10-K 1 tlp-20141231x10k.htm 10-K tlp_Current folio_10K

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


FORM 10‑K

 

 

(Mark One)

 

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

for the fiscal year ended December 31, 2014

OR

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   No 

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    No 

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    No 

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   No 

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 registrants 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. 

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

Accelerated filer

Non‑accelerated filer
(Do not check if a
smaller reporting company)

Smaller reporting company

 

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

The aggregate market value of common limited partner units held by non‑ affiliates of the registrant on June 30, 2014 was $557,971,021 computed by reference to the last sale price ($43.75 per common unit) of the registrants common limited partner units on the New York Stock Exchange on June 30, 2014.

The number of the registrants common limited partner units outstanding on February 27, 2015 was 16,124,566.

DOCUMENTS INCORPORATED BY REFERENCE

None.

 

 


 

TABLE OF CONTENTS

 

 

 

 

 

 

Item

    

    

    

Page No.

 

 

 

Part I

 

 

 

1 and 2. 

 

Business and Properties

 

 

1A. 

 

Risk Factors

 

29 

 

1B. 

 

Unresolved Staff Comments

 

44 

 

3. 

 

Legal Proceedings

 

44 

 

4. 

 

Mine Safety Disclosures

 

45 

 

 

 

Part II

 

 

 

5. 

 

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

 

46 

 

6. 

 

Selected Financial Data

 

49 

 

7. 

 

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

 

50 

 

7A. 

 

Quantitative and Qualitative Disclosures About Market Risks

 

65 

 

8. 

 

Financial Statements and Supplementary Data

 

66 

 

9. 

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

98 

 

9A. 

 

Controls and Procedures

 

98 

 

9B. 

 

Other Information

 

99 

 

 

 

Part III

 

 

 

10. 

 

Directors, Executive Officers of Our General Partner and Corporate Governance

 

100 

 

11. 

 

Executive Compensation

 

105 

 

12. 

 

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

 

109 

 

13. 

 

Certain Relationships and Related Transactions, and Director Independence

 

112 

 

14. 

 

Principal Accounting Fees and Services

 

115 

 

 

 

Part IV

 

 

 

15. 

 

Exhibits, Financial Statement Schedules

 

115 

 

 

 

1


 

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:

·

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;

·

TransMontaigne LLC controls our general partner, which has sole responsibility for conducting our business and managing our operations. TransMontaigne LLC and NGL Energy Partners LP (“NGL”) have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to our detriment;

·

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;

·

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

·

a material portion of our operations are conducted through joint ventures, over which we do not maintain full control and which have unique risks;

·

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

·

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

·

the expiration of our omnibus agreement occurs on the earlier to occur of TransMontaigne LLC ceasing to control our general partner or following at least 24 months prior written notice;

2


 

·

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

·

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 common 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;

·

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;

·

the uncertainty surrounding whether or when a merger with NGL will occur and other aspects of such a transaction, if any, could adversely affect our ability to secure new customers or increase or extend agreements with existing customers that are important to our operations or attract and retain qualified personnel to operate our business;

·

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

·

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;

·

cyber attacks or other breaches of our information security measures could disrupt our operations and result in increased costs;

·

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;

·

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;

·

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;

3


 

·

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;

·

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 technical 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 LLC.  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) 6268200.

Our general partner is TransMontaigne GP L.L.C., which is indirectly wholly owned and controlled by TransMontaigne LLCOn July 1, 2014, TransMontaigne LLC was acquired by NGL Energy Partners LP. 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 LLC are intended to mean TransMontaigne LLC and its subsidiaries other than TransMontaigne GP L.L.C., our general partner, and TransMontaigne Partners and its subsidiaries.

OVERVIEW

We are controlled by our general partner, TransMontaigne GP L.L.C., which is a wholly‑owned subsidiary of TransMontaigne LLC.  At December 31, 2014, NGL Energy Partners LP (“NGL”) owned all of the issued and outstanding capital stock of TransMontaigne LLC, and, as a result, NGL is the indirect owner of our general partner. At December 31, 2014, TransMontaigne LLC and NGL had a significant interest in our partnership through their indirect ownership of an approximate 19% limited partner interest, a 2% general partner interest and the incentive distribution rights.

Prior to July 1, 2014, Morgan Stanley Capital Group Inc., a wholly‑owned subsidiary of Morgan Stanley and the principal commodities trading arm of Morgan Stanley, owned all of the issued and outstanding capital stock of TransMontaigne LLC, and, as a result, Morgan Stanley was the indirect owner of our general partner.  Effective July 1,

4


 

2014, Morgan Stanley consummated the sale of its 100% ownership interest in TransMontaigne LLC to NGL. The sale resulted in a change in control of Partners.

In addition to the sale of our general partner to NGL, NGL acquired the common units owned by TransMontaigne LLC and affiliates of Morgan Stanley, representing approximately 20% of our outstanding common units, and assumed Morgan Stanley Capital Group’s obligations under our light oil terminaling services agreements in Florida and the Southeast regions, excluding the Collins/Purvis tankage (collectively, the “NGL Acquisition”). All other terminaling services agreements with Morgan Stanley Capital Group remained with Morgan Stanley Capital Group. The NGL Acquisition did not involve the sale or purchase of any of our common units held by the public and our common units continue to trade on the New York Stock Exchange.

TransMontaigne Partners has no officers or employees and all of our management and operational activities are provided by officers and employees of NGL Energy Operating LLC (“NGL Energy Operating”), a wholly owned subsidiary of NGL. TransMontaigne Services LLC is an indirect wholly owned subsidiary of TransMontaigne LLC. TransMontaigne LLC is an indirect wholly owned subsidiary of NGL. We are controlled by our general partner, TransMontaigne GP L.L.C., which is an indirect wholly owned subsidiary of TransMontaigne LLC. 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. TransMontaigne LLC, TransMontaigne Services LLC and TransMontaigne Product Services LLC were converted from Delaware corporations into Delaware limited

5


 

liability companies as of December 30, 2014.  The following diagram depicts our organization and structure as of December 31, 2014:

cid:image001.png@01D04C5E.B01FDF60

 

TransMontaigne LLC is a leading distributor of unbranded refined petroleum products to independent wholesalers, distributors and industrial and commercial end users, delivering approximately 0.2 million barrels per day throughout the United States, primarily in the Gulf Coast, Northeast, Southeast and Midwest regions. TransMontaigne LLC currently relies on us to provide integrated terminaling services to support its operations in these geographic regions other than the Northeast.

NGL is a Delaware limited partnership that is controlled by its general partner, NGL Energy Holdings LLC. NGL’s operations include a crude oil logistics segment, the assets of which include owned and leased crude oil storage terminals, pipeline injection stations, a fleet of trucks, a fleet of leased and owned railcars, and a fleet of barges and towboats, and a crude oil pipeline. NGL’s crude oil logistics segment purchases crude oil from producers and transports it for resale at owned and leased pipeline injection points, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs.  NGL has a water solutions segment, the assets of which include water treatment and disposal facilities. NGL’s water solutions segment generates revenues from the treatment and disposal of wastewater generated from crude oil and natural gas production, and from the sale of recycled water and recovered hydrocarbons.

