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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, 2012

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
(State or other jurisdiction of
incorporation or organization)
  34-2037221
(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 ý    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. ý

         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, 2012 was $368,871,028, computed by reference to the last sale price ($33.26 per common unit) of the registrant's common limited partner units on the New York Stock Exchange on June 29, 2012.

         The number of the registrant's common limited partner units outstanding on February 28, 2013 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

    4  

1A.

 

Risk Factors

    29  

1B.

 

Unresolved Staff Comments

    49  

3.

 

Legal Proceedings

    49  

4.

 

Mine Safety Disclosures

    49  

Part II

 

5.

 

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

    50  

6.

 

Selected Financial Data

    52  

7.

 

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

    54  

7A.

 

Quantitative and Qualitative Disclosures About Market Risks

    71  

8.

 

Financial Statements and Supplementary Data

    72  

9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

    109  

9A.

 

Controls and Procedures

    109  

9B.

 

Other Information

    111  

Part III

 

10.

 

Directors, Executive Officers of Our General Partner and Corporate Governance

    111  

11.

 

Executive Compensation

    118  

12.

 

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

    123  

13.

 

Certain Relationships and Related Transactions, and Director Independence

    127  

14.

 

Principal Accounting Fees and Services

    130  

Part IV

 

15.

 

Exhibits, Financial Statement Schedules

    132  

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        Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K (including exhibits), 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:

    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:

    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;

    the expiration of our material terminaling services agreements with Morgan Stanley Capital Group could result in a default under the credit facility if we are unable to secure adequate replacement agreements;

    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;

    whether we are able to generate sufficient cash from operations to enable us to maintain or grow the amount of the quarterly distribution to our unitholders;

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

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

    our ability to grow our business will be severely constrained by Morgan Stanley's determination that it will not approve any "significant" acquisition or investment that we may propose for the foreseeable future;

    changes that Morgan Stanley may make in the manner it conducts its commodities business could materially and adversely affect our business;

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

    the lack of availability of acquisition opportunities, constraints on our ability to make acquisitions, failure to successfully integrate acquired facilities and future performance of acquired facilities, could limit our ability to grow our business successfully and could adversely affect the price of our limited partnership units;

    a decrease in demand for products due to high prices, alternative fuel sources, new technologies or adverse economic conditions;

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

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

    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;

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

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

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

    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 partner's limited call right may require unitholders to sell their common units at an undesirable time or price;

    our ability to issue additional units without your approval would dilute your existing ownership interest;

    the possibility that our unitholders could be held liable under some circumstances for our obligations to the same extent as a general partner;

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

    constraints on our ability to make acquisitions and investments to increase our capital asset base may result in future declines in our tax depreciation;

    the impact of new IRS regulations or a challenge of our current allocation of income, gain, loss and deductions among our unitholders;

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    unitholders will be required to pay taxes on their respective share of our taxable income regardless of the amount of cash distributions;

    investment in common partnership units by tax-exempt entities and non-United States persons raises tax issues unique to them;

    unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our units; 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.


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. 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.

        Our general partner is TransMontaigne GP L.L.C., which is indirectly wholly owned and controlled by TransMontaigne Inc. In 2006, TransMontaigne Inc. was acquired by Morgan Stanley Capital Group, Inc., which is indirectly wholly owned and controlled by Morgan Stanley. As a result, Morgan Stanley controls our general partner. 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.

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

GRAPHIC

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

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        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. Morgan Stanley Capital Group is our largest customer by volume and revenue.

        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, which are all located in Florida. These facilities currently have approximately 6.9 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 and one crude oil terminal with approximately 1.6 million barrels of aggregate active storage capacity.

    Brownsville.  Effective as of April 1, 2011, we entered into a joint venture with P.M.I. Services North America Inc., or "PMI", an indirect subsidiary of Petroleos Mexicanos or "PEMEX", the Mexican state- owned petroleum company, at our Brownsville, Texas terminal. We contributed approximately 1.4 million barrels of light petroleum product storage capacity, as well as related ancillary facilities, to the joint venture, also known as Frontera Brownsville LLC or "Frontera", in exchange for a cash payment of approximately $25.6 million and a 50% ownership interest. We operate the Frontera assets under an operations and reimbursement agreement between us and Frontera. We continue to own and operate approximately 0.9 million barrels of additional tankage in Brownsville independent of Frontera, which includes a liquefied petroleum gas, or LPG, terminaling facility with aggregate active storage capacity of approximately 33,000 barrels. We 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. We also operate a bi-directional refined products pipeline for PMI for deliveries to and from Brownsville and Reynosa and Cadereyta, Mexico.

    River.  Our River facilities are composed of 12 refined product terminals located along the Mississippi and Ohio Rivers with approximately 2.8 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 product 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 10.0 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

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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 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, receive, store, blend, treat and distribute foreign and domestic cargoes to and from oil refineries, wholesalers, retailers and ultimate end-users around the country. The substantial majority of the petroleum refining that occurs in the United States is concentrated in the Gulf Coast region, which necessitates the transportation of this domestic product to other areas, such as the East Coast, Florida, Southeast and Midwest regions of the country. Recently, an increased amount of domestic crude oil is being extracted throughout unconventional shale formations (i.e. Bakken, Eagle Ford, Utica, etc.). These shale formations are generally located in areas that are highly constrained in storage transportation infrastructure; thereby offering the prospect of new growth and development for terminaling and transportation companies such as TransMontaigne Partners.

        Refining.    The storage and handling services of feedstocks or crude oil used in the refining process are generally handled by terminaling and transportation companies such as TransMontaigne Partners. United States based refineries refine multiple grades of feedstock or crude oil into various light refined products and heavy refined products. Light refined products include gasoline and diesel fuel, as well as propane, butane, heating oils and jet fuels. Heavy refined products include residual fuel oils for consumption in ships and power plants 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 are initially staged at the refinery, and then shipped out either in large "batches" via pipeline or vessel or by individual truck-loads. 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 into wholesale markets, it must first schedule that product for shipment by tankers, barges, railcars or on common carrier pipelines to a liquid bulk 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, primarily 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 multiple cycles of large 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.

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        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 specified location. Each truck holds an aggregate of approximately 8,000 gallons (approximately 190 barrels) of various refined products in different compartments. To initiate the loading 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 or credit 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, ethanol, bio diesel or additives are injected to conform to government specifications and individual customer requirements. As part of the Renewable Fuel Standard Act, ethanol and biodiesel are often blended with the refined product across the rack to create a certain "spec" of saleable product. Additionally, 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 stored in tanks may be delivered to tanker trucks over a rack in the same manner as at an inland terminal or be delivered onto large ships, ocean-going barges, or inland barges for delivery to various distribution points around the world. In addition, cruise ships and other vessels are fueled through a process 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 such as TransMontaigne Inc.

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 vessels or 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.

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        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 on our Razorback pipeline and Diamondback pipeline and the Ella-Brownsville pipeline, which in January 2013 we began leasing from a third party, based on the volume of product transported and the distance from the origin point to the delivery point. The Federal Energy Regulatory Commission, or FERC, regulates the tariff on the Razorback, Diamondback and Ella-Brownsville pipelines.

    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 PEMEX, 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. Effective as of April 1, 2011, we entered into the Frontera joint venture. We manage and operate Frontera and receive a management fee based on our costs incurred.

    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 certain terminaling services agreements with our throughput customers, we are entitled to the volume of net 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.

        Further detail regarding our financial information can be found under Item 8. "Financial Statements and Supplementary Data" of this annual report.

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        The locations and approximate aggregate active storage capacity at our terminal facilities as of December 31, 2012 are as follows:

Locations
  Active storage
capacity
(shell bbls)
 

Gulf Coast Facilities

       

Florida

       

Port Everglades Complex

       

Port Everglades-North

    2,487,000  

Port Everglades-South(1)

    377,000  

Jacksonville

    271,000  

Cape Canaveral

    724,000  

Port Manatee

    1,375,000  

Pensacola

    270,000  

Fisher Island

    673,000  

Tampa

    760,000  
       

Gulf Coast Total

    6,937,000  
       

Midwest Facilities

       

Rogers, AR and Mount Vernon, MO (aggregate amounts)

    406,000  

Cushing, OK

    1,005,000  

Oklahoma City, OK

    158,000  
       

Midwest Total

    1,569,000  
       

Brownsville Facilities

       

Brownsville, TX

    929,000  

Frontera(2)

    1,426,000  

Matamoros, Mexico

    7,000  
       

Brownsville Total

    2,362,000  
       

River Facilities

       

Arkansas City, AR

    608,000  

Evansville, IN

    245,000  

New Albany, IN

    176,000  

Greater Cincinnati, KY

    158,000  

Henderson, KY

    182,000  

Louisville, KY

    150,000  

Owensboro, KY

    157,000  

Paducah, KY

    322,000  

Baton Rouge, LA (Dock)

     

Greenville, MS (Clay Street)

    350,000  

Greenville, MS (Industrial Road)

    56,000  

Cape Girardeau, MO

    140,000  

East Liverpool, OH

    227,000  
       

River Total

    2,771,000  
       

       

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Locations
  Active storage
capacity
(shell bbls)
 
Southeast Facilities        

Albany, GA

    203,000  

Americus, GA

    93,000  

Athens, GA

    203,000  

Bainbridge, GA

    377,000  

Belton, SC

     

Birmingham, AL

    178,000  

Charlotte, NC

    121,000  

Collins/Purvis, MS

    3,419,000  

Collins, MS

    200,000  

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

    10,029,000  
       

TOTAL CAPACITY

    23,668,000  
       

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

(2)
Reflects the total active storage capacity of Frontera, of which we have a 50% ownership interest.

        Gulf Coast Operations.    Our Gulf Coast operations include eight refined product terminals located in Florida. 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 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. 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.

        The principal customers at our Gulf Coast facilities are Marathon Petroleum Company LLC, which we refer to as Marathon, and Morgan Stanley Capital Group. Our terminaling services agreement with Morgan Stanley Capital Group relating to our Florida operations expires May 31, 2014, unless extended by Morgan Stanley Capital Group on or before November 30, 2013. In February 2013, representatives

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of Morgan Stanley Capital Group indicated that they intend to extend or enter into new terminaling services agreements covering our Florida terminals for periods after the current agreements expire.

        Midwest Terminals and Pipeline Operations.    In Missouri and Arkansas we own and operate the Razorback pipeline and terminals in Mount Vernon, Missouri, at the origin of the pipeline and in Rogers, Arkansas, at the terminus of the pipeline. We refer to these two terminals collectively as the Razorback terminals. 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 Mount 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 Mount 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.

        In 2011, we entered into agreements for the construction and operation of approximately 1.0 million barrels of crude oil storage in Cushing, Oklahoma. Pursuant to such agreements, we leased a portion of land in Cushing, Oklahoma and constructed storage tanks and associated infrastructure on that property for the receipt of crude oil by truck and pipeline, the blending of crude oil and the storage of approximately 1.0 million barrels of crude oil. The facility was completed and placed into service in August 2012. We have entered into a long-term services agreement with Morgan Stanley Capital Group Inc. for the use of the facility.

        Brownsville, Texas Operations.    Effective as of April 1, 2011, we entered into the Frontera joint venture with PMI at our Brownsville, Texas terminal. We contributed approximately 1.4 million barrels of light petroleum product storage capacity, as well as related ancillary facilities, to the Frontera joint venture, in exchange for a cash payment of approximately $25.6 million and a 50% ownership interest. PMI acquired the remaining 50% ownership interest in Frontera for a cash payment of approximately $25.6 million. We operate the Frontera assets under an operations and reimbursement agreement between us and Frontera.

        We continue to own and operate approximately 0.9 million barrels of additional tankage and related ancillary facilities in Brownsville independent of the Frontera joint venture, as well as the Diamondback pipeline which handles liquid product movements between Mexico and south Texas. At our Brownsville terminal we handle refined petroleum products, chemicals, vegetable oils, naphtha, wax and propane on behalf of, and provide integrated terminaling services to, customers 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 20,000 barrels per day. The 6" pipeline has a capacity of approximately 12,000 barrels per day.

        Beginning in January 2013, we leased the capacity on the Ella-Brownsville pipeline from Seadrift Pipeline Corporation, which transports LPG from two points of origin to our terminal in Brownsville: from Exxon King Ranch in Kleberg County, Texas 121 miles to Brownsville and an additional 11 miles

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beginning near the Exxon King Ranch terminus to the DCP LaGloria Gas Plant in Jim Wells County, Texas.

        We also operate and maintain the United States portion of a 174-mile bi-directional refined products pipeline owned by PMI. 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 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.

        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. 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. Our terminaling services agreement with Valero for approximately 1.1 million barrels of tankage capacity in our River facilities (out of approximately 23.7 million barrels of active storage capacity across our entire system) will expire on March 31, 2013. Valero has indicated an interest in contracting for only a portion of its current capacity in our River facilities after its current terminaling services agreement expires. At this time we are negotiating a new terminaling services agreement with Valero for certain capacity at the terminals covered under the existing terminaling services agreement. We are also in discussions with prospective new and existing customers to engage our services for the terminal capacity that will become available when the Valero agreement expires.

        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. 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 customer at our Southeast facilities is Morgan Stanley Capital Group. Our terminaling services agreement with Morgan Stanley Capital Group relating to our Southeast operations expires December 31, 2014, unless extended by Morgan Stanley Capital Group on or before December 31, 2013. In February 2013, representatives of Morgan Stanley Capital Group indicated that they intend to extend or enter into new terminaling services agreements covering the Southeast terminals for periods after the current agreements expire.

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

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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, Diamondback and Ella-Brownsville pipelines. We have terminaling services agreements with, among others, Marathon, Morgan Stanley Capital Group, PMI Trading Limited, TransMontaigne Inc. and Valero.

        Execute cost-effective expansion and asset enhancement opportunities.    We continually evaluate opportunities to expand our existing asset base. For example, in August 2012 we completed the construction of 1.0 million barrels of crude oil storage tankage in Cushing, Oklahoma.

        Pursue strategic and accretive acquisitions in new and existing markets.    Historically, our growth strategy has included the pursuit of acquisitions of energy-related terminaling and transportation facilities, including facilities that may be outside our existing areas of operation, which we expected to pursue jointly with TransMontaigne Inc. and Morgan Stanley Capital Group. In December 2012, we acquired a 42.5% ownership interest in Battleground Oil Specialty Terminal Company LLC, or BOSTCO, from a subsidiary of Kinder Morgan Energy Partners, L.P., or Kinder Morgan. BOSTCO is developing a new black oil terminal facility on the Houston Ship Channel for handling residual fuel, feedstocks, distillates and other black oils. The initial phase of the BOSTCO terminal project involves construction of 50 storage tanks with approximately 6.1 million barrels of storage capacity at an estimated cost of approximately $425 million. Although the recent industry trend of large energy companies divesting their distribution and logistic assets has continued, our ability to pursue strategic acquisitions will be constrained because Morgan Stanley does not expect to approve any "significant" acquisition or investment that we may propose for the foreseeable future. We are currently unable to predict how the impact of this decision will affect Morgan Stanley's commodities business or the growth or development of our business and results of operations.

        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, 2013, 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, 2013. Of this firmly committed revenue, approximately 88% was generated under terminaling services agreements with remaining terms of at least one year at December 31, 2012. 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 ancillary services 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.

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        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.

        We will continue to seek cost-effective 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, to the extent Morgan Stanley approves any such expansions. In December 2012, we acquired a 42.5% ownership interest in BOSTCO, which is developing a new black oil terminal facility on the Houston Ship Channel for handling residual fuel, feedstocks, distillates and other black oils. The initial phase of the BOSTCO terminal project involves construction of 50 storage tanks with approximately 6.1 million barrels of storage capacity at an estimated cost of approximately $425 million. The BOSTCO facility's docks will benefit from one of the deepest vessel drafts and nearest access points in the Houston Ship Channel and will be well positioned to capitalize on increasing exports of petroleum related products. In addition, in August 2012, we completed a project for the construction and operation of approximately 1.0 million barrels of crude oil storage in Cushing, Oklahoma.

        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.    Eight 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.    The members of our general partner's management team have established long-standing relationships within the energy industry and significant experience with regard to the implementation of operating and growth strategies in many facets of the energy industry, including:

    crude oil marketing and transportation;

    renewable fuels, including ethanol, 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.

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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, Phillips 66, 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 L.L.C., Motiva Enterprises LLC, Murphy Oil Corporation, NuStar Energy L.P., Sunoco, Inc. and its affiliate Sunoco Logistics Partners L.P., and 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 and Southeast facilities
TransMontaigne Inc   Gulf Coast facilities
Valero Marketing and Supply Company   River facilities
Marathon Petroleum Company LLC   Gulf Coast facilities
United States Government   Southeast 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, in the aggregate, we earned revenues of $100.1 million for the year ended December 31, 2012, which represented approximately 64% of our total revenues during 2012. The substantial majority of our terminaling services with Morgan Stanley Capital Group and TransMontaigne Inc. will expire between May and December 2014, unless extended. In February 2013, representatives of Morgan Stanley Capital Group indicated that they intend to extend or enter into new terminaling services agreements covering our Florida and the Razorback terminals and the Southeast terminals for periods after the current agreements expire. As described below under "Risk Factors," if we are not successful in negotiating acceptable terms with Morgan Stanley and do not timely replace such revenues, or if we must incur substantial costs to replace such revenues, our financial condition and results of operations could be materially adversely affected.

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        We are controlled by our general partner, TransMontaigne GP L.L.C., which is an indirect wholly owned subsidiary of TransMontaigne Inc., which 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, Northeast, Southeast and Midwest regions. TransMontaigne Inc. also owns a 100% interest in TransMontaigne Canada Holdings, Inc., a Canadian petroleum marketing and terminaling company. As of December 31, 2012, TransMontaigne Inc. owned three refined product terminals; one dry bulk product terminal; three railcar facilities; 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 21.6% 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, 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.

        Omnibus Agreement.    On May 27, 2005, we entered into an omnibus agreement with TransMontaigne Inc. and our general partner, which agreement was amended and restated on December 31, 2007. The omnibus agreement, as amended and restated, addresses the following matters:

    our obligation to pay TransMontaigne Inc. an annual administrative fee, in the amount of approximately $10.8 million for the year ended December 31, 2012;

    our obligation to pay TransMontaigne Inc. an annual insurance reimbursement, in the amount of approximately $3.6 million for the year ended December 31, 2012;

    our obligation to pay TransMontaigne Inc. an annual reimbursement fee in an amount no less than $1.5 million for grants to key employees of TransMontaigne Inc. and its affiliates under the TransMontaigne Services Inc. savings and retention plan, provided that (i) no less than $1.5 million of the aggregate amount of such awards granted to key employees of TransMontaigne Inc. and its affiliates will be allocated to an investment fund indexed to the performance of our common units, and (ii) the proposed allocations of such awards among the key employees of TransMontaigne Inc. and its affiliates are approved by the compensation committee of our general partner;

    TransMontaigne Inc.'s right of first refusal to purchase any assets that we propose to sell; and

    TransMontaigne Inc.'s right of first refusal to contract for any storage capacity that becomes available after January 1, 2008.

