMontaigne Inc. TransMontaigne Inc. will then have the sole and exclusive option for a period of 45 days following receipt of the notice, to purchase the subject facilities for no less than 105% of the purchase price offered by the third party on the terms specified in the notice.

        TransMontaigne Inc. also has a right of first refusal to contract for the use of any refined product storage capacity that we put into commercial service (i) after January 1, 2008, or (ii) was subject to a terminaling services agreement that expires or is terminated (excluding a contract renewable solely at the option of our customer) after January 1, 2008, provided that TransMontaigne Inc. agrees to pay 105% of the fees offered by the third party customer.

Terminaling Services Agreements

        Florida Terminals and Razorback Pipeline System Terminaling Services Agreement—Morgan Stanley Capital Group.    We have a terminaling services agreement with Morgan Stanley Capital Group relating to our Florida, Mt. Vernon, Missouri and Rogers, Arkansas terminals. Effective June 1, 2008, we amended the terminaling services agreement to include renewable fuels blending functionality at the Florida Terminals. The initial term expires on May 31, 2014 for the Florida terminals and on May 31, 2012 for the Razorback pipeline system. After the initial term, the terminaling services agreement will automatically renew for subsequent one-year periods, subject to either party's right to terminate with six months' notice prior to the end of the initial term or the then current renewal term. Under this agreement, Morgan Stanley Capital Group agreed to throughput a volume of refined product that will, at the fee and tariff schedule contained in the agreement, result in minimum throughput payments to us of approximately $36.3 million for the contract year ending May 31, 2010 (approximately $36.6 million for the contract year ending May 31, 2011); with stipulated annual increases in throughput payments each contract year thereafter. Morgan Stanley Capital Group's minimum annual throughput payment is reduced proportionately for any decrease in storage capacity due to out-of-service tank capacity.

        If a force majeure event occurs that renders performance impossible with respect to an asset for at least 30 consecutive days, Morgan Stanley Capital Group's obligations would be temporarily suspended with respect to that asset. If a force majeure event continues for 30 consecutive days or more and

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results in a diminution in the storage capacity we make available to Morgan Stanley Capital Group, Morgan Stanley Capital Group's minimum revenue commitment would be reduced proportionately for the duration of the force majeure event.

        Morgan Stanley Capital Group may not assign the terminaling services agreement without our consent. Upon termination of the agreement, Morgan Stanley Capital Group has a right of first refusal to enter into a new terminaling services agreement with us, provided they pay no less than 105% of the fees offered by any third party.

        Southeast Terminaling Services Agreement—Morgan Stanley Capital Group.    We have a terminaling and transportation services agreement with Morgan Stanley Capital Group relating to our Southeast terminals. The terminaling services agreement commenced on January 1, 2008 and has a seven-year term expiring on December 31, 2014, subject to a seven-year renewal option at the election of Morgan Stanley Capital Group. Under this agreement, Morgan Stanley Capital Group agreed to throughput a volume of refined product at our Southeast terminals that will, at the fee schedule contained in the agreement, result in minimum throughput payments to us of approximately $33.1 million for the contract year ending December 31, 2010; with stipulated annual increases in throughput payments each contract year thereafter. Morgan Stanley Capital Group's minimum annual throughput payment is reduced proportionately for any decrease in storage capacity due to out-of-service tank capacity. In exchange for its minimum throughput commitment, we agreed to provide Morgan Stanley Capital Group approximately 8.7 million barrels of light oil storage capacity at our Southeast terminals. Under this agreement we also agreed to undertake certain capital projects to provide renewable fuels blending functionality at certain of our Southeast terminals with estimated completion dates that extend through December 31, 2010. Upon completion of each of the projects, Morgan Stanley Capital Group has agreed to pay us an ethanol blending fee. At December 31, 2009, we had received payments totaling approximately $17 million and we expect to receive future payments through December 31, 2010 from Morgan Stanley Capital Group in the range of $4 million to $8 million.

        If a force majeure event occurs that renders performance impossible with respect to an asset for at least 30 consecutive days, Morgan Stanley Capital Group's obligations would be temporarily suspended with respect to that asset. If a force majeure event continues for 30 consecutive days or more and results in a diminution in the storage capacity we make available to Morgan Stanley Capital Group, Morgan Stanley Capital Group's minimum revenue commitment would be reduced proportionately for the duration of the force majeure event.

        Morgan Stanley Capital Group may not assign the terminaling services agreement without our consent.

        Collins Terminaling Services Agreement—Morgan Stanley Capital Group.    In January 2010, we entered into a terminaling services agreement with Morgan Stanley Capital Group relating to our Collins, Mississippi facility that will expire seven years following the in-service date of certain tank capacity and other improvements to be constructed by us, subject to one-year automatic renewals unless terminated by either party upon 180 days notice prior to the end of the then-current renewal term. Under this agreement, Morgan Stanley Capital Group agreed to throughput a volume of light oil products at our terminal that will, at the fee schedule contained in the agreement, result in minimum throughput payments to us of approximately $4.1 million for the one-year period following the in-service date. In exchange for its minimum revenue commitment, we agreed to undertake certain capital projects to provide an additional 700,000 barrels of light oil capacity and other improvements at the Collins terminal, with estimated completion to occur on or before May 1, 2011.

        If a force majeure event occurs that renders performance impossible with respect to an asset for at least 30 consecutive days, Morgan Stanley Capital Group's obligations would be temporarily suspended with respect to that asset. If a force majeure event continues for 30 consecutive days or more and results in a diminution in the storage capacity we make available to Morgan Stanley Capital Group,

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Morgan Stanley Capital Group's minimum revenue commitment would be reduced proportionately for the duration of the force majeure event.

        Neither party may transfer or assign this agreement without the consent of the other party unless such assignment is to an affiliate or, in the case of Partners, a successor in interest to us or to the Collins terminal.

        Southeast Terminaling Services Agreement—United States Government.    We have a terminaling services agreement with the United States government that will expire on April 30, 2012. The United States government has the option to extend the agreement for two additional five-year increments. Pursuant to the terminaling services agreement, we agreed to provide the United States government with approximately 0.3 million barrels of light refined product storage capacity at our Selma, NC terminal.

        Gulf Coast (Mobile) Terminaling Services Agreement—TransMontaigne Inc.    We have a terminaling and transportation services agreement with TransMontaigne Inc. that will expire on December 31, 2012. Under this agreement, TransMontaigne Inc. agreed to throughput at our Mobile terminal a volume of refined products that will, at the fee schedule contained in the agreement, result in minimum revenue to us of approximately $2.5 million for the contract year ending December 31, 2010.

        Gulf Coast (Florida) Terminaling Services Agreement—Marathon.    We have a terminaling services agreement with Marathon regarding approximately 1.0 million barrels of asphalt storage capacity throughout our Florida facilities that will expire on May 1, 2011. Under the terms of the Terminaling Services Agreement, we are proscribed from placing into commercial service any new or converted asphalt storage capacity at our Florida facilities without Marathon's express written consent.

        River Terminaling Services Agreement—Valero.    We have a terminaling services agreement with Valero that will expire on April 1, 2013. Pursuant to the terminaling services agreement, we agreed to provide Valero with approximately 1.1 million barrels of light refined product storage capacity, in the aggregate, at our Cape Girardeau, Evansville, Greenville, Henderson, Owensboro and Paducah terminals. Valero also has a right to match any third-party offer to use any existing, new or converted light refined product storage capacity that we put into commercial service at any of the River terminals subject to this agreement. If Valero fails to exercise its right to match, it has the right to terminate the terminaling services agreement in its entirety or with respect to the applicable terminal.

        Brownsville LPG Terminaling Services Agreement—TransMontaigne Inc.    We have a terminaling and transportation services agreement with TransMontaigne Inc. relating to our Brownsville, Texas facilities that will expire on March 31, 2010. Under this agreement, TransMontaigne Inc. agreed to throughput at our Brownsville facilities certain minimum volumes of natural gas liquids that will result in minimum revenue to us of approximately $1.6 million per year. In exchange for TransMontaigne Inc.'s minimum throughput commitment, we agreed to provide TransMontaigne Inc. approximately 33,000 barrels of LPG storage capacity at our Brownsville facilities.

        Matamoros LPG Terminaling Services Agreement—TransMontaigne Inc.    During 2008, we entered into a terminaling and transportation services agreement with TransMontaigne Inc. relating to our natural gas liquids storage facility in Matamoros, Mexico that will expire on March 31, 2010. Under this agreement, TransMontaigne Inc. agreed to throughput a volume of natural gas liquids that will, at the fee schedule contained in the agreement, result in minimum throughput payments to us of approximately $0.6 million per year. In exchange for TransMontaigne Inc.'s minimum throughput payments, we agreed to provide TransMontaigne Inc. approximately 7,000 barrels of natural gas liquids storage capacity.

        Brownsville Terminaling Services Agreements—PMI Trading Limited.    We have multiple terminaling services agreements with PMI Trading Limited, an affiliate of PEMEX, relating to our Brownsville,

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Texas facilities that, if not renewed, will expire between August 31, 2010 and June 30, 2016. Under these agreements, PMI agreed to throughput and store at our terminals certain minimum volumes of aviation gasoline, diesel, gasoline, jet fuel, distillate, and natural gas liquids. We also manage and operate an approximately 18-mile bi-directional pipeline on behalf of PMI.

        Brownsville Terminaling Services Agreement—Morgan Stanley Capital Group.    We have a terminaling and transportation services agreement with Morgan Stanley Capital Group, relating to our Brownsville, Texas facilities that will expire on October 31, 2010. Under this agreement, Morgan Stanley Capital Group agreed to store a specified minimum amount of fuel oils at our terminals that will result in minimum revenue to us of approximately $1.3 million per year. In exchange for its minimum revenue commitment, we agreed to provide Morgan Stanley Capital Group a minimum amount of storage capacity for such fuel oils.

        Brownsville Terminaling Services Agreement—Valero.    We have a terminaling services agreement with Valero pursuant to which we agreed to provide Valero with approximately 168,000 barrels of heavy oil storage capacity at our Brownsville facilities. The current term of the terminaling services agreement expires on January 31, 2012. At the end of the current term, the terminaling services agreement will automatically renew for subsequent two-year periods, subject to either party's right to terminate with 90 days notice prior to the end of the then-current renewal term. In September 2009, we entered into an additional terminaling services agreement with Valero pursuant to which we agreed to provide Valero with approximately 147,000 barrels of light oil storage capacity at our Brownsville facilities. Under this agreement, we also agreed to undertake certain capital projects with estimated completion dates through August 1, 2010. The current term of the terminaling services agreement expires five years from the in-service date of certain capital projects. At the end of the current term, the terminaling services agreement will automatically renew for subsequent five-year periods, subject to either party's right to terminate with 90 days notice prior to the end of the then-current renewal term.

        Oklahoma City Revenue Support Agreement—TransMontaigne Inc.    We have a revenue support agreement with TransMontaigne Inc. that provides that in the event any current third-party terminaling agreement should expire, TransMontaigne Inc. agrees to enter into a terminaling services agreement that will expire no earlier than November 1, 2012. The terminaling services agreement will provide that TransMontaigne Inc. agrees to throughput such volume of refined product as may be required to guarantee minimum revenue to us of $0.8 million per year. If TransMontaigne Inc. fails to meet its minimum revenue commitment in any year, it must pay us the amount of any shortfall within 15 business days following receipt of an invoice from us. In exchange for TransMontaigne Inc.'s minimum revenue commitment, we agreed to provide TransMontaigne Inc. approximately 153,000 barrels of light oil storage capacity at our Oklahoma City terminal. TransMontaigne Inc.'s minimum revenue commitment currently is not in effect because Shell is under contract through March 31, 2011, for the utilization of the light oil storage capacity at the terminal.

        Brownsville and River Renewable Fuels Terminaling Services Agreement—TransMontaigne Inc.    We have a terminaling and transportation services agreement with TransMontaigne Inc. relating to certain renewable fuels capacity at our Brownsville and River terminals that will expire on May 31, 2012. Under this agreement, TransMontaigne Inc. agreed to throughput at these terminals certain minimum volumes of renewable fuels that will, at the fee schedule contained in the agreement, result in minimum revenue to us of approximately $0.6 million per year. In exchange for TransMontaigne Inc.'s minimum throughput commitment, we agreed to provide TransMontaigne Inc. approximately 116,000 barrels of storage capacity at these terminals.

        Other Terminaling Services Agreements.    We also have terminaling service agreements with other customers at our terminal facilities for throughput and storage of refined products, crude oil and other products. These agreements include various minimum throughput commitments, storage commitments and other terms, including duration, that we negotiate on a case-by-case basis.

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Terminals and Pipeline Control Operations

        The pipelines we own or operate are operated via geosynchronous satellite, microwave, radio and frame relay communication systems from a central control room located in Atlanta, Georgia. We also monitor activity at our terminals from this control room.

        The control center operates with state-of-the-art System Control and Data Acquisition, or SCADA, systems. Our control center is equipped with computer systems designed to continuously monitor operational data, including refined product throughput, flow rates and pressures. In addition, the control center monitors alarms and throughput balances. The control center operates remote pumps, motors, engines, and valves associated with the receipt of refined products. The computer systems are designed to enhance leak-detection capabilities, sound automatic alarms if operational conditions outside of pre-established parameters occur, and provide for remote-controlled shutdown of pump stations on the pipeline. Pump stations and meter-measurement points on the pipeline are linked by satellite or telephone communication systems for remote monitoring and control. In addition, our Brownsville, Texas and Collins, Mississippi facilities contain full back-up/redundant disaster recovery systems covering all of our SCADA systems.

Safety and Maintenance

        We perform preventive and normal maintenance on the pipeline and terminal systems we operate or own and make repairs and replacements when necessary or appropriate. We also conduct routine and required inspections of the pipeline and terminal tanks we operate or own as required by code or regulation. External coatings and impressed current cathodic protection systems are used to protect against external corrosion. We conduct all cathodic protection work in accordance with National Association of Corrosion Engineers standards. We continually monitor, test, and record the effectiveness of these corrosion-inhibiting systems.

        We monitor the structural integrity of all of our Department of Transportation, or DOT, regulated pipeline systems. These pipeline systems include the Razorback pipeline; a 37-mile pipeline, known as the "Pinebelt pipeline," located in Covington County, Mississippi that transports refined petroleum liquids between our Collins and Collins/Purvis terminal facilities; a 1-mile diesel fuel pipeline, known as the "Belle Meade pipeline," owned by and operated for Virginia Power Corp. in Richmond, Virginia; the Diamondback pipeline; and an approximately 18-mile, bi-directional refined petroleum liquids pipeline in Texas, known as the "MB pipeline," that we operate and maintain on behalf of PMI Services North America, Inc., an affiliate of PEMEX. The maintenance of structural integrity includes a program of periodic internal inspections as well as hydrostatic testing that conforms to Federal standards. Beginning in 2002, the Department of Transportation, or DOT, required internal inspections or other integrity testing of all DOT-regulated crude oil and refined product pipelines. We believe that the pipelines we own and manage meet or exceed all DOT inspection requirements for all pipelines located in the United States, and meet or exceed the corresponding Mexican regulatory requirements for the portion of the Diamondback pipeline located in Mexico.

        Maintenance facilities containing equipment for pipe repairs, spare parts, and trained response personnel are located along all of these pipelines. Employees participate in simulated spill deployment exercises on a regular basis. They also participate in actual spill response boom deployment exercises in planned spill scenarios in accordance with Oil Pollution Act of 1990 requirements. We believe that the pipelines we own and manage have been constructed and are maintained in all material respects in accordance with applicable federal, state, and local laws and the regulations and standards prescribed by the American Petroleum Institute, the DOT, and accepted industry practice.

        At our terminals, tanks designed for gasoline storage are equipped with internal or external floating roofs that minimize emissions and prevent potentially flammable vapor accumulation between

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fluid levels and the roof of the tank. Our terminal facilities have all required facility response plans, spill prevention and control plans, and other plans and programs to respond to emergencies.

        Many of our terminal loading racks are protected with water deluge systems activated by either heat sensors or an emergency switch. Several of our terminals also are protected by foam systems that are activated in case of fire.

Safety Regulation

        We are subject to regulation by the DOT under the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, or PIPES, and comparable state statutes relating to the design, installation, testing, construction, operation, replacement and management of the pipeline facilities we operate or own. PIPES covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to comply with such regulations and also to permit access to and copying of records and to make certain reports and provide information as required by the Secretary of Transportation. We believe that we are in material compliance with these PIPES regulations.

        The DOT Office of Pipeline Safety, or OPS, has promulgated regulations that require qualification of pipeline personnel. These regulations require pipeline operators to develop and maintain a written qualification program for individuals performing covered tasks on pipeline facilities. The intent of these regulations is to ensure a qualified work force and to reduce the probability and consequence of incidents caused by human error. The regulations establish qualification requirements for individuals performing covered tasks, and amends certain training requirements in existing regulations. We believe that we are in material compliance with these OPS regulations.

        We also are subject to OPS regulation for High Consequence Areas, or HCAs, for Category 2 pipeline systems (companies operating less than 500 miles of jurisdictional pipeline). This regulation specifies how to assess, evaluate, repair and validate the integrity of pipeline segments that could impact populated areas, areas unusually sensitive to environmental damage and commercially navigable waterways, in the event of a release. The pipelines we own or manage are subject to these requirements. The regulation requires an integrity management program that utilizes internal pipeline inspection, pressure testing, or other equally effective means to assess the integrity of pipeline segments in HCAs. The program requires periodic review of pipeline segments in HCAs to ensure adequate preventative and mitigative measures exist. Through this program, we evaluated a range of threats to each pipeline segment's integrity by analyzing available information about the pipeline segment and consequences of a failure in an HCA. The regulation requires prompt action to address integrity issues raised by the assessment and analysis. We have completed baseline assessments for all segments.

        Our terminals also are subject to various state regulations regarding our storage of refined product in aboveground storage tanks. These regulations require, among other things, registration of tanks, financial assurances and inspection and testing, consistent with the standards established by the American Petroleum Institute. We have completed baseline assessments for all of the segments and believe that we are in material compliance with these aboveground storage tank regulations.

        We also are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard, the Environmental Protection Agency, or EPA, community right-to-know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act, and comparable state statutes require us to organize and disclose information about the hazardous materials used in our operations. Certain parts of this information must be reported to employees, state and local governmental authorities, and local citizens upon request. We believe that we are in material compliance with OSHA and state requirements, including general industry standards, record keeping requirements and monitoring of occupational exposures.

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        In general, we expect to increase our expenditures during the next decade to comply with higher industry and regulatory safety standards such as those described above. Although we cannot estimate the magnitude of such expenditures at this time, we do not believe that they will have a material adverse impact on our results of operations.

Environmental Matters

        Our operations are subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of refined product terminals and pipelines, we must comply with these laws and regulations at federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

    requiring remedial action to mitigate releases of hydrocarbons, hazardous substances or wastes caused by our operations or attributable to former operators;

    requiring capital expenditures to comply with environmental control requirements; and

    enjoining the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations.

        Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hydrocarbons, hazardous substances or wastes have been released or disposed of. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hydrocarbons, hazardous substances or other wastes into the environment.

        The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. As a result, there can be no assurance as to the amount or timing of future expenditures that may be required for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that may affect our operations and to plan accordingly to comply with and minimize the costs of such requirements.

        We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations. In addition, we believe that the various environmental activities in which we are presently engaged are not expected to materially interrupt or diminish our operational ability. We cannot assure you, however, that future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause us to incur significant costs. The following is a discussion of certain material environmental concerns that relate to our business.

Water

        The Federal Water Pollution Control Act of 1972, renamed and amended as the Clean Water Act or CWA, imposes strict controls against the discharge of pollutants, including oil and its derivatives into navigable waters. The discharge of pollutants into regulated waters is prohibited except in accordance with the regulations issued by the EPA or the state. We are subject to various types of storm water discharge requirements at our terminals. The EPA and a number of states have adopted regulations that require us to obtain permits to discharge storm water run-off from our facilities. Such permits may require us to monitor and sample the effluent from our operations. The cost involved in obtaining and renewing these storm water permits is not material. We believe that we are in substantial compliance with effluent limitations at our facilities and with the CWA generally.

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        The CWA provides penalties for any discharges of petroleum products in reportable quantities and imposes substantial potential liability for the costs of removing an oil or hazardous substance spill. State laws for the control of water pollution also provide for various civil and criminal penalties and liabilities in the event of a release of petroleum or its derivatives in surface waters or into the groundwater. Spill prevention control and countermeasure requirements of federal laws require, among other things, appropriate containment be constructed around product storage tanks to help prevent the contamination of navigable waters in the event of a product tank spill, rupture or leak.

        The primary federal law for oil spill liability is the Oil Pollution Act of 1990, as amended, or OPA, which addresses three principal areas of oil pollution—prevention, containment and cleanup. It applies to vessels, offshore platforms, and onshore facilities, including terminals, pipelines and transfer facilities. In order to handle, store or transport oil, shore facilities are required to file oil spill response plans with the United States Coast Guard, the OPS, or the EPA. Numerous states have enacted laws similar to OPA. Under OPA and similar state laws, responsible parties for a regulated facility from which oil is discharged may be liable for removal costs and natural resources damages. We believe that we are in substantial compliance with regulations pursuant to OPA and similar state laws.

        Contamination resulting from spills or releases of refined products is an inherent risk in the petroleum terminal and pipeline industry. To the extent that groundwater contamination requiring remediation exists around the facilities we own as a result of past operations, we believe any such contamination is being controlled or remedied without having a material adverse effect on our financial condition. However, such costs can be unpredictable and are site specific and, therefore, the effect may be material in the aggregate.

Air Emissions

        Our operations are subject to the federal Clean Air Act, or CAA, and comparable state and local statutes. The CAA requires most industrial operations in the United States to incur expenditures to meet the air emission control standards that are developed and implemented by the EPA and state environmental agencies. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our operations, and also impose various monitoring and reporting requirements. Such laws and regulations may require a facility to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions and obtain and strictly comply with air permits containing requirements.