6


 

NGL has a liquids segment, which supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical plants throughout the United States and in Canada, and which provides natural gas liquids terminaling services through its more than 20 terminals throughout the United States and railcar transportation services through its fleet of leased and owned railcars. NGL’s liquids segment purchases propane, butane, and other products from refiners, processing plants, producers, and other parties, and sells the product to retailers, refiners, petrochemical plants, and other participants in the wholesale markets. NGL’s retail propane segment sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain re-sellers in 25 states. Finally, NGL’s refined products and renewables segment, which conducts gasoline, diesel, ethanol, and biodiesel marketing operations, includes NGL’s investment in us.

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 1.5 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 the U.S.‑Mexico Border, which we refer to as the Diamondback pipeline. 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 2.7 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 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.

7


 

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 and 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 LLC, for resale.

Transportation.  Before an independent distribution and marketing company, such as TransMontaigne LLC, 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.

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

8


 

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 terminaling companies such as TransMontaigne Partners.

Our Operations

We are a terminaling and transportation company with operations in the United States along the Gulf Coast, in the Midwest, in Houston and 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, railcars 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.

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 receiving, storing and distributing 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

9


 

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.

10


 

The locations and approximate aggregate active storage capacity at our terminal facilities as of December 31, 2014 are as follows:

 

 

 

 

 

 

    

Active storage

 

 

 

capacity

 

Locations

 

(shell bbls)

 

Gulf Coast Facilities

 

 

 

Florida

 

 

 

Port Everglades Complex

 

 

 

Port Everglades-North

 

2,408,000 

 

Port Everglades-South(1)

 

376,000 

 

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

 

6,857,000 

 

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

 

919,000 

 

Frontera(2)

 

1,498,000 

 

Brownsville Total

 

2,417,000 

 

River Facilities

 

 

 

Arkansas City, AR

 

446,000 

 

Evansville, IN

 

245,000 

 

New Albany, IN

 

201,000 

 

Greater Cincinnati, KY

 

189,000 

 

Henderson, KY

 

169,000 

 

Louisville, KY

 

183,000 

 

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

 

2,685,000 

 

 

 

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Active storage

 

 

 

capacity

 

Locations

 

(shell bbls)

 

Southeast Facilities

 

 

 

Albany, GA

 

203,000 

 

Americus, GA

 

93,000 

 

Athens, GA

 

203,000 

 

Bainbridge, GA

 

367,000 

 

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

 

219,000 

 

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

 

10,017,000 

 

BOSTCO(3)

 

7,080,000 

 

TOTAL CAPACITY

 

30,625,000 

 

 


(1)

Reflects our ownership interest net of a major oil companys ownership interest in certain tank capacity.

(2)

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

(3)

Reflects the completed construction total active storage capacity of Battleground Oil Specialty Terminal Company LLC (BOSTCO), of which we have a 42.5%, general voting, Class A Member (ownership) interest. The BOSTCO facility began initial commercial operation in the fourth quarter of 2013.  Completion of the 7.1 million barrels of storage capacity and related infrastructure occurred in the third quarter of 2014.

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, RaceTrac Petroleum Inc. and NGL.

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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 from our terminal at Mount Vernon, where it is interconnected with a pipeline system owned by Magellan Midstream Partners, L.P., 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. On January 10, 2014 we entered into a 10‑year capacity agreement with Magellan Pipeline Company, L.P. (“Magellan”), effective March 1, 2014, covering 100% of the capacity of Razorback terminals and the Razorback Pipeline.

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, L.P. 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.

We leased a portion of land in Cushing, Oklahoma and constructed storage tanks with approximately 1.0 million barrels of crude oil storage and associated infrastructure on such 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 1.5 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 16 miles from our Brownsville facilities to the U.S./Mexico border 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 Matamoros. 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.

In August 2013, we sold our Mexico operations to an unaffiliated third party for cash proceeds of approximately $2.1 million, net of $0.2 million in bank accounts sold related to the Mexico operations. The Mexico operations consisted of a 7,000 barrel liquefied petroleum gas storage terminal in Matamoros, Mexico and a seven mile pipeline system connecting the Matamoros terminal to our Diamondback pipeline system at the U.S. border, which connects to our Brownville, Texas terminals.

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 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,

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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 customer is Nieto Trading, B.V.

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 Marketing and Supply Company.

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, ethanol, biodiesel, 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 NGL and the United States Government.

Investment in BOSTCO.  On December 20, 2012, we acquired a 42.5%, general voting, Class A Member (“ownership”) interest in BOSTCO, for approximately $79 million, from Kinder Morgan Battleground Oil, LLC, a wholly owned subsidiary of Kinder Morgan, Inc. (“Kinder Morgan”). BOSTCO is a new terminal facility on the Houston Ship Channel designed to handle residual fuel, feedstocks, distillates and other black oils. The initial phase of BOSTCO involved the construction of 51 storage tanks with approximately 6.2 million barrels of storage capacity. The BOSTCO facility began initial commercial operation in the fourth quarter of 2013. Completion of the full 6.2 million barrels of storage capacity and related infrastructure occurred in the second quarter of 2014.

On June 5, 2013, we announced an expansion of BOSTCO. The expansion is supported by a long‑term leased storage and handling services contract with Morgan Stanley Capital Group and includes six, 150,000 barrel, ultra‑low sulphur diesel tanks, additional pipeline and deepwater vessel dock access and high‑speed loading at a rate of 25,000 barrels per hour. Work on the 900,000 barrel expansion started in the second quarter of 2013, and was placed into service at the end of the third quarter of 2014. With the addition of this expansion project, BOSTCO has fully subscribed capacity of approximately 7.1 million barrels at an overall construction cost of approximately $529 million. Our total payments for the initial and the expansion projects are estimated to be approximately $233 million, which includes our proportionate share of the BOSTCO project costs and necessary start‑up working capital, a one‑time buy‑in fee paid to Kinder Morgan to acquire our 42.5% interest and the capitalization of interest on our investment during the construction of BOSTCO. We have funded our payments for BOSTCO utilizing borrowings under our credit facility.

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 is responsible for managing BOSTCO’s day‑to‑day operations. Our 42.5% ownership interest does not allow us to control BOSTCO, but does allow us to exercise significant influence over its operations. Accordingly, we account for our investment in BOSTCO under the equity method of accounting.

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:

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

Execute cost‑effective expansion and asset enhancement opportunities.  We continually evaluate opportunities to expand our existing asset base.

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. For example, in December 2012, we acquired a 42.5% ownership interest in BOSTCO from Kinder Morgan. BOSTCO is a new terminal facility on the Houston Ship Channel for handling residual fuel, feedstocks, distillates and other black oils. The BOSTCO facility’s docks benefit from one of the deepest vessel drafts and nearest access points in the Houston Ship Channel and is well positioned to capitalize on increasing exports of petroleum related products.