        Any or all of the provisions of the omnibus agreement are terminable by TransMontaigne Inc. at its option if our general partner is removed without cause and units held by our general partner and its affiliates are not voted in favor of that removal.

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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, Mount 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 of the agreement expires on May 31, 2014. After May 31, 2014, 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 May 31, 2014 or the then-current renewal term. Under this agreement, Morgan Stanley Capital Group agreed to throughput a volume of refined product that, at the fee and tariff schedule contained in the agreement, resulted in minimum throughput payments to us of approximately $37 million for the contract year ended May 31, 2012 (approximately $37.3 million for the contract year ending May 31, 2013 and approximately $37.6 million for the contract year ending May 31, 2014); with stipulated annual increases in throughput payments each contract year thereafter. Additionally, during the year ended December 31, 2012, we derived revenues of approximately $9.2 million from the proceeds of sales of product gains, ethanol blending and other ancillary services under this agreement. 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 us unable to perform our obligations with respect to an asset, 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 may terminate its obligations with respect to the asset affected by the force majeure event and their minimum revenue commitment would be reduced proportionately for the duration of the agreement.

        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 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, at the fee schedule contained in the agreement, resulted in minimum throughput payments to us of approximately $35.4 million for the contract year ended December 31, 2012 (approximately $36.0 million for the contract year ending December 31, 2013 and approximately $36.8 million for the contract year ending December 31, 2014); with stipulated annual increases in throughput payments each contract year thereafter. Additionally, during the year ended December 31, 2012, we derived revenues of approximately $12.8 million from the proceeds of sales of product gains, ethanol blending and other ancillary services under this agreement. 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 8.9 million barrels of light oil storage capacity at our Southeast terminals and to undertake certain capital projects to provide ethanol blending functionality at certain of our Southeast terminals with completion dates that extended through August 31, 2011. Upon the completion of each of the projects, Morgan Stanley Capital Group paid us an ethanol blending fee that in total equaled approximately $22.5 million.

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        If a force majeure event occurs that renders us unable to perform our obligations with respect to an asset, 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 may terminate its obligations with respect to the asset affected by the force majeure event and their minimum revenue commitment would be reduced proportionately for the duration of the agreement.

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

        Collins/Purvis 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 in July 2018, subject to one-year automatic renewals unless terminated by either party upon 180 days prior notice. 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. These capital projects were completed and placed into service in July 2011. Under this agreement, Morgan Stanley Capital Group has 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 of July 2011 for the aforementioned capital projects, and for each contract year thereafter.

        If a force majeure event occurs that renders us unable to perform our obligations with respect to an asset, 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 may terminate its obligations with respect to the asset affected by the force majeure event and their minimum revenue commitment would be reduced proportionately for the duration of the agreement.

        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.

        Midwest (Cushing) Terminaling Services Agreement—Morgan Stanley Capital Group.    In July 2011, we entered into a terminaling services agreement with Morgan Stanley Capital Group relating to our Cushing, Oklahoma facility that will expire in July 2019, subject to a five-year automatic renewal unless terminated by either party upon 180 days prior notice. In exchange for its minimum revenue commitment, we agreed to construct storage tanks and associated infrastructure to provide 1.0 million barrels of crude oil capacity. These capital projects were completed and placed into service on August 1, 2012. Under this agreement, Morgan Stanley Capital Group agreed to throughput a volume of crude oil products at our terminal that will, at the fee schedule contained in the agreement, result in minimum throughput payments to us of approximately $4.3 million for each one-year period following the in-service date of August 1, 2012.

        If a force majeure event occurs that renders us unable to perform our obligations with respect to an asset, Morgan Stanley Capital Group's obligations would be temporarily suspended with respect to that asset. If a force majeure event continues for 120 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 may terminate its obligations with respect to the asset affected by the force majeure event and their minimum revenue commitment would be reduced proportionately for the duration of the agreement.

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        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 Cushing 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, 2017. 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 (Fisher Island) Terminaling Services Agreement—TransMontaigne Inc.    We have a terminaling services agreement with TransMontaigne Inc. that will expire on December 31, 2013. Under this agreement, TransMontaigne Inc. agreed to throughput at our Fisher Island terminal in the Gulf Coast region a volume of fuel oils that, at the fee schedule contained in the agreement, resulted in minimum revenue to us of approximately $1.8 million for the contract year ended December 31, 2012. In exchange for its minimum throughput commitment, we agreed to provide TransMontaigne Inc. with approximately 185,000 barrels of fuel oil capacity.

        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 April 30, 2016. Under the terms of the terminaling services agreement, we are prohibited 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 March 31, 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. Valero has indicated an interest in contracting for only a portion of its current capacity in our River facilities after its current terminaling services agreement expires. We are currently negotiating a new terminaling services agreement with Valero for certain capacity at the terminals covered under the existing terminaling services agreement. We are also in discussions with prospective new and existing customers to engage our services for the terminal capacity that will become available when the Valero agreement expires.

        Brownsville LPG Terminaling Services Agreement—TransMontaigne Inc.    We had a terminaling and transportation services agreement with TransMontaigne Inc. relating to our Brownsville, Texas facilities that terminated on December 31, 2012. The storage capacity under this agreement was placed under contract with a third party on January 1, 2013. Under this agreement, TransMontaigne Inc. agreed to throughput at our Brownsville facilities certain minimum volumes of natural gas liquids that resulted in minimum revenue to us of approximately $1.3 million for the contract year ended December 31, 2012. In exchange for TransMontaigne Inc.'s minimum throughput commitment, we agreed to provide TransMontaigne Inc. approximately 33,000 barrels of storage capacity at our Brownsville facilities.

        Uncertainty Relating to Certain Terminaling Relationships.    If the changing regulatory environment applicable to Morgan Stanley's or TransMontaigne Inc.'s commodities business were to result in changes to the manner in which they operate, such that they would be unable to renew our terminaling services agreements or utilize our terminals and facilities at current levels, we would need to seek new

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or expanded terminaling relationships with new customers or our other existing customers. We cannot be certain that we would be able to replace all of the revenues generated from the capacity currently used by Morgan Stanley Capital Group and TransMontaigne Inc. at or prior to the termination of our current agreements.

        Other Terminaling Services Agreements.    We have additional 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, which we negotiate on a case-by-case basis.

Operations and Reimbursement Agreement—Frontera

        Effective as of April 1, 2011, we entered into the Frontera joint venture in which we have a 50% ownership interest (see Note 3 of Notes to consolidated financial statements). In conjunction with us entering into the joint venture, we agreed to operate Frontera, in accordance with an operations and reimbursement agreement executed between us and Frontera, for a management fee that is based on our costs incurred. Our agreement with Frontera stipulates that we may resign as the operator at any time with the prior written consent of Frontera, or that we may be removed as the operator for good cause, which includes material noncompliance with laws and material failure to adhere to good industry practice regarding health, safety or environmental matters. For the year ended December 31, 2012, we recognized approximately $3.4 million of revenue related to this operations and reimbursement agreement.

Terminals and Pipeline Control Operations

        The pipelines we own or operate are operated via geosynchronous satellite, wireless, 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 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 67-mile Razorback pipeline; a 37-mile pipeline, known as the "Pinebelt pipeline," located in Covington County, Mississippi that transports refined

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petroleum liquids between our Collins and Collins/Purvis terminal facilities; a 1-mile diesel fuel pipeline, known as the Bellemeade pipeline, owned by and operated for Dominion 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 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 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 and Hazardous Materials Safety Administration, or PHMSA, 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 PHMSA regulations.

        We also are subject to PHMSA 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

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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.

        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 cleanup 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

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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 potential 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.

        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

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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 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. 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

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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) or remediate contaminated property (including groundwater contamination, whether from prior owners or operators or other historic activities or spills).

        Under an indemnification agreement, which contains the indemnification terms previously set forth in the omnibus agreement, TransMontaigne Inc. agreed to indemnify us against potential environmental claims, losses and expenses that were identified on or before May 27, 2010 and that were associated with the ownership or operation of the Florida and Midwest terminals prior to 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. TransMontaigne Inc. estimates that the total cost for remediating the contamination at the Florida terminals will be between approximately $3.5 million and approximately $5.6 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 approximately $0.6 million.

        Under the purchase agreement for the Brownsville, Texas and River facilities, TransMontaigne Inc. agreed to indemnify us against potential environmental claims, losses and expenses that were identified on or before December 31, 2011 and that were associated with the ownership or operation of the Brownsville and River facilities 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 deductible amount, cap amount and time limitation for indemnification do 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. TransMontaigne Inc. believes that its total remediation liability, net of probable reimbursements, for the Brownsville and River facilities will be between approximately $0.3 million and approximately $0.8 million.

        Under the purchase agreement for the Southeast facilities, TransMontaigne Inc. has agreed to indemnify us against potential environmental claims, losses and expenses that were identified on or before December 31, 2012 and that were associated with the ownership or operation of the Southeast terminals 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 deductible amount, cap amount and time limitation for indemnification do 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. TransMontaigne Inc. believes its total remediation liability for the Southeast facilities will be between approximately $1.3 million and approximately $2.3 million.

        Under the purchase agreement for the Pensacola, Florida terminal, TransMontaigne Inc. agreed to indemnify us against potential environmental claims, losses and expenses that are identified on or before March 1, 2016, and that were associated with the ownership or operation of the Pensacola terminal prior to March 1, 2011. Our environmental losses must first exceed $200,000 and TransMontaigne Inc.'s indemnification obligations are capped at $2.5 million. The deductible amount, cap amount and limitation of time for indemnification do not apply to any environmental liabilities

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known to exist as of March 1, 2011. 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 March 1, 2011.

        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.

        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 Mount Vernon, Missouri and Rogers, Arkansas, the Diamondback pipeline, which runs between Brownsville, Texas and Matamoros, Mexico, and the Ella-Brownsville pipeline, which runs from two points of origin in Texas to our Brownsville terminal, 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, Diamondback and Ella-Brownsville 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, and a 2.65 percent adjustment for the five-year period beginning July 1, 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 oil pipeline 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

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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 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 FERC's regulations governing oil pipeline ratemaking would have any negative material monetary impact on us unless the regulations were substantially modified in such a manner so as to effectively 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 affect the Razorback and Diamondback pipelines' ability 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 and are involved in a lawsuit with one landowner to resolve a right-of-way dispute. 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 cleanup 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 28, 2013, TransMontaigne Services Inc. had approximately 586 employees, of whom 319 provide services directly to us. As of February 28, 2013, 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.

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Risks Inherent in Our Business

         We depend upon Morgan Stanley Capital Group for a substantial majority of our revenue and have a small number of other significant customers. Several of our terminaling services agreements with Morgan Stanley Capital Group will terminate on or before December 31, 2014, unless extended. We would suffer a significant reduction of revenue, which could materially adversely affect our financial condition and results of operations, if our significant customers do not continue to engage us to provide services after the expiration of existing terminaling services agreements and we are not able to timely secure comparable alternative customer arrangements. In addition, our ability to maintain cash distributions at current levels could be materially adversely affected.

        We derive a substantial majority of our revenue from a small number of significant customers, some of whose agreements with us expire in 2013 and 2014. For example, our terminaling services agreement with Morgan Stanley Capital Group relating to our Florida terminals and the Razorback terminals expires in May of 2014, unless extended prior to November 30, 2013. This agreement provides for minimum throughput payments of approximately $37.3 million for the contract year ending May 31, 2013 and approximately $37.6 million for the contract year ending May 31, 2014. Similarly, our terminaling services agreement with Morgan Stanley Capital Group relating to our Southeast terminals expires at the end of 2014, unless extended prior to December 31, 2013, and provides for minimum throughput payments of approximately $36.0 million for the contract year ending December 31, 2013 and approximately $36.8 million for the contract year ending December 31, 2014. Additionally, during the year ended December 31, 2012, we derived revenues of approximately $13.6 million from the proceeds of sales of product gains and approximately $8.4 million in fees for ethanol blending and other services under these agreements with Morgan Stanley Capital Group. In the aggregate, these agreements accounted for 60.3% of our revenue for the year ended December 31, 2012.

        In February 2013, representatives of Morgan Stanley Capital Group indicated that they intend to extend or enter into new terminaling services agreements covering our Florida and the Razorback terminals and the Southeast terminals for periods after the current agreements expire. However, if we are not able to reach acceptable terms with respect to such terminaling services agreements, our revenues would be significantly reduced unless we are able to timely replace the expiring terminaling services agreements with new or expanded terminaling relationships with new customers or our other existing customers. Even if we are successful in entering into new agreements for such storage and transportation capacity, we cannot be certain that the new agreements will be effective at or prior to the expiration of our current agreements or that the terms of any new terminaling services agreements may be less favorable than the terms of our current agreements with Morgan Stanley Capital Group. In either case, our revenues would decline and our financial condition and results of operations could be materially adversely affected. A decline in our revenues and results of operations could adversely affect our ability to maintain cash distributions at current levels.

         Morgan Stanley Capital Group, which is our largest customer and controls our general partner, is owned by Morgan Stanley. Morgan Stanley is a bank holding company under applicable federal banking law and regulations, which impose limitations on Morgan Stanley's ability to conduct certain nonbanking activities, or to retain or make certain investments. If the Board of Governors of the Federal Reserve System determines that certain of Morgan Stanley's activities or investments are not permissible, or if legislative and regulatory developments cause Morgan Stanley to change its business strategy as it relates to our activities and investments, 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.

        Our general partner is an indirect wholly-owned subsidiary of Morgan Stanley Capital Group Inc., which, in turn, is a wholly-owned subsidiary of Morgan Stanley. Morgan Stanley is a "bank holding company," due to its ownership of Morgan Stanley Bank, N.A., subject to consolidated supervision and regulation by the Board of Governors of the Federal Reserve System, or "FRB", under the Bank

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Holding Company Act, or "BHC Act". Morgan Stanley qualifies as a bank holding company that is a "financial holding company."

        As a financial holding company, Morgan Stanley will generally be able to engage in any activity that is financial in nature, incidental to a financial activity or complementary to a financial activity in conformance with the BHC Act. Under certain circumstances and with the approval of the Board of Governors of the FRB, any company that becomes a bank holding company may have up to five years to conform its existing activities and investments to the BHC Act. When a company becomes a financial holding company, the BHC Act grandfathers "activities related to the trading, sale or investment in commodities and underlying physical properties," provided that the financial holding company conducted any such type of activities as of September 30, 1997 and provided that certain other conditions are satisfied. 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.

        In 2009, Morgan Stanley advised us that its internal review reached the conclusion that all of our activities and investments are permissible under the BHC Act. To the extent that 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.

        Upon becoming a financial holding company in 2008, 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. We are currently unable to predict whether becoming subject to the consolidated supervision and regulation affecting Morgan Stanley as a financial holding company will have a material impact on us, or what any such impact may be.

        In addition, on July 21, 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act, or Dodd-Frank Act, was enacted. The Dodd-Frank Act contains various provisions that, among other things, affect financial firms, including financial holding companies, and amend various Bank Holding Company Act provisions that affect the restrictions and prohibitions on the activities and investments of financial holding companies. The FRB and other regulatory agencies are required to issue regulations that carry out the intent of the Dodd-Frank Act's provisions. Although many new regulations remain to be written and adopted to implement the Dodd-Frank Act, including the proposed "Volcker Rule," Morgan Stanley has informed us that, based upon its internal review, Morgan Stanley has not yet identified any provision under the Dodd-Frank Act nor the regulations adopted or to be adopted thereunder that would appear to change its conclusion at this time that all of our activities and investments are permissible under the BHC Act.

        We are currently unable to predict whether Morgan Stanley's becoming subject to the consolidated supervision and regulation 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, including whether Morgan Stanley's business strategy with respect to our activities or investments would be affected. We are therefore unable to predict whether Morgan Stanley will cause us to discontinue any such activities or investments, or whether Morgan Stanley will 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 taken, 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

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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.

         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 and expenses, 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 amended and restated senior secured credit facility. As a result, we may not be able to maintain or grow our quarterly distribution to our unitholders.

         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. Moreover, the expiration of our terminaling services agreements with Morgan Stanley Capital Group could result in a default under the credit facility if we are unable to secure adequate replacement agreements prior to the time our agreements with Morgan Stanley Capital Group expire. A default under our credit facility would materially 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., 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.

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        We have various credit terms with virtually all of our customers, and our customers have varying degrees of creditworthiness. Although we evaluate the creditworthiness of each of our customers, we may not always be able to fully anticipate or detect deterioration in their creditworthiness and overall financial condition, which could expose us 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.

        Under the current terms of our senior secured bank credit facility, our terminaling service agreements with Morgan Stanley Capital Group relating to our Florida and Southeast terminals are deemed to be "Specified Contracts." The credit facility further provides that an event of default will occur if any Specified Contract terminates in whole or in part, "if such ... termination would reasonably be expected to result in a Material Adverse Effect after taking into account any replacement therefor." In February 2013, representatives of Morgan Stanley Capital Group indicated that they intend to extend or enter into new terminaling services agreements covering our Florida and the Razorback terminals and the Southeast terminals for periods after the current agreements expire. However, if these terminaling services agreements with Morgan Stanley Capital Group expire and, at that time, we have not secured sufficient replacement customer agreements to replace the majority of the revenues provided for under the expired agreements, an event of default could occur under our bank credit facility. The existence of a default under the bank credit facility would prevent us from borrowing any additional funds under the bank credit facility and could result in the banks becoming entitled to foreclose on their liens, which cover substantially all of our assets. Thus, a default under our bank credit facility could materially adversely affect our financial condition and results of operations.

         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 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. Force majeure events include, but are not limited to, wars, acts of enemies, embargoes, import or export restrictions, strikes, lockouts, acts of nature, including fires, storms, floods, hurricanes, explosions and mechanical or physical failures

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of our equipment or facilities or those of third parties. In the event of a force majeure, 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.

         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, approved capital projects and future expansion, development and acquisition opportunities. Our amended and restated senior secured credit facility provides for a maximum borrowing line of credit equal to $350 million. At December 31, 2012, our outstanding borrowings were $184 million. At December 31, 2012, we have approved additional investments in BOSTCO and expansion capital projects that currently are or will be under construction with estimated completion dates that extend through the first quarter of 2014. At December 31, 2012, the remaining capital expenditures to complete the approved additional investments and expansion capital projects are estimated to be approximately $105 million. We expect to fund our future investments and expansion capital expenditures with additional borrowings under our credit facility. If we cannot obtain adequate financing to complete the approved investments and 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.