        Many of our terminaling operations require air permits. These operations generally include volatile organic compound emissions (primarily hydrocarbons) associated with truck loading activities and tank working and breathing losses. The sources of these emissions are strictly regulated through the permitting process. Such regulation includes stringent control technology and extensive permit review and periodic renewal. The cost involved in obtaining and renewing these permits is not material.

        Moreover, any of our facilities that emit volatile organic compounds or nitrogen oxides and are located in ozone non-attainment areas face increasingly stringent regulations, including requirements to install various levels of control technology on sources of pollutants. We believe that we are in substantial compliance with existing standards and regulations pursuant to the CAA and similar state and local laws, and we do not anticipate that implementation of additional regulations will have a material adverse effect on us.

        Congress and numerous states are currently considering proposed legislation directed at reducing "greenhouse gas emissions." It is not possible at this time to predict how legislation that may be enacted to address greenhouse gas emissions would impact our operations. Although future laws and regulations could result in increased compliance costs or additional operating restrictions, they are not

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expected to have a material adverse effect on our business, financial position, results of operations and cash flows.

Hazardous and Solid Waste

        Our operations are subject to the federal Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state laws, which impose detailed requirements for the handling, storage, treatment, and disposal of hazardous and solid waste. All of our terminal facilities are classified by the EPA as Conditionally Exempt Small Quantity Generators, except for Owensboro, Kentucky, Montvale, Virginia, Paducah, Kentucky and New Albany, Indiana (which are currently classified as Large Quantity Generators, but are expected to be eligible for re-classification as Conditionally Exempt Small Quantity Generators in the near future). Our terminals do not generate hazardous waste except in isolated and infrequent cases. At such times, only third party disposal sites which have been audited and approved by us are used. Our operations also generate solid wastes that are regulated under state law or the less stringent solid waste requirements of RCRA. We believe that we are in substantial compliance with the existing requirements of RCRA and similar state and local laws, and the cost involved in complying with these requirements is not material.

Site Remediation

        The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended, or CERCLA, also known as the "Superfund" law, and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and companies that disposed or arranged for disposal of hazardous substances at offsite locations such as landfills. In the course of our operations we will generate wastes or handle substances that may fall within the definition of a "hazardous substance." CERCLA authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. Under CERCLA, we could be subject to joint and several liability for the costs of cleaning up and restoring sites where hazardous substances have been released, for damages to natural resources, and for the costs of certain health studies. We believe that we are in substantial compliance with the existing requirements of CERCLA.

        We currently own, lease, or operate numerous properties and facilities that for many years have been used for industrial activities, including refined product terminaling operations. Hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners whose treatment and disposal or release of hazardous substances, wastes, or hydrocarbons, was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes (including substances disposed of or released by prior owners or operators), remediate contaminated property (including groundwater contamination, whether from prior owners or operators or other historic activities or spills), or perform remedial plugging or pit closure operations to prevent future contamination.

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        For example, we are currently remediating two sites, one at our facility in Rogers, Arkansas and one at our facility in Owensboro, Kentucky. In October 2006, we experienced a release of product at our Rogers, Arkansas terminal that was caused by human error and did not involve any system malfunctions. Through December 31, 2009, the remediation costs incurred at the Rogers terminal were approximately $3.6 million and we estimate that the total cost for completing the remediation will be between approximately $4.5 million and approximately $5.1 million. In October 2008, we experienced a release of product near our facility in Owensboro, Kentucky due to a leak in a line that connects the terminal's storage capacity to its dock facility. Through December 31, 2009, the remediation costs incurred at the Owensboro terminal were approximately $2.8 million and we estimate that the total cost for completing the remediation will be between approximately $6.1 million and approximately $7.2 million. With respect to the costs of our remediation activity in these two locations, we believe that our share of the total remediation liability, net of probable reimbursements, will not exceed $1.7 million in the aggregate.

        Under an indemnification agreement, which contains the indemnification terms previously set forth in the omnibus agreement, TransMontaigne Inc. has agreed to indemnify us for five years after May 27, 2005 against certain potential environmental claims, losses and expenses associated with the operation of the Florida and Midwest terminals and occurring before May 27, 2005. TransMontaigne Inc.'s maximum liability for this indemnification obligation is $15.0 million and it has no obligation to indemnify us for aggregate losses until such losses exceed $250,000 in the aggregate. TransMontaigne Inc. has no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after May 27, 2005. We have agreed to indemnify TransMontaigne Inc. against environmental liabilities related to our facilities, to the extent these liabilities are not subject to TransMontaigne Inc.'s indemnification obligations. TransMontaigne Inc. estimates that the total cost for remediating the contamination at the Florida terminals will be between approximately $3.2 million and approximately $9.2 million. TransMontaigne Inc.'s activities are being administered in part by the Florida Department of Environmental Protection under state-administered programs that encourage and help to fund all or a portion of the cleanup of contaminated sites. Under these programs, TransMontaigne Inc. has received, and believes that it is eligible to continue to receive, state reimbursement of a significant portion of the costs associated with the remediation of the Florida terminals. As such, TransMontaigne Inc. believes that its share of the total remediation liability, net of probable reimbursements, will be between approximately $0.6 million and approximately $3.4 million. TransMontaigne Inc.'s remediation liability, net of probable reimbursements, for the Midwest terminals is $nil.

        Under the purchase agreement for the Brownsville, Texas and River facilities, TransMontaigne Inc. agreed to indemnify us through December 31, 2011 against certain potential environmental liabilities associated with the operation of the Brownsville and River facilities that occurred on or prior to December 31, 2006. Our environmental losses must first exceed $250,000 and TransMontaigne Inc.'s indemnification obligations are capped at $15.0 million. The cap amount does not apply to any environmental liabilities known to exist as of December 31, 2006. TransMontaigne Inc. believes that its total remediation liability, net of probable reimbursements, for the Brownsville and River facilities will be between approximately $0.4 million and approximately $1.6 million.

        Under the purchase agreement for the Southeast facilities, TransMontaigne Inc. has agreed to indemnify us through December 31, 2012, against certain potential environmental liabilities associated with the operation of the Southeast Terminals that occurred on or prior to December 31, 2007. Our environmental losses must first exceed $250,000 and TransMontaigne Inc.'s indemnification obligations are capped at $15.0 million, which cap amount does not apply to any environmental liabilities known to exist as of December 31, 2007. TransMontaigne Inc. believes its total remediation liability, net of probable reimbursements, for the Southeast facilities will be between approximately $0.9 million and approximately $1.6 million.

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Endangered Species Act

        The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitats. While some of our facilities are in areas that may be designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the Endangered Species Act. However, the discovery of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected area.

Operational Hazards and Insurance

        Our terminal and pipeline facilities may experience damage as a result of an accident or natural disaster. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain insurance of various types that we consider adequate to cover our operations, properties and loss of income at specified locations. Coverage for domestic acts of terrorism as defined in Terrorism Risk Insurance Program Reauthorization Act 2007 are covered under certain casualty insurance policies.

        The insurance covers all of our facilities in amounts that we consider to be reasonable. The insurance policies are subject to deductibles that we consider reasonable and not excessive. Our insurance does not cover every potential risk associated with operating terminals, pipelines and other facilities. Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences. The damages associated with Hurricane Ike and other recent tropical storms, and their overall effect on the Gulf Coast property insurance industry have adversely impacted the availability and cost of coastal property coverage.

        We share insurance policies, including our general liability and pollution policies, with TransMontaigne Inc. These policies contain caps on the insurer's maximum liability under the policy, and claims made by either of TransMontaigne Inc. or us are applied against the caps. The possibility exists that, in any event in which we wish to make a claim under a shared insurance policy, our claim could be denied or only partially satisfied due to claims made by TransMontaigne Inc. against the policy cap.

Tariff Regulation

        The Razorback pipeline, which runs between Mt. Vernon, Missouri and Rogers, Arkansas, and the Diamondback pipeline, which runs between Brownsville, Texas and Matamoros, Mexico, transport petroleum products subject to regulation by the FERC under the Interstate Commerce Act and the Energy Policy Act of 1992 and rules and orders promulgated under those statutes. FERC regulation requires that the rates of pipelines providing interstate service, such as the Razorback and Diamondback pipelines, be filed at FERC and posted publicly, and that these rates be "just and reasonable" and nondiscriminatory. Such rates are currently regulated by the FERC primarily through an index methodology, whereby a pipeline is allowed to change its rates based on the change from year to year in the Producer Price Index for Finished Goods (PPI-FG), plus a 1.3 percent adjustment for the period July 1, 2006 through June 30, 2011. In the alternative, interstate pipeline companies may elect to support rate filings by using a cost-of-service methodology, competitive market showings, or actual agreements between shippers and the oil pipeline company.

        The FERC generally has not investigated interstate rates on its own initiative when those rates have not been the subject of a protest or a complaint by a shipper. A shipper or other party having a substantial economic interest in our rates could, however, challenge our rates. In response to such challenges, the FERC could investigate our rates. If our rates were successfully challenged, the amount

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of cash available for distribution to unitholders could be reduced. In the absence of a challenge to our rates, given our ability to utilize either filed rates as annually indexed or to utilize rates tied to cost of service methodology, competitive market showing, or actual agreements between shippers and us, we do not believe that these regulations would have any negative material monetary impact on us unless the regulations were substantially modified in such a manner so as to prevent a pipeline company's ability to earn a fair return for the shipment of petroleum products utilizing its transportation system, which we believe to be an unlikely scenario.

        On July 20, 2004, the United States Court of Appeals for the District of Columbia Circuit, or D.C. Circuit, issued its opinion in BP West Coast Products, LLC v. FERC, which vacated the portion of the FERC's decision applying the Lakehead policy, under which the FERC allowed a regulated entity organized as a master limited partnership to include in its cost-of-service an income tax allowance to the extent that entity's unitholders were corporations subject to income tax. On May 4, 2005, the FERC adopted a policy statement providing that all entities owning public utility assets—oil and gas pipelines and electric utilities—would be permitted to include an income tax allowance in their cost-of-service rates to reflect the actual or potential income tax liability attributable to their public utility income, regardless of the form of ownership. Any tax pass-through entity seeking an income tax allowance would have to establish that its partners or members have an actual or potential income tax obligation on the entity's public utility income. The FERC's new policy was subsequently challenged before the D.C. Circuit and on May 29, 2007, the D.C. Circuit denied the petitions for review with respect to the income tax allowance issues. As the FERC continues to apply this policy in individual cases, the ultimate impact remains uncertain. If the FERC were to act to substantially reduce or eliminate the right of a master limited partnership to include in its cost-of-service an income tax allowance to reflect actual or potential income tax liability on public utility income, it may become more difficult for the Razorback and Diamondback pipelines to justify their rates if challenged in a protest or complaint.

        In addition to being regulated by the FERC, we are required to maintain a Presidential Permit from the United States Department of State to operate and maintain the Diamondback pipeline, because the pipeline transports petroleum products across the international boundary line between the United States and Mexico. The Department of State's regulations do not affect our rates but do require the agency's approval for the international crossing. We do not believe that these regulations would have any negative material monetary impact on us unless the regulations were substantially modified, which we believe to be an unlikely scenario.

Title to Properties

        The Razorback and Diamondback pipelines are generally constructed on easements and rights-of-way granted by the apparent record owners of the property and in some instances these grants are revocable at the election of the grantor. Several rights-of-way for the Razorback pipeline and other real property assets are shared with other pipelines and other assets owned by affiliates of TransMontaigne Inc. and by third parties. We have become aware that the location of our Diamondback pipeline deviates from the boundaries of certain easements obtained when the pipeline was built. We currently are investigating the situation and negotiating with individual landowners regarding several of the easements for the Diamondback pipeline in the United States and Mexico. In many instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained permits from public authorities to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, and state highways and, in some instances, these permits are revocable at the election of the grantor. We have also obtained permits from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor's election. In some cases, property for pipeline purposes was purchased in fee.

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        Some of the leases, easements, rights-of-way, permits, licenses and franchise ordinances transferred to us will require the consent of the grantor to transfer these rights, which in some instances is a governmental entity. Our general partner has obtained or is in the process of obtaining sufficient third-party consents, permits, and authorizations for the transfer of the facilities necessary for us to operate our business in all material respects as described in this annual report. With respect to any consents, permits, or authorizations that have not been obtained, our general partner believes that these consents, permits, or authorizations will be obtained, or that the failure to obtain these consents, permits, or authorizations would not have a material adverse effect on the operation of our business.

        Our general partner believes that we have satisfactory title to all of our assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with acquisition of real property, liens that can be imposed in some jurisdictions for government-initiated action to clean up environmental contamination, liens for current taxes and other burdens, and easements, restrictions, and other encumbrances to which the underlying properties were subject at the time of our acquisition, our general partner believes that none of these burdens should materially detract from the value of these properties or from our interest in these properties or should materially interfere with their use in the operation of our business.

Employees

        TransMontaigne GP L.L.C. is our general partner and manages our operations and activities. TransMontaigne GP L.L.C. is an indirect wholly owned subsidiary of TransMontaigne Inc. Likewise, TransMontaigne Services Inc. is an indirect wholly owned subsidiary of TransMontaigne Inc. and employs the personnel who provide support to TransMontaigne Inc.'s operations, as well as our operations. As of February 19, 2010, TransMontaigne Services Inc. had approximately 588 employees, of whom 315 provide services directly to us. As of February 19, 2010, none of TransMontaigne Services Inc.'s employees who provide services directly to us were covered by a collective bargaining agreement. TransMontaigne Services Inc. considers its employee relations to be good.

ITEM 1A.    RISK FACTORS

        Our business, operations and financial condition are subject to various risks. You should consider carefully the following risk factors, in addition to the other information set forth in this annual report in connection with any investment in our securities. Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. If any of the following risks actually occurs, our business, financial condition, results of operations or cash flows could be materially adversely affected. In that case, we might not be able to continue to make distributions on our common units at current levels, or at all. As a result of any of these risks, the market value of our common units representing limited partnership interests could decline, and investors could lose all or a part of their investment.

Risks Inherent in Our Business

         We depend upon a relatively small number of customers for a substantial majority of our revenue. A substantial reduction of revenue from one or more of these customers would have a material adverse effect on our financial condition and results of operations.

        We expect to derive a substantial majority of our revenue from a small number of significant customers for the foreseeable future. Events that adversely affect the business operations of any one or more of our significant customers may adversely affect our financial condition or results of operations. Therefore, we are indirectly subject to the business risks of our significant customers, many of which are similar to the business risks we face. For example, a material decline in refined petroleum product

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supplies available to our customers, or a significant decrease in our customers' ability to negotiate marketing contracts on favorable terms, could result in a material decline in the use of our tank capacity or throughput of product at our terminal facilities, which would likely cause our revenue and results of operations to decline. In addition, if any of our significant customers were unable to meet its contractual commitments to us for any reason, then our revenue and cash flow would decline.

         The obligations of several of our key customers under their terminaling services agreements may be reduced or suspended in some circumstances, which would adversely affect our financial condition and results of operations.

        Our agreements with several of our significant customers provide that, if any of a number of events occur, which we refer to as events of force majeure, and the event renders performance impossible with respect to a facility, usually for a specified minimum period of days, our customer's obligations would be temporarily suspended with respect to that facility. In that case, a significant customer's minimum revenue commitment may be reduced or the contract may be subject to termination. As a result, our revenue and results of operations could be materially adversely affected.

         If one or more of our current terminaling services agreements is terminated or expires and we are unable to secure comparable alternative arrangements, our financial condition and results of operations will be adversely affected.

        We have terminaling services agreements that expire on various dates ranging from 2010 to 2016. After the expiration of each of these terminaling services agreements, the customers may elect not to continue to engage us to provide services. In addition, even if a customer does engage us, the terms of any renegotiated agreement may be less favorable than the agreement it replaces. In either case, we may not be able to generate sufficient additional revenue from third parties to replace any shortfall in revenue or increase in costs. Additionally, we may incur substantial costs if modifications to our terminals are required by a new or renegotiated terminaling services agreement. To the extent a customer does not extend or renew a terminaling services agreement, if we extend or renew such a terminaling services agreement on less favorable terms or if we must incur substantial costs in relation to a new or renegotiated terminaling services agreement, our financial condition and results of operations could be adversely affected.

         Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.

        Our level of debt could have important consequences to us. For example our level of debt could:

    impair our ability to obtain additional financing, if necessary, for distributions to unitholders, working capital, capital expenditures, acquisitions or other purposes;

    require us to dedicate a substantial portion of our cash flow to make principal and interest payments on our debt, reducing the funds that would otherwise be available for operations and future business opportunities;

    make us more vulnerable to competitive pressures, changes in interest rates or a downturn in our business or the economy generally;

    impair our ability to make quarterly distributions to our unitholders; and

    limit our flexibility in responding to changing business and economic conditions.

        If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or

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seeking additional equity capital. We may not be able to affect any of these actions on satisfactory terms, or at all.

        Our senior secured credit facility also contains covenants limiting our ability to make distributions to unitholders in certain circumstances. In addition, our senior secured credit facility contains various covenants that limit, among other things, our ability to incur indebtedness, grant liens or enter into a merger, consolidation or sale of assets. Furthermore, our senior secured credit facility contains covenants requiring us to maintain certain financial ratios and tests. Any future breach of any of these covenants or our failure to meet any of these ratios or conditions could result in a default under the terms of our senior secured credit facility, which could result in acceleration of our debt and other financial obligations. If we were unable to repay those amounts, the lenders could initiate a bankruptcy proceeding or liquidation proceeding or proceed against the collateral.

         In the event we are required to refinance our existing debt in unfavorable market conditions, we may have to pay higher interest rates and be subject to more stringent financial covenants, which could adversely affect our results of operations and may impair our ability to make quarterly distributions to our unitholders.

        Our existing senior secured credit facility matures by its terms in December 2011. At December 31, 2009, we had outstanding borrowings of approximately $165.0 million under our senior secured credit facility. Our credit facility provides that we pay interest on outstanding balances at interest rates based on market rates plus specified margins, ranging from 1.5% to 2.5% depending on the total leverage ratio in the case of loans with interest rates based on LIBOR, and ranging from 0.5% to 1.5% depending on the total leverage ratio in the case of loans with interest rates based on the prime rate. In the event we are required to refinance our senior secured credit facility in unfavorable market conditions, we may have to pay interest at higher rates on outstanding borrowings and may be subject to more stringent financial covenants than we are today, which could adversely affect our results of operations and may impair our ability to make quarterly distributions to our unitholders.

         Our continued working capital requirements, distributions to unitholders and expansion programs may require access to additional capital. Tightened credit markets or more expensive capital could impair our ability to maintain or grow our operations, or to fund distributions to our unitholders.

        Our primary liquidity needs are to fund our working capital requirements, distributions to unitholders and capital expenditures. At December 31, 2009, our senior secured credit facility provides for a maximum borrowing line of credit equal to $200 million, which may be increased by up to an additional $100 million subject to the approval of the administrative agent and the receipt of additional commitments from one or more lenders. At December 31, 2009, our outstanding borrowings under the senior secured credit facility were approximately $165 million, resulting in available capacity of approximately $35 million. At December 31, 2009, we have capital projects that currently are or will be under construction with estimated completion dates that extend through March 31, 2011, pursuant to which we expect to incur between $29 million and $33 million in remaining capital expenditures. We expect to fund these capital expenditures with additional borrowings under our senior secured credit facility and payments from Morgan Stanley Capital Group in the range of $4 million to $8 million, which are due and payable upon completion of certain of the capital projects. Upon our payment of the remaining capital expenditures to complete the capital projects referred to above, our receipt of payments from Morgan Stanley Capital Group and a reduction in our outstanding borrowings under the senior secured credit facility considering the net proceeds and cash contribution of approximately $52.1 million from our January 15, 2010 equity offering, we currently expect to have approximately $60 million in available capacity under our senior secured credit facility. If we cannot obtain adequate financing to complete the approved capital projects while maintaining our current operations, we may not be able to continue to operate our business as it is currently conducted, or we may be unable to maintain or grow the quarterly distribution to our unitholders.

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        Moreover, our long term business strategies include acquiring additional energy-related terminaling and transportation facilities and further expansion of our existing terminal capacity. We will need to raise additional funds to grow our business and implement these strategies. We anticipate that such additional funds would be raised through equity or debt financings. Any equity or debt financing, if available at all, may not be on terms that are favorable to us. An inability to access the capital markets may result in a substantial increase in our leverage and have a detrimental impact on our creditworthiness. If we cannot obtain adequate financing, we may not be able to fully implement our business strategies, and our business, results of operations and financial condition would be adversely affected.

         Morgan Stanley Capital Group, which is our largest customer and controls our general partner, is owned by Morgan Stanley. On September 21, 2008, Morgan Stanley became a bank holding company under applicable federal banking law and regulations, which impose regulatory limitations on Morgan Stanley's ability to conduct certain nonbanking activities or retain or make certain investments. If the Board of Governors of the Federal Reserve System, or the FRB, determines that any of our activities or investments would be impermissible under the Bank Holding Company Act, or BHC Act, and Morgan Stanley is unable to obtain relief from the FRB within the statutory two-year grace period, with the possibility of three one-year extensions, Morgan Stanley (i) may cause us to discontinue any such activity or divest any such investment, or (ii) may transfer control of our general partner to an unaffiliated third party, prior to the end of the referenced grace period.

        On September 21, 2008, Morgan Stanley obtained the approval of the Board of Governors of the Federal Reserve System, or the FRB, to become a bank holding company. Two days later, Morgan Stanley became a financial holding company under the BHC Act. As a financial holding company, Morgan Stanley will be able to engage in any activity that is financial in nature, incidental to a financial activity or complementary to a financial activity. The BHC Act, by its terms, provides any company, such as Morgan Stanley, that becomes a financial holding company a two-year grace period to conform its existing nonfinancial activities and investments to the requirements of the BHC Act with the possibility of three one-year extensions. The BHC Act grandfathers "activities related to the trading, sale or investment in commodities and underlying physical properties," provided that Morgan Stanley conducted any such type of activities as of September 30, 1997 and provided that certain other conditions are satisfied, which conditions are reasonably in the control of Morgan Stanley. In addition, the BHC Act permits the FRB to determine by regulation or order that certain activities are complementary to a financial activity and do not pose a risk to safety and soundness. The FRB has previously determined that a range of commodities activities are either financial in nature, incidental to a financial activity, or complementary to a financial activity.