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.  We have contractual commitments from our customers that generated a substantial majority of our actual revenue. Of this firmly committed revenue, approximately 92% was generated under terminaling services agreements with remaining terms of at least one year at December 31, 2014. Our actual revenue for a year is 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 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. In December 2012, we acquired a 42.5% ownership interest in BOSTCO, which constructed a new terminal facility on the Houston Ship Channel for handling residual fuel, feedstocks, distillates and other black oils. In the second quarter of 2013 we announced a 900,000 barrel expansion at the BOSTCO terminal. The expansion included six, 150,000‑barrel, ultra‑low sulphur diesel tanks, additional pipeline and deepwater vessel dock access, and high‑speed loading at a rate of 25,000 barrels per hour. The BOSTCO facility began initial commercial operation in the fourth quarter of 2013. Completion of the full 6.2 million barrels of storage capacity and related infrastructure occurred in the second quarter of 2014. Work on the 900,000 barrel expansion started in the second quarter of 2013, and was placed into service at the end of the third quarter of 2014.

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 NGL Energy Partners LP 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.

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., Buckeye Partners, L.P., Chevron U.S.A. Inc., CITGO Petroleum Corporation, Exxon Mobil Corporation, HollyFrontier Corporation and its affiliate Holly Energy Partners, L.P., Kinder Morgan, Inc.,  Magellan Midstream Partners, L.P., Marathon Petroleum Corporation and its affiliate MPLX LP, Motiva Enterprises LLC, Murphy Oil Corporation, NuStar Energy L.P., Phillips 66 and its affiliate Phillips 66 Partners LP, 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

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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 derive a substantial majority of our revenue for the foreseeable future. These relationships include:

 

 

 

 

Customer

    

Location

 

NGL Energy Partners LP

 

Southeast facilities

 

Morgan Stanley Capital Group

 

Southeast and Midwest facilities

 

United States Government

 

Southeast and Gulf Coast facilities

 

RaceTrac Petroleum Inc.

 

Gulf Coast facilities

 

Marathon Petroleum Company LLC

 

Gulf Coast facilities

 

Glencore Ltd.

 

Gulf Coast facilities

 

World Fuel Services Corporation

 

Gulf Coast facilities

 

Shell Oil Products U.S.

 

Gulf Coast and Midwest facilities

 

Magellan Pipeline Company, L.P.

 

Midwest facilities

 

P.M.I. Trading Ltd.

 

Brownsville facilities

 

Nieto Trading, B.V.

 

Brownsville facilities

 

Valero Marketing and Supply Company

 

River facilities

 

 

Our Relationship with TransMontaigne LLC and NGL Energy Partners LP

General.    We are controlled by our general partner, TransMontaigne GP L.L.C., which is an indirect wholly owned subsidiary of TransMontaigne LLC, a 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. As of December 31, 2014, TransMontaigne LLC and its subsidiaries owned two railcar facilities; a hydrant system in Port Everglades; and its distribution and marketing business. TransMontaigne LLC’s marketing operations generally consist of the distribution and marketing of refined products through contract and rack spot sales in the physical markets.

At December 31,  2014,  NGL owned all of the issued and outstanding capital stock of TransMontaigne LLC, and, as a result, NGL is the indirect owner of our general partner. At December 31, 2014, TransMontaigne LLC and NGL had a significant interest in our partnership through their indirect ownership of an approximate 20% limited partner interest, a 2% general partner interest and the incentive distribution rights.

NGL is a Delaware limited partnership that is controlled by its general partner, NGL Energy Holdings LLC. NGL’s operations include a crude oil logistics segment, the assets of which include owned and leased crude oil storage terminals, pipeline injection stations, a fleet of trucks, a fleet of leased and owned railcars, and a fleet of barges and towboats, and a crude oil pipeline. NGL’s crude oil logistics segment purchases crude oil from producers and transports it for resale at owned and leased pipeline injection points, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs.  NGL has a water solutions segment, the assets of which include water treatment and disposal facilities. NGL’s water solutions segment generates revenues from the treatment and disposal of wastewater generated from crude oil and natural gas production, and from the sale of recycled water and recovered hydrocarbons. NGL has a liquids segment, which supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical

17


 

plants throughout the United States and in Canada, and which provides natural gas liquids terminaling services through its more than 20 terminals throughout the United States and railcar transportation services through its fleet of leased and owned railcars. NGL’s liquids segment purchases propane, butane, and other products from refiners, processing plants, producers, and other parties, and sells the product to retailers, refiners, petrochemical plants, and other participants in the wholesale markets. NGL’s retail propane segment sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain re-sellers in 25 states. Finally, NGL’s refined products and renewables segment, which conducts gasoline, diesel, ethanol, and biodiesel marketing operations, includes NGL’s investment in us.

Prior to July 1, 2014, Morgan Stanley Capital Group Inc., a wholly‑owned subsidiary of Morgan Stanley and the principal commodities trading arm of Morgan Stanley, owned all of the issued and outstanding capital stock of TransMontaigne LLC, and, as a result, Morgan Stanley was the indirect owner of our general partner.  Effective July 1, 2014, Morgan Stanley consummated the sale of its 100% ownership interest in TransMontaigne LLC to NGL. The sale resulted in a change in control of Partners, but did not result in a deemed termination of Partners for tax purposes.  In addition to the sale of our general partner to NGL, NGL acquired the common units owned by TransMontaigne LLC and affiliates of Morgan Stanley, representing approximately 20% of our outstanding common units, and assumed Morgan Stanley Capital Group’s obligations under our light oil terminaling services agreements in Florida and the Southeast regions, excluding the Collins/Purvis tankage. All other terminaling services agreements with Morgan Stanley Capital Group remained with Morgan Stanley Capital Group. The NGL Acquisition did not involve the sale or purchase of any of our common units held by the public and our common units continue to trade on the New York Stock Exchange.

Omnibus Agreement.  We have an omnibus agreement with TransMontaigne LLC that will continue in effect until the earlier to occur of (i) TransMontaigne LLC ceasing to control our general partner or (ii) the election of either us or TransMontaigne LLC, following at least 24 months’ prior written notice to the other parties.

Under the omnibus agreement we pay TransMontaigne LLC an administrative fee for the provision of various general and administrative services for our benefit. For the years ended December 31, 2014, 2013 and 2012, the administrative fee paid to TransMontaigne LLC was approximately $11.1 million, $11.0 million and $10.8 million, respectively. If we acquire or construct additional facilities, TransMontaigne LLC 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 LLC will provide services for the additional facilities pursuant to the agreement. The administrative fee includes expenses incurred by TransMontaigne LLC 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 LLC.

The omnibus agreement further provides that we pay TransMontaigne LLC an insurance reimbursement for premiums on insurance policies covering our facilities and operations. For the years ended December 31, 2014, 2013 and 2012, the insurance reimbursement paid to TransMontaigne LLC was approximately $3.7 million, $3.8 million and $3.6 million, respectively. We also reimburse TransMontaigne LLC for direct operating costs and expenses that TransMontaigne LLC incurs on our behalf, such as salaries of operational personnel performing services on‑site at our terminals and pipelines and the cost of employee benefits, including 401(k) and health insurance benefits.