        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. Limitations on our access to capital, including on our ability to issue additional debt and equity, could result from events or causes beyond our control, and could include, among other factors, significant increases in interest rates, increases in the risk premium required by investors, generally or for investments in energy-related companies or master limited partnerships, decreases in the availability of credit or the tightening of terms required by lenders. 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 has informed us that, for the foreseeable future, it does not expect to approve any "significant" acquisition or investment that we may propose, which will severely constrain or curtail our ability to grow our business and could reduce the potential for increasing distributions on our common units, could adversely affect the tax characteristics of an investment in our units for some of our unitholders and could cause the market price of our units to decline.

        Morgan Stanley, which indirectly controls our general partner, informed us in October 2011 that, for the foreseeable future, it does not expect to approve any "significant" acquisition or investment that we may propose. Morgan Stanley indicated that it has not established a specific definition of what constitutes a "significant" investment and significance may be determined on either a quantitative or qualitative basis, depending on the facts and circumstances and relevant legal and regulatory considerations. Morgan Stanley has informed us they will review on a case by case basis each proposed transaction to determine its significance, whether an acquisition of, or investment in, assets or legal entities and that an acquisition of, or investment in, a noncontrolling interest or joint venture interest may be "significant" without respect to the size of the transaction. The practical effect of these limitations is to significantly constrain our ability to expand our asset base and operations through

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acquisitions from third parties. These constraints will reduce the potential for increasing our distributions to unitholders in the future. In addition, these constraints will limit additions to our capital assets primarily to additions and improvements that we construct or add to our existing facilities, although some acquisitions of assets from third parties may be possible to the extent approved by Morgan Stanley. As a result, we may not be able to add to our capital asset base quickly enough to prevent our tax depreciation from declining in the future, which could adversely affect the tax characteristics of an investment in our units for some of our unit holders as discussed under "Tax Risks," below, and could cause the market price of our units to decline. Our December 2012 investment in BOSTCO was approved by Morgan Stanley based on the specific facts and circumstances of the BOSTCO project and the structure of our investment in BOSTCO, and is not indicative of whether Morgan Stanley will approve any other acquisition or investment that we may propose in the future.

        Morgan Stanley's decision regarding limitations on its approval of acquisitions or investments that we may propose is the result of the uncertain regulatory environment relating to Morgan Stanley's status as a financial holding company subject to the Bank Holding Company Act, or BHC Act, as amended by the Dodd-Frank Act, and consolidated supervision by the Board of Governors of the Federal Reserve System, or FRB, including uncertainty surrounding the application of regulations under the BHC Act affecting the acquisition and ownership of non-financial business activities. In particular, as a result of the Dodd-Frank Act (including the proposed Volcker Rule), Morgan Stanley is subject to significantly revised and expanded regulation and supervision, to more intensive scrutiny of its businesses and any plans for expansion of those businesses and to limitations on engaging in new business activities which, in turn, affect TransMontaigne Partners by virtue of Morgan Stanley having control of our business activities through its indirect ownership of our general partner. The Dodd-Frank Act and the mandates it includes for further regulatory actions are part of a trend to increase regulatory supervision of the financial industry. As a result of this trend, including further legislative or regulatory changes, Morgan Stanley's ability to own and operate our general partner or its business strategies with respect to operating our general partner and TransMontaigne Partners may change significantly in ways that we cannot currently predict with certainty. We are currently unable to predict how the impact of Morgan Stanley's decision and such regulatory developments will affect Morgan Stanley's commodities business or the growth or development of our business and results of operations. A sustained, material decrease in our ability to pursue opportunities for future growth could materially adversely affect the market price of our common units.

         Together, Morgan Stanley Capital Group and TransMontaigne Inc. is our largest customer and we receive a substantial majority of our revenue from them. Material changes to Morgan Stanley's commodities business, if any, as a result of the changing regulatory environment may have a material adverse impact on our business.

        Together, Morgan Stanley Capital Group and TransMontaigne Inc. is our largest customer and we receive a substantial majority of our revenue from them. As noted above, we and our general partner are subject to and affected by significantly revised and expanded regulation and supervision, and there is considerable uncertainty in this regulatory environment, including the interpretation of the Volcker Rule, as proposed in October 2011 and for which the comment period ended on February 13, 2012. We are unable to predict what the final version of the Volcker Rule will be or the impact it may have on Morgan Stanley's business, including its commodities business. Material changes to Morgan Stanley's commodities business, if any, resulting from the changing regulatory environment may have a material adverse impact on our business, financial condition and results of operations.

        Although we cannot predict whether such circumstances will result in any material changes to Morgan Stanley's commodities business, if any such changes occur, they may have a material adverse impact on our business. For example, if Morgan Stanley Capital Group's or TransMontaigne Inc.'s

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commodities business were to change as a result of the changing regulatory environment such that they would be unable to renew our terminaling services agreements or utilize our terminals and facilities at current levels, we would need to seek new or expanded terminaling relationships with new customers or our other existing customers. We cannot be certain that we would be able to replace all of the revenues on account of capacity currently used by Morgan Stanley Capital Group and TransMontaigne Inc. at or prior to the termination of our current agreements. In addition, depending on market and other conditions, we may have to accept agreements with new customers on terms that are less favorable to us than the terms of our current agreements with Morgan Stanley Capital Group and TransMontaigne Inc. Additionally, we may incur costs for modifications to our terminals required by new customers. Any of these factors may adversely affect our ability to generate sufficient additional revenue and income to replace all of the revenue and income we earn under our current agreements, which may materially adversely affect our financial condition and results of operations.

         If we do not make acquisitions or make acquisitions on economically acceptable terms, any future growth of our business will be limited and the price of our limited partnership units may be adversely affected.

        Our ability to grow has been 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. As discussed above, Morgan Stanley informed us in October 2011 that, for the foreseeable future, it does not expect to approve any "significant" acquisition or investment that we may propose. Morgan Stanley's decision will severely limit our ability to grow our business for the foreseeable future and may have an adverse effect on the price of our common units representing limited partnership interests or on the tax characteristics of an investment in our common units.

        To the extent Morgan Stanley approves any acquisition we may propose, our ability to acquire facilities will be based, in part, on divestitures of product terminal and transportation facilities by large industry participants. A material decrease in such divestitures could therefore limit our opportunities for future acquisitions.

        In addition, we may be unable to make attractive acquisitions for any of the additional 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, and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of our capital resources.

         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;

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

    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.

         A significant decrease in demand for refined products due to high prices, alternative fuel sources, new technologies 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 market uncertainties, economic recession resulting in lower consumer spending on gasolines, distillates and travel, and high prices of refined products 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 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;

    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; or

    an increase in the use of alternative fuel sources, such as ethanol, biodiesel, fuel cells and solar, electric and battery-powered engines.

        Mergers between our existing customers and our competitors could provide strong economic incentives for the combined entities to utilize their existing systems instead of ours in those markets where the systems compete. As a result, we could lose some or all of the volumes and associated revenues from these customers and we could experience difficulty in replacing those lost volumes and revenues.

        Because most of our operating costs are fixed, any decrease in throughput volumes at our terminal facilities, would likely result not only in a decrease in our revenue, but also a decline in cash flow of a similar magnitude, which would adversely affect our results of operations, financial position and cash flows and may impair our ability to make quarterly distributions to our unitholders.

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

        Our amended and restated senior secured credit facility also contains covenants limiting our ability to make distributions to unitholders in certain circumstances. In addition, our amended and restated 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 amended and restated 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 amended and restated 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.

         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.

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         Adverse economic conditions periodically result in weakness and volatility in the capital markets, that may limit, temporarily or for extended periods, the ability of one or more of our significant customers 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.

        Domestic and international economic conditions affect the functioning of capital markets and the availability of credit. Adverse economic conditions, such as those prevalent during the recent recessionary period, periodically result in weakness and volatility in the capital markets, which in turn can limit, temporarily or for extended periods, 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. 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 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 and governmental claims for natural resource damages or fines or penalties for related violations of environmental laws or regulations. We are not fully insured against all risks to our business and if losses in excess of our insurance coverage were to occur, they could have a material adverse effect on our operations. 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.

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         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.

        On March 9, 2011, we entered into an amended and restated senior secured credit facility that matures in March 2016. At December 31, 2012, we had outstanding borrowings of $184 million. Our amended and restated senior secured credit facility provides that we pay interest on outstanding balances at interest rates based on market rates plus specified margins, ranging from 2% to 3% depending on the total leverage ratio in the case of loans with interest rates based on LIBOR, or ranging from 1% to 2% depending on the total leverage ratio in the case of loans with interest rates based on the base rate. In the event we are required to refinance our amended and restated 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 have today, which could adversely affect our results of operations and may impair our ability to make quarterly distributions to our unitholders.

         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.

         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. If we experience material cost overruns, we would have to finance these overruns using cash from operations, delaying other planned projects, incurring additional indebtedness, or issuing additional equity. Any or all of these methods may not be available when needed or may adversely affect our future results of operations and cash flows. 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

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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 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.

        Federal, state and local agencies also have the authority to prescribe specific product quality specifications of refined products. Changes in product quality specifications or blending requirements could reduce our throughput volume, require us to incur additional handling costs or require capital expenditures. For example, different product specifications for different markets impact the fungibility of the products in our system and could require the construction of additional storage. If we are unable to recover these costs through increased revenues, our cash flows and ability to pay cash distributions could be adversely affected.

         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.

         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

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adversely affect our results of operations, financial position and cash flows, as well as our ability to pay cash distributions.

         Climate change legislation or regulations restricting emissions of "greenhouse gases" or setting fuel economy or air quality standards could result in increased operating costs or reduced demand for the refined petroleum products that we transport, store or otherwise handle in connection with our business.

        New environmental laws and regulations, including new federal or state regulations relating to alternative energy sources and the risk of global climate change, increased governmental enforcement or other developments could increase our costs in complying with environmental and safety regulations and require us to make additional unforeseen expenditures. On December 15, 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other "greenhouse gases" endanger human health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth's atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the Federal Clean Air Act. Moreover, more than one-third of the states, either individually or through multi-state regional initiatives, have already begun implementing legal measures to reduce emissions of greenhouse gases.

        While it is not possible at this time to fully predict how legislation or new regulations that may be adopted in the United States to address greenhouse gas emissions would impact our business, new legislation or regulatory programs that restrict emissions of greenhouse gases in areas where we conduct business could, depending on the particular program adopted, increase our costs to operate and maintain our facilities, measure and report our emissions, install new emission controls on our facilities and administer and manage a greenhouse gas emissions program. Laws or regulations regarding fuel economy, air quality or greenhouse gas emissions could also include efficiency requirements or other methods of curbing carbon emissions that could adversely affect demand for the refined petroleum products, natural gas and other hydrocarbon products that we transport, store or otherwise handle in connection with our business. A significant decrease in demand for petroleum products would have a material adverse effect on our business, financial condition, results of operations or cash flows.

        In addition, some scientists have concluded that increasing concentrations of greenhouse gases in the earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climate events; if any such effects were to occur, they could have an adverse effect on our assets and operations.

Risks Inherent in an Investment in Us

         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 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, it may be difficult for unitholders to remove our general partner without its consent because our general partner and its

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affiliates own units representing approximately 22% 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.

    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.

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    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 partnership agreement permits us to treat a distribution of a certain amount of cash from non-operating sources such as asset sales, issuances of securities and long-term borrowings as a distribution of operating surplus instead of capital surplus. The amount that can be distributed in such fashion is equal to four times the amount needed for us to pay a quarterly distribution on the common units, the general partner interest and the incentive distribution rights at the same per-unit distribution amount as the distribution paid in the immediately preceding quarter. As of December 31, 2012, that amount was $42.4 million, $13.5 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, 2012, we paid TransMontaigne Inc. and its affiliates an administrative fee of approximately $10.8 million, an additional insurance reimbursement of approximately $3.6 million and $1.3 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 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

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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 28, 2013, affiliates of our general partner own approximately 22.0% of our aggregate outstanding common units representing limited partner interests.

         We may issue additional units without your approval, which would dilute your existing ownership interests.

        Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects: your proportionate ownership interest in us will decrease; the amount of cash available for distribution on each unit may decrease; the ratio of taxable income to distributions may increase; the relative voting strength of each previously outstanding unit may be diminished; and the market price of the common units may decline.

         Unitholders may not have limited liability in some circumstances.

        The limitations on the liability of holders of limited partnership interests for the obligations of a limited partnership have not been clearly established in some states. If it were determined that we had been conducting business in any state without compliance with the applicable limited partnership statute, or that our unitholders as a group took any action pursuant to our partnership agreement that constituted participation in the "control" of our business, then the unitholders could be held liable under some circumstances for our obligations to the same extent as a general partner. Under applicable state law, our general partner has unlimited liability for our obligations, including our debts and environmental liabilities, if any, except for our contractual obligations that are expressly made without recourse to the general partner.

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        In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances a Unitholder may be liable to us for the amount of distributions paid to the unitholder for a period of three years from the date of the distribution.

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 our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this matter.

        A publicly-traded partnership may be treated as a corporation for federal income tax purposes unless its gross income from its business activities satisfies a "qualifying income" requirement under U.S. tax code. Based upon our current operations, we believe that we qualify to be treated as a partnership for federal income tax purposes under these requirements. While we intend to continue to meet this gross income requirement, we may not find it possible to meet, or may inadvertently fail to meet, these requirements. If we do not meet these requirements for any taxable year, and the IRS does not determine that such failure was inadvertent, we would be treated as a corporation for such taxable year and each taxable year thereafter.

        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 a publicly traded partnership, including us, change the character or treatment of portions of our income and adversely affect an investment in our common units. We are unable to predict whether any current or future proposed federal income tax law changes will ultimately be enacted.

        In addition, some states have subjected partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation, and other states may follow this trend. 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, 2012, we recognized a liability of approximately $73,000 for the Texas margin tax, which is imposed at a maximum effective rate of 0.7% of our total revenue and tax gains 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.

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         Constraints on our ability to make acquisitions and investments to increase our capital asset base may result in future declines in our tax depreciation, which may cause some unitholders to recognize higher taxable income in respect of their units and adversely affect the tax characteristics of an investment in our units and reduce the market price of our units.

        Morgan Stanley, which indirectly controls our general partner, informed us in October 2011 that, for the foreseeable future, it does not expect to approve any "significant" acquisition or investment that we may propose. The practical effect of these limitations is to significantly constrain our ability to expand our asset base and operations through acquisitions from third parties, limiting additions to our capital assets primarily to additions and improvements that we construct or add to our existing facilities, although some acquisitions of assets from third parties may be possible to the extent approved by Morgan Stanley. As a result, we may not be able to add to our capital asset base quickly enough to avoid our tax depreciation from declining in the future, which could cause some unitholders to recognize higher taxable income. The federal and state tax laws and regulations applicable to an investment in our units are complex and each investor's tax considerations are likely to be different from those of other investors, so it is impossible to state with certainty the impact of any change on any single investor or group of investors in our units. It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of an investment in our common units. Accordingly, each unitholder or prospective investor in our units is urged to consult with, and depend upon, their tax counsel or other advisor with regard to those matters.

        Nevertheless, adverse changes in investors' perception of the tax characteristics of an investment in our units could adversely affect market value of our units.

         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 technical 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 a change in our ownership structure effective December 31, 2007. 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

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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.

         Unitholders will be required to pay taxes on their respective share of our taxable income regardless of the amount of cash distributions.

        Unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on the unitholder's respective share of our taxable income, whether or not such unitholder receives cash distributions from us. In addition, supplemental taxes that apply to net investment income from passive activities and from gains on sales of partnership interests may be required of unitholders. Unitholders may not receive cash distributions from us equal to the unitholder's respective share of our taxable income or even equal to the actual tax liability that results from the unitholder's respective share of our taxable income or due to the unitholder's taxes relating to net investment income.

         Tax-exempt entities and foreign persons face unique tax issues from owning units that may result in adverse tax consequences to them.

        Investment in common partnership units by tax-exempt entities, such as individual retirement accounts, and non-United States persons raises tax issues unique to them. For example, the partnership's ordinary income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income, or UBTI, and may be taxable to them. Due to allocations of reportable tax items to unitholders being dependent on the date of each unitholder's purchase of our common units, we are not able to provide an estimate of a unitholder's UBTI prior to processing that unitholder's Schedule K-1. Because the Partnership's distributions are attributed to income that is effectively connected with a United States trade or business, distributions to non-United States persons are subject to withholding taxes at the highest applicable effective tax rate set by the federal tax laws in effect at the time of such distributions. Nominees, rather than the Partnership, are treated as withholding agents. Non-United States persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.

         Our unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our limited partner units.

        In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file returns and pay state and local income tax in some or all of these jurisdictions, and unitholders may be subject to penalties for failure to comply with those requirements. It is our unitholders' responsibility to file all United States federal, state and local tax returns.

         We will treat each purchaser of our units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of our units.

        Because we cannot match transferors and transferees of units, we adopt various conventions for administrative purposes (including depreciation and amortization positions) that may not conform in all aspects to existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from any sale of units and could have a negative impact on the value of our units or result in audit adjustments to a unitholder's tax returns.

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         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 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.    MINE SAFETY DISCLOSURES

        Not applicable.

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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 28, 2013, there were approximately 23 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, 2011 through March 31, 2011

  $ 33.81   $ 40.69  

April 1, 2011 through June 30, 2011

  $ 32.74   $ 37.78  

July 1, 2011 through September 30, 2011

  $ 29.65   $ 37.50  

October 1, 2011 through December 31, 2011

  $ 30.00   $ 36.90  

January 1, 2012 through March 31, 2012

  $ 33.62   $ 35.71  

April 1, 2012 through June 30, 2012

  $ 29.89   $ 35.48  

July 1, 2012 through September 30, 2012

  $ 33.28   $ 38.74  

October 1, 2012 through December 31, 2012

  $ 31.51   $ 38.55  

DISTRIBUTIONS OF AVAILABLE CASH

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

 
  Distribution  

January 1, 2011 through March 31, 2011

  $ 0.61  

April 1, 2011 through June 30, 2011

  $ 0.62  

July 1, 2011 through September 30, 2011

  $ 0.62  

October 1, 2011 through December 31, 2011

  $ 0.63  

January 1, 2012 through March 31, 2012

  $ 0.63  

April 1, 2012 through June 30, 2012

  $ 0.64  

July 1, 2012 through September 30, 2012

  $ 0.64  

October 1, 2012 through December 31, 2012

  $ 0.64  

        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.

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        The terms of our 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.

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 credit facility.

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Common Unit Purchases for the quarter ended December 31, 2012

        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, 2012.