        During April 2009, Morgan Stanley advised us that it has conducted an internal review and has concluded that, based upon its review, all of our activities and investments are permissible under the BHC Act.

        The FRB has not yet completed its review of these activities and investments. The FRB could conclude that certain of our activities or investments will not be deemed permissible under the BHC Act. If so, Morgan Stanley (i) may cause us to discontinue any such activity or divest any such investment or (ii) may transfer control of our general partner to an unaffiliated third party, prior to the end of the referenced grace period. We are unable to predict whether, if either of these actions is required, it would have a material adverse impact on our financial condition or results of operations.

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        Upon becoming a financial holding company, Morgan Stanley became subject to the consolidated supervision and regulation of the FRB. As a result, our general partner, which is an indirectly wholly owned subsidiary of Morgan Stanley, and the Partnership are now also subject to such supervision and regulation. In addition, the statutes and regulations governing the activities of financial holding companies are subject to change from time to time. We are currently unable to predict whether becoming subject to the consolidated supervision and regulation affecting Morgan Stanley as a financial holding company, or any future changes in the statutes and regulations governing the activities of financial holding companies, will have a material impact on us, or what any such impact may be.

        We are currently unable to predict whether the FRB will conclude that certain of our activities or investments will not be deemed permissible under the BHC Act. We are therefore unable to predict whether Morgan Stanley would be required to cause us to discontinue any such activities or investments, or whether Morgan Stanley would be required to transfer control of our general partner to an unaffiliated third party. We are, therefore, also unable to predict whether, if either of these actions is required, it would have a material adverse impact on our financial condition or results of operation. We also cannot currently predict whether, if Morgan Stanley is required to transfer control of our general partner to an unaffiliated third party, it would materially affect our relationship with Morgan Stanley Capital Group, or materially adversely affect our results of operations or financial condition. In addition, the uncertainty surrounding our future relationship with Morgan Stanley may suppress the market value of our common units.

         If we do not make acquisitions on economically acceptable terms, any future growth will be limited.

        Our ability to grow is dependent principally on our ability to make acquisitions that are attractive because they are expected to result in an increase in our quarterly distributions to unitholders. Our acquisition strategy is based, in part, on our expectation of ongoing divestitures of product terminal and transportation facilities by large industry participants. A material decrease in such divestitures would limit our opportunities for future acquisitions and could adversely affect our operations and cash flows.

        In addition, we may be unable to make attractive acquisitions for any of the following reasons, among others:

    because we are outbid by competitors, some of which are substantially larger than us and have greater financial resources and lower costs of capital than we do;

    because we are unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, or acceptable terminaling services contracts with them or another customer; or

    because we are unable to raise financing for such acquisitions on economically acceptable terms.

        If we consummate future acquisitions, our capitalization and results of operations may change significantly.

         Any acquisitions we make are subject to substantial risks, which could adversely affect our financial condition and results of operations.

        Any acquisition involves potential risks, including risks that we may:

    fail to realize anticipated benefits, such as cost-savings or cash flow enhancements;

    decrease our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;

    significantly increase our interest expense or financial leverage if we incur additional debt to finance acquisitions;

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    encounter difficulties operating in new geographic areas or new lines of business;

    incur or assume unanticipated liabilities, losses or costs associated with the business or assets acquired for which we are not indemnified or for which the indemnity is inadequate;

    be unable to hire, train or retain qualified personnel to manage and operate our growing business and assets;

    less effectively manage our historical assets because of the diversion of management's attention; or

    incur other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.

        If any acquisitions we ultimately consummate result in one or more of these outcomes, our financial condition and results of operations may be adversely affected.

        For example, effective December 31, 2007, we acquired the Diamondback Pipeline running from Brownsville, Texas to Matamoros, Mexico, with associated rights of way and easements. In late 2008 and early 2009, we were notified that the location of the pipeline deviates in certain respects from the easements granted in connection with its construction. We are continuing to investigate the situation and negotiate with individual landowners regarding several of the easements for the pipelines in the United States and Mexico. In the event we are unable to correct the easements and are instead required to relocate a portion of the Diamondback pipeline to conform with the current easements, we could incur significant costs and our results of operations and cash flows may be adversely affected.

         Competition from other terminals and pipelines that are able to supply our customers with storage capacity at a lower price could adversely affect our financial condition and results of operations.

        We face competition from other terminals and pipelines that may be able to supply our customers with integrated terminaling services on a more competitive basis. We compete with national, regional and local terminal and pipeline companies, including the major integrated oil companies, of widely varying sizes, financial resources and experience. Our ability to compete could be harmed by factors we cannot control, including:

    price competition from terminal and transportation companies, some of which are substantially larger than us and have greater financial resources and control substantially greater product storage capacity, than we do;

    the perception that another company may provide better service; and

    the availability of alternative supply points or supply points located closer to our customers' operations.

        If we are unable to compete with services offered by other enterprises, our financial condition and results of operations would be adversely affected.

         We are exposed to the credit risks of Morgan Stanley Capital Group and TransMontaigne Inc. and our other significant customers, which could affect our creditworthiness. Any material nonpayment or nonperformance by such customers could also adversely affect our financial condition and results of operations.

        Because of Morgan Stanley Capital Group's and TransMontaigne Inc.'s ownership interest in and control of us, the strong operational links between Morgan Stanley Capital Group and TransMontaigne Inc. and us and our reliance on Morgan Stanley Capital Group and TransMontaigne Inc. for a substantial majority of our revenue, if one or more credit rating agencies were to view unfavorably the credit quality of Morgan Stanley Capital Group or TransMontaigne Inc.,

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we could experience an increase in our borrowing costs or difficulty accessing capital markets. Such a development could adversely affect our ability to grow our business.

        We are subject to risks of loss resulting from nonpayment or nonperformance by our other significant customers. Some of our significant customers may be highly leveraged and subject to their own operating and regulatory risks. Any material nonpayment or nonperformance by our other significant customers could require us to pursue substitute customers for our affected assets or provide alternative services. There can be no assurance that any such efforts would be successful or would provide similar fees. These events could adversely affect our financial condition and results of operations.

         A significant decrease in demand for refined products due to price volatility or adverse economic conditions may cause one or more of our significant customers to reduce their use of our tank capacity and throughput volumes at our terminal facilities, which would adversely affect our financial condition and results of operations.

        The recent volatile market conditions, economic recession resulting in lower consumer spending on gasolines, distillates and travel, and record high prices of refined products as seen during 2008 may cause a reduction in demand for refined products, which could result in a material decline in the use of our tank capacity or throughput of product at our terminal facilities. Additionally, the continued volatility in the price of refined products may render our customers' hedging activities ineffective, which could cause one or more of our significant customers to decrease their supply and marketing activities in order to reduce their exposure to price fluctuations.

        Additional factors that could lead to a decrease in market demand for refined products include:

    an increase in the market price of crude oil that leads to higher refined product prices;

    higher fuel taxes or other governmental or other regulatory actions that increase, directly or indirectly, the cost of gasolines or other refined products; or

    a shift by consumers to more fuel-efficient or alternative fuel vehicles or an increase in fuel economy, whether as a result of technological advances by manufacturers, pending legislation proposing to mandate higher fuel economy or otherwise.

        Any decrease in supply and marketing activities may result in reduced throughput volumes at our terminal facilities, which would adversely affect our financial condition and results of operations.

         Because of recent, unprecedented contraction in global financial and credit markets, one or more of our significant customers may become unable to secure financing arrangements adequate to purchase their desired volume of product, which could reduce use of our tank capacity and throughput volumes at our terminal facilities and adversely affect our financial condition and results of operations.

        The contraction in the global financial and credit markets in 2008 and 2009 has adversely affected the liquidity of many large financial institutions and may affect other businesses in the future. In part, these conditions have reduced the credit available to various enterprises, including those involved in the supply and marketing of refined products. As a result of these conditions, some of our customers may suffer short or long-term reductions in their ability to finance their supply and marketing activities, or may voluntarily elect to reduce their supply and marketing activities in order to preserve working capital. A significant decrease in our customers' ability to secure financing arrangements adequate to support their historic refined product throughput volumes could result in a material decline in use of our tank capacity or the throughput of refined product at our terminal facilities. In the current economic climate, we may not be able to generate sufficient additional revenue from third parties to replace any shortfall in revenue from our current customers, which would likely cause our revenue and

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results of operations to decline and may impair our ability to make quarterly distributions to our unitholders.

         Our business involves many hazards and operational risks, including adverse weather conditions, which could cause us to incur substantial liabilities and increased operating costs.

        Our operations are subject to the many hazards inherent in the terminaling and transportation of products, including:

    leaks or accidental releases of products or other materials into the environment, whether as a result of human error or otherwise;

    extreme weather conditions, such as hurricanes, tropical storms, and rough seas, which are common along the Gulf Coast;

    explosions, fires, accidents, mechanical malfunctions, faulty measurement and other operating errors; and

    acts of terrorism or vandalism.

        If any of these events were to occur, we could suffer substantial losses because of personal injury or loss of life, severe damage to and destruction of storage tanks, pipelines and related property and equipment, and pollution or other environmental damage resulting in curtailment or suspension of our related operations and potentially substantial unanticipated costs for the repair or replacement of property and environmental cleanup. In addition, if we suffer accidental releases or spills of products at our terminals or pipelines, we could be faced with material third-party costs and liabilities, including those relating to claims for damages to property and persons. For example, in October 2008 we experienced a release of product at our facility in Owensboro, Kentucky, which we anticipate will result in approximately $0.9 million in unreimbursed environmental remediation costs and product losses. Furthermore, events like hurricanes can affect large geographical areas which can cause us to suffer additional costs and delays in connection with subsequent repairs and operations because contractors and other resources are not available, or are only available at substantially increased costs following widespread catastrophes.

         Expanding our business by constructing new facilities subjects us to risks that the project may not be completed on schedule and that the costs associated with the project may exceed our estimates or budgeted costs, which could adversely affect our financial condition and results of operations.

        The construction of additions or modifications to our existing terminal and transportation facilities, and the construction of new terminals and pipelines, involves numerous regulatory, environmental, political, legal and operational uncertainties beyond our control and requires the expenditure of significant amounts of capital. If we undertake these projects, they may not be completed on schedule or at all and may exceed the budgeted cost. Moreover, our revenue may not increase immediately upon the expenditure of funds on a particular project. For instance, if we construct additional storage capacity, the construction may occur over an extended period of time, and we will not receive any material increases in revenue until the project is completed. Moreover, we may construct additional storage capacity to capture anticipated future growth in consumption of products in a market in which such growth does not materialize.

         Because of our lack of asset diversification, adverse developments in our terminals or pipeline operations could adversely affect our revenue and cash flows.

        We rely exclusively on the revenue generated from our terminals and pipeline operations. Because of our lack of diversification in asset type, an adverse development in these businesses would have a

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significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets.

         Our operations are subject to governmental laws and regulations relating to the protection of the environment that may expose us to significant costs and liabilities.

        Our business is subject to the jurisdiction of numerous governmental agencies that enforce complex and stringent laws and regulations with respect to a wide range of environmental, safety and other regulatory matters. We could be adversely affected by increased costs resulting from more strict pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. New environmental laws and regulations might adversely impact our activities, including the transportation, storage and distribution of petroleum products. Federal, state and local agencies also could impose additional safety requirements, any of which could affect our profitability. Furthermore, our failure to comply with environmental or safety related laws and regulations also could result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory and remedial obligations and even the issuance of injunctions that restrict or prohibit the performance of our operations.

         Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our ability to make distributions to our unitholders.

        The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the threat of future terrorist attacks, on the energy transportation industry in general, and on us in particular, is impossible to predict. Increased security measures that we have taken as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terrorism.

         We are not fully insured against all risks incident to our business, and could incur substantial liabilities as a result.

        We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially, and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. For example, our insurance carriers require broad exclusions for losses due to terrorist acts. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial condition. In accordance with typical industry practice, we do not have any property or title insurance on the Razorback and Diamondback pipelines.

        We share insurance policies, including our general liability and pollution policies, with TransMontaigne Inc. These policies contain caps on the insurer's maximum liability under the policy, and claims made by either of TransMontaigne Inc. or us are applied against the caps. In the event we reach the cap, we would seek to acquire additional insurance in the marketplace; however, we can provide no assurance that such insurance would be available or if available, at a reasonable cost. The possibility exists that, in any event in which we wish to make a claim under a shared insurance policy, our claim could be denied or only partially satisfied due to claims made by TransMontaigne Inc. against the policy cap.

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         Many of our storage tanks and portions of our pipeline system have been in service for several decades that could result in increased maintenance or remediation expenditures, which could adversely affect our results of operations and our ability to pay cash distributions.

        Our pipeline and storage assets are generally long-lived assets. As a result, some of those assets have been in service for many decades. The age and condition of these assets could result in increased maintenance or remediation expenditures. Any significant increase in these expenditures could adversely affect our results of operations, financial position and cash flows, as well as our ability to pay cash distributions.

Risks Inherent in an Investment in Us

         We may not have sufficient cash from operations to enable us to maintain or grow the distribution to our unitholders following establishment of cash reserves and payment of fees and expenses, including payments to our general partner.

        The amount of cash we can distribute on our common units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

    the level of consumption of products in the markets in which we operate;

    the prices we obtain for our services;

    the level of our operating costs, including payments to our general partner; and

    prevailing economic conditions.

        Additionally, the actual amount of cash we have available for distribution to our unitholders depends on other factors such as:

    the level of capital expenditures we make;

    the restrictions contained in our debt instruments and our debt service requirements;

    fluctuations in our working capital needs; and

    the amount, if any, of reserves, including reserves for future capital expenditures and other matters, established by our general partner in its discretion.

        The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow, including cash flow from operations and working capital borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions to our unitholders during periods when we incur net losses and may not make cash distributions to our unitholders during periods when we generate net earnings. We may not be able to obtain debt or equity financing on terms that are favorable to us, if at all, and we may be required to fund our working capital requirements principally on cash generated by our operations and borrowings under our senior secured credit facility. As a result, we may not be able to maintain or grow our quarterly distribution to our unitholders.

         TransMontaigne Inc. controls our general partner, which has sole responsibility for conducting our business and managing our operations. TransMontaigne Inc. and Morgan Stanley Capital Group have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to our detriment.

        TransMontaigne GP L.L.C. is our general partner and manages our operations and activities. TransMontaigne GP L.L.C. is an indirect wholly owned subsidiary of TransMontaigne Inc. Likewise, TransMontaigne Services Inc. is an indirect wholly owned subsidiary of TransMontaigne Inc. and

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employs the personnel who provide support to TransMontaigne Inc.'s operations, as well as our operations. TransMontaigne Inc., in turn, is wholly owned by Morgan Stanley Capital Group, which is the principal commodities trading arm of Morgan Stanley. Neither our general partner nor its board of directors is elected by our unitholders and our unitholders have no right to elect our general partner or its board of directors on an annual or other continuing basis. Furthermore, unitholders may be unable to remove our general partner without its consent because our general partner and its affiliates own units representing approximately 22.5% of our aggregate outstanding limited partner interests. The vote of the holders of at least 662/3% of all outstanding common units, including any common units owned by our general partner and its affiliates, but excluding the general partner interest, voting together as a single class, is required to remove our general partner.

        Additionally, any or all of the provisions of our omnibus agreement with TransMontaigne Inc., other than the indemnification provisions, will be terminable by TransMontaigne Inc. at its option if our general partner is removed without cause and common units held by our general partner and its affiliates are not voted in favor of that removal. Cause is narrowly defined in the omnibus agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business.

        All of the executive officers of our general partner are affiliated with TransMontaigne Inc. and three of our general partner's directors are affiliated with Morgan Stanley Capital Group. Therefore, conflicts of interest may arise between TransMontaigne Inc. and its affiliates, including Morgan Stanley Capital Group and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving those conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders.

        The following are potential conflicts of interest:

    TransMontaigne Inc. and Morgan Stanley Capital Group, as users of our pipeline and terminals, have economic incentives not to cause us to seek higher tariffs or higher terminaling service fees, even if such higher rates or terminaling service fees would reflect rates that could be obtained in arm's-length, third-party transactions.

    Morgan Stanley Capital Group, TransMontaigne Inc. and their affiliates may engage in competition with us under certain circumstances.

    Neither our partnership agreement nor any other agreement requires TransMontaigne Inc. or Morgan Stanley Capital Group to pursue a business strategy that favors us. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. TransMontaigne Inc.'s and Morgan Stanley Capital Group's respective directors and officers have fiduciary duties to make decisions in the best interests of those companies, which may be contrary to our interests or the interests of our other customers.

    Our general partner is allowed to take into account the interests of parties other than us, such as TransMontaigne Inc. and Morgan Stanley Capital Group, in resolving conflicts of interest. Specifically, in determining whether a transaction or resolution is "fair and reasonable," our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us.

    Officers of TransMontaigne Inc. who provide services to us also devote significant time to the businesses of TransMontaigne Inc., and are compensated by TransMontaigne Inc. for the services rendered to it.

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    Our general partner has limited its liability and reduced its fiduciary duties, and also has restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty. Our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed that its decision was in the best interests of our partnership.

    Our general partner determines the amount and timing of acquisitions and dispositions, capital expenditures, borrowings, issuance of additional partnership securities, and reserves, each of which can affect the amount of cash that is distributed to our unitholders.

    Our general partner determines the amount and timing of any capital expenditures by our partnership and whether a capital expenditure is a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. That determination can affect the amount of cash that is distributed to our unitholders.

    Our general partner may use an amount, equal to $33.2 million as of December 31, 2009, which would not otherwise constitute operating surplus, in order to permit the payment of cash distributions, $10.3 million of which would go to TransMontaigne Inc. and Morgan Stanley Capital Group in the form of distributions on their common units, general partner interest and incentive distribution rights.

    Our general partner determines which out-of-pocket costs incurred by TransMontaigne Inc. are reimbursable by us.

    Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.

    Our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.

    Our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including the terminaling services agreements with TransMontaigne Inc. and Morgan Stanley Capital Group.

    Our general partner decides whether to retain separate counsel, accountants, or others to perform services on our behalf.

         Cost reimbursements, which will be determined by our general partner, and fees due our general partner and its affiliates for services provided are and will continue to be substantial and will reduce our cash available for distribution to unitholders.

        Payments to our general partner are and will continue to be substantial and will reduce the amount of available cash for distribution to unitholders. For the year ended December 31, 2009, we paid TransMontaigne Inc. and its affiliates an administrative fee of approximately $10.0 million, an additional insurance reimbursement of approximately $2.9 million and $1.2 million as partial reimbursement for grants to key employees of TransMontaigne Inc. and its affiliates under the TransMontaigne Services Inc. savings and retention plan. Both the administrative fee and the insurance reimbursement are subject to increase in the event we acquire or construct facilities to be managed and operated by TransMontaigne Inc. Our general partner and its affiliates will continue to be entitled to reimbursement for all other direct expenses they incur on our behalf, including the salaries of and the cost of employee benefits for employees working on-site at our terminals and pipelines. Our general

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partner will determine the amount of these expenses. Our general partner and its affiliates also may provide us other services for which we will be charged fees as determined by our general partner. The Omnibus Agreement expires on December 31, 2014, subject to our right to extend the agreement for an additional seven years if Morgan Stanley Capital Group elects to renew the terminaling services agreement for the Southeast terminals. If we are unable to renew the Omnibus Agreement on terms that are satisfactory to us or if we are required to pay a higher administrative fee, our results of operations and financial condition could be adversely affected.

         The control of our general partner may be transferred to a third party without unitholder consent.

        Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the members of our general partner from transferring their respective limited liability company interests in our general partner to a third party. The new members of our general partner could then be in a position to replace the board of directors and officers of our general partner with their own choices and to control the decisions taken by the board of directors and officers.

         Our general partner has a limited call right that may require unitholders to sell their common units at an undesirable time or price.

        If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their common units. At February 26, 2010, affiliates of our general partner own approximately 22.5% of our aggregate outstanding common units representing limited partner interests.

Tax Risks

         Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as not being subject to a material amount of entity-level taxation by states. If the Internal Revenue Service were to treat us as a corporation or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to unitholders would be substantially reduced.

        The anticipated after-tax benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes.

        If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%. In such a circumstance, distributions to our unitholders would generally be taxed again as corporate distributions (if such distributions were less than our earnings and profits) and no income, gains, losses, deductions or credits would flow through to our unitholders. Imposition of a corporate tax would substantially reduce our cash flows and after-tax return to our unitholders. This likely would cause a substantial reduction in the value of the common units.

        Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the qualifying income requirements, affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our common units. For example, in response to certain recent developments, members of Congress are considering substantive changes to the definition of qualifying income under

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Section 7704(d) of the Internal Revenue Code and the treatment of certain types of income earned from profits interests in partnerships. It is possible that these efforts could result in changes to the existing U.S. tax laws that affect publicly traded partnerships, including us. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

        In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, our cash flows would be reduced. For example, under current legislation, we are subject to an entity-level tax on the portion of our total revenue (as that term is defined in the legislation) that is generated in Texas. For the year ended December 31, 2009, we recognized a liability of approximately $150,000 for the Texas margin tax, which is imposed at a maximum effective rate of 0.7% of our total revenue from Texas. Imposition of such a tax on us by Texas, or any other state, will reduce the cash available for distribution to our unitholders. The partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amounts will be reduced to reflect the impact of that law on us.

         If the Internal Revenue Service were to successfully challenge our use of a calendar year end for federal income tax purposes, the challenge may result in adjustments to the federal income tax liability of our unitholders, and the imposition of tax penalties on us, and we may have difficulty providing our unitholders with all of the information necessary to timely file their federal income tax returns. As a result, the market for our common units may be adversely affected and our relations with our unitholders could suffer.

        Under the Internal Revenue Code and applicable Treasury Regulations, we are required to use a taxable year that is determined by reference to the taxable years of our partners. If holders of a majority of the interests in our capital and profits use a single taxable year, we must use that year. If there is no such "majority interest taxable year," and if no person with a taxable year different from that of our general partner and its affiliates owns a 5% or greater interest in our capital or profits, then we must use the same taxable year as our general partner and its affiliates. If there is no majority interest taxable year and there is an owner, other than our general partner and its affiliates, of 5% or more of our capital or profits that has a taxable year different from that of our general partner and its affiliates, we must use the taxable year that produces the "least aggregate deferral" to holders of partnership interests. In general, these determinations are made on the first day of each taxable year.