We also agreed to reimburse TransMontaigne LLC and its affiliates for a portion of the incentive payment grants to key employees of NGL and its affiliates under the TransMontaigne Services LLC 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 years ended December 31, 2014, 2013 and 2012, we reimbursed TransMontaigne LLC and its affiliates approximately $1.5 million, $1.3 million and $1.3 million, respectively.

The omnibus agreement also provides TransMontaigne LLC a right of first refusal to purchase our assets, subject to certain exceptions discussed below and provided that TransMontaigne LLC 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 LLC.

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TransMontaigne LLC 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. Subject to certain exceptions discussed below, TransMontaigne LLC 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 LLC agrees to pay no less than 105% of the fees offered by the third party customer.  The above rights of first refusal do not apply to any storage capacity or terminaling assets for which TransMontaigne LLC, or an affiliate of TransMontaigne LLC, has, subsequent to July 2013, elected to terminate (or not renew upon expiration) its existing terminaling services agreement relating thereto.

Secondment Agreement.  On December 30, 2014, we entered into a secondment agreement with TransMontaigne Services LLC and TransMontaigne GP L.L.C. Under the secondment agreement, TransMontaigne Services LLC agrees to second to Partners certain personnel to provide the on-site operational, maintenance and administrative services necessary to operate, manage and maintain the operations and assets of the Partnership in connection with its obligations under our omnibus agreement with TransMontaigne LLC.  The seconded personnel work under the direction, supervision and control of the Partnership.  Partners is obligated to reimburse TransMontaigne LLC for the seconded personnel pursuant to the terms of the omnibus agreement.

Significant Terminaling Services Agreements

Southeast Terminaling Services AgreementNGL.  In connection with the NGL Acquisition, effective July 1, 2014, Morgan Stanley Capital Group assigned to NGL its obligations under our terminaling services agreement relating to our Southeast terminals, excluding the Collins/Purvis, Mississippi tankage. The Southeast terminaling services agreement with NGL will continue in effect unless and until NGL provides us at least 24 months’ prior notice of its intent to terminate the agreement. We have the right to terminate the terminaling services agreement effective at any time after July 31, 2023 by providing at least 24 months’ prior notice to NGL.

Southeast Terminaling Services Agreement—Morgan Stanley Capital Group.  In connection with the NGL Acquisition, the Southeast terminaling services agreement provisions pertaining to the Collins/Purvis, Mississippi tankage remained with Morgan Stanley Capital Group.  Morgan Stanley Capital Group had previously provided us 24 months’ prior notice that it would terminate its obligations under the Southeast terminaling services agreement relating to our Collins/Purvis terminal effective December 31, 2015, which encompasses approximately 2.7 million barrels of light refined product storage capacity. This termination notice does not encompass the Collins/Purvis additional light oil tankage, which is part of a separate terminaling services agreement.  We expect to re-contract the upcoming available space at Collins/Purvis prior to December 31, 2015 and at rates that are in excess of the current rates charged to Morgan Stanley Capital Group.

Collins/Purvis Additional Light Oil Tankage—Morgan Stanley Capital Group.    We have a terminaling services agreement with Morgan Stanley Capital Group at our Collins/Purvis, Mississippi terminal for approximately 0.7 million barrels of additional light refined product storage capacity.  The agreement expires on June 30, 2018, after which the terminaling services agreement will continue in effect unless and until Morgan Stanley Capital Group provides us at least 24 months’ prior notice of its intent to terminate the agreement.

Midwest Terminaling Services Agreement—Morgan Stanley Capital Group.    We have a terminaling services agreement with Morgan Stanley Capital Group at our Cushing, Oklahoma terminal for approximately 1.0 million barrels of crude oil storage capacity.  The agreement expires on July 31, 2019, subject to a five‑year automatic renewal unless terminated by Morgan Stanley Capital Group upon 180 days’ prior notice.

Southeast Terminaling Services Agreement—United States Government.  We have a terminaling services agreement with the United States government at our Selma, North Carolina terminal for approximately 0.3 million barrels of light refined product storage capacity.  The agreement expires on April 30, 2017, with the United States government having the option to extend the agreement for two additional five‑year increments.

Gulf Coast Terminaling Services Agreement—United States Government.    We have a terminaling services

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agreement with the United States government at our Port Everglades North, Florida terminal for approximately 0.1 million barrels of light refined product storage capacity. The agreement expires on May 31, 2015.

Gulf Coast Terminaling Services Agreement—RaceTrac Petroleum Inc.    We have terminaling services agreements with RaceTrac Petroleum Inc. at our Tampa, Cape Canaveral, Port Manatee and Port Everglades South, Florida terminals for approximately 2.2 million barrels of light refined product storage capacity.  The agreements expire at various points in time between September 16, 2018 and September 15, 2019.  The tankage at Port Manatee is currently not available to RaceTrac Petroleum Inc. until the fall of 2015, upon the completion of certain enhancements by us at this terminal.

Gulf Coast Terminaling Services Agreement—Marathon Petroleum Company LLC.    We have a terminaling services agreement with Marathon Petroleum Company LLC at our Cape Canaveral, Jacksonville, Port Manatee and Port Everglades North, Florida terminals for approximately 1.0 million barrels of asphalt storage capacity.  The agreement expires on April 30, 2016.

Gulf Coast Terminaling Services Agreement—Glencore Ltd.    We have a terminaling services agreement with Glencore Ltd. at our Port Everglades North and Fisher Island, Florida terminals for approximately 1.4 million barrels of bunker fuel storage capacity.  The agreement expires on May 31, 2016, with Glencore Ltd. having the option to extend the agreement for an additional three years.

Gulf Coast Terminaling Services Agreement—World Fuel Services Corporation.    We have terminaling services agreements with World Fuel Services Corporation at our Cape Canaveral, Florida terminal for approximately 0.1 million barrels of bunker fuel storage capacity and at our Port Everglades North, Florida terminal for approximately 0.4 million barrels of light refined product storage capacity.  The bunker fuel storage agreement expires on December 22, 2017. The light refined product storage agreement is for a three year term commencing in the second quarter of 2015, with the option to extend for one year renewals unless terminated by either party upon 180 days’ prior notice.

Gulf Coast Terminaling Services Agreement—Shell Oil Products U.S.    We have a terminaling services agreement with Shell Oil Products U.S. at our Pensacola, Florida terminal for approximately 0.2 million barrels of light refined product storage capacity.  The agreement expires on February 1, 2016.

Midwest Terminaling Services Agreement—Shell Oil Products U.S.    We have a terminaling services agreement with Shell Oil Products U.S. at our Oklahoma City, Oklahoma terminal for approximately 0.2 million barrels of light refined product storage capacity.  The agreement expires on January 31, 2016.

Midwest Capacity Agreement—Magellan Pipeline Company, L.P.    We have a capacity agreement with Magellan Pipeline Company, L.P. covering 100% of the capacity of our Razorback terminals and the use of our Razorback Pipeline, which runs from Mount Vernon, Missouri to Rogers, Arkansas.  The agreement expires on February 28, 2024.

Brownsville Terminaling Services Agreement—P.M.I. Trading Ltd.    We have terminaling services agreements with P.M.I. Trading Ltd. at our Brownsville, Texas terminal for approximately 0.3 million barrels of heavy refined product storage capacity.  The agreements expire at various points in time between August 31, 2015 and February 6, 2016.