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

    575   $ 38.41     575     2,875  

November

    575   $ 36.06     575     2,300  

December

    575   $ 35.05     575     1,725  
                     

    1,725   $ 36.51     1,725        
                     

        During the three months ended December 31, 2012, we purchased 1,725 common units, with $62,980 of aggregate market value, in the open market pursuant to a purchase program announced on May 7, 2007. The purchase program establishes the purchase, 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. There is no guarantee as to the exact number of common units that will be purchased under the purchase program, and the purchase program may be amended or discontinued at any time. Unless we choose to terminate the purchase program earlier, the purchase program terminates on the earlier to occur of March 31, 2013; 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. We currently anticipate purchasing in the first quarter of 2013 up to approximately 1,725 common units, in the aggregate, through the purchase program's scheduled termination date of March 31, 2013.

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 five-year period ended December 31, 2012, has been derived from our consolidated financial statements. 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

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and Analysis of Financial Condition and Results of Operations" included elsewhere in this annual report.

 
  Years ended December 31,  
 
  2012(1)   2011(2)   2010   2009   unaudited
2008(3)
 
 
  (dollars in thousands except per unit amounts)
 

Operations Data:

                               

Revenue

  $ 156,239   $ 152,292   $ 150,899   $ 142,547   $ 138,140  

Direct operating costs and expenses

    (65,964 )   (64,498 )   (64,696 )   (64,968 )   (61,850 )

Direct general and administrative expenses

    (4,810 )   (4,703 )   (3,159 )   (3,242 )   (4,138 )

Allocated general and administrative expenses

    (10,780 )   (10,466 )   (10,311 )   (10,040 )   (10,030 )

Allocated insurance expense

    (3,590 )   (3,290 )   (3,185 )   (2,900 )   (2,835 )

Reimbursement of bonus awards

    (1,250 )   (1,250 )   (1,250 )   (1,237 )   (1,500 )

Depreciation and amortization

    (28,260 )   (27,654 )   (27,869 )   (26,306 )   (23,316 )

Gain (loss) on disposition of assets

        9,576     (765 )   1     2  

Impairment of goodwill

            (8,465 )        

Earnings from unconsolidated affiliates

    558     113              
                       

Operating income

    42,143     50,120     31,199     33,855     34,473  

Other income (expenses):

                               

Interest income

    22     1     8     7     38  

Interest expense

    (2,877 )   (2,458 )   (3,405 )   (6,048 )   (8,135 )

Amortization of deferred financing costs

    (767 )   (1,055 )   (598 )   (598 )   (599 )

Foreign currency transaction gain (loss)

    51     (88 )   38     36     (179 )
                       

Net earnings

    38,572     46,520     27,242     27,252     25,598  

Less—earnings allocable to general partner interest including incentive distribution rights

    (5,157 )   (4,415 )   (3,017 )   (2,451 )   (2,226 )
                       

Net earnings allocable to limited partners

  $ 33,415   $ 42,105   $ 24,225   $ 24,801   $ 23,372  
                       

Net earnings per limited partner unit—basic

  $ 2.31   $ 2.92   $ 1.69   $ 1.99   $ 1.88  
                       

Net earnings per limited partner unit—diluted

  $ 2.31   $ 2.91   $ 1.68   $ 1.99   $ 1.88  
                       

Other Financial Data:

                               

Net cash provided by operating activities

  $ 64,311   $ 66,091   $ 65,336   $ 72,045   $ 53,488  

Net cash used in investing activities

  $ (85,731 ) $ (18,566 ) $ (37,508 ) $ (37,742 ) $ (53,406 )

Net cash provided by (used in) financing activities

  $ 20,964   $ (45,605 ) $ (29,056 ) $ (32,534 ) $ 3,200  

Cash distributions declared per common unit attributable to the period

  $ 2.55   $ 2.48   $ 2.41   $ 2.36   $ 2.33  

Balance Sheet Data (at period end):

                               

Property, plant and equipment, net

  $ 427,701   $ 431,782   $ 452,402   $ 459,598   $ 447,753  

Investments in unconsolidated affiliates

  $ 105,164   $ 25,875   $   $   $  

Total assets

  $ 569,801   $ 514,104   $ 514,306   $ 515,535   $ 507,039  

Long-term debt

  $ 184,000   $ 120,000   $ 122,000   $ 165,000   $ 165,500  

Partners' equity

  $ 348,737   $ 351,876   $ 344,816   $ 303,125   $ 307,579  

(1)
At December 31, 2012, our investments in unconsolidated affiliates include a 42.5% interest in BOSTCO and a 50% interest in Frontera with carrying values of approximately $78.9 million and $26.2 million, respectively. BOSTCO is a $425 million terminal facility construction project that is scheduled to begin commercial operations in the fourth quarter of 2013 (See Note 3 of Notes to consolidated financial statements).

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(2)
The consolidated financial statements, effective April 1, 2011, include the impact of our contribution of approximately 1.4 million barrels of light petroleum product storage capacity, as well as related ancillary facilities, to the Frontera joint venture in exchange for a cash payment of approximately $25.6 million and a 50% ownership interest (see Note 3 of Notes to consolidated financial statements).

(3)
Based on the determination that our prior auditor, KPMG LLP, was not "independent" of TransMontaigne Partners within the meaning of the rules of applicable regulatory agencies, we have accordingly marked the year not subject to audit by our new auditor, Deloitte & Touche LLP, as unaudited (see Significant Developments During the Year Ended December 31, 2012 contained in Item 7. for further discussion).

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, 2012, our operations are composed of:

    eight refined product terminals located in Florida, with an aggregate active storage capacity of approximately 6.9 million barrels, that provide integrated terminaling services to Marathon, Morgan Stanley Capital Group, TransMontaigne Inc. and other distribution and marketing companies;

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

    two refined product terminals, one located in Mount 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 crude oil terminal located in Cushing, Oklahoma, with aggregate active storage capacity of approximately 1.0 million barrels, that provides 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 929,000 barrels that provides integrated terminaling services to TransMontaigne Inc., Valero and other distribution and marketing companies;

    a 50/50 joint venture with PMI, an indirect subsidiary of PEMEX, for the operation of the Frontera light petroleum products terminal located in Brownsville, Texas with an aggregate active storage capacity of approximately 1.4 million barrels that provides services to PMI Trading Ltd, Valero and other distribution and marketing companies;

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    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 an affiliate of PEMEX;

    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 a third party;

    twelve refined product terminals located along the Mississippi and Ohio rivers ("River terminals") with aggregate active storage capacity of approximately 2.8 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 10 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 pipelines 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 the Florida ports. Despite these seasonalities, the overall impact on the volume of product throughput in our terminals and pipelines is not material.

        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 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% limited partner interest, a 2% general partner interest and the incentive distribution rights.

        The majority of our business is devoted to providing terminaling and transportation services to Morgan Stanley Capital Group and TransMontaigne Inc., which currently rely on us to provide substantially all the integrated terminaling services they require to support their operations along the Gulf Coast, along the Mississippi and Ohio rivers, along the Colonial and Plantation pipelines, and in the Midwest. 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

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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.

        Taken together, Morgan Stanley Capital Group and TransMontaigne Inc. is our largest customer and our agreements with them provide a substantial majority of our revenues, representing approximately 69%, 69% and 68% of our revenue for the years ended December 31, 2012, 2011 and 2010, respectively. Our revenue from Morgan Stanley Capital Group and TransMontaigne Inc. is primarily earned pursuant to terminaling services agreements with Morgan Stanley Capital Group relating to our Florida terminals and the Razorback terminals and our Southeast terminals. In the aggregate, these agreements accounted for approximately 60.3% of our revenue for the year ended December 31, 2012. See Item 1. "Business—Terminaling Services Agreements" in this Form 10-K for additional descriptions of these agreements.

        Our terminaling services agreements with Morgan Stanley Capital Group relating to our Florida and Razorback terminals and our Southeast terminals expire in May and December 2014, respectively. In February 2013, representatives of Morgan Stanley Capital Group indicated that they intend to extend or enter into new terminaling services agreements covering our Florida and the Razorback terminals and the Southeast terminals for periods after the current agreements expire. However, if we are not able to reach acceptable terms with respect to such agreements, or to replace the expiring terminaling services agreements with new or expanded terminaling relationships with new customers or our other existing customers, our revenues would be significantly reduced. See Item 1A. "Risk Factors—Risks Inherent in Our Business" in this Form 10-K for further discussion.

REGULATORY MATTERS

        During 2008, Morgan Stanley, which indirectly controls our general partner, obtained the approval of the Board of Governors of the Federal Reserve System, or the FRB, to become a bank holding company, due to its ownership of Morgan Stanley Bank, N.A., subject to regulation as a financial holding company under the Bank Holding Company Act, or the BHC Act. As a result, Morgan Stanley has become subject to the consolidated supervision and regulation of the FRB under the BHC Act. In addition, in 2010 the Dodd-Frank Wall Street Reform and Consumer Protection Act, or Dodd-Frank Act was enacted. The Dodd-Frank Act contains various provisions that affect financial firms, including financial holding companies, and amends various existing laws, including the BHC Act, as amended and supplemented by the Dodd-Frank Act.

        As a financial holding company, Morgan Stanley is permitted to engage in any activity that is financial in nature, incidental to a financial activity, or complementary to a financial activity in conformance with the BHC Act. Under certain circumstances and with the approval of the FRB, any company that becomes a bank holding company may have up to five years to conform its existing activities and investments to the BHC Act. The BHC Act also grandfathers "activities of a financial holding company related to the trading, sale or investment in commodities and underlying physical properties" provided that the financial holding company conducted any of such type of activities as of September 30, 1997 and provided that certain other conditions are satisfied, which conditions Morgan Stanley has informed us 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.

        In 2009, Morgan Stanley advised us that its internal review reached the conclusion that all of our activities and investments are permissible under the BHC Act. To the extent the FRB has not yet

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completed its review of these activities and investments, however, the FRB could conclude that certain of our activities or investments will not be deemed permissible under the BHC Act. We are unable to predict whether, or in what ways, such a determination might affect our financial condition or results of operations or how significant any such effects could be.

        The Dodd-Frank Act and the mandates it includes for further regulatory actions are part of a trend to increase regulatory supervision of the financial industry. As a result of this trend, including further legislative and/or regulatory changes, Morgan Stanley's ability or business strategy to own and operate our general partner and to operate Partners may be adversely affected. We cannot predict how any such changes might affect our financial condition or results of operations or how significant any such effects could be.

        Morgan Stanley informed us in October 2011 that, for the foreseeable future, it does not expect to approve any "significant" acquisition or investment that we may propose. Morgan Stanley indicated that it has not established a specific definition of what constitutes a "significant" investment and significance may be determined on either a quantitative or qualitative basis, depending on the facts and circumstances and relevant legal and regulatory considerations. Morgan Stanley has informed us they will review on a case by case basis each proposed transaction to determine its significance, whether an acquisition of, or investment in, assets or legal entities and that an acquisition of, or investment in, a noncontrolling interest or joint venture interest may be "significant" without respect to the size of the transaction. The practical effect of these limitations is to significantly constrain our ability to expand our asset base and operations through acquisitions from third parties. These constraints will reduce the potential for increasing our distributions to unitholders in the future. In addition, these constraints will limit additions to our capital assets primarily to additions and improvements that we construct or add to our existing facilities, although some acquisitions of assets from third parties may be possible to the extent approved by Morgan Stanley. See Item 1A. "Risk Factors—Tax Risks" in this Form 10-K for further discussion. Our December 2012 investment in BOSTCO was approved by Morgan Stanley based on the specific facts and circumstances of the BOSTCO project and the structure of our investment in BOSTCO, and is not indicative of whether Morgan Stanley will approve any other acquisition or investment that we may propose in the future.

        Morgan Stanley's decision regarding limitations on its approval of acquisitions or investments that we may propose is the result of the uncertain regulatory environment relating to Morgan Stanley's status as a financial holding company subject to the BHC Act, as amended by the Dodd-Frank Act, and consolidated supervision by the Board of Governors of the FRB, including uncertainty surrounding the application of regulations under the BHC Act affecting the acquisition and ownership of non-financial business activities. In particular, as a result of the Dodd-Frank Act (including the proposed Volcker Rule), Morgan Stanley is subject to significantly revised and expanded regulation and supervision, to more intensive scrutiny of its businesses and any plans for expansion of those businesses and to limitations on engaging in new business activities which, in turn, affect TransMontaigne Partners by virtue of Morgan Stanley having control of our business activities through its indirect ownership of our general partner. The Dodd-Frank Act and the mandates it includes for further regulatory actions are part of a trend to increase regulatory supervision of the financial industry. As a result of this trend, including further legislative or regulatory changes, Morgan Stanley's ability to own and operate our general partner or its business strategies with respect to operating our general partner and TransMontaigne Partners may change significantly in ways that we cannot currently predict with certainty. We are currently unable to predict how the impact of Morgan Stanley's decision and such regulatory developments will affect Morgan Stanley's commodities business or the growth or development of our business and results of operations.

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SIGNIFICANT DEVELOPMENTS DURING THE YEAR ENDED DECEMBER 31, 2012

        On December 20, 2012, we acquired a 42.5% interest in BOSTCO, for approximately $79 million, from Kinder Morgan. BOSTCO is a new black oil terminal facility under construction on the Houston Ship Channel designed for the handling of residual fuel, feedstocks, distillates and other black oils. The initial phase of the BOSTCO project involves construction of 50 storage tanks with approximately 6.1 million barrels of storage capacity at an estimated cost of $425 million. The BOSTCO facility's docks will benefit from one of the deepest vessel drafts and nearest access points in the Houston Ship Channel and will be well positioned to capitalize on increasing exports of petroleum related products. The BOSTCO facility is scheduled to begin commercial operation in the fourth quarter of 2013. Completion of the full 6.1 million barrels of storage capacity and related infrastructure is scheduled for early 2014. Upon completion of the project, and assuming we maintain our 42.5% interest, we expect our total payments for the project to be approximately $183 million, which includes our December 20, 2012 investment of approximately $79 million. Our December 2012 investment in BOSTCO was approved by Morgan Stanley based on the specific facts and circumstances of the BOSTCO project and the structure of our investment in BOSTCO, and is not indicative of whether Morgan Stanley will approve any other acquisition or investment that we may propose in the future.

        We funded the acquisition utilizing additional borrowings under our credit facility, which we amended in connection with the purchase of the BOSTCO interest. The amendment increased the maximum borrowing line of credit under the facility from $250 million to $350 million. The amendment also provided us with the ability to make future capital contributions to BOSTCO to fund its ongoing construction and to maintain our ownership interest percentage.

        On January 13, 2012, we announced a distribution of $0.63 per unit for the period from October 1, 2011 through December 31, 2011, payable on February 7, 2012 to unitholders of record on January 31, 2012. The distribution represented a $0.01 increase over the previous quarter and a 3.3% increase over the $0.61 per unit distribution declared for the fourth quarter of 2010.

        On April 16, 2012, we announced a distribution of $0.63 per unit for the period from January 1, 2012 through March 31, 2012, payable on May 8, 2012 to unitholders of record on April 30, 2012.

        On May 3, 2012, we filed with the SEC our December 31, 2011 annual report on Form 10-K/A, Amendment No. 1. As previously disclosed, on December 15, 2011 the audit committee of our general partner dismissed KPMG LLP from its engagement as the principal accountant to audit the December 31, 2011 financial statements of TransMontaigne Partners L.P. The dismissal of KPMG LLP resulted from the determination that KPMG LLP was not "independent" of TransMontaigne Partners L.P. within the meaning of the rules of applicable regulatory agencies, and did not qualify as independent at the time of our audits for the years ended December 31, 2010 and 2009, and prior periods. In conjunction with our investigation of this matter, it was determined that our investors would receive meaningful benefit from the reassurance that would be provided by having our financial statements for the years ended December 31, 2010 and December 31, 2009 re-audited, and by having the quarterly financial information that is contained in the 2011 annual report re-reviewed, by Deloitte & Touche LLP, our new independent registered public accounting firm. The re-audits and re-reviews were completed by Deloitte & Touche LLP on May 3, 2012. The re-audits and re-reviews did not materially change the information previously reported in our consolidated financial statements for any of the prior periods presented in our 2011 annual report or our previously filed quarterly and annual reports with respect to such periods.

        On July 16, 2012, we announced a distribution of $0.64 per unit for the period from April 1, 2012 through June 30, 2012, payable on August 7, 2012 to unitholders of record on July 31, 2012. The distribution represented a $0.01 increase over the previous quarter and a 3.2% increase over the $0.62 per unit distribution declared for the second quarter of 2011.

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        As of August 1, 2012 we completed the construction of 1.0 million barrels of crude oil storage tankage in Cushing, Oklahoma. We have a long-term terminaling services agreement with Morgan Stanley Capital Group for the use of this facility. Under this agreement, Morgan Stanley Capital Group has agreed to throughput a volume of crude oil at our Cushing, Oklahoma terminal that will, at the fee schedule contained in the agreement, result in minimum throughput payments to us of approximately $4.3 million for each one-year period following the in-service date of August 1, 2012 through July 31, 2019.

        On October 15, 2012, we announced a distribution of $0.64 per unit for the period from July 1, 2012 through September 30, 2012, payable on November 6, 2012 to unitholders of record on October 31, 2012.

SUBSEQUENT DEVELOPMENT

        On January 14, 2013, we announced a distribution of $0.64 per unit for the period from October 1, 2012 through December 31, 2012, payable on February 7, 2013 to unitholders of record on January 31, 2013.

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 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 earned 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. Prior to April 27, 2010, we managed and operated for another major oil company two terminals that are adjacent to our Collins, Mississippi and Bainbridge, Georgia facilities and received a reimbursement of their proportionate share of operating and maintenance costs. On April 27, 2010, we purchased these two terminals. Effective as of April 1, 2011, upon the formation of Frontera, we began providing operations and maintenance services to Frontera for a management fee based on our costs incurred.

        Other Revenue.    We provide ancillary services including heating and mixing of stored products and product transfer services. Pursuant to terminaling services agreements with certain of 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.

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        Direct Operating Costs and Expenses.    The direct operating costs and expenses of our operations include the directly related wages and employee benefits, utilities, communications, repairs and maintenance, 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 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 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.

        Useful Lives of Plant and Equipment.    We calculate depreciation using the straight-line method, based on estimated useful lives of our assets. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration, economic conditions and supply and demand in the area. When assets are put into service, we make estimates with respect to useful lives that we believe to be reasonable. However, subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation. Estimated useful lives are 15 to 25 years for plant, which includes buildings, storage tanks, and pipelines, and 3 to 25 years for equipment.

        Accrued Environmental Obligations.    At December 31, 2012, we have an accrued liability of approximately $3.1 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 facilities acquired on December 31, 2006, not to exceed $15.0 million for the Southeast terminals acquired on December 31, 2007 and not to exceed $2.5 million for the Pensacola terminal acquired on March 1, 2011) for these indemnification obligations.