        Our initial taxable year ended on June 30, 2005, because our general partner and its affiliates, who used a June 30 taxable year at the time we were organized, initially owned all of the interests in our profits and capital. We have taken the position that we were required to change our taxable year to the calendar year as of July 1, 2005, on the basis that the calendar year was our "majority interest taxable year" due to public ownership of our common units by calendar year taxpayers. In view of the factual and legal uncertainties regarding the taxable year that we are required to use, our position that we are required to use the calendar year as our taxable year is also based in part upon the fact that the calendar year is (i) the simplest and most administrable taxable year for a publicly traded partnership, (ii) to our knowledge, the taxable year used by all other publicly traded partnerships and (iii) the default taxable year originally provided by the Internal Revenue Code for partnerships in certain other circumstances. Based upon that position, we used the calendar year as our taxable year for 2006 and 2007. Effective December 31, 2007, we implemented a holding structure that caused our general partner and most of our affiliate-held units to be owned by entities using the calendar year as their taxable year. Effective December 31, 2008, Morgan Stanley and all of its subsidiaries elected to use a calendar year as their taxable year. Nevertheless, the IRS could disagree with the position we have taken with respect to our taxable years.

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        If we are required to change our taxable year to a year other than the calendar year, we may have difficulty providing certain unitholders with information about our income, gain, loss and deduction for our taxable year in a manner that allows those unitholders to timely file their federal income tax returns for the years in which they are required to include their share of our income, gain, loss and deduction. In addition, if we are required to change our taxable year as a result of an IRS challenge of our use of the calendar year for a taxable year as to which we and our unitholders have already filed a federal income tax return, the change may result in an adjustment to a unitholder's federal income tax liability and we could be subject to penalties. In that event, our relations with our unitholders could suffer. Moreover, if we were not allowed to use a calendar year end for tax purposes, many existing and potential unitholders that have a calendar tax year may not be willing to purchase our units, which could adversely affect the market price of our units and limit our ability to raise capital through public or private offerings of our units in the future.

         If the sale or exchange of 50% or more of our capital and profit interests occurs within a 12-month period, we would experience a deemed termination of our partnership for federal income tax purposes.

        The sale or exchange of 50% or more of the partnership's units within a 12-month period would result in a deemed "technical" termination of our partnership for federal income tax purposes. Such an event would not terminate a unitholder's interest in the partnership, nor would it terminate the continuing business operations of the partnership. However, it would, among other things, result in the closing of our taxable year for all unitholders and would result in a deferral of depreciation and cost recovery deductions allowable in computing our taxable income for future tax years. The partnership previously experienced a deemed "technical" termination for the period ending December 30, 2007, due to the implementation of the December 31, 2007 holding structure referred to above. If our partnership were deemed terminated for federal income tax purposes, this deferral of cost recovery deductions would impact each unitholder through allocations of an increased amount of federal taxable income (or reduced amount of allocated loss) for the year in which the partnership is deemed terminated and for subsequent years as a percentage of the cash distributed to the unitholder with respect to that period.

         We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

        For administrative purposes and consistent with other publicly traded partnerships, we generally prorate our items of income, gain, loss, and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

         A unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

        Because a unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of the loaned units, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and

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the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from loaning their units.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

        None.

ITEM 3.    LEGAL PROCEEDINGS

        TransMontaigne Inc. has agreed to indemnify us for any losses we may suffer as a result of legal claims for actions that occurred prior to the closing of our initial public offering on May 27, 2005.

        We currently are not a party to any material litigation. Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, at any given time we may be a defendant in various legal proceedings and litigation arising in the ordinary course of business. We are a beneficiary of various insurance policies TransMontaigne Inc. maintains with insurers in amounts and with coverage and deductibles that our general partner believes are reasonable and prudent. However, we cannot assure that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that the levels of insurance will be available in the future at economical prices.

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

        No matters were submitted to a vote of the security holders, through solicitation of proxies or otherwise, during the period covered by this annual report.


Part II

ITEM 5.    MARKET FOR THE REGISTRANT'S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

MARKET FOR COMMON UNITS

        The common units are listed and traded on the New York Stock Exchange under the symbol "TLP." On February 26, 2010, there were approximately 29 unitholders of record of our common units. This number does not include unitholders whose units are held in trust by other entities. The actual number of unitholders is greater than the number of unitholders of record.

        The following table sets forth, for the periods indicated, the range of high and low per unit sales prices for our common units as reported on the New York Stock Exchange.

 
  Low   High  

January 1, 2008 through March 31, 2008

  $ 24.88   $ 32.10  

April 1, 2008 through June 30, 2008

  $ 25.69   $ 32.85  

July 1, 2008 through September 30, 2008

  $ 15.95   $ 27.47  

October 1, 2008 through December 31, 2008

  $ 11.27   $ 21.39  

January 1, 2009 through March 31, 2009

  $ 13.23   $ 20.29  

April 1, 2009 through June 30, 2009

  $ 16.60   $ 23.51  

July 1, 2009 through September 30, 2009

  $ 20.33   $ 28.66  

October 1, 2009 through December 31, 2009

  $ 23.32   $ 29.07  

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DISTRIBUTIONS OF AVAILABLE CASH

        The following table sets forth the distribution declared per common unit attributable to the periods indicated:

 
  Distribution  

January 1, 2008 through March 31, 2008

  $ 0.57  

April 1, 2008 through June 30, 2008

  $ 0.58  

July 1, 2008 through September 30, 2008

  $ 0.59  

October 1, 2008 through December 31, 2008

  $ 0.59  

January 1, 2009 through March 31, 2009

  $ 0.59  

April 1, 2009 through June 30, 2009

  $ 0.59  

July 1, 2009 through September 30, 2009

  $ 0.59  

October 1, 2009 through December 31, 2009

  $ 0.59  

        Within approximately 45 days after the end of each quarter, we will distribute all of our available cash, as defined in our partnership agreement, to unitholders of record on the applicable record date. Available cash generally means all cash on hand at the end of the quarter:

    less the amount of cash reserves established by our general partner to:

    provide for the proper conduct of our business;

    comply with applicable law, any of our debt instruments, or other agreements; or

    provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;

    plus, if our general partner so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter.

        The terms of our senior secured credit facility may limit our ability to distribute cash under certain circumstances as discussed under "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources" of this annual report.

Distributions of Available Cash During and After the Subordination Period

        Prior to the expiration of the subordination period or the earlier conversion of the subordinated units following satisfaction of the financial tests set forth in the partnership agreement, which occurred on November 13, 2009 with respect to the quarter ended September 30, 2009 as described below, the common units were entitled to receive distributions from operating surplus of $0.40 per unit per quarter, which we refer to as the minimum quarterly distribution, or $1.60 per unit per year, plus any arrearages in the payment of the minimum quarterly distribution from prior quarters, before any such distributions are paid on our subordinated units.

        During the subordination period, we were required to make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

    First, 98% to the common unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

    Second, 98% to the common unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

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    Third, 98% to the subordinated unitholders, pro rata, and 2% to our general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

    Thereafter, cash in excess of the minimum quarterly distributions is distributed to unitholders and the general partner in the manner described under "—Incentive Distribution Rights" below.

        On November 13, 2008, approximately 0.8 million subordinated units converted into an equal number of common units. On May 7, 2009, approximately 0.8 million subordinated units converted into an equal number of common units. On November 13, 2009, the remaining approximately 1.7 million subordinated units converted into an equal number of common units. After each such conversion, the newly issued common units participate pro rata with the other common units in distributions of available cash. Accordingly, we make distributions of available cash for any quarter after the subordination period or the earlier conversion of the subordinated units in the following manner:

    First, 98% to all unitholders, pro rata, and 2% to our general partner until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

    Thereafter, in the manner described under "—Incentive Distribution Rights" below.

Incentive Distribution Rights

        Incentive distribution rights are non-voting limited partner interests that represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in the partnership agreement.

        The following table illustrates the percentage allocations of the additional available cash from operating surplus between the unitholders and our general partner up to the various target distribution levels. The amounts set forth under "Marginal percentage interest in distributions" are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column "Total per unit quarterly distribution," until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2% general partner interest and assume our general partner has contributed any additional capital to maintain its 2% general partner interest and has not transferred its incentive distribution rights.

 
   
  Marginal percentage
interest in distributions
 
 
  Total per unit
quarterly distribution
  Unitholders   General partner  

Minimum quarterly distribution

  $0.40     98 %   2 %

First target distribution

  up to $0.44     98 %   2 %

Second target distribution

  above $0.44 up to $0.50     85 %   15 %

Third target distribution

  above $0.50 up to $0.60     75 %   25 %

Thereafter

  Above $0.60     50 %   50 %

        There is no guarantee that we will be able to pay the minimum quarterly distribution on the common units in any quarter, and we will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default is existing, under our senior secured credit facility.

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Common Unit Repurchases for the quarter ended December 31, 2009

        Purchases of Securities.    The following table covers the purchases of our common units by, or on behalf of, Partners during the three months ended December 31, 2009.

Period
  Total number of
common units
purchased
  Average price
paid per
common unit
  Total number of
common units
purchased as part of
publicly announced
plans or programs
  Maximum number
of common units that
may yet be purchased
under the plans or
programs
 

October

    625   $ 26.76     625     4,365  

November

    625   $ 25.86     625     3,740  

December

    625   $ 25.95     625     3,115  
                     

    1,875   $ 26.19     1,875        
                     

        All repurchases were made in the open market pursuant to a program announced on May 7, 2007 for the repurchase, from time to time, of our outstanding common units for purposes of making subsequent grants of restricted phantom units under the TransMontaigne Services Inc. long-term incentive plan to independent directors of our general partner. Pursuant to the terms of the repurchase plan, we anticipate repurchasing annually up to 10,000 common units. During the three months ended December 31, 2009, we repurchased 1,875 common units with approximately $49,000 of aggregate market value for this purpose. Unless we choose to terminate the repurchase program earlier, the repurchase program terminates on the earlier to occur of May 31, 2012; our liquidation, dissolution, bankruptcy or insolvency; the public announcement of a tender or exchange offer for the common units; or a merger, acquisition, recapitalization, business combination or other occurrence of a "Change of Control" under the TransMontaigne Services Inc. long-term incentive plan.

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ITEM 6.    SELECTED FINANCIAL DATA

        The following table sets forth selected historical consolidated financial data of TransMontaigne Partners for the periods and as of the dates indicated. The following selected financial data for each of the years in the four-year period ended December 31, 2009, six months ended December 31, 2005 and year ended June 30, 2005, has been derived from our consolidated financial statements. We adopted a December 31 year end for financial and tax reporting purposes effective December 31, 2005; we previously maintained a June 30 year end. You should not expect the results for any prior periods to be indicative of the results that may be achieved in future periods. You should read the following information together with our historical consolidated financial statements and related notes and with "Management's Discussion and Analysis of Financial Condition and Results of Operations" included elsewhere in this annual report.

 
  Years ended December 31,   Six Months
Ended
December 31,
  Year
ended
June 30,
 
 
  2009   2008(5)   2007   2006(3)(4)   2005(1)(2)   2005  
 
  (dollars in thousands)
 

Statement of Operations Data:

                                     

Revenue

  $ 142,547   $ 138,140   $ 131,651   $ 71,669   $ 22,908   $ 36,093  

Direct operating costs and expenses

    (64,968 )   (61,850 )   (60,686 )   (32,508 )   (7,896 )   (15,175 )

Direct general and administrative expenses

    (3,242 )   (4,138 )   (2,991 )   (6,453 )   (1,267 )   (79 )

Allocated general and administrative expenses

    (10,040 )   (10,030 )   (9,901 )   (5,431 )   (1,588 )   (2,800 )

Allocated insurance expense

    (2,900 )   (2,835 )   (2,837 )   (1,525 )   (500 )   (1,000 )

Reimbursement of bonus awards

    (1,237 )   (1,500 )   (1,125 )            

Depreciation and amortization

    (26,306 )   (23,316 )   (21,432 )   (11,750 )   (3,461 )   (6,154 )

Gain on disposition of assets, net

    1     2                  
                           
 

Operating income

    33,855     34,473     32,679     14,002     8,196     10,885  

Other income (expense):

                                     
 

Interest income

    7     38     214     37     4      
 

Interest expense

    (5,486 )   (6,007 )   (6,515 )   (3,356 )   (969 )   (167 )
 

Amortization of deferred financing costs

    (598 )   (599 )   (1,236 )   (810 )   (92 )   (15 )
 

Unrealized loss on derivative instrument

    (562 )   (2,128 )                
 

Foreign currency transaction gain (loss)

    36     (179 )                
                           

Net earnings

  $ 27,252   $ 25,598   $ 25,142   $ 9,873   $ 7,139   $ 10,703  
                           

Other Financial Data:

                                     

Net cash provided by operating activities

  $ 72,045   $ 53,488   $ 56,406   $ 25,251   $ 7,833   $ 18,517  

Net cash (used in) investing activities

  $ (37,742 ) $ (53,406 ) $ (155,550 ) $ (163,797 ) $ (3,042 ) $ (3,686 )

Net cash provided by (used in) financing activities

  $ (32,534 ) $ 3,200   $ 97,286   $ 141,310   $ (4,334 ) $ (14,592 )

Balance Sheet Data:

                                     

Property, plant and equipment, net

  $ 459,598   $ 447,753   $ 417,827   $ 401,613   $ 125,884   $ 116,281  

Total assets

  $ 515,535   $ 507,039   $ 460,818   $ 441,684   $ 131,036   $ 119,573  

Long-term debt

  $ 165,000   $ 165,500   $ 132,000   $ 189,621   $ 28,000   $ 28,307  

Partners' equity

  $ 303,125   $ 307,579   $ 312,830   $ 245,331   $ 100,013   $ 87,425  

(1)
The consolidated financial statements include the results of operations of the Mobile, Alabama terminal facility from the closing date of its acquisition by TransMontaigne Inc. (August 1, 2005).

(2)
The consolidated financial statements include the results of operations of the Oklahoma City terminal from the closing date of our acquisition (October 31, 2005).

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(3)
The consolidated financial statements include the results of operations of the Brownsville and River terminal facilities from the closing date of Morgan Stanley Capital Group Inc.'s acquisition of TransMontaigne Inc. (September 1, 2006).

(4)
The consolidated financial statements include the results of operations of the Southeast terminal facilities from the closing date of Morgan Stanley Capital Group Inc.'s acquisition of TransMontaigne Inc. (September 1, 2006). See Note 3 of Notes to consolidated financial statements.

(5)
The consolidated financial statements include the results of operations of the Mexican LPG operations from the closing date of our acquisition (December 31, 2007). See Note 3 of Notes to consolidated financial statements.

ITEM 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

OVERVIEW

        We are a refined petroleum products terminaling and pipeline transportation company formed by TransMontaigne Inc. At December 31, 2009, our operations are composed of:

    seven refined product terminals located in Florida, with an aggregate active storage capacity of approximately 7.1 million barrels, that provide integrated terminaling services to Marathon, Morgan Stanley Capital Group, other distribution and marketing companies and the United States government;

    one refined product terminal located in Mobile, Alabama with aggregate active storage capacity of approximately 163,000 barrels that provides integrated terminaling services to TransMontaigne Inc.;

    a 67-mile, interstate refined products pipeline, which we refer to as the Razorback pipeline, that currently transports gasolines and distillates for Morgan Stanley Capital Group from Mt. Vernon, Missouri to Rogers, Arkansas;

    two refined product terminals, one located in Mt. Vernon, Missouri and the other located in Rogers, Arkansas, with an aggregate active storage capacity of approximately 406,000 barrels, that are connected to the Razorback pipeline and provide integrated terminaling services to Morgan Stanley Capital Group;

    one refined product terminal located in Oklahoma City, Oklahoma, with aggregate active storage capacity of approximately 158,000 barrels, that provides integrated terminaling services to a major oil company;

    one refined product terminal located in Brownsville, Texas with aggregate active storage capacity of approximately 2.2 million barrels that provides integrated terminaling services to TransMontaigne Inc., Morgan Stanley Capital Group, Valero, PMI Trading Ltd. and other distribution and marketing companies;

    one refined product terminal located in Matamoros, Mexico with aggregate active LPG storage capacity of approximately 7,000 barrels that provides integrated terminaling services to TransMontaigne Inc.;

    a pipeline from our Brownsville facilities to our terminal in Matamoros, Mexico, which we refer to as the Diamondback pipeline, that currently transports LPG for TransMontaigne Inc.;

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    twelve refined product terminals located along the Mississippi and Ohio rivers ("River terminals") with aggregate active storage capacity of approximately 2.5 million barrels and the Baton Rouge, Louisiana dock facility that provide integrated terminaling services to Valero and other distribution and marketing companies; and

    twenty-two refined product terminals located along the Colonial and Plantation pipelines ("Southeast terminals") with aggregate active storage capacity of approximately 9.1 million barrels that provides integrated terminaling services to Morgan Stanley Capital Group and the United States government.

        We provide integrated terminaling, storage, transportation and related services for customers engaged in the distribution and marketing of light refined petroleum products, heavy refined petroleum products, crude oil, chemicals, fertilizers and other liquid products. Light refined products include gasolines, diesel fuels, heating oil and jet fuels. Heavy refined products include residual fuel oils and asphalt.

        We do not take ownership of or market products that we handle or transport and, therefore, we are not directly exposed to changes in commodity prices, except for the value of product gains and losses arising from certain of our terminaling services agreements with our customers. The volume of product that is handled, transported through or stored in our terminals and pipeline is directly affected by the level of supply and demand in the wholesale markets served by our terminals and pipeline. Overall supply of refined products in the wholesale markets is influenced by the products' absolute prices, the availability of capacity on delivering pipelines and vessels, fluctuating refinery margins and the markets' perception of future product prices. The demand for gasoline typically peaks during the summer driving season, which extends from April to September, and declines during the fall and winter months. The demand for marine fuels typically peaks in the winter months due to the increase in the number of cruise ships originating from the Florida ports. Despite these seasonalities, the overall impact on the volume of product throughput in our terminals and pipelines is not material.

        The majority of our business is devoted to providing terminaling and transportation services to TransMontaigne Inc. and Morgan Stanley Capital Group. TransMontaigne Inc. and Morgan Stanley Capital Group, in the aggregate, accounted for approximately 65%, 64% and 59% of our revenue for the years ended December 31, 2009, 2008 and 2007, respectively. TransMontaigne Inc., formed in 1995, is a terminaling, distribution and marketing company that distributes and markets refined petroleum products to wholesalers, distributors, marketers and industrial and commercial end users throughout the United States, primarily in the Gulf Coast, Midwest and Southeast regions. Morgan Stanley Capital Group, a wholly owned subsidiary of Morgan Stanley, is the principal commodities trading arm of Morgan Stanley. Morgan Stanley Capital Group is a leading global commodity trader involved in proprietary and counterparty-driven trading in numerous commodities including crude oil, refined petroleum products, natural gas and natural gas liquids, coal, electric power, base and precious metals, and others. Morgan Stanley Capital Group engages in trading physical commodities, like the refined petroleum products that we handle in our terminals, and exchange or over-the-counter commodities derivative instruments. TransMontaigne Inc. and Morgan Stanley Capital Group currently rely on us to provide substantially all the integrated terminaling services they require to support their operations along the Gulf Coast, in Brownsville, Texas, along the Mississippi and Ohio rivers, along the Colonial and Plantation pipelines, and in the Midwest. Pursuant to the terms of terminaling services agreements we have executed with TransMontaigne Inc. and Morgan Stanley Capital Group, we expect to continue to derive a majority of our revenue from TransMontaigne Inc. and Morgan Stanley Capital Group for the foreseeable future.

        We are controlled by our general partner, TransMontaigne GP L.L.C., which is an indirect wholly owned subsidiary of TransMontaigne Inc. Effective September 1, 2006, Morgan Stanley Capital Group purchased all of the issued and outstanding capital stock of TransMontaigne Inc. As a result of

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Morgan Stanley's acquisition of TransMontaigne Inc., Morgan Stanley became the indirect owner of our general partner. TransMontaigne Inc. and Morgan Stanley have a significant interest in our partnership through their indirect ownership of a 22.1% limited partner interest, a 2% general partner interest and the incentive distribution rights.

REGULATORY MATTERS

        On September 21, 2008, Morgan Stanley obtained the approval of the Board of Governors of the Federal Reserve System (the "FRB") to become a bank holding company upon the conversion of its wholly owned indirect subsidiary, Morgan Stanley Bank, from a Utah industrial bank to a national bank. On September 23, 2008, the Office of the Comptroller of the Currency (the "OCC") authorized Morgan Stanley Bank to commence business as a national bank, operating as Morgan Stanley Bank, N.A. Concurrently with this conversion, Morgan Stanley became a financial holding company under the Bank Holding Company Act, as amended (the "BHC Act"). As a result, Morgan Stanley has become subject to the consolidated supervision and regulation of the FRB and Morgan Stanley Bank, N.A. has become subject to the supervision and regulation of the OCC.

        As a financial holding company, Morgan Stanley will be able to engage in any activity that is financial in nature, incidental to a financial activity, or complementary to a financial activity. The BHC Act, by its terms, provides any company, such as Morgan Stanley, that becomes a financial holding company a two-year grace period to conform its existing nonfinancial activities and investments to the requirements of the BHC Act with the possibility of three one-year extensions. The BHC Act grandfathers "activities related to the trading, sale or investment in commodities and underlying physical properties" provided that Morgan Stanley conducted any of such type of activities as of September 30, 1997 and provided that certain other conditions are satisfied, which conditions are reasonably within the control of Morgan Stanley. In addition, the BHC Act permits the FRB to determine by regulation or order that certain activities are complementary to a financial activity and do not pose a risk to safety and soundness. The FRB has previously determined that a range of commodities activities are either financial in nature, incidental to a financial activity, or complementary to a financial activity.