Brownsville Terminaling Services Agreement—Nieto Trading, B.V.    We have a terminaling and transportation services agreement with Neito Trading, B.V. for approximately 33,000 barrels of LPG storage capacity at our Brownsville, Texas terminal and the use of our Ella-Brownsville and Diamondback pipelines. The agreement expires on September 30, 2017.

River Terminaling Services Agreement—Valero Marketing and Supply Company.    We have a terminaling services agreement with Valero Marketing and Supply Company at six of our River terminals for approximately 0.6 million barrels of light refined product storage capacity.  The agreement expires on March 31, 2016.

Other Terminaling Services Agreements.  We have additional terminaling services 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

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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 Brownsville LLC joint venture, or “Frontera”, in which we have a 50% ownership interest. 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, 2014, 2013 and 2012, we recognized revenue of approximately $4.0 million, $3.7 million and $3.4 million, respectively, related to this operations and reimbursement agreement.

Terminals and Pipeline Control Operations

The pipelines we own or operate are operated via 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 Supervisory 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, 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 high speed communication systems for remote monitoring and control. In addition, our Collins, Mississippi facility contains 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 petroleum liquids between our Collins and Collins/Purvis terminal facilities; a one‑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 pipelines located in the United States.

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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 designed to 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 fire protection 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 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

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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 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

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or its derivatives in surface waters or into the groundwater. Spill prevention control and countermeasure requirements of federal laws require, among other things, appropriate containment be constructed around product storage tanks to help prevent the contamination of navigable waters in the event of a product tank spill, rupture or leak.

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

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

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

Most 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 future legislation that may be enacted to address greenhouse gas emissions would impact our operations. We believe we are in compliance with existing federal and state greenhouse gas reporting regulations. 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

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a hazardous substance was released, and companies that disposed or arranged for disposal of hazardous substances at offsite locations such as landfills. In the course of our operations we will generate wastes or handle substances that may fall within the definition of a “hazardous substance.” CERCLA authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. Under CERCLA, we could be subject to joint and several liability for the costs of cleaning up and restoring sites where hazardous substances have been released, for damages to natural resources and for the costs of certain health studies. We believe that we are in substantial compliance with the existing requirements of CERCLA.

We currently own, lease, or operate numerous properties and facilities that for many years have been used for industrial activities, including refined product terminaling operations. Hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners whose treatment and disposal or release of hazardous substances, wastes, or hydrocarbons, was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes (including substances disposed of or released by prior owners or operators) 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 LLC 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 LLC’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 LLC 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 LLC estimates that the total cost for remediating the contamination at the Florida terminals will be between approximately $3.3 million and approximately $7.3 million. TransMontaigne LLC’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 LLC 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 LLC believes that its share of the total remediation liability, net of probable reimbursements, will be between approximately $0.4 million and approximately $2.8 million.

Under the purchase agreement for the Brownsville, Texas and River facilities, TransMontaigne LLC 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 LLC’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 LLC 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 LLC believes that its total remediation liability, net of probable reimbursements, for the Brownsville and River facilities will be between approximately $0.2 million and approximately $0.8 million.

Under the purchase agreement for the Southeast facilities, TransMontaigne LLC 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 LLC’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 LLC 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 LLC believes its total remediation liability for the Southeast facilities will be between approximately $1.3 million and approximately $2.2 million.

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Under the purchase agreement for the Pensacola, Florida terminal, TransMontaigne LLC 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 LLC’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 LLC 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 LLC. These policies contain caps on the insurer’s maximum liability under the policy, and claims made by either of TransMontaigne LLC 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 LLC 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 the United States‑ Mexico border, 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 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

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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, Ella‑Brownsville 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 LLC and by third parties. 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.

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

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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 LLC which is a wholly owned subsidiary of NGL.  Prior to January 1, 2015, TransMontaigne Services LLC, a wholly owned subsidiary of TransMontaigne LLC, employed the personal who provide support to TransMontaigne LLC’s operations, as well as our operations.  As of January 1, 2015 TransMontaigne Services LLC had approximately 510 employees, of whom 335 provided services directly to us.  Effective January 1, 2015, all the employees of TransMontaigne Services LLC became employees of NGL Energy Operating, LLC (“NGL Energy Operating”). As of February 27, 2015, none of NGL Energy Operating’s employees who provide services directly to us were covered by a collective bargaining agreement. NGL Energy Operating considers its relations with such employees to be good.

On December 30, 2014, we entered into a secondment agreement with TransMontaigne Services LLC and TransMontaigne GP L.L.C.  Under the secondment agreement, TransMontaigne Services LLC agrees to second, or cause NGL Energy Operating to second, to Partners certain personnel to provide the on-site operational, maintenance and administrative services necessary to operate, manage and maintain the operations and assets of the Partnership in connection with its obligations under our omnibus agreement with TransMontaigne LLC.  The seconded personnel work under the direction, supervision and control of the Partnership.  Partners is obligated to reimburse TransMontaigne LLC for the seconded personnel pursuant to the terms of the omnibus agreement.

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ITEM 1A.  RISK FACTORS

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

Risks Inherent in Our Business

We 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 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’

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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 their contractual commitments to us for any reason, then our revenue and cash flow would decline.

The omnibus agreement expires on the earlier to occur of TransMontaigne LLC ceasing to control our general partner or following at least 24 months’ prior written notice to the other parties.

We cannot predict whether an acquirer of TransMontaigne LLC or our general partner will seek to terminate, amend or modify the terms of the omnibus agreement, which may be terminated following at least 24 months’ prior written notice. If we are not successful in negotiating acceptable terms with such successor, if we are required to pay a higher administrative fee, or if we must incur substantial costs to replicate the services currently provided by TransMontaigne LLC and its affiliates under the omnibus agreement, our financial condition and results of operations could be materially adversely affected.

We are exposed to the credit risks of NGL Energy Partners LP (“NGL”) and our other significant customers which could affect our creditworthiness. Any material nonpayment or nonperformance by such customers could also adversely affect our financial condition and results of operations.

Because of NGL’s ownership interest in and control of us, the strong operational links between NGL and us and our reliance on NGL for a majority of our revenue, if one or more credit rating agencies were to view unfavorably the credit quality of NGL, we could experience an increase in our borrowing costs or difficulty accessing capital markets. Such a development could adversely affect our ability to grow our business.

We 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 revenue. These events could adversely affect our financial condition and results of operations.

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 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.

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A material portion of our operations are conducted through joint ventures, over which we do not maintain full control and which have unique risks.