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        Goodwill.    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 18 of Notes to consolidated financial statements). The fair value of each reporting unit is determined on a stand-alone basis from the perspective of a market participant and represents an estimate of the price that would be received to sell the unit as a whole in an orderly transaction between market participants at the measurement date. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered to be impaired. Management exercises judgment in estimating the fair values of the reporting units. The reporting units' fair values are estimated using a discounted cash flow technique. We believe that our estimates of the future cash flows and related assumptions are consistent with those that would be used by market participants (that is, potential buyers of the reporting units). The cash flows represent our best estimate of the future revenues, expenses and capital expenditures to maintain the facilities associated with each of our reporting units. Estimated cash flows do not include future expenditures to expand the facilities beyond the expenditures necessary to complete expansion projects approved prior to December 31, 2012. The cash flows attributed to our reporting units include 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, since market participants would likely have pre-existing management and back office capabilities (that is, a market participant synergy). At December 31, 2012 we discounted the estimated net cash flows at an assumed market participant weighted average cost of capital of approximately 9.7%. The aggregate fair value of our reporting units was reconciled to the fair value of our partners' equity.

        At December 31, 2012, our estimate of the fair value of our Brownsville terminals reporting unit exceeded its carrying amount. Accordingly, we did not recognize any goodwill impairment charges during the year ended December 31, 2012 for this reporting unit. However, a significant decline in the price of our common units with a resulting increase in the assumed market participants' weighted average cost of capital, the loss of a significant customer, the disposition of significant assets, or an unforeseen increase in the costs to operate and maintain the Brownsville terminals, could result in the recognition of an impairment charge in the future.

        At December 31, 2010, our estimate of the fair value of our River terminals reporting unit was less than its carrying amount. The decline in the estimated fair value was attributable to the loss of a customer in 2010 at one of our larger River facilities and the underutilization of certain other facilities in the River region. Accordingly, management reduced its short and medium-term revenue forecasts related to these facilities, which resulted in an overall decline in the estimated future cash flows for the River terminals reporting unit. Given the estimated fair value of our River terminals was less than its carrying amount, we performed further analysis as required by generally accepted accounting principles. This resulted in a determination that goodwill for the River terminals reporting unit was no longer supported by its estimated fair value and, as a result, we recognized an $8.5 million impairment charge reflected in our accompanying consolidated statements of comprehensive income for the year ended December 31, 2010. There is no longer any goodwill recorded related to the River terminals reporting unit (see Note 7 of Notes to consolidated financial statements).

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RESULTS OF OPERATIONS—YEARS ENDED DECEMBER 31, 2012, 2011 AND 2010

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,
2012
  Year ended
December 31,
2011
  Year ended
December 31,
2010
 

Terminaling services fees, net

  $ 119,465   $ 116,353   $ 122,289  

Pipeline transportation fees

    5,656     4,746     4,817  

Management fees and reimbursed costs

    5,806     3,899     2,161  

Other

    25,312     27,294     21,632  
               

Revenue

  $ 156,239   $ 152,292   $ 150,899  
               

        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,
2012
  Year ended
December 31,
2011
  Year ended
December 31,
2010
 

Gulf Coast terminals

  $ 57,752   $ 57,027   $ 54,729  

Midwest terminals and pipeline system

    10,553     7,857     7,721  

Brownsville terminals

    18,614     19,850     24,222  

River terminals

    14,161     12,672     14,739  

Southeast terminals

    55,159     54,886     49,488  
               

Revenue

  $ 156,239   $ 152,292   $ 150,899  
               

        Total revenue by business segment is presented and further analyzed below by category of revenue.

        Terminaling Services Fees, Net.    Pursuant to terminaling services agreements with our customers, which range from one month to seven 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

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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,
2012
  Year ended
December 31,
2011
  Year ended
December 31,
2010
 

Gulf Coast terminals

  $ 47,692   $ 46,699   $ 46,508  

Midwest terminals and pipeline system

    5,381     3,784     3,757  

Brownsville terminals

    6,398     9,133     15,709  

River terminals

    13,219     12,244     14,359  

Southeast terminals

    46,775     44,493     41,956  
               

Terminaling services fees, net

  $ 119,465   $ 116,353   $ 122,289  
               

        The increase in terminaling services fees, net for the year ended December 31, 2012 as compared to the year ended December 31, 2011 includes an increase of approximately $0.5 million resulting from a full year of revenue from the acquisition of the Pensacola terminal, which occurred on March 1, 2011 in the Gulf Coast region, an increase of approximately $1.8 million resulting from newly constructed tank capacity placed into service during August of 2012 at our Cushing, Oklahoma facility in the Midwest region, an increase of approximately $0.5 million from new business in our River region and an increase of approximately $1.8 million resulting from newly constructed tank capacity placed into service during July of 2011 at our Collins/Purvis complex in the Southeast region. This increase has been partially offset by a decrease in terminaling service fees, net of approximately $2.5 million at our Brownsville terminals resulting from product storage capacity contributed to Frontera effective as of April 1, 2011.

        Included in terminaling services fees, net for the years ended December 31, 2012, 2011 and 2010 are fees charged to Morgan Stanley Capital Group of approximately $81.1 million, $77.6 million and $76.1 million, respectively, and fees charged to TransMontaigne Inc. of approximately $3.0 million, $3.5 million and $6.4 million, respectively.

        Our terminaling services agreements are structured as either throughput agreements or storage agreements. Most of our 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

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commitments" and "variable" revenue included in terminaling services fees, net were as follows (in thousands):

 
  Firm Commitments and Variable Revenue  
 
  Year ended
December 31,
2012
  Year ended
December 31,
2011
  Year ended
December 31,
2010
 

Firm commitments:

                   

External customers

  $ 32,412   $ 32,744   $ 35,554  

Affiliates

    84,347     81,190     82,651  
               

Total

    116,759     113,934     118,205  
               

Variable:

                   

External customers

    2,814     2,585     4,230  

Affiliates

    (108 )   (166 )   (146 )
               

Total

    2,706     2,419     4,084  
               

Terminaling services fees, net

  $ 119,465   $ 116,353   $ 122,289  
               

        At December 31, 2012, the remaining terms on the terminaling services agreements that generated "firm commitments" for the year ended December 31, 2012 were as follows (in thousands):

 
  At
December 31,
2012
 

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

       

Less than 1 year remaining

  $ 13,557  

1 year or more, but less than 3 years remaining

    84,574  

3 years or more, but less than 5 years remaining

    16,828  

5 years or more remaining

    1,800  
       

Total firm commitments for the year ended December 31, 2012

  $ 116,759  
       

        Pipeline Transportation Fees.    We earned 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,
2012
  Year ended
December 31,
2011
  Year ended
December 31,
2010
 

Gulf Coast terminals

  $   $   $  

Midwest terminals and pipeline system

    1,876     1,948     2,041  

Brownsville terminals

    3,780     2,798     2,776  

River terminals

             

Southeast terminals

             
               

Pipeline transportation fees

  $ 5,656   $ 4,746   $ 4,817  
               

        Included in pipeline transportation fees for the years ended December 31, 2012, 2011 and 2010 are fees charged to Morgan Stanley Capital Group of approximately $1.9 million, $1.9 million and

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$2.0 million, respectively, and TransMontaigne Inc. of approximately $3.8 million, $2.8 million and $2.8 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. Prior to April 27, 2010, we also managed and operated for another major oil company two terminals that are adjacent to our Collins and Bainbridge terminals and received a reimbursement of their proportionate share of operating and maintenance costs. On April 27, 2010, we purchased these terminals. Effective as of April 1, 2011, upon the formation of Frontera, we began providing operations and maintenance services to Frontera for a management fee based on our costs incurred. 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,
2012
  Year ended
December 31,
2011
  Year ended
December 31,
2010
 

Gulf Coast terminals

  $ 288   $ 75   $ 103  

Midwest terminals and pipeline system

             

Brownsville terminals

    5,518     3,824     1,938  

River terminals

             

Southeast terminals

            120  
               

Management fees and reimbursed costs

  $ 5,806   $ 3,899   $ 2,161  
               

        Included in management fees and reimbursed costs for the years ended December 31, 2012 and 2011 are fees charged to Frontera of approximately $3.4 million and $1.9 million, respectively.

        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 certain 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,
2012
  Year ended
December 31,
2011
  Year ended
December 31,
2010
 

Product gains

  $ 16,136   $ 18,686   $ 12,755  

Steam heating fees

    3,473     4,380     4,313  

Product transfer services

    1,166     1,110     1,342  

Railcar handling

    533     617     639  

Other

    4,004     2,501     2,583  
               

Other revenue

  $ 25,312   $ 27,294   $ 21,632  
               

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        For the years ended December 31, 2012, 2011 and 2010, we sold approximately 161,000, 208,000 and 172,000 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 $121, $118 and $92 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. For the years ended December 31, 2012 and 2011, we have accrued a liability due to Morgan Stanley Capital Group of approximately $3.4 million and $5.9 million, respectively, representing our rebate liability.

        Included in other revenue for the years ended December 31, 2012, 2011 and 2010 are amounts charged to Morgan Stanley Capital Group of approximately $17.1 million, $18.9 million and $14.1 million, respectively, and TransMontaigne Inc. of approximately $0.1 million, $0.1 million and $0.7 million, respectively.

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

 
  Other Revenue by Business Segment  
 
  Year ended
December 31,
2012
  Year ended
December 31,
2011
  Year ended
December 31,
2010
 

Gulf Coast terminals

  $ 9,772   $ 10,253   $ 8,118  

Midwest terminals and pipeline system

    3,296     2,125     1,923  

Brownsville terminals

    2,918     4,095     3,799  

River terminals

    942     428     380  

Southeast terminals

    8,384     10,393     7,412  
               

Other revenue

  $ 25,312   $ 27,294   $ 21,632  
               


ANALYSIS OF COSTS AND EXPENSES

        The direct operating costs and expenses of our operations include the directly related wages and employee benefits, utilities, communications, repairs and maintenance, rent, property taxes, 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,
2012
  Year ended
December 31,
2011
  Year ended
December 31,
2010
 

Wages and employee benefits

  $ 22,957   $ 22,410   $ 22,574  

Utilities and communication charges

    6,972     7,973     8,032  

Repairs and maintenance

    21,440     20,614     20,633  

Office, rentals and property taxes

    6,669     6,562     7,055  

Vehicles and fuel costs

    1,306     1,448     1,353  

Environmental compliance costs

    2,978     3,264     3,203  

Other

    3,642     2,227     1,846  
               

Direct operating costs and expenses

  $ 65,964   $ 64,498   $ 64,696  
               

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        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,
2012
  Year ended
December 31,
2011
  Year ended
December 31,
2010
 

Gulf Coast terminals

  $ 21,586   $ 20,425   $ 22,115  

Midwest terminals and pipeline system

    1,976     1,329     1,662  

Brownsville terminals

    11,584     12,746     12,740  

River terminals

    9,171     8,586     8,521  

Southeast terminals

    21,647     21,412     19,658  
               

Direct operating costs and expenses

  $ 65,964   $ 64,498   $ 64,696  
               

        Direct general and administrative expenses of our operations primarily 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 deferred equity-based compensation. The direct general and administrative expenses for the years ended December 31, 2012, 2011 and 2010 were approximately $4.8 million, $4.7 million and $3.2 million, respectively.

        Allocated general and administrative expenses include charges from TransMontaigne Inc. for 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, 2012, 2011 and 2010 were approximately $10.8 million, $10.5 million and $10.3 million, respectively.

        Allocated insurance expense include charges from TransMontaigne Inc. for allocations of 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 expenses for the years ended December 31, 2012, 2011 and 2010 were approximately $3.6 million, $3.3 million and $3.2 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 $1.3 million for each of the years ended December 31, 2012, 2011 and 2010, respectively.

        Depreciation and amortization expenses for the years ended December 31, 2012, 2011 and 2010 were approximately $28.3 million, $27.7 million and $27.9 million, respectively.

        The accompanying consolidated financial statements for the year ended December 31, 2011 also include a gain of approximately $9.6 million recognized on the deconsolidation of assets transferred to the Frontera joint venture effective April 1, 2011 (see Note 3 of Notes to consolidated financial statements). The gain was measured as the difference between the carrying amount of the contributed assets and the aggregate of the cash we received and the fair value of the 50% interest we retained in the joint venture.

        The accompanying consolidated financial statements for the year ended December 31, 2010 also include a goodwill impairment charge to operating income for approximately $8.5 million related to our River terminals reporting unit (see Note 7 of Notes to consolidated financial statements).

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LIQUIDITY AND CAPITAL RESOURCES

        Our primary liquidity needs are to fund our working capital requirements, distributions to unitholders, approved capital projects and approved future expansion, development and acquisition opportunities. Future expansion, development and acquisition expenditures will depend on numerous factors, including approval by Morgan Stanley; 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. Further discussion of Morgan Stanley's current position with respect to approval of any proposed acquisitions and investments and the potential impact of such decision is set forth under the captions "Item 1A. Risk Factors" and "Overview—Regulatory Matters" in Item 7.

        We expect to initially fund our approved capital projects and our approved future expansion, development and acquisition opportunities, if any, with additional borrowings under our credit facility (see Note 12 of Notes to consolidated financial statements). After initially funding expenditures for approved capital projects and approved future expansion, development and acquisition opportunities, if any, with borrowings under our credit facility, we may raise funds through additional equity offerings and debt financings, which may include the issuance of senior unsecured notes. The proceeds of such equity offerings and debt financings may then be used to reduce our outstanding borrowings under our credit facility.

        Our capital expenditures for the year ended December 31, 2012 were approximately $23.6 million for terminal and pipeline facilities and assets to support these facilities. In addition, we made cash investments during the year ended December 31, 2012 of approximately $80.2 million in unconsolidated affiliates. Management and the board of directors of our general partner have approved additional investments in BOSTCO and expansion capital projects that currently are or will be under construction with estimated completion dates that extend through the first quarter of 2014. At December 31, 2012, the remaining capital expenditures to complete the approved additional investments and expansion capital projects are estimated to be approximately $105 million. We expect to fund our future investments and expansion capital expenditures with additional borrowings under our credit facility.

        Amended and restated senior secured credit facility.    On March 9, 2011, we entered into an amended and restated senior secured credit facility, or credit facility. The credit facility originally provided for a maximum borrowing line of credit equal to the lesser of (i) $250 million and (ii) 4.75 times Consolidated EBITDA (as defined: $340.7 million at December 31, 2012). On December 20, 2012, in connection with our repurchase of a 42.5% interest in BOSTCO, we amended the credit facility to increase our maximum borrowing line of credit to the lesser of (i) $350 million and (ii) 4.75 times Consolidated EBITDA. The amendment also provided us with the ability to make up to $225 million of investments in BOSTCO, referred to as the "Specified BOSTCO Investment", without regard to certain financial tests (including the "total leverage ratio," the "senior secured leverage ratio," the "interest coverage ratio" and the minimum liquidity requirements to have at least $50 million in unused borrowing capacity before and after giving effect to each such joint venture investment) that must otherwise be satisfied in order for us to make "permitted joint venture investments". In addition to the Specified BOSTCO Investment, under the terms of the amendment, we may also make an additional $75 million of other permitted joint venture investments (including additional investments in BOSTCO). Prior to the December 20, 2012 amendment, the credit facility permitted us to make up to only $125 million of joint venture investments in the aggregate, subject to satisfying the financial and other conditions set forth in the credit facility.

        We may elect to have loans under the credit facility bear interest either (i) at a rate of LIBOR plus a margin ranging from 2% to 3% depending on the total leverage ratio then in effect, or (ii) at

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the base rate plus a margin ranging from 1% to 2% depending on the total leverage ratio then in effect. We also pay a commitment fee on the unused amount of commitments, ranging from 0.375% to 0.5% per annum, depending on the total leverage ratio then in effect. Our obligations under the credit facility are secured by a first priority security interest in favor of the lenders in the majority of our assets, including our interests in unconsolidated affiliates. At December 31, 2012, our outstanding borrowings under the credit facility were $184 million.

        The terms of the credit facility include covenants that restrict our ability to make cash distributions, acquisitions and investments, including investments in joint ventures. We may make distributions of cash to the extent of our "available cash" as defined in our partnership agreement. We may make acquisitions and investments that meet the definition of "permitted acquisitions"; "other investments" which may not exceed 5% of "consolidated net tangible assets"; and "permitted JV investments". The principal balance of loans and any accrued and unpaid interest are due and payable in full on the maturity date, March 9, 2016.

        Under the credit facility, our terminaling service agreements with Morgan Stanley Capital Group relating to our Florida and the Razorback terminals and the Southeast terminals are deemed to be "Specified Contracts." The credit facility further provides that an event of default will occur if any Specified Contract terminates in whole or in part, "if such ... termination would reasonably be expected to result in a Material Adverse Effect after taking into account any replacement therefor." In February 2013, representatives of Morgan Stanley Capital Group indicated that they intend to extend or enter into new terminaling services agreements covering our Florida and the Razorback terminals and the Southeast terminals for periods after the current agreements expire. However, in the event that these terminaling services agreements with Morgan Stanley Capital Group expire and, at that time, we have not secured sufficient replacement customer agreements to replace the majority of the revenues provided for under the expired agreements, an event of default could occur under our bank credit facility.

        The 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 credit facility are (i) a total leverage ratio test (not to exceed 4.75 times), (ii) a senior secured leverage ratio test (not to exceed 3.75 times) in the event we issue senior unsecured notes, and (iii) a minimum interest coverage ratio test (not less than 3.0 times). These financial covenants are based on a defined financial performance measure within the credit facility known as "Consolidated EBITDA." The

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calculation of the "total leverage ratio" and "interest coverage ratio" contained in the credit facility is as follows (in thousands, except ratios):

 
  Three months ended    
 
 
  Twelve
months ended
December 31,
2012
 
 
  March 31,
2012
  June 30,
2012
  September 30,
2012
  December 31,
2012
 

Financial performance debt covenant test:

                               

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

  $ 18,311   $ 19,662   $ 18,102   $ 15,654   $ 71,729  

Consolidated funded indebtedness

                          $ 184,000  

Total leverage ratio

                            2.57x  

Consolidated EBITDA for the interest coverage ratio

  $ 18,311   $ 19,662   $ 18,102   $ 15,654   $ 71,729  

Consolidated interest expense, as stipulated in the credit facility

  $ 681   $ 648   $ 692   $ 834   $ 2,855  

Interest coverage ratio

                            25.12x  

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

                               

Consolidated EBITDA

  $ 18,311   $ 19,662   $ 18,102   $ 15,654   $ 71,729  

Consolidated interest expense

    (681 )   (648 )   (692 )   (834 )   (2,855 )

Amortization of deferred revenue

    (1,144 )   (1,134 )   (1,173 )   (1,173 )   (4,624 )

Amounts due under long-term terminaling services agreements, net

    128     140     179     105     552  

Change in operating assets and liabilities

    (7,076 )   (1,584 )   6,264     1,905     (491 )
                       

Cash flows provided by operating activities

  $ 9,538   $ 16,436   $ 22,680   $ 15,657   $ 64,311  
                       

        If we were to fail either financial performance covenant, or any other covenant contained in the 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 credit facility, and the lenders would be entitled to declare all outstanding borrowings immediately due and payable.