        During April 2009, Morgan Stanley advised us that it has conducted an internal review and has concluded that, based upon its review, all of our activities and investments are permissible under the BHC Act.

        The FRB has not yet completed its review of these activities and investments. The FRB could conclude that certain of our activities or investments will not be deemed permissible under the BHC Act. If so, Morgan Stanley (i) may cause us to discontinue any such activity or divest any such investment or (ii) may transfer control of our general partner to an unaffiliated third party, prior to the end of the referenced grace period. We are unable to predict whether, if either of these actions is required, it would have a material adverse impact on our financial condition or results of operations.

SIGNIFICANT DEVELOPMENTS DURING THE YEAR ENDED DECEMBER 31, 2009

        On January 16, 2009, we announced a distribution of $0.59 per unit for the period from October 1, 2008 through December 31, 2008, payable on February 10, 2009 to unitholders of record on January 30, 2009.

        On February 5, 2009, we executed an additional interest rate swap agreement with Wachovia Bank, N.A. This interest rate swap agreement has a notional amount of $25.0 million that expires May 2010. Pursuant to the terms of the interest rate swap agreement, we pay a fixed rate of 1.145% and receive an interest payment based on the one-month LIBOR.

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        On February 26, 2009, Javed Ahmed notified the board of directors of our general partner of his intention to resign from the boards of directors of our general partner and TransMontaigne Inc., each to be effective March 31, 2009. The resignations follow Mr. Ahmed's decision on February 9, 2009 to resign as a Managing Director of Morgan Stanley effective May 10, 2009. To fill the vacancy resulting from Mr. Ahmed's resignation, on March 3, 2009, we announced the appointment of Randall P. O'Connor to serve as a member of the board of directors of our general partner, effective March 31, 2009. Mr. O'Connor is a Managing Director at Morgan Stanley, working in the firm's Commodities Group and currently serves as head of the Strategic Transactions Group.

        On April 17, 2009, we announced a distribution of $0.59 per unit for the period from January 1, 2009 through March 31, 2009, payable on May 5, 2009 to unitholders of record on April 30, 2009.

        On May 7, 2009, approximately 0.8 million subordinated units converted into an equal number of common units.

        On June 10, 2009, we combined our interest rate swap agreements into a single interest rate swap agreement with Wachovia Bank, N.A. with a notional amount of $150 million that expires June 2011.

        On July 17, 2009, we announced a distribution of $0.59 per unit for the period from April 1, 2009 through June 30, 2009, payable on August 11, 2009 to unitholders of record on July 31, 2009.

        On August 4, 2009, Randall J. Larson notified Partners of his intention to resign as Chief Executive Officer of our general partner and as President, Chief Executive Officer and member of the board of directors of TransMontaigne Inc., and the other subsidiaries of Partners and TransMontaigne Inc., each to be effective August 5, 2009. The board of directors of our general partner appointed Charles L. Dunlap to serve as Chief Executive Officer of our general partner, effective August 10, 2009. Mr. Dunlap was also appointed to serve as the President and Chief Executive Officer of TransMontaigne Inc., effective August 10, 2009. As a result of this appointment, Mr. Dunlap ceased to qualify as an independent director of the board of directors of our general partner and therefore tendered his resignation from the board of directors of our general partner, also effective August 10, 2009.

        On October 16, 2009, we announced a distribution of $0.59 per unit for the period from July 1, 2009 through September 30, 2009, payable on November 10, 2009 to unitholders of record on October 30, 2009.

        On November 13, 2009, the remaining approximately 1.7 million subordinated units converted into an equal number of common units.

SUBSEQUENT DEVELOPMENTS

        On January 15, 2010, we announced a distribution of $0.59 per unit for the period from October 1, 2009 through December 31, 2009, payable on February 9, 2010 to unitholders of record on January 29, 2010.

        On January 6, 2010, Duke R. Ligon notified Partners of his intention to resign from the board of directors of our general partner, effective January 7, 2010. To fill the vacancy resulting from Mr. Ligon's resignation, the board of directors appointed Henry M. Kuchta to serve as an independent member of the board of directors of our general partner, effective January 7, 2010. Mr. Kuchta was also appointed to serve as a member of the Audit Committee and Conflicts Committee of our general partner, also effective January 7, 2010.

        On January 15, 2010, we issued, pursuant to an underwritten public offering, 1,750,000 common units representing limited partner interests at a public offering price of $26.60 per common unit. On January 15, 2010, the underwriters of our secondary offering exercised in full their over-allotment option to purchase an additional 262,500 common units representing limited partnership interests at a

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price of $26.60 per common unit. The net proceeds from the offering were approximately $51.1 million, after deducting underwriting discounts, commissions, and offering expenses of approximately $0.2 million. Additionally, TransMontaigne GP L.L.C., our general partner, made a cash contribution of approximately $1.1 million to us to maintain its 2% general partner interest. The net proceeds from the offering and cash contribution were used to repay outstanding borrowings under our senior secured credit facility.

NATURE OF REVENUE AND EXPENSES

        We derive revenue from our terminal and pipeline transportation operations by charging fees for providing integrated terminaling, transportation and related services. The fees we charge, our other sources of revenue and our direct operating costs and expenses are described below.

        Terminaling Services Fees, Net.    We generate terminaling services fees, net by distributing and storing products for our customers. Terminaling services fees, net include throughput fees based on the volume of product distributed from the facility, injection fees based on the volume of product injected with additive compounds and storage fees based on a rate per barrel of storage capacity per month.

        Pipeline Transportation Fees.    We earn pipeline transportation fees at our Razorback pipeline and Diamondback pipeline based on the volume of product transported and the distance from the origin point to the delivery point. The Federal Energy Regulatory Commission regulates the tariff on the Razorback pipeline and the Diamondback pipeline.

        Management Fees and Reimbursed Costs.    We manage and operate certain tank capacity at our Port Everglades (South) terminal for a major oil company and receive a reimbursement of its proportionate share of operating and maintenance costs. We manage and operate for an affiliate of Mexico's state-owned petroleum company a bi-directional products pipeline connected to our Brownsville, Texas terminal facility and receive a management fee and reimbursement of costs. We also manage and operate for another major oil company two terminals that are adjacent to our Southeast facilities and receive a reimbursement of its proportionate share of operating and maintenance costs.

        Other Revenue.    We provide ancillary services including heating and mixing of stored products and product transfer services. Pursuant to terminaling services agreements with our throughput customers, we are entitled to the volume of product gained resulting from differences in the measurement of product volumes received and distributed at our terminaling facilities. Consistent with recognized industry practices, measurement differentials occur as the result of the inherent variances in measurement devices and methodology. We recognize as revenue the net proceeds from the sale of the product gained.

        Direct Operating Costs and Expenses.    The direct operating costs and expenses of our 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.

        Direct General and Administrative Expenses.    The direct general and administrative expenses of our operations include accounting and legal costs associated with annual and quarterly reports and tax return and Schedule K-1 preparation and distribution, independent director fees and amortization of deferred equity-based compensation.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

        A summary of the significant accounting policies that we have adopted and followed in the preparation of our historical consolidated financial statements is detailed in Note 1 of Notes to consolidated financial statements. Certain of these accounting policies require the use of estimates. We have identified the following estimates that, in our opinion, are subjective in nature, require the

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exercise of judgment, and involve complex analyses. These estimates are based on our knowledge and understanding of current conditions and actions that 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.

        Allowance for Doubtful Accounts.    At December 31, 2009, our allowance for doubtful accounts was approximately $0.4 million. Our allowance for doubtful accounts represents the amount of trade receivables that we do not expect to collect. The valuation of our allowance for doubtful accounts is based on our analysis of specific individual customer balances that are past due and, from that analysis, we estimate the amount of the receivable balance that we do not expect to collect. That estimate is based on various factors, including our experience in collecting past due amounts from the customer being evaluated, the customer's current financial condition, the current economic environment and the economic outlook for the future. Changes in our estimates and assumptions may occur as a result of the passage of time and the occurrence of future events.

        Accrued Environmental Obligations.    At December 31, 2009, we have an accrued liability of approximately $5.6 million representing our best estimate of the undiscounted future payments we expect to pay for environmental costs to remediate existing conditions. Estimates of our environmental obligations are subject to change due to a number of factors and judgments involved in the estimation process, including the early stage of investigation at certain sites, the lengthy time frames required to complete remediation, technology changes affecting remediation methods, alternative remediation methods and strategies, and changes in environmental laws and regulations. Changes in our estimates and assumptions may occur as a result of the passage of time and the occurrence of future events.

        Costs incurred to remediate existing contamination at the terminals we acquired from TransMontaigne Inc. have been, and are expected in the future to be, insignificant. Pursuant to agreements with TransMontaigne Inc., TransMontaigne Inc. retained 100% of these liabilities and indemnified us against certain potential environmental claims, losses and expenses associated with the operation of the acquired terminal facilities and occurring before our date of acquisition from TransMontaigne Inc., up to a maximum liability (not to exceed $15.0 million for the Florida and Midwest terminals acquired on May 27, 2005, not to exceed $15.0 million for the Brownsville and River terminals acquired on December 29, 2006, and not to exceed $15.0 million for the Southeast terminals acquired on December 31, 2007) for these indemnification obligations.

        Goodwill.    At December 31, 2009, the carrying amount of our goodwill was approximately $24.7 million. Goodwill is required to be tested for impairment annually unless events or changes in circumstances indicate it is more likely than not that an impairment loss has been incurred at an interim date. Our annual test for the impairment of goodwill is performed as of December 31. The impairment test is performed at the reporting unit level. Our reporting units are our operating segments (see Note 17 of Notes to consolidated financial statements). At December 31, 2009, our reporting units with goodwill were the Brownsville terminal and the River terminals. Approximately $16.2 million of the goodwill was assigned to our Brownsville terminal and approximately $8.5 million was assigned to our River terminals (see Note 7 of Notes to consolidated financial statements). Management exercises judgment in determining the estimated fair values of the Partnership's reporting units. At December 31, 2009, we estimated the fair value of our reporting units using a discounted cash flow technique. We believe that our estimates of the future cash flows and related assumptions would be consistent with those used by market participants (that is, potential buyers of the reporting unit) at December 31, 2009. The cash flows represented our best estimate of the future revenues, expenses and capital expenditures to maintain the facilities associated with each of our reporting units. The cash flows did not anticipate future expenditures to expand the facilities beyond the expenditures necessary to complete expansion projects approved prior to December 31, 2009. The cash flows attributed to our

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reporting units included only a portion of our historical general and administrative expenses under the assumption that market participants would only include limited amounts of general and administrative expenses in their estimates of future cash flows because market participants would likely have pre-existing management and back office capabilities (that is, a market participant synergy). At December 31, 2009, the fair value of our reporting units with goodwill exceeded their carrying amount. Accordingly, we did not recognize any goodwill impairment charges during the year ended December 31, 2009. A significant decline in the price of our common units with a resulting increase in our weighted average cost of capital, the loss of a significant customer, or an unforeseen increase in the costs to operate and maintain our terminals and pipelines, may result in the recognition of an impairment charge in the future. Changes in our estimates and assumptions may occur as a result of the passage of time and the occurrence of future events.

RESULTS OF OPERATIONS—YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007

        In reviewing our historical results of operations, you should be aware that the accompanying consolidated financial statements include the assets, liabilities and results of operations of certain TransMontaigne Inc. terminal operations prior to their acquisition by us from TransMontaigne Inc. The results of operations of TransMontaigne Inc.'s terminals prior to being acquired by us are reflected in the accompanying consolidated financial statements as being attributable to TransMontaigne Inc. ("Predecessor"). The acquired assets and liabilities have been recorded at TransMontaigne Inc.'s carryover basis. On December 31, 2007, we acquired from TransMontaigne Inc. 22 terminals along the Colonial and Plantation pipelines (the "Southeast terminals") for a cash payment of approximately $118.6 million. The acquisition of terminal operations from TransMontaigne Inc. have been accounted for as transactions among entities under common control and, accordingly, prior periods include the activity of the acquired terminal operations since September 1, 2006 (the date of Morgan Stanley Capital Group Inc.'s acquisition of TransMontaigne Inc.) for acquisitions made by us on or after September 1, 2006.

        The historical results of operations reflect the impact of the following acquisitions:

    The purchase of the Southeast terminals by Morgan Stanley Capital Group, completed in September 2006 when it acquired TransMontaigne Inc., and subsequent acquisition by us from TransMontaigne Inc. in December 2007; and

    Our December 2007 acquisition from Rio Vista Energy Partners L.P. ("Rio Vista") of a terminal facility in Matamoros, Mexico, the Diamondback pipeline from Brownsville, Texas to Matamoros, Mexico, with associated rights of way and easements and 47 acres of land, together with a permit to distribute liquefied petroleum gas, or LPG, to Mexico's state-owned petroleum company.

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        Selected results of operations data for each of the quarters in the years ended December 31, 2009, 2008 and 2007, are summarized below (in thousands):

 
  Three months ended    
 
 
  March 31,
2009
  June 30,
2009
  September 30,
2009
  December 31,
2009
  Year ended
December 31,
2009
 

Revenue

  $ 34,402   $ 35,849   $ 35,370   $ 36,926   $ 142,547  

Direct operating costs and expenses

    (15,544 )   (15,430 )   (16,915 )   (17,079 )   (64,968 )

Direct general and administrative expenses

    (1,099 )   (705 )   (606 )   (832 )   (3,242 )

Allocated general and administrative expenses

    (2,510 )   (2,510 )   (2,510 )   (2,510 )   (10,040 )

Allocated insurance expense

    (725 )   (725 )   (725 )   (725 )   (2,900 )

Reimbursement of bonus awards

    (309 )   (309 )   (309 )   (310 )   (1,237 )

Depreciation and amortization

    (6,355 )   (6,450 )   (6,541 )   (6,960 )   (26,306 )

Gain on disposition of assets

        1             1  
                       
 

Operating income

    7,860     9,721     7,764     8,510     33,855  

Other expense, net

    (1,438 )   (1,812 )   (2,065 )   (1,288 )   (6,603 )
                       
 

Net earnings

  $ 6,422   $ 7,909   $ 5,699   $ 7,222   $ 27,252  
                       

 

 
  Three months ended    
 
 
  March 31,
2008
  June 30,
2008
  September 30,
2008
  December 31,
2008
  Year ended
December 31,
2008
 

Revenue

  $ 33,824   $ 35,092   $ 35,204   $ 34,020   $ 138,140  

Direct operating costs and expenses

    (15,467 )   (15,320 )   (16,331 )   (14,732 )   (61,850 )

Direct general and administrative expenses

    (1,073 )   (1,317 )   (705 )   (1,043 )   (4,138 )

Allocated general and administrative expenses

    (2,507 )   (2,508 )   (2,508 )   (2,507 )   (10,030 )

Allocated insurance expense

    (713 )   (704 )   (708 )   (710 )   (2,835 )

Reimbursement of bonus awards

    (375 )   (375 )   (375 )   (375 )   (1,500 )

Depreciation and amortization

    (5,733 )   (5,772 )   (5,794 )   (6,017 )   (23,316 )

Gain on disposition of assets

                2     2  
                       
 

Operating income

    7,956     9,096     8,783     8,638     34,473  

Other expense, net

    (1,754 )   (1,471 )   (1,819 )   (3,831 )   (8,875 )
                       
 

Net earnings

  $ 6,202   $ 7,625   $ 6,964   $ 4,807   $ 25,598  
                       

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  Three months ended    
 
 
  March 31,
2007
  June 30,
2007
  September 30,
2007
  December 31,
2007
  Year ended
December 31,
2007
 

Revenue

  $ 32,700   $ 32,204   $ 31,921   $ 34,826   $ 131,651  

Direct operating costs and expenses

    (13,945 )   (15,262 )   (14,414 )   (17,065 )   (60,686 )

Direct general and administrative expenses

    (894 )   (461 )   (288 )   (1,348 )   (2,991 )

Allocated general and administrative expenses

    (2,456 )   (2,467 )   (2,489 )   (2,489 )   (9,901 )

Allocated insurance expense

    (717 )   (717 )   (717 )   (686 )   (2,837 )

Reimbursement of bonus awards

        (375 )   (375 )   (375 )   (1,125 )

Depreciation and amortization

    (4,965 )   (5,430 )   (5,481 )   (5,556 )   (21,432 )
                       
 

Operating income

    9,723     7,492     8,157     7,307     32,679  

Other expense, net

    (3,911 )   (3,279 )   (242 )   (105 )   (7,537 )
                       
 

Net earnings

  $ 5,812   $ 4,213   $ 7,915   $ 7,202   $ 25,142  
                       


ANALYSIS OF REVENUE

        Total Revenue.    We derive revenue from our terminal and pipeline transportation operations by charging fees for providing integrated terminaling, transportation and related services. Our total revenue by category was as follows (in thousands):

 
  Total Revenue by Category  
 
  Year ended
December 31,
2009
  Year ended
December 31,
2008
  Year ended
December 31,
2007
 

Terminaling services fees, net

  $ 118,024   $ 111,313   $ 109,906  

Pipeline transportation fees

    4,375     4,020     1,996  

Management fees and reimbursed costs

    2,124     1,905     1,724  

Other

    18,024     20,902     18,025  
               
 

Revenue

  $ 142,547   $ 138,140   $ 131,651  
               

        See discussion below for a detailed analysis of terminaling services fees, net, pipeline transportation fees, management fees and reimbursed costs, and other revenue included in the table above.

        We operate our business and report our results of operations in five principal business segments: (i) Gulf Coast terminals, (ii) Midwest terminals and pipeline system, (iii) Brownsville terminals, (iv) River terminals and (v) Southeast terminals. The aggregate revenue of each of our business segments was as follows (in thousands):

 
  Total Revenue by Business Segment  
 
  Year ended
December 31,
2009
  Year ended
December 31,
2008
  Year ended
December 31,
2007
 

Gulf Coast terminals

  $ 52,123   $ 49,315   $ 44,669  

Midwest terminals and pipeline system

    6,711     5,476     5,797  

Brownsville terminals

    22,258     20,693     15,672  

River terminals

    17,395     19,606     19,511  

Southeast terminals

    44,060     43,050     46,002  
               
 

Revenue

  $ 142,547   $ 138,140   $ 131,651  
               

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        Total revenue by business segment is presented and further analyzed below by category of revenue. In addition to the detailed discussion and analysis of revenue by category and business segment, our results of operations reflect:

    Our acquisition, effective December 31, 2007, of the Southeast terminals, which are included in our results of operations for the entirety of 2007 because the acquisition is accounted for as a transaction among entities under common control; and

    Our acquisition of the Mexican LPG operations from Rio Vista, effective December 31, 2007, which are included in our results of operations from such date. For the years ended December 31, 2009, 2008 and 2007, revenue attributable to our Brownsville terminals included revenue from the Mexican LPG operations of approximately $1.5 million, $2.1 million and $nil, respectively.

        Terminaling Services Fees, Net.    Pursuant to terminaling services agreements with our customers, which range from one month to ten years in duration, we generate fees by distributing and storing products for our customers. Terminaling services fees, net include throughput fees based on the volume of product distributed from the facility, injection fees based on the volume of product injected with additive compounds, and storage fees based on a rate per barrel of storage capacity per month. The terminaling services fees, net by business segments were as follows (in thousands):

 
  Terminaling Services Fees, Net,
by Business Segment
 
 
  Year ended
December 31,
2009
  Year ended
December 31,
2008
  Year ended
December 31,
2007
 

Gulf Coast terminals

  $ 43,798   $ 39,750   $ 38,555  

Midwest terminals and pipeline system

    3,640     3,466     2,976  

Brownsville terminals

    14,755     13,103     11,799  

River terminals

    16,864     18,868     18,942  

Southeast terminals

    38,967     36,126     37,634  
               
 

Terminaling services fees, net

  $ 118,024   $ 111,313   $ 109,906  
               

        The increase in terminaling services fees, net for the year ended December 31, 2009 as compared to the year ended December 31, 2008 includes an increase of approximately $2.9 million resulting from newly constructed tank capacity placed into service at certain of our Gulf Coast terminals, an increase of approximately $2.2 million resulting from completion of ethanol blending functionality at certain of our Southeast terminals, and an increase of approximately $0.7 million resulting from newly constructed LPG tank capacity placed into service at our Brownsville terminals.

        In connection with our acquisition of the Mexican LPG operations, we amended the existing LPG terminaling services agreement with TransMontaigne Inc., resulting in a decrease in the rates charged to TransMontaigne Inc. on volumes throughput at the Brownsville LPG terminal in exchange for an increase in pipeline transportation fees related to the volume of product transported through the Diamondback pipeline. For the years ended December 31, 2009 and 2008, the change in the rates charged on volumes throughput at the Brownsville LPG terminal resulted in a reduction of approximately $(0.9) million and $(0.8) million, respectively, of terminaling services fees, net.

        Included in terminaling services fees, net for the years ended December 31, 2009, 2008 and 2007 are fees charged to Morgan Stanley Capital Group of approximately $69.7 million, $63.9 million and $27.1 million, respectively, and fees charged to TransMontaigne Inc. of approximately $7.0 million, $6.3 million and $36.1 million, respectively. Effective January 1, 2008, we entered into a terminaling services agreement with Morgan Stanley Capital Group relating to our Southeast facilities that replaced

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certain capacity previously utilized by TransMontaigne Inc. The increase in fees charged to Morgan Stanley Capital Group therefore offset the decrease in fees charged to TransMontaigne Inc.