 

A material portion of our operations are conducted through joint ventures. We are entitled to appoint a member to the BOSTCO board of managers and maintain certain rights of approval over significant changes to, or expansion of, BOSTCO’s business, however Kinder Morgan serves as the operator of BOSTCO and is responsible for its day-to-day operations.   Although we serve as the operator of Frontera, there are restrictions and limitations on our authority to take certain material actions absent the consent of our joint venture partner. With respect to our existing joint ventures, we share ownership with partners that may not always share our goals and objectives. Differences in views among the partners may result in delayed decisions or failures to agree on major matters, such as large expenditures or contractual commitments, the construction of assets or borrowing money, among others. Delay or failure to agree may prevent action with respect to such matters, even though such action may not serve our best interest or that of the joint venture. Accordingly, delayed decisions and disagreements could adversely affect the business and operations of the joint ventures and, in turn, our business and operations. From time to time, our joint ventures may be involved in disputes or legal proceedings which may negatively affect our investments. Accordingly, any such occurrences could adversely affect our financial condition, operating results and cash flows. 

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.

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 $400 million. At December 31, 2014, our outstanding borrowings were $252 million. At December 31, 2014, the capital expenditures to complete the approved additional investments and expansion capital projects are estimated to be approximately $15 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.

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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.

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. 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;

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

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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 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.

Market uncertainties, adverse economic conditions or lack of consumer confidence 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.

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

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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.

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.

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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.

A potential acquisition by NGL of Partners creates uncertainty that could adversely affect our ability to secure new customers or increase or extend agreements with existing customers that are important to our operations and to attract and retain qualified personnel, any of which could materially and adversely affect our business or results of operations.

While the conflicts committee and NGL were not able to reach an agreement as a result of NGL’s July 10, 2014 proposal to acquire Partners, NGL may at any time reinitiate efforts to pursue a combination transaction with us.  The uncertainty surrounding whether or when such a transaction with NGL will occur may adversely affect our ability to enter into new customer agreements or extend or expand existing customer relationships if potential and existing customers choose to wait to learn whether we will be acquired before committing to new, extended or expanded customer relationships with us. If such uncertainty continues for a protracted period, our ability to secure new, extended or expanded customer relationships may be adversely affected, which could materially and adversely affect our revenues and results of operations in future periods.

Furthermore, the uncertainty surrounding a potential transaction with NGL may adversely affect our ability to attract and retain qualified personnel.  We operate in an industry that currently experiences a high level of competition among different companies for qualified and experienced personnel. The uncertainty relating to the possibility of a merger transaction may increase the risk that we could experience higher than normal rates of attrition or that we experience increased difficulty in attracting qualified personnel or incur higher expenses to do so. High levels of attrition among the management and employee personnel necessary to operate our business or difficulties or increased expense incurred to replace any personnel who leave, could materially adversely affect our business or results of operations.

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

Our amended and restated senior secured credit facility matures in July 2018. At December 31, 2014, we had outstanding borrowings of $252 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

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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 LLC. These policies contain caps on the insurer’s maximum liability under the policy, and claims made by either of TransMontaigne LLC 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 LLC against the policy cap.

Cyber attacks that circumvent our security measures and other breaches of our information security measures could disrupt our operations and result in increased costs.

We utilize information technology systems to operate our assets and manage our businesses. A cyber attack or other security breach of our information technology systems could result in a breach of critical operational or financial controls and lead to a disruption of our operations, commercial activities or financial processes. Additionally, we rely on third‑party systems that could also be subject to cyber attacks or security breaches, and the failure of which could have a significant adverse effect on the operation of our assets. We and the operators of the third‑party systems on which we depend may not have the resources or technical sophistication to anticipate or prevent every emerging type of cyber attack, and such an attack, or the additional security measures undertaken to prevent such an attack, could adversely affect our results of operations, financial position or cash flows.

In addition, we collect and store sensitive data, including our proprietary business information and information about our customers, suppliers and other counterparties, and personally identifiable information of the employees of NGL Energy Operating, on our information technology networks. Despite our security measures, our information technology and infrastructure may be vulnerable to cyber attacks or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored therein could be accessed, publicly disseminated, lost or stolen. Any such access, dissemination or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties, or could disrupt our operations, any of which could adversely affect our results of operations, financial position or cash flows.

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 construct additional storage capacity to capture anticipated future growth in consumption of products in a market in which such growth does not materialize.

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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 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,

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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 LLC controls our general partner, which has sole responsibility for conducting our business and managing our operations. TransMontaigne LLC and NGL 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 LLC.  Likewise, TransMontaigne Services LLC is an indirect wholly owned subsidiary of TransMontaigne LLC and is responsible under our omnibus agreement with TransMontaigne LLC for providing the personnel who provide support to TransMontaigne LLC’s operations, as well as our operations.  TransMontaigne LLC, in turn, is wholly owned by NGL.  NGL Energy Operating, a wholly owned subsidiary of NGL, employs all of the employees who satisfy TransMontaigne LLC’s obligations under our omnibus agreement. NGL’s business includes, among other things, crude oil logistics services, oil field services, propane and natural gas liquids trading and distribution. 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 affiliates own units representing approximately 20% of our aggregate outstanding common units. 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 LLC, other than the indemnification provisions, will be terminable by TransMontaigne LLC 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 employees of NGL Energy Operating and four of our general partner’s directors are affiliated with NGL. Therefore, conflicts of interest may arise between NGL and its affiliates and subsidiaries, including TransMontaigne LLC, 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

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the interests of its affiliates over the interests of our unitholders.

The following are potential conflicts of interest:

TransMontaigne LLC and NGL, 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 services fees would reflect rates that could be obtained in arm’s‑length, third‑party transactions.

NGL, TransMontaigne LLC and their affiliates may engage in competition with us under certain circumstances.

Neither our partnership agreement nor any other agreement requires TransMontaigne LLC or NGL 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 LLC’s and NGL’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 LLC and NGL, 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 NGL and TransMontaigne LLC who provide services to us also devote significant time to the businesses of NGL and TransMontaigne LLC, and are compensated by NGL for the services rendered to them.

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

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

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

Our 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 a  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, 2014, that amount was $50.5 million, $16.0 million of which would go to NGL, TransMontaigne LLC affiliates and our general partner 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 LLC 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

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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 NGL.

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

The control of our general partner may be transferred to a third party without the consent of our general partner, Partners or our unitholders.

Our general partner may transfer its general partner interest in TransMontaigne Partners L.P. to a third party in a merger, a sale of all or substantially all of the general partner's assets, or other transaction without the consent of the general partner on behalf of Partners. Furthermore, our partnership agreement does not restrict the ability of TransMontaigne Services LLC, the sole member of our general partner, from transferring its respective limited liability company interest in our general partner to a third party. The new owner of TransMontaigne LLC, or new members of our general partner, as applicable, 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. In that event, neither TransMontaigne LLC nor our general partner would be able to take steps to protect the interests of Partners.

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, 2014, we paid TransMontaigne LLC and its affiliates an administrative fee of approximately $11.1 million, an additional insurance reimbursement of approximately $3.7 million and $1.5 million as partial reimbursement for grants to key employees of TransMontaigne Services LLC and its affiliates under the TransMontaigne Services LLC 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 LLC. 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 omnibus agreement will continue in effect until the earlier to occur of (i) TransMontaigne LLC ceasing to control our general partner or (ii) the election of either us or TransMontaigne LLC, following at least 24 months’ prior written notice to the other parties. We cannot predict whether TransMontaigne LLC or our general partner will seek to terminate, amend or modify the terms of the omnibus agreement. If we are not successful in negotiating acceptable terms with such successor, if we are required to pay a higher administrative fee or if we must incur substantial costs to replicate the services currently provided by TransMontaigne LLC and its affiliates under the omnibus agreement, our financial condition and results of operations could be materially adversely affected.