        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, 2012 are as follows (in thousands):

 
  Years ending December 31,  
 
  2013   2014   2015   2016   2017   Thereafter  

Additions to property, plant and equipment under contract

  $ 10,008   $   $   $   $   $  

Operating leases—property and equipment

    1,451     1,536     1,552     1,567     633     4,244  

Long-term debt

                184,000          

Interest expense on debt(1)

    4,416     4,416     4,416     823          
                           

Total contractual obligations to be settled in cash

  $ 15,875   $ 5,952   $ 5,968   $ 186,390   $ 633   $ 4,244  
                           

(1)
Assumes that our outstanding long-term debt at December 31, 2012 remains outstanding until its maturity date under the amended and restated senior secured credit facility and we incur interest

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    expense at the weighted average interest rate on our borrowings outstanding for the three months ended December 31, 2012, which is 2.4% per year.

            Off-Balance Sheet Arrangements.    At December 31, 2012 our outstanding letters of credit were approximately $nil.

            See Notes 2, 10, 11, 12, 14 and 15 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 amended and restated senior secured credit facility, and our relationship with institutional lenders and equity investors should enable us to meet our committed capital and our essential liquidity requirements for the next twelve months.

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 credit facility. Borrowings under our credit facility bear interest at a variable rate based on LIBOR or the lender's base rate. At December 31, 2012, we had outstanding borrowings of $184 million under our credit facility. Based on the outstanding balance of our variable-interest-rate debt at December 31, 2012 and assuming market interest rates increase or decrease by 100 basis points, the potential annual increase or decrease in interest expense is $1.8 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 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, 2012, 2011 and 2010, we sold approximately 161,000, 208,000 and 172,000 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 $121, $118 and $92 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, 2012 and 2011, and the related consolidated statements of comprehensive income, partners' equity, and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these 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, such consolidated financial statements present fairly, in all material respects, the financial position of TransMontaigne Partners L.P. and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

        We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership's internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 12, 2013 expressed an unqualified opinion on the Partnership's internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Denver, Colorado
March 12, 2013

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TransMontaigne Partners L.P. and subsidiaries

Consolidated balance sheets

(Dollars in thousands)

 
  December 31,
2012
  December 31,
2011
 

ASSETS

             

Current assets:

             

Cash and cash equivalents

  $ 6,745   $ 7,138  

Trade accounts receivable, net

    5,035     4,271  

Due from affiliates

    3,035     3,906  

Other current assets

    4,579     22,768  
           

Total current assets

    19,394     38,083  

Property, plant and equipment, net

    427,701     431,782  

Goodwill

    8,736     8,716  

Investments in unconsolidated affiliates

    105,164     25,875  

Other assets, net

    8,806     9,648  
           

  $ 569,801   $ 514,104  
           

LIABILITIES AND EQUITY

             

Current liabilities:

             

Trade accounts payable

  $ 10,810   $ 7,936  

Accrued liabilities

    15,606     19,924  
           

Total current liabilities

    26,416     27,860  

Other liabilities

    10,648     14,368  

Long-term debt

    184,000     120,000  
           

Total liabilities

    221,064     162,228  
           

Partners' equity:

             

Common unitholders (14,457,066 units issued and outstanding at December 31, 2012 and 2011)

    292,648     296,052  

General partner interest (2% interest with 295,042 equivalent units outstanding at December 31, 2012 and 2011)

    56,564     56,490  

Accumulated other comprehensive loss

    (475 )   (666 )
           

Total partners' equity

    348,737     351,876  
           

  $ 569,801   $ 514,104  
           

   

See accompanying notes to consolidated financial statements.

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TransMontaigne Partners L.P. and subsidiaries

Consolidated statements of comprehensive income

(In thousands, except per unit amounts)

 
  Year ended
December 31,
2012
  Year ended
December 31,
2011
  Year ended
December 31,
2010
 

Revenue:

                   

External customers

  $ 45,749   $ 45,576   $ 48,787  

Affiliates

    110,490     106,716     102,112  
               

Total revenue

    156,239     152,292     150,899  
               

Operating costs and expenses and other:

                   

Direct operating costs and expenses

    (65,964 )   (64,498 )   (64,696 )

Direct general and administrative expenses

    (4,810 )   (4,703 )   (3,159 )

Allocated general and administrative expenses

    (10,780 )   (10,466 )   (10,311 )

Allocated insurance expense

    (3,590 )   (3,290 )   (3,185 )

Reimbursement of bonus awards

    (1,250 )   (1,250 )   (1,250 )

Depreciation and amortization

    (28,260 )   (27,654 )   (27,869 )

Gain (loss) on disposition of assets

        9,576     (765 )

Impairment of goodwill

            (8,465 )

Earnings from unconsolidated affiliates

    558     113      
               

Total operating costs and expenses and other

    (114,096 )   (102,172 )   (119,700 )
               

Operating income

    42,143     50,120     31,199  

Other income (expenses):

                   

Interest income

    22     1     8  

Interest expense

    (2,877 )   (2,458 )   (3,405 )

Amortization of deferred financing costs

    (767 )   (1,055 )   (598 )

Foreign currency transaction gain (loss)

    51     (88 )   38  
               

Total other expenses, net

    (3,571 )   (3,600 )   (3,957 )
               

Net earnings

    38,572     46,520     27,242  

Other comprehensive income (loss)—foreign currency translation adjustments

    191     (317 )   120  
               

Comprehensive income

  $ 38,763   $ 46,203   $ 27,362  
               

Net earnings

  $ 38,572   $ 46,520   $ 27,242  

Less—earnings allocable to general partner interest including incentive distribution rights

    (5,157 )   (4,415 )   (3,017 )
               

Net earnings allocable to limited partners

  $ 33,415   $ 42,105   $ 24,225  
               

Net earnings per limited partner unit—basic

  $ 2.31   $ 2.92   $ 1.69  
               

Net earnings per limited partner unit—diluted

  $ 2.31   $ 2.91   $ 1.68  
               

Weighted average limited partner units outstanding—basic

    14,441     14,442     14,363  
               

Weighted average limited partner units outstanding—diluted

    14,448     14,457     14,379  
               

   

See accompanying notes to consolidated financial statements.

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TransMontaigne Partners L.P. and subsidiaries

Consolidated statements of partners' equity

(Dollars in thousands)

 
  Common
units
  General
partner
interest
  Accumulated
other
comprehensive
loss
  Total  

Balance January 1, 2010

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

Proceeds from offering of 2,012,500 common units, net of underwriters' discounts and offering expenses of $2,562

    50,971             50,971  

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

        1,093         1,093  

Distributions to unitholders

    (34,567 )   (3,011 )       (37,578 )

Deferred equity-based compensation related to restricted phantom units

    385             385  

Purchase of 19,435 common units by our long-term incentive plan and from affiliate

    (542 )           (542 )

Issuance of 14,000 common units by our long-term incentive plan due to vesting of restricted phantom units

                 

Net earnings for year ended December 31, 2010

    24,225     3,017         27,242  

Other comprehensive income

                120     120  
                   

Balance December 31, 2010

    289,632     55,533     (349 )   344,816  
                   

Distributions to unitholders

    (35,575 )   (3,926 )       (39,501 )

Deferred equity-based compensation related to restricted phantom units

    419             419  

Purchase of 13,652 common units by our long-term incentive plan and from affiliate

    (529 )           (529 )

Acquisition of Pensacola Terminal from TransMontaigne Inc. in exchange for $12.8 million

        468         468  

Issuance of 11,392 common units by our long-term incentive plan due to vesting of restricted phantom units

                 

Net earnings for year ended December 31, 2011

    42,105     4,415         46,520  

Other comprehensive loss

            (317 )   (317 )
                   

Balance December 31, 2011

    296,052     56,490     (666 )   351,876  
                   

Distributions to unitholders

    (36,763 )   (5,083 )       (41,846 )

Deferred equity-based compensation related to restricted phantom units

    398             398  

Purchase of 12,716 common units by our long-term incentive plan and from affiliate

    (454 )           (454 )

Issuance of 11,980 common units by our long-term incentive plan due to vesting of restricted phantom units

                 

Net earnings for year ended December 31, 2012

    33,415     5,157         38,572  

Other comprehensive income

            191     191  
                   

Balance December 31, 2012

  $ 292,648   $ 56,564   $ (475 ) $ 348,737  
                   

   

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,
2012
  Year ended
December 31,
2011
  Year ended
December 31,
2010
 

Cash flows from operating activities:

                   

Net earnings

  $ 38,572   $ 46,520   $ 27,242  

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

                   

Depreciation and amortization

    28,260     27,654     27,869  

(Gain) loss on disposition of assets

        (9,576 )   765  

Earnings from unconsolidated affiliates

    (558 )   (113 )    

Distributions from unconsolidated affiliates

    1,435     852      

Deferred equity-based compensation

    398     419     385  

Amortization of deferred financing costs

    767     1,055     598  

Amortization of deferred revenue

    (4,624 )   (4,508 )   (3,817 )

Amounts due under long-term terminaling services agreements, net

    552     (579 )   (7 )

Unrealized gain on derivative instrument

        (1,250 )   (1,440 )

Impairment of goodwill

            8,465  

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

                   

Trade accounts receivable, net

    (640 )   2,083     319  

Due from affiliates

    1,662     1,497     2,248  

Other current assets

    203     2,188     738  

Trade accounts payable

    2,623     (1,580 )   692  

Due to affiliates

        (89 )   (32 )

Accrued liabilities

    (4,339 )   1,518     1,311  
               

Net cash provided by operating activities

    64,311     66,091     65,336  
               

Cash flows from investing activities:

                   

Acquisition of terminal facilities

        (12,781 )   (1,633 )

Investments in unconsolidated affiliates

    (80,166 )   (1,021 )    

Capital expenditures—expansion of facilities

    (15,805 )   (33,359 )   (33,290 )

Capital expenditures—maintain existing facilities

    (7,760 )   (7,814 )   (7,675 )

Proceeds in return for contribution of assets to unconsolidated affiliate

        25,593      

Proceeds from sale of assets

    18,000     10,816     5,181  

Other

            (91 )
               

Net cash used in investing activities

    (85,731 )   (18,566 )   (37,508 )
               

Cash flows from financing activities:

                   

Net proceeds from issuance of common units

            50,971  

Contribution of cash by TransMontaigne GP

            1,093  

Borrowings of debt under credit facility

    147,000     80,343     53,000  

Repayments of debt under credit facility

    (83,000 )   (82,343 )   (96,000 )

Deferred debt issuance costs

    (736 )   (3,575 )    

Distributions paid to unitholders

    (41,846 )   (39,501 )   (37,578 )

Purchase of common units by our long-term incentive plan and from affiliate

    (454 )   (529 )   (542 )
               

Net cash provided by (used in) financing activities

    20,964     (45,605 )   (29,056 )
               

(Decrease) increase in cash and cash equivalents

    (456 )   1,920     (1,228 )

Foreign currency translation effect on cash

    63     (135 )   13  

Cash and cash equivalents at beginning of period

    7,138     5,353     6,568  
               

Cash and cash equivalents at end of period

  $ 6,745   $ 7,138   $ 5,353  
               

Supplemental disclosure of cash flow information:

                   

Cash paid for interest

  $ 2,886   $ 3,865   $ 5,258  
               

   

See accompanying notes to consolidated financial statements.

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Notes to Consolidated Financial Statements

Years ended December 31, 2012, 2011 and 2010

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a)   Nature of business

        TransMontaigne Partners L.P. ("Partners") was formed in February 2005 as a Delaware 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 trading, 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 December 31, 2012, TransMontaigne Inc. and Morgan Stanley have a significant interest in our partnership through their indirect ownership of a 22% 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. Investments where we do not have the ability to exercise control, but do have the ability to exercise significant influence, are accounted for using the equity method of accounting. All inter-company accounts and transactions have been eliminated in the preparation of the accompanying consolidated financial statements. The accompanying consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly our financial position as of December 31, 2012 and 2011, our results of operations for the years ended December 31, 2012, 2011 and 2010 and our cash flows for the years ended December 31, 2012, 2011 and 2010.

        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: useful lives of our plant and equipment, accrued environmental obligations and determining the fair value of our reporting units when analyzing goodwill. 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 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

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Notes to Consolidated Financial Statements (Continued)

Years ended December 31, 2012, 2011 and 2010

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

and administrative expenses were approximately $10.8 million, $10.5 million and $10.3 million for the years ended December 31, 2012, 2011 and 2010, 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 $3.6 million, $3.3 million and $3.2 million for the years ended December 31, 2012, 2011 and 2010, respectively. The accompanying consolidated financial statements also include reimbursement of amounts 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 who provide services to Partners that vest over future periods. The reimbursement of bonus awards was approximately $1.3 million for each of the years ended December 31, 2012, 2011 and 2010, 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 net 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.

        Pursuant to terminaling services agreements with certain of 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. For the years ended December 31, 2012, 2011 and 2010, we recognized revenue of approximately $16.1 million, $18.7 million and $12.8 million, respectively, for net product gained. Within these amounts, approximately $13.6 million, $16.8 million and $12.1 million, respectively, were pursuant to terminaling services agreements with affiliate customers.

(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 terminals and pipelines, and 3 to 25 years for furniture, fixtures and 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.

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Notes to Consolidated Financial Statements (Continued)

Years ended December 31, 2012, 2011 and 2010

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

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

(f)    Investments in unconsolidated affiliates

        We account for our investments in our unconsolidated affiliates, which we do not control but do have the ability to exercise significant influence over, using the equity method of accounting. Under this method, the investment is recorded at acquisition cost, increased by our proportionate share of any earnings and additional capital contributions and decreased by our proportionate share of any losses, distributions received, and amortization of any excess investment. Excess investment is the amount by which our total investment exceeds our proportionate share of the book value of the net assets of the investment entity. We evaluate our investments in unconsolidated affiliates for impairment whenever events or circumstances indicate there is a loss in value of the investment that is other than temporary. In the event of impairment, we would record a charge to earnings to adjust the carrying amount to fair value.

(g)   Environmental obligations

        We accrue for environmental costs that relate to existing conditions caused by past operations when estimable (see Note 10 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. agreed to indemnify us against certain potential environmental claims, losses and expenses that were identified on or before May 27, 2010 and that were associated with the ownership or operation of the Florida and Midwest terminal facilities prior to 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. agreed to indemnify us against certain potential environmental claims, losses and expenses that were identified on or before December 31, 2011 and that were associated with the ownership or operation of the Brownsville and River facilities

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Notes to Consolidated Financial Statements (Continued)

Years ended December 31, 2012, 2011 and 2010

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

prior to 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. agreed to indemnify us against certain potential environmental claims, losses and expenses that were identified on or before December 31, 2012 and that were associated with the ownership or operation of the Southeast terminals prior to 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). TransMontaigne Inc. has agreed to indemnify us against certain potential environmental claims, losses and expenses that are identified on or before March 1, 2016 and that were associated with the ownership or operation of the Pensacola terminal prior to March 1, 2011, up to a maximum liability not to exceed $2.5 million for this indemnification obligation (see Note 2 of Notes to consolidated financial statements).

(h)   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. Generally accepted accounting principles require 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. If and when it is determined that a legal obligation has been incurred, the fair value of the liability is determined based on estimates and assumptions related to retirement costs, future inflation rates and interest rates. Our long-lived assets include above-ground storage facilities and underground pipelines. We are unable to predict if and when these long-lived assets will become completely obsolete and require dismantlement. We have not recorded an asset retirement obligation, or corresponding asset, because the future dismantlement and removal dates of our long-lived assets is indeterminable and the amount of any associated costs are believed to be insignificant. Changes in our estimates and assumptions may occur as a result of the passage of time and the occurrence of future events.

(i)    Equity-based compensation plan

        Generally accepted accounting principles require 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.

(j)    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

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Years ended December 31, 2012, 2011 and 2010

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

in the consolidated statements of comprehensive income. 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 other income (expenses) in the consolidated statements of comprehensive income.

(k)   Accounting for derivative instruments

        Generally accepted accounting principles require us to recognize all derivative instruments at fair value in the consolidated balance sheet as assets or liabilities. Changes in the fair value of our derivative instruments are recognized as a component of net earnings unless specific hedge accounting criteria are met.

        We did not have any derivative instruments during the year ended December 31, 2012. During the years ended December 31, 2011 and 2010, our derivative instruments were limited to an interest rate swap agreement with a notional amount of $150.0 million. Our interest rate swap agreement expired in June 2011. The interest rate swap reduced our cash exposure to changes in interest rates by converting variable interest rates to fixed interest rates. Pursuant to the terms of the interest rate swap agreement, we paid a fixed rate of approximately 2.2% and received an interest payment based on the one-month LIBOR. The net difference to be paid or received under the interest rate swap agreement was settled monthly and was recognized as an adjustment to interest expense. For the years ended December 31, 2012, 2011 and 2010, we recognized net payments to the counterparty of $nil and approximately $1.3 million and $2.8 million, respectively.

        At the time we entered into the interest rate swap we did not designate it as a hedge, and therefore the change in the fair value of our interest rate swap is included in the consolidated statements of comprehensive income. During the years ended December 31, 2012, 2011 and 2010, we recognized unrealized gains in the amount of $nil and approximately $1.3 million and $1.4 million, respectively, related to the estimated change in the fair value of the interest rate swap, which was recorded as a reduction to interest expense. The fair value of our interest rate swap was 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.

(l)    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, primarily 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 generally accepted accounting principles. Currently, Mexican federal and provincial income taxes and U.S. state income taxes are not material.

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Years ended December 31, 2012, 2011 and 2010

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

(m)  Net earnings per limited partner unit

        Generally accepted accounting principles address 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. Any excess of distributions over earnings are allocated to the limited partners and general partner interest based on their respective sharing of losses specified in the partnership agreement, which is based on their ownership percentages of 98% and 2%, respectively. Incentive distribution rights do not share in losses under our partnership agreement. The earnings allocable to the general partner interest for the period represents distributions attributable to the period on behalf of the general partner interest and any incentive distribution rights less the excess of distributions over earnings allocated to the limited partners (see Note 16 of Notes to consolidated financial statements). 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.