        Our terminaling services agreements are structured as either throughput agreements or storage agreements. Certain throughput agreements contain provisions that require our customers to throughput a minimum volume of product at our facilities over a stipulated period of time, which results in a fixed amount of revenue to be recognized by us. Our storage agreements require our customers to make minimum payments based on the volume of storage capacity available to the customer under the agreement, which results in a fixed amount of revenue to be recognized by us. We refer to the fixed amount of revenue recognized pursuant to our terminaling services agreements as being "firm commitments." Revenue recognized in excess of firm commitments and revenue recognized based solely on the volume of product distributed or injected are referred to as "variable." The "firm commitments" and "variable" revenue included in terminaling services fees, net were as follows (in thousands):

 
  Firm Commitments and Variable Revenue  
 
  Year ended
December 31,
2009
  Year ended
December 31,
2008
  Year ended
December 31,
2007
 

Firm commitments:

                   
 

External customers

  $ 36,341   $ 35,816   $ 38,394  
 

Affiliates

    77,633     70,574     34,716  
               
   

Total

    113,974     106,390     73,110  
               

Variable:

                   
 

External customers

    4,870     5,287     8,321  
 

Affiliates

    (820 )   (364 )   28,475  
               
   

Total

    4,050     4,923     36,796  
               
 

Terminaling services fees, net

  $ 118,024   $ 111,313   $ 109,906  
               

        Under the terminaling services agreement we entered into with Morgan Stanley Capital Group, effective January 1, 2008, Morgan Stanley Capital Group agreed to throughput a minimum volume of product at our Southeast facilities resulting in affiliated "firm commitments" during the year ended December 31, 2008. The Morgan Stanley Capital Group terminaling services agreement replaced certain capacity utilized under our prior terminaling services agreement with TransMontaigne Inc. related to our Southeast facilities. The terms of the previous agreement with TransMontaigne Inc. resulted in affiliated "variable" revenue during the year ended December 31, 2007.

        At December 31, 2009, the remaining terms on the terminaling services agreements that generated "firm commitments" for the year ended December 31, 2009 were as follows (in thousands):

 
  At
December 31,
2009
 

Remaining terms on terminaling services agreements that generated "firm commitments:"

       
 

Less than 1 year remaining

  $ 13,434  
 

More than 1 year but less than 3 years remaining

    21,200  
 

More than 3 years but less than 5 years remaining

    77,762  
 

More than 5 years remaining

    1,578  
       
   

Total firm commitments for the year ending December 31, 2009

  $ 113,974  
       

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        Pipeline Transportation Fees.    We earn pipeline transportation fees at our Razorback pipeline and Diamondback pipeline based on the volume of product transported and the distance from the origin point to the delivery point. The Federal Energy Regulatory Commission regulates the tariff on the Razorback pipeline and the Diamondback pipeline. The pipeline transportation fees by business segments were as follows (in thousands):

 
  Pipeline Transportation Fees
by Business Segment
 
 
  Year ended
December 31,
2009
  Year ended
December 31,
2008
  Year ended
December 31,
2007
 

Gulf Coast terminals

  $   $   $  

Midwest terminals and pipeline system

    1,981     1,130     1,996  

Brownsville terminals

    2,394     2,890      

River terminals

             

Southeast terminals

             
               
 

Pipeline transportation fees

  $ 4,375   $ 4,020   $ 1,996  
               

        Effective December 31, 2007, we acquired the Mexican LPG operations, including the Diamondback pipeline, from Rio Vista. For the year ended December 31, 2009 and 2008, the Mexican LPG operations generated approximately $2.4 million and $2.9 million, respectively, of pipeline transportation fees attributable to our Brownsville terminals.

        Included in pipeline transportation fees for the years ended December 31, 2009, 2008 and 2007 are fees charged to Morgan Stanley Capital Group of approximately $2.0 million, $1.1 million and $1.0 million, respectively, and fees charged to TransMontaigne Inc. of approximately $2.4 million, $2.9 million and $1.0 million, respectively.

        Management Fees and Reimbursed Costs.    We manage and operate for a major oil company certain tank capacity at our Port Everglades (South) terminal and receive reimbursement of their proportionate share of operating and maintenance costs. We manage and operate for an affiliate of Mexico's state-owned petroleum company a bi-directional products pipeline connected to our Brownsville, Texas terminal facility and receive a management fee and reimbursement of costs. We also manage and operate for another major oil company two terminals that are adjacent to our Southeast facilities and receive a reimbursement of their proportionate share of operating and maintenance costs. The management fees and reimbursed costs by business segments were as follows (in thousands):

 
  Management Fees and Reimbursed Costs
by Business Segment
 
 
  Year ended
December 31,
2009
  Year ended
December 31,
2008
  Year ended
December 31,
2007
 

Gulf Coast terminals

  $ 63   $ 141   $ 165  

Midwest terminals and pipeline system

             

Brownsville terminals

    1,739     1,449     1,171  

River terminals

             

Southeast terminals

    322     315     388  
               
 

Management fees and reimbursed costs

  $ 2,124   $ 1,905   $ 1,724  
               

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        Other Revenue.    We provide ancillary services including heating and mixing of stored products, product transfer services, railcar handling, wharfage fees and vapor recovery fees. Pursuant to terminaling services agreements with our throughput customers, we are entitled to the volume of product gained resulting from differences in the measurement of product volumes received and distributed at our terminaling facilities. Consistent with recognized industry practices, measurement differentials occur as the result of the inherent variances in measurement devices and methodology. We recognize as revenue the net proceeds from the sale of the product gained. Other revenue is composed of the following (in thousands):

 
  Principal Components of Other Revenue  
 
  Year ended
December 31,
2009
  Year ended
December 31,
2008
  Year ended
December 31,
2007
 

Product gains

  $ 8,927   $ 11,272   $ 10,509  

Steam heating fees

    3,828     5,389     4,391  

Product transfer services

    766     762     679  

Railcar handling

    1,022     865     567  

Other

    3,481     2,614     1,879  
               
 

Other revenue

  $ 18,024   $ 20,902   $ 18,025  
               

        For the years ended December 31, 2009, 2008 and 2007, we sold approximately 130,000, 139,000 and 134,000 barrels, respectively, of product gained resulting from differences in the measurement of product volumes received and distributed at our terminaling facilities at average prices of $72, $97 and $78 per barrel, respectively. Pursuant to our terminaling services agreement related to the Southeast terminals, we agreed to rebate to Morgan Stanley Capital Group 50% of the proceeds we receive annually in excess of $4.2 million from the sale of product gains at our Southeast terminals. At December 31, 2009 and 2008, we have accrued a liability due to Morgan Stanley Capital Group of approximately $0.5 million and $2.2 million, respectively, representing our rebate liability.

        Other revenue from steam heating fees decreased during the year ended December 31, 2009 as compared to the year ended December 31, 2008 by approximately $1.6 million due principally to a decrease in utility charges rebilled to customers for the heating of stored products.

        Included in other revenue for the years ended December 31, 2009, 2008 and 2007 are amounts charged to Morgan Stanley Capital Group of approximately $11.5 million, $13.2 million and $2.9 million, respectively, and amounts charged to TransMontaigne Inc. of approximately $0.2 million, $0.1 million and $8.9 million, respectively. The increase in amounts charged to Morgan Stanley Capital Group, and the corresponding decrease in amounts charged to TransMontaigne Inc., primarily resulted from the shift of the terminaling services agreement for the Southeast terminals, formerly with TransMontaigne Inc. to Morgan Stanley Capital Group.

        The other revenue by business segments were as follows (in thousands):

 
  Other Revenue by Business Segment  
 
  Year ended
December 31,
2009
  Year ended
December 31,
2008
  Year ended
December 31,
2007
 

Gulf Coast terminals

  $ 8,262   $ 9,424   $ 5,949  

Midwest terminals and pipeline system

    1,090     880     825  

Brownsville terminals

    3,370     3,251     2,702  

River terminals

    531     738     569  

Southeast terminals

    4,771     6,609     7,980  
               
 

Other revenue

  $ 18,024   $ 20,902   $ 18,025  
               

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ANALYSIS OF COSTS AND EXPENSES

        Costs and Expenses.    The direct operating costs and expenses of our 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. The direct operating costs and expenses of our operations were as follows (in thousands):

 
  Direct Operating Costs and Expenses  
 
  Year ended
December 31,
2009
  Year ended
December 31,
2008
  Year ended
December 31,
2007
 

Wages and employee benefits

  $ 21,370   $ 20,786   $ 18,189  

Utilities and communication charges

    7,642     9,304     7,290  

Repairs and maintenance

    23,952     19,725     22,116  

Office, rentals and property taxes

    6,307     6,103     5,989  

Vehicles and fuel costs

    1,050     1,507     2,575  

Environmental compliance costs

    3,319     2,989     3,754  

Other

    1,328     1,436     824  

Less—property and environmental insurance recoveries

            (51 )
               
 

Direct operating costs and expenses

  $ 64,968   $ 61,850   $ 60,686  
               

        The direct operating costs and expenses of our business segments were as follows (in thousands):

 
  Direct Operating Costs and
Expenses by Business Segment
 
 
  Year ended
December 31,
2009
  Year ended
December 31,
2008
  Year ended
December 31,
2007
 

Gulf Coast terminals

  $ 20,986   $ 21,774   $ 18,711  

Midwest terminals and pipeline system

    2,428     1,500     2,519  

Brownsville terminals

    11,916     11,510     9,039  

River terminals

    8,912     7,858     6,716  

Southeast terminals

    20,726     19,208     23,701  
               
 

Direct operating costs and expenses

  $ 64,968   $ 61,850   $ 60,686  
               

        Effective December 31, 2007, we acquired the Southeast terminals from TransMontaigne Inc. The Southeast terminals are included in our results of operations for the entirety of 2007 because the acquisition is accounted for as a transaction among entities under common control.

        Effective December 31, 2007, we acquired the Mexican LPG operations from Rio Vista. For the years ended December 31, 2009, 2008 and 2007, the Mexican LPG operations incurred approximately $0.7 million, $0.8 million and $nil, respectively, of direct operating costs and expenses attributable to our Brownsville terminals.

        The direct general and administrative expenses of our operations include accounting and legal costs associated with annual and quarterly reports and tax return and Schedule K-1 preparation and

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distribution, independent director fees and amortization of deferred equity-based compensation. Direct general and administrative expenses were as follows (in thousands):

 
  Direct General and Administrative Expenses  
 
  Year ended
December 31,
2009
  Year ended
December 31,
2008
  Year ended
December 31,
2007
 

Accounting and tax expenses

  $ 1,368   $ 1,799   $ 1,268  

Legal expenses

    747     1,087     1,054  

Independent director fees and investor relations expenses

    285     447     322  

Amortization of deferred equity-based compensation

    213     35     66  

Provision for potentially uncollectible accounts receivable

        289     83  

Other

    629     481     198  
               
 

Direct general and administrative expenses

  $ 3,242   $ 4,138   $ 2,991  
               

        The accompanying consolidated financial statements include allocated general and administrative charges from TransMontaigne Inc. for allocations of indirect corporate overhead to cover costs of centralized corporate functions such as legal, accounting, treasury, insurance administration and claims processing, health, safety and environmental, information technology, human resources, credit, payroll, taxes, engineering and other corporate services. The allocated general and administrative expenses for the years ended December 31, 2009, 2008 and 2007 were approximately $10.0 million, $10.0 million and $9.9 million, respectively.

        The accompanying consolidated financial statements also include allocated insurance charges from TransMontaigne Inc. for allocations of insurance premiums to cover costs of insuring activities such as property, casualty, pollution, automobile, directors' and officers', and other insurable risks. The allocated insurance expense for the years ended December 31, 2009, 2008 and 2007 were approximately $2.9 million, $2.8 million and $2.8 million, respectively.

        The accompanying consolidated financial statements also include amounts paid to TransMontaigne Services Inc. as a partial reimbursement of bonus awards granted by TransMontaigne Services Inc. to certain key officers and employees that vest over future service periods. The reimbursements were approximately $1.2 million, $1.5 million and $1.1 million for the years ended December 31, 2009, 2008 and 2007, respectively.

        Depreciation and amortization for the years ended December 31, 2009, 2008 and 2007 were approximately $26.3 million, $23.3 million and $21.4 million, respectively.

LIQUIDITY AND CAPITAL RESOURCES

        Our primary liquidity needs are to fund our working capital requirements, distributions to unitholders and capital expenditures. We believe that we will be able to generate sufficient cash from operations in the future to meet our liquidity needs to fund our working capital requirements and to fund our distributions to unitholders. We expect to fund our capital expenditures with additional borrowings under our senior secured credit facility.

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        Excluding acquisitions, our capital expenditures for the year ended December 31, 2009 were approximately $37.7 million for terminal and pipeline facilities and assets to support these facilities. Management and the board of directors of our general partner approved capital projects that currently are or will be under construction with estimated completion dates that extend through March 31, 2011. At December 31, 2009, the remaining capital expenditures to complete the approved capital projects are estimated to range from $29 million to $33 million. We expect to fund our capital expenditures with additional borrowings under our senior secured credit facility. The budgeted capital projects include the following:

Terminal
  Description of project   Incremental
storage
capacity
  Expected
completion
 
   
  (in Bbls)
   

Tampa

  Improve truck rack capacity and functionality         1st half 2010

Southeast

  Renewable fuels blending functionality         2nd half 2010

Brownsville

  Build truck rack         2nd half 2010

Collins/Purvis

  Increase light oil tank capacity     700,000   1st half 2011

        Pursuant to existing terminaling services agreements with Morgan Stanley Capital Group, we expect to receive payments through December 31, 2010 from Morgan Stanley Capital Group in the range of $4 million to $8 million, which are due and payable upon completion of certain of the capital projects referred to above.

        At December 31, 2009, our senior secured credit facility provides for a maximum borrowing line of credit equal to $200 million. At December 31, 2009, our outstanding borrowings were approximately $165 million, resulting in available capacity of approximately $35 million. Upon payment of the remaining capital expenditures to complete the approved capital projects, receipt of payments from Morgan Stanley Capital Group upon completion of certain of the capital projects and a reduction in our outstanding borrowings under the senior secured credit facility considering the net proceeds and cash contribution of approximately $52.1 million from our January 15, 2010 equity offering, we currently expect to have approximately $60 million in available capacity under our senior secured credit facility. In addition, at our request, the revolving loan commitment can be increased up to an additional $100 million, in the aggregate, without the approval of the lenders, but subject to the approval of the administrative agent and the receipt of additional commitments from one or more lenders. The terms of the senior secured credit facility also permit us to borrow up to approximately $25 million from other lenders, including our general partner and its affiliates. 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.

        Senior Secured Credit Facility.    At December 31, 2009, the senior secured credit facility provides for a maximum borrowing line of credit equal to the lesser of (i) $200 million and (ii) four times Consolidated EBITDA (as defined: $241.6 million at December 31, 2009). We may elect to have loans under the senior secured credit facility bear interest either (i) at a rate of LIBOR plus a margin ranging from 1.5% to 2.5% depending on the total leverage ratio then in effect, or (ii) at a base rate (the greater of (a) the federal funds rate plus 0.5% or (b) the prime rate) plus a margin ranging from 0.5% to 1.5% depending on the total leverage ratio then in effect. We also pay a commitment fee ranging from 0.3% to 0.5% per annum, depending on the total leverage ratio then in effect, on the total amount of unused commitments. Our obligations under the senior secured credit facility are secured by a first priority security interest in favor of the lenders in our assets, including cash, accounts receivable, inventory, general intangibles, investment property, contract rights and real property.

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        The terms of the senior secured credit facility include covenants that restrict our ability to make cash distributions and acquisitions. We may make distributions of cash to the extent of our "available cash" as defined in our partnership agreement. We may make acquisitions meeting the definition of "permitted acquisitions" which include: acquisitions in which the consideration paid for such acquisition, together with the consideration paid for other acquisitions in the same fiscal year, does not exceed $25 million; acquisitions that arise from the exercise of options under the omnibus agreement with TransMontaigne Inc.; and acquisitions in which we have (1) provided the agent prior written documentation in form and substance reasonably satisfactory to the agent demonstrating our pro forma compliance with all financial and other covenants contained in the senior secured credit facility after giving effect to such acquisition and (2) satisfied all other conditions precedent to such acquisition which the agent may reasonably require in connection therewith. The principal balance of loans and any accrued and unpaid interest are due and payable in full on the maturity date, December 22, 2011.

        The senior secured credit facility also contains customary representations and warranties (including those relating to 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 primary financial covenants contained in the senior secured credit facility are (i) a total leverage ratio test (not to exceed 4.5 times), (ii) a senior secured leverage ratio test (not to exceed 4.0 times), and (iii) a minimum interest coverage ratio test (not less than 2.75 times). These financial covenants are based on a defined financial performance measure within the senior secured credit facility known as "Consolidated EBITDA." The calculation of the "total leverage ratio," "senior secured leverage ratio" and "interest coverage ratio" contained in the senior secured credit facility is as follows (in thousands, except ratios):

 
  Three months ended    
 
 
  Year
ended
December 31,
2009
 
 
  March 31,
2009
  June 30,
2009
  September 30,
2009
  December 31,
2009
 

Financial performance debt covenant test:

                               

Consolidated EBITDA for the total leverage ratio, as stipulated in the credit facility

  $ 14,228   $ 16,241   $ 14,357   $ 15,583   $ 60,409  

Consolidated funded indebtedness

                          $ 165,000  

Total leverage ratio and senior secured leverage ratio

                            2.73x  

Consolidated EBITDA for the interest coverage ratio

  $ 14,228   $ 16,241   $ 14,357   $ 15,583   $ 60,409  

Consolidated interest expense, as stipulated in the credit facility

  $ 1,275   $ 1,439   $ 1,349   $ 1,416   $ 5,479  

Interest coverage ratio

                            11.03x  

Reconciliation of consolidated EBITDA to cash flows provided by operating activities:

                               

Consolidated EBITDA

  $ 14,228   $ 16,241   $ 14,357   $ 15,583   $ 60,409  

Consolidated interest expense

    (1,275 )   (1,439 )   (1,349 )   (1,416 )   (5,479 )

Amortization of deferred revenue

    (326 )   (562 )   (764 )   (809 )   (2,461 )

Amounts due under long-term terminaling services agreements, net

    (478 )   (386 )   25     (627 )   (1,466 )

Change in operating assets and liabilities

    3,191     11,017     5,553     1,281     21,042  
                       

Cash flows provided by operating activities

  $ 15,340   $ 24,871   $ 17,822   $ 14,012   $ 72,045  
                       

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        If we were to fail either financial performance covenant, or any other covenant contained in the senior secured credit facility, we would seek a waiver from our lenders under such facility. If we were unable to obtain a waiver from our lenders and the default remained uncured after any applicable grace period, we would be in breach of the senior secured credit facility, and the lenders would be entitled to declare all outstanding borrowings immediately due and payable.

        On January 15, 2010, we issued, pursuant to an underwritten public offering, 1,750,000 common units representing limited partner interests at a public offering price of $26.60 per common unit. On January 15, 2010, the underwriters of our secondary offering exercised in full their over-allotment option to purchase an additional 262,500 common units representing limited partnership interests at a price of $26.60 per common unit. The net proceeds from the offering were approximately $51.1 million, after deducting underwriting discounts, commissions, and offering expenses of approximately $0.2 million. Additionally, TransMontaigne GP L.L.C., our general partner, made a cash contribution of approximately $1.1 million to us to maintain its 2% general partner interest. The net proceeds from the offering and cash contribution were used to repay outstanding borrowings under our senior secured credit facility.

        Contractual Obligations and Contingencies.    We have contractual obligations that are required to be settled in cash. The amounts of our contractual obligations at December 31, 2009 are as follows (in thousands):

 
  Years ending December 31,  
 
  2010   2011   2012   2013   2014   Thereafter  

Additions to property, plant and equipment under contract

  $ 5,502   $   $   $   $   $  

Operating leases—property and equipment

    1,509     1,433     812     717     621     5,804  

Long-term debt

        165,000                  

Interest expense on debt(1)

    6,600     6,600                  
                           

Total contractual obligations to be settled in cash

  $ 13,611   $ 173,033   $ 812   $ 717   $ 621   $ 5,804  
                           

(1)
Assumes that our outstanding long-term debt at December 31, 2009 remains outstanding until its maturity date and we incur interest expense at 4.0%, which considers the effect of our interest rate swaps.

        Off-Balance Sheet Arrangements.    At December 31, 2009, our outstanding letters of credit were $nil.

        See Notes 2, 9, 10, 11 and 14 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 future cash expected to be provided by operating activities, available borrowing capacity under our senior secured credit facility, 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 credit facility (December 2011).

ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

        Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risk to which we are exposed is interest rate risk associated with borrowings under our senior secured credit facility. Borrowings under our senior secured credit facility bear interest at a variable rate based on LIBOR or the lender's base rate. At December 31, 2009, we had outstanding borrowings of $165.0 million under our senior secured credit facility.

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        We manage a portion of our interest rate risk with interest rate swaps, which reduce our exposure to changes in interest rates by converting variable interest rates to fixed interest rates. At December 31, 2009, we were party to an interest rate swap agreement with Wachovia Bank, N.A with a notional amount of $150.0 million that expires June 2011. Pursuant to the terms of the interest rate swap agreement, we pay a fixed rate of approximately 2.2% and receive an interest payment based on the one-month LIBOR. The net difference to be paid or received under the interest rate swap agreement is settled monthly and is recognized as an adjustment to interest expense.

        Based on the outstanding balance of our variable-interest-rate debt at December 31, 2009, the terms of our interest rate swap agreement with a notional amount of $150.0 million, and assuming market interest rates increase or decrease by 100 basis points, the potential annual increase or decrease in interest expense is approximately $0.2 million.

        We do not purchase or market products that we handle or transport and, therefore, we do not have material direct exposure to changes in commodity prices, except for the value of product gains and losses arising from certain of our terminaling services agreements with our customers. Pursuant to our terminaling services agreement related to the Southeast terminals, we agreed to rebate to Morgan Stanley Capital Group 50% of the proceeds we receive annually in excess of $4.2 million from the sale of product gains at our Southeast terminals. We do not use derivative commodity instruments to manage the commodity risk associated with the product we may own at any given time. Generally, to the extent we are entitled to retain product pursuant to terminaling services agreements with our customers, we sell the product to Morgan Stanley Capital Group and other marketing and distribution companies on a monthly basis; the sales price is based on industry indices.

        For the years ended December 31, 2009, 2008 and 2007, we sold approximately 130,000, 139,000 and 134,000 barrels, respectively, of product gained resulting from differences in the measurement of product volumes received and distributed at our terminaling facilities at average prices of $72, $97 and $78 per barrel, respectively.

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ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

        The following consolidated financial statements should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" included elsewhere in this annual report.