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

40


 

return on their investment. Unitholders may also incur a tax liability upon a sale of their common units. At February 27,  2015, affiliates of our general partner own approximately 20% 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.

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.

41


 

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, 2014, we recognized a liability of approximately $0.1 million 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.

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.  

Pursuant to the NGL Acquisition, on July 1, 2014, Morgan Stanley sold its direct ownership interest in TransMontaigne LLC to NGL.  The disposition of Morgan Stanley’s direct ownership interest in TransMontaigne LLC did not result in a technical termination of TransMontaigne Partners.  However, as a result of certain post transaction restructuring of NGL’s  investment in TransMontaigne LLC, including the conversion of TransMontaigne LLC, TransMontaigne Services LLC and TransMontaigne Product Services LLC from Delaware corporations into Delaware limited liability companies, TransMontaigne Partners did experience a technical termination as of December 30, 2014.  Further, as a result of TransMontaigne Partners’ technical termination, Frontera also experienced a technical termination on December 30, 2014.   Unrelated to TransMontaigne Partners and Frontera’s technical terminations, BOSTCO experienced a technical termination as of November 26, 2014, caused by restructuring of Kinder Morgan Energy Partners, L.P. and its affiliates.  Due to these technical terminations experienced for federal income tax purposes, the Partnership and the Frontera and BOSTCO joint ventures will each realize a deferral of cost recovery deductions that will impact each of our unitholders through allocations of an increased amount of federal taxable income (or reduced amount of allocated loss) for the current and subsequent years.

Prior 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.

Prior to July 1, 2014, Morgan Stanley indirectly controlled our general partner and was a bank holding company under applicable federal banking law and regulation, which imposed limitations on Morgan Stanley and its affiliates’ ability to conduct certain nonbanking activities.  As a result of such regulation, Morgan Stanley informed us in October 2011 that it was unable, or limited in approving any “significant” acquisition or investment. The practical effect of these limitations significantly constrained our ability to expand our asset base and operations through acquisitions

42


 

from third parties, limiting additions to our capital assets primarily to additions and improvements that we constructed or added to our existing facilities. While we are no longer under such regulatory constraints following the sale of TransMontaigne LLC from Morgan Stanley to NGL and we now have the ability to grow our asset base, 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 the market value of our units.

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

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

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.

43


 

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.

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 LLC 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.

Exxon’s King Ranch natural-gas-processing plant in Kleberg County, Texas, was shut down as a result of a fire at the plant beginning in November 2013.  This plant supplies a significant amount of liquefied petroleum gas, or “LPG,” to our third-party customer, Nieto Trading, B.V. (“Nieto”), which transports LPG through our Ella Brownsville and Diamondback pipelines, and has contracted for the LPG storage capacity at our Brownsville terminals.  The King Ranch plant became operational again in late November 2014.  In an effort to increase Nieto’s ability to transport LPG through the Diamondback pipeline during the period that Exxon’s King Ranch plant was not operating and in reliance upon Nieto’s promise to reimburse us for the costs of construction, we constructed a truck unloading facility at our Brownsville terminal for Nieto’s use at a cost of approximately $0.5 million.  Nieto disputes requesting such a facility and has not reimbursed us for it.  Nieto also has claimed that the fire at the Exxon King Ranch plant constitutes a force majeure event that relieves Nieto of its obligation to pay certain fees required under the related terminaling services agreement for failure to throughput a minimum number of barrels of LPG (“deficiency fees”).  We do not believe that the King Ranch fire qualified as a force majeure event under the terminaling services agreement, or that, even if it did, it relieved Nieto of its obligation to pay the deficiency fees.  As a result of Nieto’s failure to pay the deficiency fees due to

44


 

us and Nieto’s failure to reimburse us for the costs of the truck unloading facility that we constructed for it, on September 26, 2014, we filed a complaint for damages and declaratory relief in the Supreme Court of the State of New York, County of New York, against Nieto, by which we seek damages in the amount of at least $4.2 million and a declaratory judgment clarifying our rights to receive the deficiency fees under the terminaling services agreement.  The $4.2 million in damages we seek is comprised of approximately $3.7 million in deficiency fees under the terminaling services agreement as of the date of the complaint and approximately $0.5 million that we incurred in constructing the truck unloading facility.  Those numbers will be augmented as the case moves forward to reflect actual deficiency fee damages to date, which increase monthly.

ITEM 4.  MINE SAFETY DISCLOSURES

Not applicable.

45


 

Part II

ITEM 5.  MARKET FOR THE REGISTRANTS 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 27, 2015, there were 26 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, 2013 through March 31, 2013

 

$

38.25 

 

$

50.77 

 

April 1, 2013 through June 30, 2013

 

$

40.42 

 

$

50.36 

 

July 1, 2013 through September 30, 2013

 

$

38.70 

 

$

45.61 

 

October 1, 2013 through December 31, 2013

 

$

38.93 

 

$

44.09 

 

January 1, 2014 through March 31, 2014

 

$

40.69 

 

$

44.00 

 

April 1, 2014 through June 30, 2014

 

$

41.93 

 

$

50.00 

 

July 1, 2014 through September 30, 2014

 

$

40.00 

 

$

44.98 

 

October 1, 2014 through December 31, 2014

 

$

31.00 

 

$

41.37 

 

 

DISTRIBUTIONS OF AVAILABLE CASH

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

 

 

 

 

 

 

 

    

Distribution

 

January 1, 2013 through March 31, 2013

 

$

0.640 

 

April 1, 2013 through June 30, 2013

 

$

0.650 

 

July 1, 2013 through September 30, 2013

 

$

0.650 

 

October 1, 2013 through December 31, 2013

 

$

0.650 

 

January 1, 2014 through March 31, 2014

 

$

0.660 

 

April 1, 2014 through June 30, 2014

 

$

0.665 

 

July 1, 2014 through September 30, 2014

 

$

0.665 

 

October 1, 2014 through December 31, 2014

 

$

0.665 

 

 

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;

46


 

·

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

The terms of our credit facility may limit our ability to distribute cash under certain circumstances as discussed under Item 7. Managements Discussion and Analysis of Financial Condition and Results of OperationsLiquidity 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.

 

r

 

 

 

 

 

 

 

 

 

 

 

Marginal percentage

 

 

 

 

 

interest in

 

 

 

 

 

distributions

 

 

    

Total per unit

    

 

 

General

 

 

 

quarterly distribution

 

Unitholders

 

partner

 

Minimum quarterly distribution

    

$0.40

    

98 

%  

%  

First target distribution

 

up to $0.44

 

98 

%  

%  

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, 2014

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, 2014.