(2) TRANSACTIONS WITH AFFILIATES

        Constraints on expansion.    Morgan Stanley informed us in October 2011 that, for the foreseeable future, it does not expect to approve any "significant" acquisition or investment that we may propose. Morgan Stanley's decision is the result of the uncertain regulatory environment relating to Morgan Stanley's status as a financial holding company subject to the Bank Holding Company Act and consolidated supervision by the Board of Governors of the Federal Reserve System. Morgan Stanley indicated that it has not established a specific definition of what constitutes a "significant" investment and significance may be determined on either a quantitative or qualitative basis, depending on the facts and circumstances and relevant legal and regulatory considerations. Morgan Stanley has informed us they will review on a case by case basis each proposed transaction to determine its significance, whether an acquisition of, or investment in, assets or legal entities and that an acquisition of, or investment in, a noncontrolling interest or joint venture interest may be "significant" without respect to the size of the transaction. The practical effect of these limitations is to significantly constrain our ability to expand our asset base and operations through acquisitions from third parties. These constraints will reduce the potential for increasing our distributions to unitholders in the future. In addition, these constraints will limit additions to our capital assets primarily to additions and improvements that we construct or add to our existing facilities, although some acquisitions of assets from third parties may be possible to the extent approved by Morgan Stanley. For example, our December 2012 investment in Battleground Oil Specialty Terminal Company LLC ("BOSTCO") was approved by Morgan Stanley based on the specific facts and circumstances of the BOSTCO project and the structure of our investment in BOSTCO, and is not indicative of whether Morgan Stanley will approve any other acquisition or investment that we may propose in the future (see Note 3 of Notes to consolidated financial statements).

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Years ended December 31, 2012, 2011 and 2010

(2) TRANSACTIONS WITH AFFILIATES (Continued)

        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, 2013, the annual administrative fee payable to TransMontaigne Inc. will be approximately $10.9 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, 2013, the annual insurance reimbursement payable to TransMontaigne Inc. will be approximately $3.7 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, 2012, we have agreed to reimburse TransMontaigne Inc. and its affiliates approximately $1.3 million.

        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 no less than 105% of the fees offered by the third party customer.

        Environmental indemnification.    In connection with our acquisition of the Florida and Midwest terminals, TransMontaigne Inc. agreed to indemnify us against certain potential environmental claims, losses and expenses that were identified on or before May 27, 2010, and that were associated with the ownership or operation of the Florida and Midwest terminals prior to May 27, 2005. TransMontaigne

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Years ended December 31, 2012, 2011 and 2010

(2) TRANSACTIONS WITH AFFILIATES (Continued)

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, Texas and River terminals, TransMontaigne Inc. agreed to indemnify us against potential environmental claims, losses and expenses that were identified on or before December 31, 2011, and that were associated with the ownership or operation of the Brownsville and River facilities prior to December 31, 2006. 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. The deductible amount, cap amount and limitation of time for indemnification do 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 against potential environmental claims, losses and expenses that were identified on or before December 31, 2012, and that were associated with the ownership or operation of the Southeast terminals prior to December 31, 2007. 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. The deductible amount, cap amount and limitation of time for indemnification do 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.

        In connection with our acquisition of the Pensacola terminal, TransMontaigne Inc. agreed to indemnify us against potential environmental claims, losses and expenses that are identified on or before March 1, 2016, and that are associated with the ownership or operation of the Pensacola terminal prior to March 1, 2011. Our environmental losses must first exceed $200,000 and TransMontaigne Inc.'s indemnification obligations are capped at $2.5 million. The deductible amount, cap amount and limitation of time for indemnification do not apply to any environmental liabilities known to exist as of March 1, 2011. 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 March 1, 2011.

        Terminaling services agreement—Florida terminals and Razorback pipeline system.    We have a terminaling services agreement with Morgan Stanley Capital Group relating to our Florida, Mount 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 of the agreement expires on May 31, 2014. After May 31, 2014, 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 May 31, 2014 or the then-current renewal term. Under this agreement, Morgan Stanley Capital Group agreed to throughput a volume of refined product that, at the fee and tariff schedule contained in the agreement, resulted in minimum throughput payments to us of approximately $37 million for the contract year ended May 31, 2012 (approximately $37.3 million for the contract year ending May 31, 2013); with stipulated annual increases in throughput payments

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Years ended December 31, 2012, 2011 and 2010

(2) TRANSACTIONS WITH AFFILIATES (Continued)

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 us unable to perform our obligations with respect to an asset, 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 may terminate its obligations with respect to the asset affected by the force majeure event and their minimum revenue commitment would be reduced proportionately for the duration of the agreement.

        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.

        Terminaling services agreement—Fisher Island terminal.    We have a terminaling services agreement with TransMontaigne Inc. that will expire on December 31, 2013. Under this agreement, TransMontaigne Inc. agreed to throughput at our Fisher Island terminal in the Gulf Coast region a volume of fuel oils that, at the fee schedule contained in the agreement, resulted in minimum revenue to us of approximately $1.8 million for the contract year ended December 31, 2012. In exchange for its minimum throughput commitment, we agreed to provide TransMontaigne Inc. with approximately 185,000 barrels of fuel oil capacity.

        Terminaling services agreement—Mobile terminal.    We had a terminaling services agreement with TransMontaigne Inc. that terminated on December 17, 2010 with the sale of the Mobile terminal (see Note 3 of Notes to consolidated financial statements). As consideration for the early termination of the terminaling services agreement and release of TransMontaigne Inc. from its obligations thereunder, we received an early termination payment of approximately $1.3 million. Under this agreement, TransMontaigne Inc. agreed to throughput at our Mobile terminal a volume of refined products that, at the fee schedule contained in the agreement, resulted in minimum revenue to us of approximately $2.5 million for the contract year ending December 31, 2010.

        Terminaling services agreement—Cushing terminal.    In July 2011, we entered into a terminaling services agreement with Morgan Stanley Capital Group relating to our Cushing, Oklahoma facility that will expire in July 2019, subject to a five-year automatic renewal unless terminated by either party upon 180 days prior notice. In exchange for its minimum revenue commitment, we agreed to construct storage tanks and associated infrastructure to provide 1.0 million barrels of crude oil capacity. These capital projects were completed and placed into service on August 1, 2012. Under this agreement, Morgan Stanley Capital Group agreed to throughput a volume of crude oil products at our terminal that will, at the fee schedule contained in the agreement, result in minimum throughput payments to us of approximately $4.3 million for each one-year period following the in-service date of August 1, 2012.

        If a force majeure event occurs that renders us unable to perform our obligations with respect to an asset, Morgan Stanley Capital Group's obligations would be temporarily suspended with respect to that asset. If a force majeure event continues for 120 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 may terminate its obligations with respect to the asset affected by the force

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Years ended December 31, 2012, 2011 and 2010

(2) TRANSACTIONS WITH AFFILIATES (Continued)

majeure event and their minimum revenue commitment would be reduced proportionately for the duration of the agreement.

        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 Cushing terminal.

        Terminaling services agreement—Brownsville LPG.    We had a terminaling services agreement with TransMontaigne Inc. relating to our Brownsville, Texas facilities that terminated on December 31, 2012. The storage capacity under this agreement is now under contract with a third party beginning January 1, 2013. Under this agreement, TransMontaigne Inc. agreed to throughput at our Brownsville facilities certain minimum volumes of natural gas liquids that resulted in minimum revenue to us of approximately $1.3 million for the contract year ended December 31, 2012. In exchange for TransMontaigne Inc.'s minimum throughput commitment, we agreed to provide TransMontaigne Inc. approximately 33,000 barrels of storage capacity at our Brownsville facilities.

        Operations and reimbursement agreement—Frontera.    Effective as of April 1, 2011, we entered into the Frontera joint venture in which we have a 50% ownership interest (see Note 3 of Notes to consolidated financial statements). In conjunction with us entering into the joint venture, we agreed to operate Frontera, in accordance with an operations and reimbursement agreement executed between us and Frontera, for a management fee that is based on our costs incurred. Our agreement with Frontera stipulates that we may resign as the operator at any time with the prior written consent of Frontera, or that we may be removed as the operator for good cause, which includes material noncompliance with laws and material failure to adhere to good industry practice regarding health, safety or environmental matters. For the years ended December 31, 2012 and 2011, we recognized approximately $3.4 million and $1.9 million, respectively, of revenue related to this operations and reimbursement agreement.

        Terminaling services agreement—Southeast terminals.    We have a terminaling 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, at the fee schedule contained in the agreement, resulted in minimum throughput payments to us of approximately $35.4 million for the contract year ended December 31, 2012; 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 8.9 million barrels of light oil storage capacity at our Southeast terminals and to undertake certain capital projects to provide ethanol blending functionality at certain of our Southeast terminals with completion dates that extended through August 31, 2011. Upon the completion of each of the projects, Morgan Stanley Capital Group paid us a lump-sum ethanol blending fee that in total equaled approximately $22.5 million.

        If a force majeure event occurs that renders us unable to perform our obligations with respect to an asset, 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

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Years ended December 31, 2012, 2011 and 2010

(2) TRANSACTIONS WITH AFFILIATES (Continued)

diminution in the storage capacity we make available to Morgan Stanley Capital Group, Morgan Stanley Capital Group may terminate its obligations with respect to the asset affected by the force majeure event and their minimum revenue commitment would be reduced proportionately for the duration of the agreement.

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

        Terminaling services agreement—Collins/Purvis terminal.    In January 2010, we entered into a terminaling services agreement with Morgan Stanley Capital Group relating to our Collins, Mississippi facility that will expire in July 2018, subject to one-year automatic renewals unless terminated by either party upon 180 days prior notice. 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. These capital projects were completed and placed into service in July 2011. Under this agreement, Morgan Stanley Capital Group has 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 of July 2011 for the aforementioned capital projects, and for each contract year thereafter.

        If a force majeure event occurs that renders us unable to perform our obligations with respect to an asset, 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 may terminate its obligations with respect to the asset affected by the force majeure event and their minimum revenue commitment would be reduced proportionately for the duration of the agreement.

        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.

(3) ACQUISITIONS AND DISPOSITIONS

        Investment in BOSTCO project.    On December 20, 2012, we acquired a 42.5% interest in Battleground Oil Specialty Terminal Company LLC ("BOSTCO"), for approximately $79 million, from Kinder Morgan Energy Partners, L.P. ("Kinder Morgan"). We funded this acquisition utilizing additional borrowings under our credit facility. BOSTCO is a new black oil terminal facility on the Houston Ship Channel designed to handle residual fuel, feedstocks, distillates and other black oils. The initial phase of the BOSTCO project involves construction of 50 storage tanks with approximately 6.1 million barrels of storage capacity at an estimated cost of approximately $425 million. The BOSTCO facility is scheduled to begin commercial operation in the fourth quarter of 2013. Completion of the full 6.1 million barrels of storage capacity and related infrastructure is scheduled for early 2014. Upon completion of the project, and assuming we maintain our 42.5% interest, we expect our total payments for the project to be approximately $183 million, which includes our December 20, 2012 investment of approximately $79 million.

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Years ended December 31, 2012, 2011 and 2010

(3) ACQUISITIONS AND DISPOSITIONS (Continued)

        Our investment in BOSTCO entitles us to appoint a member to the Board of Managers of BOSTCO to vote our proportionate ownership share on general governance matters and to certain rights of approval over significant changes in, or expansion of, BOSTCO's business. Kinder Morgan will be responsible for managing BOSTCO's day-to-day operations. Our 42.5% interest does not allow us to control BOSTCO, but does allow us to exercise significant influence over its operations. Accordingly, as of December 20, 2012 we account for our investment in BOSTCO under the equity method of accounting.

        We originally initiated the BOSTCO project by acquiring approximately 190 acres of undeveloped land on the Houston Ship Channel in November 2010. During 2010 and 2011, we undertook the design, permitting and initial development of BOSTCO. On October 18, 2011, as part of our original plan to involve one or more strategic partners, we sold 50% of our interest in the BOSTCO project to Kinder Morgan for approximately $10.8 million. The consideration received was equivalent to 50% of our recorded investment in the BOSTCO project at the time of the sale, and, accordingly, no gain or loss was recognized.

        On December 29, 2011, as a result of Morgan Stanley's October 2011 determination that we cannot continue to pursue any "significant" acquisition or investment, we sold our remaining 50% interest in BOSTCO to Kinder Morgan for $18 million plus a transferrable option to buy up to 50% of Kinder Morgan's interest in the project at any time prior to January 20, 2013. The $18 million was equivalent to the amount we had recorded for our remaining 50% interest in the BOSTCO project and, accordingly, no gain or loss was recognized. The $18 million was not received by us until January 3, 2012, and at December 31, 2011 is reflected in other current assets as amounts due from the sale of the BOSTCO project (see Note 5 of Notes to consolidated financial statements).

        Our December 20, 2012 reentry into the BOSTCO project was approved by Morgan Stanley based on the specific facts and circumstances of the BOSTCO project and the structure of our investment in BOSTCO, and is not indicative of whether Morgan Stanley will approve any other acquisition or investment that we may propose in the future.

        Contribution of certain Brownsville, Texas terminal assets to Frontera.    Effective as of April 1, 2011, we entered into a joint venture with P.M.I. Services North America Inc. ("PMI"), an indirect subsidiary of Petroleos Mexicanos ("PEMEX"), the Mexican state- owned petroleum company, at our Brownsville, Texas terminal. We contributed approximately 1.4 million barrels of light petroleum product storage capacity, as well as related ancillary facilities, to the joint venture, also known as Frontera Brownsville LLC or "Frontera", in exchange for a cash payment of approximately $25.6 million and a 50% ownership interest. PMI acquired a 50% ownership interest in Frontera for a cash payment of approximately $25.6 million. We operate the Frontera assets under an operations and reimbursement agreement executed between us and Frontera. All significant decisions affecting the business are decided by PMI and us based upon our respective 50% ownership interests. We continue to own and operate approximately 0.9 million barrels of tankage in Brownsville independent of Frontera.

        The assets contributed to Frontera constitute a business that we no longer control. We accounted for the deconsolidation of these assets by recognizing a gain on disposition of assets of approximately $9.6 million in the accompanying consolidated statement of comprehensive income for the year ended December 31, 2011. The gain was measured as the difference between the carrying amount of the contributed assets and the aggregate of the cash we received and the fair value of the 50% interest we

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Years ended December 31, 2012, 2011 and 2010

(3) ACQUISITIONS AND DISPOSITIONS (Continued)

retained in Frontera. The approximate $7.5 million carrying amount of goodwill associated with the contributed assets was disposed. The carrying amount of goodwill disposed was based on the relative fair values of the contributed assets and the portion of Brownsville assets retained by us independent of Frontera. The fair value of the contributed assets was determined based on the cash payment made by PMI to acquire a 50% interest in Frontera multiplied by two. The fair value of the assets retained in Brownsville independent of Frontera was estimated using a discounted cash flow model, similar to the model we use to evaluate the recovery of goodwill on at least an annual basis. At the time of our contribution of assets to Frontera, the carrying amount of the contributed assets was approximately $41.6 million and consisted of the following as of April 1, 2011 (in thousands):

Other current assets

  $ 98  

Property, plant and equipment, net

    33,244  

Goodwill

    7,481  

Other assets, net—customer relationships, net

    787  
       

Total carrying amount

  $ 41,610  
       

        We account for our investment in Frontera, which we do not control but do have the ability to exercise significant influence over, using the equity method of accounting. Under this method, the investment was initially recorded at the fair value of our 50% ownership interest on April 1, 2011.

        Acquisition of Pensacola terminal.    Effective as of March 1, 2011, we acquired from TransMontaigne Inc. its Pensacola, Florida refined petroleum products terminal with approximately 270,000 barrels of aggregate active storage capacity for a cash payment of approximately $12.8 million. The Pensacola terminal provides integrated terminaling services principally to a third party customer. The acquisition of the Pensacola terminal from TransMontaigne Inc. has been recorded at carryover basis in a manner similar to a reorganization of entities under common control. As TransMontaigne Inc. controls our general partner, the difference between the consideration we paid to TransMontaigne Inc. and the carryover basis of the net assets purchased has been reflected in the accompanying consolidated balance sheet and changes in partners' equity as an increase to the general partner's equity interest. The accompanying consolidated financial statements include the assets, liabilities and results of operations of the Pensacola Terminal from March 1, 2011.

        The carryover basis in the assets and liabilities of the Pensacola terminal as of March 1, 2011 was as follows (in thousands):

Cash and cash equivalents

  $ 1  

Other current assets

    61  

Property, plant and equipment, net

    13,232  

Accrued liabilities

    (45 )
       

Total carryover basis

  $ 13,249  
       

        Disposition of Mobile terminal.    On December 17, 2010, we sold our Mobile terminal with approximately 163,000 barrels of aggregate active storage capacity to an unaffiliated third party for cash proceeds of approximately $3.9 million. The accompanying consolidated financial statements exclude the assets, liabilities and results of operations of these assets subsequent to December 17, 2010.

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Notes to Consolidated Financial Statements (Continued)

Years ended December 31, 2012, 2011 and 2010

(3) ACQUISITIONS AND DISPOSITIONS (Continued)

        Acquisition of Collins and Bainbridge terminals.    On April 27, 2010, we purchased from BP Products North America Inc. ("BP"), two refined product terminals with approximately 60,000 barrels and 110,000 barrels of aggregate active storage capacity in Collins, Mississippi and Bainbridge, Georgia, respectively, for cash consideration of approximately $1.6 million. We previously managed and operated these two refined product terminals that are adjacent to our Collins and Bainbridge terminals and received a reimbursement of their proportionate share of operating and maintenance costs. These two refined product terminals currently provide integrated terminaling services to Morgan Stanley Capital Group. The accompanying consolidated financial statements include the assets, liabilities and results of operations of these assets from April 27, 2010.

(4) CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE

        Our primary market areas are located 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 have a concentration of trade receivable balances due from companies engaged in the trading, distribution and marketing of refined products and crude oil, and the United States government. These concentrations of customers may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. Our customers' historical financial and operating information is analyzed prior to extending credit. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions we may request letters of credit, prepayments or guarantees. We maintain allowances for potentially uncollectible accounts receivable.

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

 
  December 31,
2012
  December 31,
2011
 

Trade accounts receivable

  $ 5,235   $ 4,471  

Less allowance for doubtful accounts

    (200 )   (200 )
           

  $ 5,035   $ 4,271  
           

        The following table presents a rollforward of our allowance for doubtful accounts (in thousands):

 
  Balance at
beginning
of period
  Charged
to
expenses
  Deductions   Balance at
end of
period
 

2012

  $ 200   $   $   $ 200  

2011

  $ 310   $   $ (110 ) $ 200  

2010

  $ 394   $   $ (84 ) $ 310  

        The following customer accounted for at least 10% of our consolidated revenue in at least one of the periods presented in the accompanying consolidated statements of comprehensive income:

 
  Year ended
December 31,
2012
  Year ended
December 31,
2011
  Year ended
December 31,
2010
 

Morgan Stanley Capital Group

    64 %   65 %   61 %

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Notes to Consolidated Financial Statements (Continued)

Years ended December 31, 2012, 2011 and 2010

(5) OTHER CURRENT ASSETS

        Other current assets are as follows (in thousands):

 
  December 31,
2012
  December 31,
2011
 

Amounts due from insurance companies

  $ 2,631   $ 2,695  

Amounts due from the sale of the BOSTCO project

        18,000  

Additive detergent

    1,603     1,812  

Deposits and other assets

    345     261  
           

  $ 4,579   $ 22,768  
           

        Amounts due from insurance companies.    We periodically file claims for recovery of environmental remediation costs with our insurance carriers under our comprehensive liability policies. We recognize our insurance recoveries in the period that we assess the likelihood of recovery as being probable (i.e., likely to occur). At December 31, 2012 and December 31, 2011, we have recognized amounts due from insurance companies of approximately $2.6 million and $2.7 million, respectively, representing our best estimate of our probable insurance recoveries. During the year ended December 31, 2012, we received reimbursements from insurance companies of approximately $1.2 million. During the year ended December 31, 2012, we increased our estimate of insurance recoveries approximately $1.1 million to reflect a change in our estimate of our future environmental remediation costs (see Note 10 of Notes to consolidated financial statements).