TransMontaigne Partners L.P. and Subsidiaries:

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Member
TransMontaigne GP L.L.C.:

        We have audited the accompanying consolidated balance sheets of TransMontaigne Partners L.P. and subsidiaries (the Partnership) as of December 31, 2009 and 2008, and the related consolidated statements of operations, partners' equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2009. These consolidated financial statements are the responsibility of TransMontaigne GP L.L.C.'s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of TransMontaigne Partners L.P. and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.

        As discussed in note 1 to the accompanying consolidated financial statements, effective January 1, 2009, the Partnership adopted Emerging Issues Task Force Issue 07-4, Application of the Two-Class Method Under FASB Statement No. 128 to Master Limited Partnerships (FASB Accounting Standards Codification 260).

        We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of TransMontaigne Partners L.P. and subsidiaries' internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 8, 2010 expressed an unqualified opinion on the effectiveness of the Partnership's internal control over financial reporting.

                        KPMG LLP

Denver, Colorado
March 8, 2010

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TransMontaigne Partners L.P. and subsidiaries

Consolidated balance sheets

(Dollars in thousands)

 
  December 31,
2009
  December 31,
2008
 

ASSETS

             

Current assets:

             
 

Cash and cash equivalents

  $ 6,568   $ 4,795  
 

Trade accounts receivable, net

    6,317     6,694  
 

Due from TransMontaigne Inc. 

        761  
 

Due from Morgan Stanley Capital Group

    2,148     5,641  
 

Other current assets

    7,706     8,870  
           
   

Total current assets

    22,739     26,761  

Property, plant and equipment, net

    459,598     447,753  

Goodwill

    24,682     24,667  

Other assets, net

    8,516     7,858  
           

  $ 515,535   $ 507,039  
           

LIABILITIES AND EQUITY

             

Current liabilities:

             
 

Trade accounts payable

  $ 11,007   $ 7,327  
 

Due to TransMontaigne Inc. 

    168      
 

Accrued liabilities

    19,235     21,814  
           
   

Total current liabilities

    30,410     29,141  

Other liabilities

    17,000     4,819  

Long-term debt

    165,000     165,500  
           
   

Total liabilities

    212,410     199,460  
           

Partners' equity:

             
 

Common unitholders (12,444,566 and 9,952,867 units issued and outstanding at December 31, 2009 and 2008, respectively)

    249,160     249,264  
 

Subordinated unitholders (nil and 2,491,699 units issued and outstanding at December 31, 2009 and 2008, respectively)

        4,449  
 

General partner interest (2% interest with 253,971 equivalent units outstanding at December 31, 2009 and 2008, respectively)

    54,434     54,450  
 

Accumulated other comprehensive loss

    (469 )   (584 )
           
   

Total partners' equity

    303,125     307,579  
           

  $ 515,535   $ 507,039  
           

See accompanying notes to consolidated financial statements.

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TransMontaigne Partners L.P. and subsidiaries

Consolidated statements of operations

(In thousands, except per unit amounts)

 
  Year ended
December 31,
2009
  Year ended
December 31,
2008
  Year ended
December 31,
2007
 

Revenue:

                   
 

External customers

  $ 49,697   $ 50,705   $ 54,711  
 

Affiliates

    92,850     87,435     76,940  
               

    142,547     138,140     131,651  

Costs and expenses:

                   
 

Direct operating costs and expenses

    (64,968 )   (61,850 )   (60,686 )
 

Direct general and administrative expenses

    (3,242 )   (4,138 )   (2,991 )
 

Allocated general and administrative expenses

    (10,040 )   (10,030 )   (9,901 )
 

Allocated insurance expense

    (2,900 )   (2,835 )   (2,837 )
 

Reimbursement of bonus awards

    (1,237 )   (1,500 )   (1,125 )
 

Depreciation and amortization

    (26,306 )   (23,316 )   (21,432 )
 

Gain on disposition of assets

    1     2      
               
   

Operating income

    33,855     34,473     32,679  
               

Other income (expenses):

                   
 

Interest income

    7     38     214  
 

Interest expense

    (5,486 )   (6,007 )   (6,515 )
 

Amortization of deferred financing costs

    (598 )   (599 )   (1,236 )
 

Unrealized loss on derivative instrument

    (562 )   (2,128 )    
 

Foreign currency transaction gain (loss)

    36     (179 )    
               
   

Total other income (expenses), net

    (6,603 )   (8,875 )   (7,537 )
               
   

Net earnings

    27,252     25,598     25,142  

Less:

                   
 

Net earnings attributable to predecessor

            (10,044 )
 

Earnings allocable to general partner interest including incentive distribution rights

    (2,451 )   (2,226 )   (757 )
               

Net earnings allocable to limited partners

  $ 24,801   $ 23,372   $ 14,341  
               

Net earnings per limited partner unit—basic

  $ 1.99   $ 1.88   $ 1.38  
               

Net earnings per limited partner unit—diluted

  $ 1.99   $ 1.88   $ 1.38  
               

Weighted average limited partner units outstanding—basic

    12,438     12,442     10,400  
               

Weighted average limited partner units outstanding—diluted

    12,441     12,442     10,401  
               

See accompanying notes to consolidated financial statements.

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TransMontaigne Partners L.P. and subsidiaries

Consolidated statements of partners' equity and comprehensive income

(Dollars in thousands)

 
  Predecessor   Common
units
  Subordinated
units
  General
partner
interest
  Accumulated
other
comprehensive
loss
  Total  

Balance December 31, 2006

  $ 167,466   $ 72,852   $ 10,427   $ (5,414 ) $   $ 245,331  
 

Proceeds from secondary offering of 5,149,800 common units, net of underwriters' discounts and offering expenses of $9,567

        179,946                 179,946  
 

Contribution of cash by TransMontaigne GP to maintain its 2% general partner interest

                3,867         3,867  
 

Contribution by TransMontaigne Inc. of capital improvements to the Brownsville and River terminals

                6,273         6,273  
 

Distributions to unitholders

        (12,712 )   (6,311 )   (656 )       (19,679 )
 

Amortization of deferred equity-based compensation related to restricted phantom units

        66                 66  
 

Repurchase of 1,680 common units by our long-term incentive plan

        (54 )               (54 )
 

Acquisition of Southeast terminals from Predecessor in exchange for $118.6 million

    (168,047 )           49,448         (118,599 )
 

Distributions and repayments, net to Predecessor

    (9,463 )                   (9,463 )
 

Net earnings for year ended December 31, 2007

    10,044     10,616     3,725     757         25,142  
                           

Balance December 31, 2007

        250,714     7,841     54,275         312,830  
 

Distributions to unitholders

        (20,636 )   (7,509 )   (2,051 )       (30,196 )
 

Amortization of deferred equity-based compensation related to restricted phantom units

        84                 84  
 

Reversal of previously recognized equity-based compensation due to repurchase of unvested restricted phantom units

        (49 )               (49 )
 

Repurchase of 4,180 common units by our long-term incentive plan

        (104 )               (104 )
 

Issuance of 1,000 common units by our long-term incentive plan due to vesting of restricted phantom units

                         
 

Conversion of 830,567 subordinated units into common units

        1,741     (1,741 )            
 

Net earnings for year ended December 31, 2008

        17,514     5,858     2,226         25,598  
 

Foreign currency translation adjustments

                    (584 )   (584 )
                                     
 

Comprehensive income

                                  25,014  
                           

Balance December 31, 2008

        249,264     4,449     54,450     (584 )   307,579  
 

Distributions to unitholders

        (24,514 )   (4,900 )   (2,467 )       (31,881 )
 

Amortization of deferred equity-based compensation related to restricted phantom units

        213                 213  
 

Repurchase of 6,885 common units by our long-term incentive plan

        (153 )               (153 )
 

Issuance of 3,000 common units by our long-term incentive plan due to vesting of restricted phantom units

                         
 

Conversion of 2,491,699 subordinated units into common units

        2,719     (2,719 )            
 

Net earnings for year ended December 31, 2009

        21,631     3,170     2,451         27,252  
 

Foreign currency translation adjustments

                    115     115  
                                     
 

Comprehensive income

                                  27,367  
                           

Balance December 31, 2009

  $   $ 249,160   $   $ 54,434   $ (469 ) $ 303,125  
                           

See accompanying notes to consolidated financial statements.

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TransMontaigne Partners L.P. and subsidiaries

Consolidated statements of cash flows

(In thousands)

 
  Year ended
December 31,
2009
  Year ended
December 31,
2008
  Year ended
December 31,
2007
 

Cash flows from operating activities:

                   

Net earnings

  $ 27,252   $ 25,598   $ 25,142  
 

Adjustments to reconcile net earnings to net cash provided by operating activities:

                   
 

Depreciation and amortization

    26,306     23,316     21,432  
 

Gain on disposition of assets

    (1 )        
 

Amortization of deferred equity-based compensation

    213     84     66  
 

Reversal of previously recognized equity-based compensation

        (49 )    
 

Amortization of deferred financing costs

    598     599     1,236  
 

Amortization of deferred revenue

    (2,461 )        
 

Amounts due under long-term terminaling services agreements, net

    (1,466 )   (1,425 )   (724 )
 

Unrealized loss on derivative instrument

    562     2,128      
 

Changes in operating assets and liabilities, net of effects from acquisitions:

                   
   

Trade accounts receivable, net

    377     (2,285 )   (2,796 )
   

Due from TransMontaigne Inc. 

    896     1,169     3,385  
   

Due from Morgan Stanley Capital Group. 

    18,069     (1,093 )    
   

Other current assets

    1,174     188     (1,772 )
   

Trade accounts payable

    3,684     4,788     (102 )
   

Accrued liabilities

    (3,158 )   470     10,539  
               
   

Net cash provided by operating activities

    72,045     53,488     56,406  
               

Cash flows from investing activities:

                   
 

Acquisition of terminal facilities, net of cash acquired

            (127,560 )
 

Additions to property, plant and equipment—expansion of facilities

    (30,245 )   (48,614 )   (18,390 )
 

Additions to property, plant and equipment—maintain existing facilities

    (7,468 )   (4,765 )   (9,600 )
 

Proceeds from sale of assets

    2          
 

Other

    (31 )   (27 )    
               
   

Net cash (used in) investing activities

    (37,742 )   (53,406 )   (155,550 )
               

Cash flows from financing activities:

                   
 

Net proceeds from issuance of common units

            179,946  
 

Contribution of cash by TransMontaigne GP

            3,867  
 

Net borrowings (payments) under credit facility

    (500 )   33,500     (57,621 )
 

Distributions paid to unitholders

    (31,881 )   (30,196 )   (19,679 )
 

Cash paid for deferred financing costs

            (1,027 )
 

Repurchase of common units by our long-term incentive plan

    (153 )   (104 )   (54 )
 

Distributions and repayments to TransMontaigne Inc., net

            (8,146 )
               
   

Net cash provided by (used in) financing activities

    (32,534 )   3,200     97,286  
               
   

Increase (decrease) in cash and cash equivalents

    1,769     3,282     (1,858 )

Foreign currency exchange effect on cash

    4     (91 )    

Cash and cash equivalents at beginning of period

    4,795     1,604     3,462  
               

Cash and cash equivalents at end of period

  $ 6,568   $ 4,795   $ 1,604  
               

Supplemental disclosures of cash flow information:

                   
 

Cash paid for interest

  $ 6,769   $ 6,092   $ 6,678  
               
 

Non-cash distributions to TransMontaigne Inc., net

  $   $   $ (1,317 )
               

See accompanying notes to consolidated financial statements.

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Notes to Consolidated Financial Statements

Years ended December 31, 2009, 2008 and 2007

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a)    Nature of business

        TransMontaigne Partners L.P. ("Partners") was formed in February 2005 as a Delaware master limited partnership initially to own and operate refined petroleum products terminaling and transportation facilities. We conduct our operations primarily in the United States along the Gulf Coast, in the Southeast, in Brownsville, Texas, along the Mississippi and Ohio rivers, and in the Midwest. We provide integrated terminaling, storage, transportation and related services for companies engaged in the distribution and marketing of refined petroleum products, crude oil, chemicals, fertilizers and other liquid products, including TransMontaigne Inc. and Morgan Stanley Capital Group Inc.

        We are controlled by our general partner, TransMontaigne GP L.L.C. ("TransMontaigne GP"), which is a wholly-owned subsidiary of TransMontaigne Inc. Effective September 1, 2006, Morgan Stanley Capital Group Inc. ("Morgan Stanley Capital Group"), a wholly-owned subsidiary of Morgan Stanley, purchased all of the issued and outstanding capital stock of TransMontaigne Inc. Morgan Stanley Capital Group is the principal commodities trading arm of Morgan Stanley. As a result of Morgan Stanley's acquisition of TransMontaigne Inc., Morgan Stanley became the indirect owner of our general partner. At February 26, 2010, TransMontaigne Inc. and Morgan Stanley have a significant interest in our partnership through their indirect ownership of a 22.1% limited partner interest, a 2% general partner interest and the incentive distribution rights.

(b)    Basis of presentation and use of estimates

        Our accounting and financial reporting policies conform to accounting principles and practices generally accepted in the United States of America. The accompanying consolidated financial statements include the accounts of TransMontaigne Partners L.P., a Delaware limited partnership, and its controlled subsidiaries. All significant inter-company accounts and transactions have been eliminated in the preparation of the accompanying consolidated financial statements.

        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 revenue and expenses during the reporting periods. The following estimates, in management's opinion, are subjective in nature, require the exercise of judgment, and involve complex analyses: allowance for doubtful accounts, accrued environmental obligations and determining the fair value of our reporting units when performing our annual goodwill impairment analysis. 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.

        The accompanying consolidated financial statements include the assets, liabilities and results of operations of certain terminal and pipeline operations prior to their acquisition by us from TransMontaigne Inc. The acquired assets and liabilities have been recorded at TransMontaigne Inc.'s carryover basis. At the closing of our initial public offering on May 27, 2005, we acquired from TransMontaigne Inc. seven Florida terminals, including terminals located in Tampa, Port Manatee, Fisher Island, Port Everglades (North), Port Everglades (South), Cape Canaveral, and Jacksonville; and the Razorback pipeline system, including the terminals located at Mt. Vernon, Missouri and Rogers, Arkansas in exchange for 120,000 common units, 2,872,266 subordinated units, a 2% general partner interest, and a cash payment of approximately $111.5 million. On January 1, 2006, we acquired from

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Notes to Consolidated Financial Statements (Continued)

Years ended December 31, 2009, 2008 and 2007

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)


TransMontaigne Inc. the Mobile, Alabama terminal in exchange for a cash payment of approximately $17.9 million. On December 29, 2006, we acquired from TransMontaigne Inc. the Brownsville, Texas terminal, 12 terminals along the Mississippi and Ohio rivers ("River terminals"), and the Baton Rouge, Louisiana dock facility in exchange for a cash payment of approximately $135 million. On December 31, 2007, we acquired from TransMontaigne Inc. twenty-two terminals along the Colonial and Plantation pipelines ("Southeast terminals") in exchange for a cash payment of approximately $118.6 million (See Note 3 of Notes to consolidated financial statements). The acquisitions of terminal and pipeline operations from TransMontaigne Inc. have been accounted for as transactions among entities under common control and, accordingly, prior periods include the activity of the acquired terminal and pipeline operations since the date they were purchased by TransMontaigne Inc. for acquisitions made by us prior to September 1, 2006, and since September 1, 2006 (the date of Morgan Stanley Capital Group's acquisition of TransMontaigne Inc.) for acquisitions made by us on or after September 1, 2006.

        The accompanying consolidated financial statements include allocated general and administrative charges from TransMontaigne Inc. for indirect corporate overhead to cover costs of functions such as legal, accounting, treasury, engineering, environmental safety, information technology, and other corporate services (see Note 2 of Notes to consolidated financial statements). The allocated general and administrative expenses were approximately $10.0 million, $10.0 million and $9.9 million for the years ended December 31, 2009, 2008 and 2007, respectively. The accompanying consolidated financial statements also include allocated insurance charges from TransMontaigne Inc. for insurance premiums to cover costs of insuring activities such as property, casualty, pollution, automobile, directors' and officers' liability, and other insurable risks. The allocated insurance charges were approximately $2.9 million, $2.8 million and $2.8 million for the years ended December 31, 2009, 2008 and 2007, respectively. Management believes that the allocated general and administrative charges and insurance charges are representative of the actual costs and expenses incurred by TransMontaigne Inc. for managing Partners' operations. The accompanying consolidated financial statements also include reimbursement of bonus awards paid to TransMontaigne Services Inc. (a wholly-owned subsidiary of TransMontaigne Inc.) towards bonus awards granted by TransMontaigne Services Inc. to certain key officers and employees that vest over future periods. The reimbursement of bonus awards was approximately $1.2 million, $1.5 million and $1.1 million for the years ended December 31, 2009, 2008 and 2007, respectively.

(c)    Accounting for terminal and pipeline operations

        In connection with our terminal and pipeline operations, we utilize the accrual method of accounting for revenue and expenses. We generate revenue in our terminal and pipeline operations from terminaling services fees, transportation fees, management fees and cost reimbursements, fees from other ancillary services and gains from the sale of refined products. Terminaling services revenue is recognized ratably over the term of the agreement for storage fees and minimum revenue commitments that are fixed at the inception of the agreement and when product is delivered to the customer for fees based on a rate per barrel throughput; transportation revenue is recognized when the product has been delivered to the customer at the specified delivery location; management fee revenue and cost reimbursements are recognized as the services are performed or as the costs are incurred; ancillary service revenue is recognized as the services are performed; and gains from the sale of refined products are recognized when the title to the product is transferred.

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Notes to Consolidated Financial Statements (Continued)

Years ended December 31, 2009, 2008 and 2007

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

(d)    Cash and cash equivalents

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

(e)    Property, plant and equipment

        Depreciation is computed using the straight-line method. Estimated useful lives are 15 to 25 years for plant, which includes buildings, storage tanks, and pipelines, and 3 to 25 years for equipment. All items of property, plant and equipment are carried at cost. Expenditures that increase capacity or extend useful lives are capitalized. Repairs and maintenance are expensed as incurred.

        We evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable based on expected undiscounted future cash flows attributable to that asset. If an asset is impaired, the impairment loss to be recognized is the excess of the carrying amount of the asset over its estimated fair value.

(f)    Environmental obligations

        We accrue for environmental costs that relate to existing conditions caused by past operations when estimable (see Note 9 of Notes to consolidated financial statements). Environmental costs include initial site surveys and environmental studies of potentially contaminated sites, costs for remediation and restoration of sites determined to be contaminated and ongoing monitoring costs, as well as fines, damages and other costs, including direct legal costs. Liabilities for environmental costs at a specific site are initially recorded, on an undiscounted basis, when it is probable that we will be liable for such costs, and a reasonable estimate of the associated costs can be made based on available information. Such an estimate includes our share of the liability for each specific site and the sharing of the amounts related to each site that will not be paid by other potentially responsible parties, based on enacted laws and adopted regulations and policies. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods. Estimates of our ultimate liabilities associated with environmental costs are difficult to make with certainty due to the number of variables involved, including the early stage of investigation at certain sites, the lengthy time frames required to complete remediation, technology changes, alternatives available and the evolving nature of environmental laws and regulations. We periodically file claims for insurance recoveries of certain environmental remediation costs with our insurance carriers under our comprehensive liability policies (see Note 5 of Notes to consolidated financial statements). We recognize our insurance recoveries as a credit to income in the period that we assess the likelihood of recovery as being probable (i.e., likely to occur).

        TransMontaigne Inc. has indemnified us through May 27, 2010 against certain potential environmental claims, losses and expenses associated with the operation of the Florida and Midwest terminal facilities and occurring before May 27, 2005, up to a maximum liability not to exceed $15.0 million for this indemnification obligation (see Note 2 of Notes to consolidated financial statements). TransMontaigne Inc. has indemnified us through December 31, 2011 against certain potential environmental claims, losses and expenses associated with the operation of the Brownsville and River terminals and occurring before December 31, 2006, up to a maximum liability not to exceed $15.0 million for this indemnification obligation (see Note 2 of Notes to consolidated financial statements). TransMontaigne Inc. has indemnified us through December 31, 2012 against certain

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Notes to Consolidated Financial Statements (Continued)

Years ended December 31, 2009, 2008 and 2007

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)


potential environmental claims, losses and expenses associated with the operation of the Southeast terminals and occurring before December 31, 2007, up to a maximum liability not to exceed $15.0 million for this indemnification obligation (see Note 2 of Notes to consolidated financial statements).

(g)    Asset retirement obligations

        Asset retirement obligations are legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development or normal use of the asset. Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" or FASB Accounting Standards Codification ("ASC") 410, "Asset Retirement and Environmental Obligations," requires that the fair value of a liability related to the retirement of long-lived assets be recorded at the time a legal obligation is incurred. Once an asset retirement obligation is identified and a liability is recorded, a corresponding asset is recorded, which is depreciated over the remaining useful life of the asset. After the initial measurement, the liability is adjusted to reflect changes in the asset retirement obligation's fair value. If and when it is determined that a legal obligation has been incurred, the fair value of any liability is determined based on estimates and assumptions related to retirement costs, future inflation rates and interest rates. Our long-lived assets consist of above-ground storage facilities and underground pipelines. We are unable to predict if and when our long-lived assets will become completely obsolete and require dismantlement. Accordingly, we have not recorded an asset retirement obligation, or corresponding asset, because the future dismantlement and removal dates of our long-lived assets, and the amount of any associated costs, are indeterminable. Changes in our estimates and assumptions may occur as a result of the passage of time and the occurrence of future events.

(h)    Equity-based compensation plan

        We account for our equity-based compensation awards pursuant to the provisions of Statement of Financial Accounting Standards No. 123 (R), "Share-Based Payment" or FASB ASC 718, "Compensation—Stock Compensation." This Statement requires us to measure the cost of 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 a board member or 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. Compensation cost is recognized over the service period on a straight-line basis.

(i)    Foreign currency translation and transactions

        The functional currency of Partners and its U.S.-based subsidiaries is the U.S. Dollar. The functional currency of our foreign subsidiaries, including Penn Octane de Mexico, S. de R.L. de C.V., Termatsal, S. de R.L. de C.V., and Tergas, S. de R.L. de C.V., is the Mexican Peso. The assets and liabilities of our foreign subsidiaries are translated at period-end rates of exchange, and revenue and expenses are translated at average exchange rates prevailing for the period. The resulting translation adjustments, net of related income taxes, are recorded as a component of other comprehensive income in partners' equity. Gains and losses from the remeasurement of foreign currency transactions (transactions denominated in a currency other than the entity's functional currency) are included in the consolidated statements of operations in other income (expenses).