        Amounts due from the sale of the BOSTCO project.    On December 29, 2011 we sold our remaining interest in the BOSTCO project, which at that time represented 50% of the outstanding ownership interest, for $18 million and a transferrable purchase option to buy back into the project at any time prior to January 20, 2013, which we exercised on December 20, 2012 to reacquire a 42.5% interest in BOSTCO (see Note 3 of Notes to consolidated financial statements). The $18 million in cash consideration was received on January 3, 2012 and, accordingly, has been reflected as amounts due at December 31, 2011.

(6) PROPERTY, PLANT AND EQUIPMENT, NET

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

 
  December 31,
2012
  December 31,
2011
 

Land

  $ 52,652   $ 52,641  

Terminals, pipelines and equipment

    552,232     524,346  

Furniture, fixtures and equipment

    1,716     1,507  

Construction in progress

    4,652     8,745  
           

    611,252     587,239  

Less accumulated depreciation

    (183,551 )   (155,457 )
           

  $ 427,701   $ 431,782  
           

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Notes to Consolidated Financial Statements (Continued)

Years ended December 31, 2012, 2011 and 2010

(7) GOODWILL

        Goodwill is as follows (in thousands):

 
  December 31,
2012
  December 31,
2011
 

Brownsville terminals (includes approximately $55 and $75, respectively, of foreign currency translation adjustments)

  $ 8,736   $ 8,716  

        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 18 of Notes to consolidated financial statements). The fair value of each reporting unit is determined on a stand-alone basis from the perspective of a market participant and represents an estimate of the price that would be received to sell the unit as a whole in an orderly transaction between market participants at the measurement date. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered to be impaired.

        At December 31, 2012 and 2011, our only reporting unit that contained goodwill was our Brownsville terminals. Our estimate of the fair value of our Brownsville terminals at December 31, 2012 and 2011 exceeded its carrying amount. Accordingly, we did not recognize any goodwill impairment charges during the years ended December 31, 2012 and 2011, respectively, for this reporting unit. However, a significant decline in the price of our common units with a resulting increase in the assumed market participants' weighted average cost of capital, the loss of a significant customer, the disposition of significant assets, or an unforeseen increase in the costs to operate and maintain the Brownsville terminals, could result in the recognition of an impairment charge in the future.

        At December 31, 2010, our estimate of the fair value of our River terminals was less than its carrying amount. The decline in the estimated fair value was attributable primarily to the loss of a customer in 2010 at one of our larger River facilities and the underutilization of certain other facilities in the River region. This resulted in a determination that goodwill for the River terminals reporting unit, as of December 31, 2010, was no longer supported by its estimated fair value and, as a result, we recognized an $8.5 million impairment charge reflected in our accompanying consolidated statement of comprehensive income for the year ended December 31, 2010. Subsequent to December 31, 2010, there was no longer any goodwill recorded related to the River terminals reporting unit.

(8) INVESTMENTS IN UNCONSOLIDATED AFFILIATES

        At December 31, 2012, our investments in unconsolidated affiliates include a 42.5% interest in BOSTCO and a 50% interest in Frontera. At December 31, 2011, our investments in unconsolidated affiliates include a 50% interest in Frontera. BOSTCO is a terminal facility construction project for 6.1 million barrels of storage capacity at an estimated cost of approximately $425 million. BOSTCO is located on the Houston Ship Channel and is scheduled to begin commercial operations in the fourth quarter of 2013. Frontera is a terminal facility located in Brownsville, Texas that encompasses approximately 1.4 million barrels of light petroleum product storage capacity, as well as related ancillary facilities (see Note 3 of Notes to consolidated financial statements).

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Notes to Consolidated Financial Statements (Continued)

Years ended December 31, 2012, 2011 and 2010

(8) INVESTMENTS IN UNCONSOLIDATED AFFILIATES (Continued)

        The following table summarizes our investments in unconsolidated affiliates:

 
  Percentage
of ownership
December 31,
  Carrying value
(in thousands)
December 31,
 
 
  2012   2011   2012   2011  

BOSTCO

    42.5 %     $ 78,930   $  

Frontera

    50 %   50 %   26,234     25,875  
                       

Total investments in unconsolidated affiliates

              $ 105,164   $ 25,875  
                       

        As of December 31, 2012, our investment in BOSTCO includes approximately $2.9 million of excess investment related to a one time buy-in fee paid to Kinder Morgan to acquire our 42.5% interest and capitalization of interest on our investment during the construction of BOSTCO. Excess investment is the amount by which our investment exceeds our proportionate share of the book value of the net assets of the BOSTCO entity.

        Earnings from investments in unconsolidated affiliates were as follows (in thousands):

 
  Year ended
December 31,
2012
  Year ended
December 31,
2011
  Year ended
December 31,
2010
 

BOSTCO

  $   $   $  

Frontera

    558     113      
               

Total earnings from unconsolidated affiliates

  $ 558   $ 113   $  
               

        The financial information of our investments in unconsolidated affiliates was as follows (in thousands):

        Balance sheets:

 
  BOSTCO
December 31,
  Frontera
December 31,
 
 
  2012   2011   2012   2011  

Current assets

  $   $ 9,936   $ 4,209   $ 4,045  

Long-term assets

    234,520     26,064     50,013     48,859  

Current liabilities

    (55,541 )       (1,754 )   (1,154 )

Long-term liabilities

                 
                   

Net assets

  $ 178,979   $ 36,000   $ 52,468   $ 51,750  
                   

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Notes to Consolidated Financial Statements (Continued)

Years ended December 31, 2012, 2011 and 2010

(8) INVESTMENTS IN UNCONSOLIDATED AFFILIATES (Continued)

        Statements of comprehensive income:

 
  BOSTCO
Year ended
December 31,
  Frontera
Year ended
December 31,
 
 
  2012   2011   2012   2011  

Operating revenue

  $   $   $ 11,539   $ 8,440  

Operating expenses

            (10,423 )   (8,214 )
                   

Net earnings and comprehensive income

  $   $   $ 1,116   $ 226  
                   

(9) OTHER ASSETS, NET

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

 
  December 31,
2012
  December 31,
2011
 

Amounts due under long-term terminaling services agreements:

             

External customers

  $ 652   $ 760  

Morgan Stanley Capital Group

    3,648     4,146  
           

    4,300     4,906  

Deferred financing costs, net of accumulated amortization of $1,328 and $561, respectively

    3,088     3,119  

Customer relationships, net of accumulated amortization of $1,283 and $1,080, respectively

    1,147     1,350  

Deposits and other assets

    271     273  
           

  $ 8,806   $ 9,648  
           

        Amounts due under long-term terminaling services agreements.    We have long-term terminaling services agreements with certain of our customers that provide for minimum payments that increase over the terms of the respective agreements. We recognize as revenue the minimum payments under the long-term terminaling services agreements on a straight-line basis over the term of the respective agreements. At December 31, 2012 and 2011, we have recognized revenue in excess of the minimum payments that are due through those respective dates under the long-term terminaling services agreements resulting in an asset of approximately $4.3 million and $4.9 million, respectively.

        Deferred financing costs.    Deferred financing costs are amortized using the effective interest method over the term of the related credit facility (see Note 12 of Notes to consolidated financial statements).

        Customer relationships.    Our acquisitions from TransMontaigne Inc. have been recorded at TransMontaigne Inc.'s carryover basis in a manner similar to a reorganization of entities under common control. Other assets, net include the carryover basis of certain customer relationships. The carryover basis of the customer relationships is being amortized on a straight-line basis over twelve years.

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Notes to Consolidated Financial Statements (Continued)

Years ended December 31, 2012, 2011 and 2010

(9) OTHER ASSETS, NET (Continued)

Expected amortization expense for the customer relationships as of December 31, 2012 is as follows (in thousands):

 
  Years ending December 31,    
 
 
  2013   2014   2015   2016   2017   Thereafter  

Amortization expense

  $ 203   $ 203   $ 203   $ 203   $ 203   $ 132  

(10) ACCRUED LIABILITIES

        Accrued liabilities are as follows (in thousands):

 
  December 31,
2012
  December 31,
2011
 

Customer advances and deposits:

             

External customers

  $ 1,205   $ 1,364  

Morgan Stanley Capital Group

    3,470     6,378  
           

    4,675     7,742  

Accrued property taxes

    658     558  

Accrued environmental obligations

    3,116     2,887  

Interest payable

    39     48  

Rebate due to Morgan Stanley Capital Group

    3,402     5,877  

Accrued expenses and other

    3,716     2,812  
           

  $ 15,606   $ 19,924  
           

        Customer advances and deposits.    We bill certain of our customers one month in advance for terminaling services to be provided in the following month. At December 31, 2012 and 2011, we have billed and collected from certain of our customers approximately $4.7 million and $7.7 million, respectively, in advance of the terminaling services being provided.

        Accrued environmental obligations.    At December 31, 2012 and 2011, we have accrued environmental obligations of approximately $3.1 million and $2.9 million, respectively, representing our best estimate of our remediation obligations. During the year ended December 31, 2012, we made payments of approximately $1.1 million towards our environmental remediation obligations. During the year ended December 31, 2012, we increased our remediation obligations by approximately $1.3 million to reflect a change in our estimate of our future environmental remediation costs. Changes in our estimates of our future environmental remediation obligations may occur as a result of the passage of time and the occurrence of future events.

        Rebate due to Morgan Stanley Capital Group.    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, 2012 and 2011, we have accrued a liability due to Morgan Stanley Capital Group of approximately $3.4 million and $5.9 million, respectively. During the three months ended March 31, 2012, we paid Morgan Stanley Capital Group approximately $5.9 million for the rebate due to Morgan Stanley Capital Group for the year ended December 31, 2011.

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Notes to Consolidated Financial Statements (Continued)

Years ended December 31, 2012, 2011 and 2010

(11) OTHER LIABILITIES

        Other liabilities are as follows (in thousands):

 
  December 31,
2012
  December 31,
2011
 

Advance payments received under long-term terminaling services agreements

  $ 1,067   $ 1,121  

Deferred revenue—ethanol blending fees and other projects

    9,581     13,247  
           

  $ 10,648   $ 14,368  
           

        Advance payments received under long-term terminaling services agreements.    We have long-term terminaling services agreements with certain of our customers that provide for advance minimum payments. We recognize the advance minimum payments as revenue either on a straight-line basis over the term of the respective agreements or when services have been provided based on volumes of product distributed. At December 31, 2012 and 2011, we have received advance minimum payments in excess of revenue recognized under these long-term terminaling services agreements resulting in a liability of approximately $1.1 million and $1.1 million, respectively.

        Deferred revenue—ethanol blending fees and other projects.    Pursuant to agreements with Morgan Stanley Capital Group and others, we agreed to undertake certain capital projects that primarily pertain to providing ethanol blending functionality at certain of our Southeast terminals. Upon completion of the projects, Morgan Stanley Capital Group and others have agreed to pay us lump-sum amounts that will be recognized as revenue on a straight-line basis over the remaining term of the agreements. At December 31, 2012 and 2011, we have unamortized deferred revenue of approximately $9.6 million and $13.2 million, respectively, for completed projects. During the years ended December 31, 2012, 2011 and 2010, we billed Morgan Stanley Capital Group and others approximately $1 million, $1.5 million, and $4.3 million, respectively, for completed projects. During the years ended December 31, 2012, 2011 and 2010, we recognized revenue on a straight-line basis of approximately $4.6 million, $4.5 million and $3.8 million, respectively, for completed projects.

(12) LONG-TERM DEBT

        On March 9, 2011, we entered into an amended and restated senior secured credit facility, or credit facility. The credit facility replaced in its entirety the senior secured credit facility that was in place as of December 31, 2010. The credit facility provides for a maximum borrowing line of credit equal to the lesser of (i) $350 million and (ii) 4.75 times Consolidated EBITDA (as defined: $340.7 million at December 31, 2012). We may elect to have loans under the credit facility bear interest either (i) at a rate of LIBOR plus a margin ranging from 2% to 3% depending on the total leverage ratio then in effect, or (ii) at the base rate plus a margin ranging from 1% to 2% depending on the total leverage ratio then in effect. We also pay a commitment fee on the unused amount of commitments, ranging from 0.375% to 0.5% per annum, depending on the total leverage ratio then in effect. Our obligations under the credit facility are secured by a first priority security interest in favor of the lenders in the majority of our assets.

        The terms of the credit facility include covenants that restrict our ability to make cash distributions, acquisitions and investments, including investments in joint ventures. We may make

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Notes to Consolidated Financial Statements (Continued)

Years ended December 31, 2012, 2011 and 2010

(12) LONG-TERM DEBT (Continued)

distributions of cash to the extent of our "available cash" as defined in our partnership agreement. We may make acquisitions and investments that meet the definition of "permitted acquisitions"; "other investments" which may not exceed 5% of "consolidated net tangible assets"; and "permitted JV investments". Permitted JV investments include up to $225 million of investments in BOSTCO (including the initial investment on December 20, 2012 for approximately $79 million), the "Specified BOSTCO Investment". In addition to the Specified BOSTCO Investment, under the terms of the credit facility, we may make an additional $75 million of other joint venture investments (including additional investments in BOSTCO). The principal balance of loans and any accrued and unpaid interest are due and payable in full on the maturity date, March 9, 2016.

        Under the credit facility, our terminaling service agreements with Morgan Stanley Capital Group relating to our Florida and Mount Vernon, Missouri and Rogers, Arkansas terminals and our Southeast terminals are deemed to be "Specified Contracts." The credit facility further provides that an event of default will occur if any Specified Contract terminates in whole or in part, "if such ... termination would reasonably be expected to result in a Material Adverse Effect after taking into account any replacement therefor." The 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 credit facility are (i) a total leverage ratio test (not to exceed 4.75 times), (ii) a senior secured leverage ratio test (not to exceed 3.75 times) in the event we issue senior unsecured notes, and (iii) a minimum interest coverage ratio test (not less than 3.0 times).

        If we were to fail any financial performance covenant, or any other covenant contained in the 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 credit facility, and the lenders would be entitled to declare all outstanding borrowings immediately due and payable. We were in compliance with all of the covenants under the credit facility as of December 31, 2012.

        For the years ended December 31, 2012, 2011 and 2010, the weighted average interest rate on borrowings under the applicable credit facility was approximately 2.4%, 3.3% and 4.2%, respectively. Weighted average interest rates include any net settlements received or paid under our interest rate swap, which was applicable during 2010 and the first six months of 2011, expiring in June 2011. At December 31, 2012 and 2011, our outstanding borrowings under the applicable credit facility were $184 million and $120 million, respectively. At December 31, 2012 and 2011, our outstanding letters of credit were approximately $nil at both dates.

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Notes to Consolidated Financial Statements (Continued)

Years ended December 31, 2012, 2011 and 2010

(13) PARTNERS' EQUITY

        The number of units outstanding is as follows:

 
  Common
units
  General
partner units
 

Units outstanding at January 1, 2010

    12,444,566     253,971  

Public offering of common units

    2,012,500      

TransMontaigne GP to maintain its 2% general partner interest

        41,071  
           

Units outstanding at December 31, 2010, 2011 and 2012

    14,457,066     295,042  
           

        At December 31, 2012 and 2011, common units outstanding include 17,635 and 16,899 common units, respectively, held on behalf of TransMontaigne Services Inc.'s long-term incentive plan.

        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 $51.0 million, after deducting underwriting discounts, commissions, and offering expenses of approximately $0.3 million. Additionally, TransMontaigne GP, our general partner, made a cash contribution of approximately $1.1 million to us to maintain its 2% general partner interest.

(14) LONG-TERM INCENTIVE PLAN

        TransMontaigne GP is our general partner and manages our operations and activities. TransMontaigne GP is an indirect wholly owned subsidiary of TransMontaigne Inc. TransMontaigne Services Inc. is an indirect wholly owned subsidiary of TransMontaigne Inc. TransMontaigne Services Inc. employs the personnel who provide support to TransMontaigne Inc.'s operations, as well as our operations. TransMontaigne Services Inc. adopted a long-term incentive plan for its employees and consultants and the independent directors of our general partner. The long-term incentive plan currently permits the grant of awards covering an aggregate of 1,816,745 units, which amount will automatically increase on an annual basis by 2% of the total outstanding common and subordinated units, if any, at the end of the preceding fiscal year. At December 31, 2012, 1,583,933 units are available for future grant under the long-term incentive plan. Ownership in the awards is subject to forfeiture until the vesting date, but recipients have distribution and voting rights from the date of grant. Pursuant to the terms of the long-term incentive plan, all restricted phantom units and restricted common units vest upon a change in control of TransMontaigne Inc. The long-term incentive plan is administered by the compensation committee of the board of directors of our general partner. TransMontaigne GP purchases outstanding common units on the open market for purposes of making grants of restricted phantom units to independent directors of our general partner.

        TransMontaigne GP, on behalf of the long-term incentive plan, has purchased 6,825, 7,760 and 9,435 common units pursuant to the program during the years ended December 31, 2012, 2011 and 2010, respectively. In addition to the foregoing purchases, upon the vesting of 10,000 restricted phantom units on August 10, 2012, 2011 and 2010, respectively, we purchased 5,891, 5,892 and 10,000 common units, respectively, from TransMontaigne Services Inc. for the purpose of delivering these units to Charles L. Dunlap, the Chief Executive Officer ("CEO") of our general partner. These units were

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Notes to Consolidated Financial Statements (Continued)

Years ended December 31, 2012, 2011 and 2010

(14) LONG-TERM INCENTIVE PLAN (Continued)

granted to Mr. Dunlap on August 10, 2009 under the long-term incentive plan. The amount of the units purchased for delivery to Mr. Dunlap varies based upon the funding of the related withholding taxes.

        Information about restricted phantom unit activity is as follows:

 
  Available for
future grant
  Restricted
phantom
units
  NYSE
closing
price
 

Units outstanding at January 1, 2010

    765,632     56,000        

Automatic increase in units available for future grant on January 1, 2010

    248,891            

Vesting on January 7, 2010

        (3,500 ) $ 27.97  

Grant on March 31, 2010

    (6,000 )   6,000   $ 27.24