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Notes to Consolidated Financial Statements (Continued)

Years ended December 31, 2009, 2008 and 2007

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

(j)    Accounting for Derivative Instruments

        We account for our derivative instruments pursuant to the provisions of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" or FASB ASC 815, "Derivatives and Hedging." This Statement requires us to recognize all derivative instruments at fair value in the consolidated balance sheet as assets or liabilities (see Note 9 of Notes to consolidated financial statements). Changes in the fair value of our derivative instruments are recognized in earnings unless specific hedge accounting criteria are met.

        At December 31, 2009 and 2008, our derivative instruments were limited to interest rate swaps. We have not designated these interest rate swaps as hedges and therefore the change in the fair value of our interest rate swaps is included in the consolidated statements of operations in other income (expenses). The fair value of our interest rate swaps is determined using a pricing model based on the LIBOR swap rate and other observable market data. The fair value was determined after considering the potential impact of collateralization, adjusted to reflect nonperformance risk of both Wachovia Bank N.A., the counterparty, and us. Our fair value measurement of our interest rate swaps utilizes Level 2 inputs.

(k)    Income taxes

        No provision for U.S. federal income taxes has been reflected in the accompanying consolidated financial statements because Partners is treated as a partnership for federal income taxes. As a partnership, all income, gains, losses, expenses, deductions and tax credits generated by Partners flow through to the unitholders of the partnership.

        Partners is a taxable entity under certain U.S. state jurisdictions. We are subject to income taxes in the state of Texas. Certain of our Mexican subsidiaries are corporations for Mexican tax purposes and, therefore, are subject to Mexican federal and provincial income taxes.

        Partners accounts for U.S. state income taxes and Mexican federal and provincial income taxes under the asset and liability method pursuant to Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" or FASB ASC 740, "Income Taxes." Currently, Mexican federal and provincial income taxes and U.S. state income taxes are not significant.

(l)    Net earnings per limited partner unit

        Emerging Issues Task Force ("EITF") Issue 07-4, "Application of the Two-Class Method Under FASB Statement No. 128 to Master Limited Partnerships" or FASB ASC 260, "Earnings Per Share," addresses the computation of earnings per limited partnership unit for master limited partnerships that consist of publicly traded common units held by limited partners, a general partner interest, and incentive distribution rights that are accounted for as equity interests. Partners' incentive distribution rights are owned by our general partner. Distributions are declared from available cash (as defined by our partnership agreement) and the incentive distribution rights are not entitled to distributions other than from available cash. The consensus states that any excess of distributions over earnings shall be allocated to the limited partners and general partner interest based on their respective sharing of losses specified in the partnership agreement. Partners has allocated the excess of distributions over earnings to the limited partners and general partner interest based on their ownership percentages of 98% and 2%, respectively. Incentive distribution rights do not share in losses under our partnership agreement.

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Notes to Consolidated Financial Statements (Continued)

Years ended December 31, 2009, 2008 and 2007

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)


The earnings allocable to the general partner interest, including the incentive distribution rights, for the period represents distributions declared after period end on behalf of the general partner interest and incentive distribution rights less the allocated excess of distributions over earnings for the period (see Note 15 of Notes to consolidated financial statements). Partners adopted the consensus reached on EITF Issue 07-4 effective January 1, 2009, and applied it retrospectively to all periods presented.

        The following is a summary of the impact of the adoption of the consensus reached on EITF Issue 07-4 on our consolidated statements of partners' equity and comprehensive income as of December 31, 2008, 2007 and 2006 (in thousands):

 
  Predecessor   Common
units
  Subordinated
units
  General
partner
interest
  Accumulated
other
comprehensive
loss
  Total  

Balance previously reported December 31, 2006

  $ 167,466   $ 72,852   $ 10,427   $ (5,414 ) $   $ 245,331  
 

Impact of adoption

                         
                           

Balance December 31, 2006

  $ 167,466   $ 72,852   $ 10,427   $ (5,414 ) $   $ 245,331  
                           

Balance previously reported December 31, 2007

  $   $ 250,351   $ 8,659   $ 53,820   $   $ 312,830  
 

Impact of adoption

        363     (818 )   455          
                           

Balance December 31, 2007

  $   $ 250,714   $ 7,841   $ 54,275   $   $ 312,830  
                           

Balance previously reported December 31, 2008

  $   $ 249,681   $ 5,779   $ 52,703   $ (584 ) $ 307,579  
 

Impact of adoption

        (417 )   (1,330 )   1,747          
                           

Balance December 31, 2008

  $   $ 249,264   $ 4,449   $ 54,450   $ (584 ) $ 307,579  
                           

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Notes to Consolidated Financial Statements (Continued)

Years ended December 31, 2009, 2008 and 2007

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

        The following is a summary of the impact of the adoption of the consensus reached on EITF Issue 07-4 on our consolidated statements of operations for the years ended December 31, 2008 and 2007 (in thousands except per unit amounts):

 
  Year ended
December 31,
2008
  Year ended
December 31,
2007
 

Earnings allocable to general partner interest including incentive distribution rights previously reported

  $ 934   $ 302  
 

Impact of adoption

    1,292     455  
           

Earnings allocable to general partner interest including incentive distribution rights

  $ 2,226   $ 757  
           

Net earnings allocable to limited partners previously reported

  $ 24,664   $ 14,796  
 

Impact of adoption

    (1,292 )   (455 )
           

Net earnings allocable to limited partners

  $ 23,372   $ 14,341  
           

Net earnings per limited partner unit—basic and diluted previously reported

  $ 1.98   $ 1.42  
 

Impact of adoption

    (0.10 )   (0.04 )
           

Net earnings per limited partner unit—basic and diluted

  $ 1.88   $ 1.38  
           

        Basic earnings per limited partner unit are computed by dividing net earnings allocable to limited partners by the weighted average number of limited partnership units outstanding during the period, excluding restricted phantom units. Diluted earnings per limited partner unit are computed by dividing net earnings allocable to limited partners by the weighted average number of limited partnership units outstanding during the period and, when dilutive, restricted phantom units. Net earnings allocable to limited partners are net of the earnings allocable to the general partner interest including incentive distribution rights.

(m)    Reclassifications

        Certain amounts in the prior periods have been reclassified to conform to the current period's presentation. Net earnings and total partners' equity and comprehensive income have not been affected by these reclassifications.

        Acquisitions of terminals from TransMontaigne Inc. during the years ended December 31, 2007 and 2006 have been recorded at carryover basis in a manner similar to a reorganization of entities under common control (see Note 3 of Notes to consolidated financial statements). The difference of approximately $50.0 million between the consideration paid to TransMontaigne Inc. and the carryover basis of the net assets acquired was previously reflected in the consolidated statements of partners' equity and comprehensive income as being attributed to the subordinated units. We are controlled by our general partner, TransMontaigne GP L.L.C., which is an indirect wholly-owned subsidiary of TransMontaigne Inc. TransMontaigne Inc.'s ownership of our general partner results in the entities being under common control. As a result, during the year ended December 31, 2008, we changed the presentation in the consolidated statements of partners' equity and comprehensive income to attribute this difference to the general partner interest. The adjustment to change the presentation is considered an immaterial correction to the accompanying consolidated balance sheets and consolidated statements of partners' equity and comprehensive income.

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Notes to Consolidated Financial Statements (Continued)

Years ended December 31, 2009, 2008 and 2007

(2) TRANSACTIONS WITH TRANSMONTAIGNE INC. AND MORGAN STANLEY CAPITAL GROUP

        Omnibus Agreement.    We have an omnibus agreement with TransMontaigne Inc. that will expire in December 2014, unless extended. Under the omnibus agreement we pay TransMontaigne Inc. an administrative fee for the provision of various general and administrative services for our benefit. Effective January 1, 2010, the annual administrative fee payable to TransMontaigne Inc. will be approximately $10.3 million. If we acquire or construct additional facilities, TransMontaigne Inc. will propose a revised administrative fee covering the provision of services for such additional facilities. If the conflicts committee of our general partner agrees to the revised administrative fee, TransMontaigne Inc. will provide services for the additional facilities pursuant to the agreement. The administrative fee includes expenses incurred by TransMontaigne Inc. to perform centralized corporate functions, such as legal, accounting, treasury, insurance administration and claims processing, health, safety and environmental, information technology, human resources, credit, payroll, taxes and engineering and other corporate services, to the extent such services are not outsourced by TransMontaigne Inc.

        The omnibus agreement further provides that we pay TransMontaigne Inc. an insurance reimbursement for premiums on insurance policies covering our facilities and operations. Effective January 1, 2010, the annual insurance reimbursement payable to TransMontaigne Inc. will be approximately $3.2 million. We also reimburse TransMontaigne Inc. for direct operating costs and expenses that TransMontaigne Inc. incurs on our behalf, such as salaries of operational personnel performing services on-site at our terminals and pipelines and the cost of their employee benefits, including 401(k) and health insurance benefits.

        We also agreed to reimburse TransMontaigne Inc. and its affiliates for a portion of the incentive payment grants to key employees of TransMontaigne Inc. and its affiliates under the TransMontaigne Services Inc. savings and retention plan, provided the compensation committee of our general partner determines that an adequate portion of the incentive payment grants are allocated to an investment fund indexed to the performance of our common units. For the year ending December 31, 2010, we have agreed to reimburse TransMontaigne Inc. and its affiliates approximately $1.25 million.

        The omnibus agreement provides us with a right of first offer to purchase all of TransMontaigne Inc.'s and its subsidiaries' right, title and interest in the Pensacola, Florida refined petroleum products terminal and any assets acquired in an asset exchange transaction that replace the Pensacola assets. This right of first offer is exercisable through December 2010.

        The omnibus agreement also provides TransMontaigne Inc. a right of first refusal to purchase our assets, provided that TransMontaigne Inc. agrees to pay no less than 105% of the purchase price offered by the third party bidder. Before we enter into any contract to sell such terminal or pipeline facilities, we must give written notice of all material terms of such proposed sale to TransMontaigne Inc. TransMontaigne Inc. will then have the sole and exclusive option, for a period of 45 days following receipt of the notice, to purchase the subject facilities for no less than 105% of the purchase price on the terms specified in the notice.

        TransMontaigne Inc. also has a right of first refusal to contract for the use of any petroleum product storage capacity that (i) is put into commercial service after January 1, 2008, or (ii) was subject to a terminaling services agreement that expires or is terminated (excluding a contract renewable solely at the option of our customer), provided that TransMontaigne Inc. agrees to pay 105% of the fees offered by the third party customer.

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Years ended December 31, 2009, 2008 and 2007

(2) TRANSACTIONS WITH TRANSMONTAIGNE INC. AND MORGAN STANLEY CAPITAL GROUP (Continued)

        Environmental Indemnification.    In connection with our acquisition of the Florida and Midwest terminals, TransMontaigne Inc. agreed to indemnify us through May 27, 2010, against certain potential environmental liabilities associated with the operation of the Florida and Midwest terminals that occurred on or prior to May 27, 2005. TransMontaigne Inc.'s maximum liability for this indemnification obligation is $15.0 million. TransMontaigne Inc. has no obligation to indemnify us for losses until such aggregate losses exceed $250,000. TransMontaigne Inc. has no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after May 27, 2005.

        In connection with our acquisition of the Brownsville and River terminals, TransMontaigne Inc. agreed to indemnify us through December 31, 2011, against certain potential environmental liabilities associated with the operation of the Brownsville and River terminals that occurred on or prior to December 31, 2006. Our environmental losses must first exceed $250,000 and TransMontaigne Inc.'s indemnification obligations are capped at $15.0 million. The cap amount does not apply to any environmental liabilities known to exist as of December 31, 2006. TransMontaigne Inc. has no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after December 31, 2006.

        In connection with our acquisition of the Southeast terminals, TransMontaigne Inc. agreed to indemnify us through December 31, 2012, against certain potential environmental liabilities associated with the operation of the Southeast terminals that occurred on or prior to December 31, 2007. Our environmental losses must first exceed $250,000 and TransMontaigne Inc.'s indemnification obligations are capped at $15.0 million. The cap amount does not apply to any environmental liabilities known to exist as of December 31, 2007. TransMontaigne Inc. has no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after December 31, 2007.

        Terminaling Services Agreement—Florida Terminals and Razorback Pipeline System.    We have a terminaling services agreement with Morgan Stanley Capital Group relating to our Florida, Mt. Vernon, Missouri and Rogers, Arkansas terminals. Effective June 1, 2008, we amended the terminaling services agreement to include renewable fuels blending functionality at the Florida Terminals. The initial term expires on May 31, 2014 for the Florida terminals and on May 31, 2012 for the Razorback pipeline system. After the initial term, the terminaling services agreement will automatically renew for subsequent one-year periods, subject to either party's right to terminate with six months' notice prior to the end of the initial term or the then current renewal term. Under this agreement, Morgan Stanley Capital Group agreed to throughput a volume of refined product that will, at the fee and tariff schedule contained in the agreement, result in minimum throughput payments to us of approximately $36.3 million for the contract year ending May 31, 2010 (approximately $36.6 million for the contract year ending May 31, 2011); with stipulated annual increases in throughput payments each contract year thereafter. Morgan Stanley Capital Group's minimum annual throughput payment is reduced proportionately for any decrease in storage capacity due to out-of-service tank capacity.

        If a force majeure event occurs that renders performance impossible with respect to an asset for at least 30 consecutive days, Morgan Stanley Capital Group's obligations would be temporarily suspended with respect to that asset. If a force majeure event continues for 30 consecutive days or more and results in a diminution in the storage capacity we make available to Morgan Stanley Capital Group,

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Years ended December 31, 2009, 2008 and 2007

(2) TRANSACTIONS WITH TRANSMONTAIGNE INC. AND MORGAN STANLEY CAPITAL GROUP (Continued)


Morgan Stanley Capital Group's minimum revenue commitment would be reduced proportionately for the duration of the force majeure event.

        Morgan Stanley Capital Group may not assign the terminaling services agreement without our consent. Upon termination of the agreement, Morgan Stanley Capital Group has a right of first refusal to enter into a new terminaling services agreement with us, provided they pay no less than 105% of the fees offered by any third party.

        Revenue Support Agreement—Oklahoma City Terminal.    We have a revenue support agreement with TransMontaigne Inc. that provides that in the event any current third-party terminaling agreement should expire, TransMontaigne Inc. agrees to enter into a terminaling services agreement that will expire no earlier than November 1, 2012. The terminaling services agreement will provide that TransMontaigne Inc. agrees to throughput such volume of refined product as may be required to guarantee minimum revenue of approximately $0.8 million per year. If TransMontaigne Inc. fails to meet its minimum revenue commitment in any year, it must pay us the amount of any shortfall within 15 business days following receipt of an invoice from us. In exchange for TransMontaigne Inc.'s minimum revenue commitment, we will agree to provide TransMontaigne Inc. approximately 153,000 barrels of light oil storage capacity at our Oklahoma City terminal. TransMontaigne Inc.'s minimum revenue commitment currently is not in effect because a major oil company is under contract through March 31, 2011, for the utilization of the light oil storage capacity at the terminal.

        Terminaling Services Agreement—Mobile Terminal.    We have a terminaling and transportation services agreement with TransMontaigne Inc. that will expire on December 31, 2012. Under this agreement, TransMontaigne Inc. agreed to throughput at our Mobile terminal a volume of refined products that will, at the fee schedule contained in the agreement, result in minimum revenue to us of approximately $2.5 million for the contract year ending December 31, 2010.

        Terminaling Services Agreement—Brownsville Terminals.    We have a terminaling and transportation services agreement with Morgan Stanley Capital Group, relating to our Brownsville, Texas terminal complex that will expire on October 31, 2010. Under this agreement, Morgan Stanley Capital Group agreed to store a specified minimum amount of fuel oils at our terminals that will result in minimum revenue to us of approximately $2.2 million per year. In exchange for its minimum revenue commitment, we agreed to provide Morgan Stanley Capital Group a minimum amount of storage capacity for such fuel oils. Effective November 1, 2009, we amended the terminaling services agreement with Morgan Stanley Capital Group to reduce Morgan Stanley Capital Group's minimum revenue commitment to approximately $1.3 million per year in exchange for Morgan Stanley Capital Group returning approximately 200,000 barrels of storage capacity.

        Terminaling Services Agreement—Brownsville LPG.    We have a terminaling and transportation services agreement with TransMontaigne Inc. relating to our Brownsville, Texas facilities that will expire on March 31, 2010. Under this agreement, TransMontaigne Inc. agreed to throughput at our Brownsville facilities certain minimum volumes of natural gas liquids that will result in minimum revenue to us of approximately $1.4 million per year. In exchange for TransMontaigne Inc.'s minimum throughput commitment, we agreed to provide TransMontaigne Inc. approximately 15,000 barrels of storage capacity at our Brownsville facilities. During 2008, we amended the terminaling and transportation services agreement with TransMontaigne Inc. to reduce TransMontaigne Inc.'s minimum

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Years ended December 31, 2009, 2008 and 2007

(2) TRANSACTIONS WITH TRANSMONTAIGNE INC. AND MORGAN STANLEY CAPITAL GROUP (Continued)


revenue commitment to approximately $0.7 million per year in exchange for entering into terminaling and transportation agreements to deliver natural gas liquids to Matamoros, Mexico. During October 2008, TransMontaigne Inc.'s minimum revenue commitment increased to approximately $1.6 million per year when we increased the LPG storage capacity at our Brownsville LPG terminal to approximately 33,000 barrels.

        Terminaling Services Agreement—Matamoros LPG.    During 2008, we entered into a terminaling and transportation services agreement with TransMontaigne Inc. relating to our natural gas liquids storage facility in Matamoros, Mexico that will expire on March 31, 2010. Under this agreement, TransMontaigne Inc. agreed to throughput a volume of natural gas liquids that will, at the fee schedule contained in the agreement, result in minimum throughput payments to us of approximately $0.6 million per year. In exchange for TransMontaigne Inc.'s minimum throughput payments, we agreed to provide TransMontaigne Inc. approximately 7,000 barrels of natural gas liquids storage capacity.

        Terminaling Services Agreement—Brownsville and River Terminals.    We have a terminaling and transportation services agreement with TransMontaigne Inc. relating to certain renewable fuels capacity at our Brownsville and River terminals that will expire on May 31, 2012. Under this agreement, TransMontaigne Inc. agreed to throughput at these terminals certain minimum volumes of renewable fuels that will, at the fee schedule contained in the agreement, result in minimum revenue to us of approximately $0.6 million per year. In exchange for TransMontaigne Inc.'s minimum throughput commitment, we agreed to provide TransMontaigne Inc. approximately 116,000 barrels of storage capacity at these terminals.

        Terminaling Services Agreement—Southeast Terminals.    We have a terminaling and transportation services agreement with Morgan Stanley Capital Group relating to our Southeast terminals. The terminaling services agreement commenced on January 1, 2008 and has a seven-year term expiring on December 31, 2014, subject to a seven-year renewal option at the election of Morgan Stanley Capital Group. Under this agreement, Morgan Stanley Capital Group agreed to throughput a volume of refined product at our Southeast terminals that will, at the fee schedule contained in the agreement, result in minimum throughput payments to us of approximately $33.1 million for the contract year ending December 31, 2010; with stipulated annual increases in throughput payments each contract year thereafter. Morgan Stanley Capital Group's minimum annual throughput payment is reduced proportionately for any decrease in storage capacity due to out-of-service tank capacity. In exchange for its minimum throughput commitment, we agreed to provide Morgan Stanley Capital Group approximately 8.7 million barrels of light oil storage capacity at our Southeast terminals. Under this agreement we also agreed to undertake certain capital projects to provide renewable fuels blending functionality at certain of our Southeast terminals with estimated completion dates that extend through December 31, 2010. Upon completion of each of the projects, Morgan Stanley Capital Group has agreed to pay us an ethanol blending fee. At December 31, 2009, we had received payments totaling approximately $17 million and we expect to receive future payments through December 31, 2010 from Morgan Stanley Capital Group in the range of $4 million to $8 million.

        If a force majeure event occurs that renders performance impossible with respect to an asset for at least 30 consecutive days, Morgan Stanley Capital Group's obligations would be temporarily suspended with respect to that asset. If a force majeure event continues for 30 consecutive days or more and results in a diminution in the storage capacity we make available to Morgan Stanley Capital Group,

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Notes to Consolidated Financial Statements (Continued)

Years ended December 31, 2009, 2008 and 2007

(2) TRANSACTIONS WITH TRANSMONTAIGNE INC. AND MORGAN STANLEY CAPITAL GROUP (Continued)


Morgan Stanley Capital Group's minimum revenue commitment would be reduced proportionately for the duration of the force majeure event.

        Morgan Stanley Capital Group may not assign the terminaling services agreement without our consent.

(3) ACQUISITIONS

        Mexican LPG Operations.    Effective December 31, 2007, we acquired from Rio Vista Energy Partners L.P. ("Rio Vista") a terminal facility in Matamoros, Mexico, the Diamondback pipeline which runs from Brownsville, Texas to Matamoros, Mexico, with associated rights of way and easements and 47 acres of land, together with a permit to distribute liquefied petroleum gas ("LPG") to Mexico's state-owned petroleum company for a cash payment of approximately $9.0 million. These LPG assets complement our existing LPG storage facilities in Brownsville, Texas. The accompanying consolidated financial statements include the assets, liabilities and results of operations of the Mexican LPG operations from December 31, 2007.

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

 
  Mexican
LPG
operations
 

Cash

  $ 15  

Trade accounts receivable

    61  

Other current assets

    75  

Property, plant and equipment

    8,892  

Goodwill

    1,502  

Other assets

    101  

Trade accounts payable

    (266 )

Other accrued liabilities

    (904 )

Due to Rio Vista

    (500 )
       
 

Cash paid

  $ 8,976  
       

        Southeast Terminals.    Effective December 31, 2007, we acquire