 

 

 

 

 

 

 

 

 

 

 

 

 

    

 

    

 

 

    

Total number of

    

Maximum number

 

 

 

 

 

 

 

 

common units

 

of common units

 

 

 

 

 

 

 

 

purchased as

 

that may yet be

 

 

 

Total number of

 

Average price

 

part of publicly

 

purchased under

 

 

 

common units

 

paid per

 

announced

 

the plans or

 

Period

 

purchased

 

common unit

 

plans or programs

 

programs

 

October

 

667 

 

$

41.24 

 

667 

 

3,335 

 

November

 

667 

 

$

37.36 

 

667 

 

2,668 

 

December

 

667 

 

$

36.95 

 

667 

 

2,001 

 

 

 

2,001 

 

$

38.52 

 

2,001 

 

 

 

 

During the three months ended December 31, 2014, we purchased 2,001 common units, with $77,079 of aggregate market value, in the open market pursuant to an amended purchase program announced on March 31, 2013. 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 LLC 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 April 1, 2015; 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 LLC Long‑Term Incentive Plan. The current amended purchase program allows us to purchase in future periods up to 2,001 common units, in the aggregate, through the amended purchase programs scheduled termination date of April 1, 2015.

48


 

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, 2014, 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 Managements Discussion and Analysis of Financial Condition and Results of Operations included elsewhere in this annual report.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Years ended December 31,

 

 

 

2014(1)

 

2013(1)

 

2012(1)

 

2011(2)

 

2010

 

 

 

(dollars in thousands except per unit amounts)

 

Operations Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenue

    

$

150,062 

    

$

158,886 

    

$

156,239 

    

$

152,292 

    

$

150,899 

 

Direct operating costs and expenses

 

 

(66,183)

 

 

(69,390)

 

 

(65,964)

 

 

(64,498)

 

 

(64,696)

 

Direct general and administrative expenses

 

 

(3,535)

 

 

(3,911)

 

 

(4,810)

 

 

(4,703)

 

 

(3,159)

 

Allocated general and administrative expenses

 

 

(11,127)

 

 

(10,963)

 

 

(10,780)

 

 

(10,466)

 

 

(10,311)

 

Allocated insurance expense

 

 

(3,711)

 

 

(3,763)

 

 

(3,590)

 

 

(3,290)

 

 

(3,185)

 

Reimbursement of bonus awards

 

 

(1,500)

 

 

(1,250)

 

 

(1,250)

 

 

(1,250)

 

 

(1,250)

 

Depreciation and amortization

 

 

(29,522)

 

 

(29,568)

 

 

(28,260)

 

 

(27,654)

 

 

(27,869)

 

Gain (loss) on disposition of assets

 

 

 —

 

 

(1,294)

 

 

 

 

9,576 

 

 

(765)

 

Impairment of goodwill

 

 

 —

 

 

 

 

 

 

 

 

(8,465)

 

Earnings (loss) from unconsolidated affiliates

 

 

4,443 

 

 

(321)

 

 

558 

 

 

113 

 

 

 

Operating income

 

 

38,927 

 

 

38,426 

 

 

42,143 

 

 

50,120 

 

 

31,199 

 

Other income (expenses):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

 

(5,489)

 

 

(2,712)

 

 

(2,855)

 

 

(2,457)

 

 

(3,397)

 

Amortization of deferred financing costs

 

 

(975)

 

 

(975)

 

 

(767)

 

 

(1,055)

 

 

(598)

 

Foreign currency transaction gain (loss)

 

 

 —

 

 

(13)

 

 

51 

 

 

(88)

 

 

38 

 

Net earnings

 

 

32,463 

 

 

34,726 

 

 

38,572 

 

 

46,520 

 

 

27,242 

 

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

 

 

(7,167)

 

 

(5,929)

 

 

(5,157)

 

 

(4,415)

 

 

(3,017)

 

Net earnings allocable to limited partners

 

$

25,296 

 

$

28,797 

 

$

33,415 

 

$

42,105 

 

$

24,225 

 

Net earnings per limited partner unit—basic and diluted

 

$

1.57 

 

$

1.90 

 

$

2.31 

 

$

2.92 

 

$

1.69 

 

Other Financial Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

 

$

60,929 

 

$

64,235 

 

$

64,311 

 

$

66,091 

 

$

65,336 

 

Net cash used in investing activities

 

$

(50,702)

 

$

(119,958)

 

$

(85,731)

 

$

(18,566)

 

$

(37,508)

 

Net cash provided by (used in) financing activities

 

$

(10,186)

 

$

52,192 

 

$

20,964 

 

$

(45,605)

 

$

(29,056)

 

Cash distributions declared per common unit attributable to the period

 

$

2.655 

 

$

2.590 

 

$

2.550 

 

$

2.480 

 

$

2.410 

 

Balance Sheet Data (at period end):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property, plant and equipment, net

 

$

385,301 

 

$

407,045 

 

$

427,701 

 

$

431,782 

 

$

452,402 

 

Investments in unconsolidated affiliates

 

$

249,676 

 

$

211,605 

 

$

105,164 

 

$

25,875 

 

$

 

Total assets

 

$

664,057 

 

$

648,432 

 

$

569,801 

 

$

514,104 

 

$

514,306 

 

Long-term debt

 

$

252,000 

 

$

212,000 

 

$

184,000 

 

$

120,000 

 

$

122,000 

 

Partners’ equity

 

$

391,465 

 

$

408,467 

 

$

348,737 

 

$

351,876 

 

$

344,816 

 

 


(1)

At December 31, 2014, 2013 and 2012, our investments in unconsolidated affiliates include a 42.5% ownership interest in Battleground Oil Specialty Terminal Company LLC (“BOSTCO”) and a 50% interest in Frontera. BOSTCO is a newly constructed terminal facility with approximately 7.1 million barrels of storage capacity at a cost of approximately $529 million. BOSTCO is located on the Houston Ship Channel.  The BOSTCO facility began initial commercial operation in the fourth quarter of 2013.  Completion of the 7.1 million barrels of storage

49


 

capacity and related infrastructure occurred in the third quarter of 2014. (See Note 8 of Notes to consolidated financial statements).

(2)

The consolidated financial statements, effective April 1, 2011, include the impact of our contribution of approximately 1.5 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.

ITEM 7.  MANAGEMENTS 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 LLC. At December 31, 2014, our operations are composed of:

A 42.5%, general voting, Class A Member (“ownership”) interest in BOSTCO. BOSTCO is a new fully subscribed, 7.1 million barrel terminal facility on the Houston Ship Channel designed to handle residual fuel, feedstocks, distillates and other black oils. The BOSTCO facility began initial commercial operation in the fourth quarter of 2013.  Completion of the full 7.1 million barrels of storage capacity and related infrastructure occurred at the end of the third quarter of 2014;

Eight refined product terminals located in Florida (“Gulf Coast terminals”), with an aggregate active storage capacity of approximately 6.9 million barrels, that provide integrated terminaling services to Glencore Ltd., Marathon Petroleum Company LLC, NGL, RaceTrac Petroleum Inc.,  Shell Oil Products U.S., United States government, World Fuel Services Corporation, and other distribution and marketing companies;

A 67‑mile interstate refined products pipeline, which we refer to as the Razorback pipeline, that transports gasoline and distillates for customers of Magellan Pipeline Company, L.P. from our two refined product terminals, one located in Mount Vernon, Missouri and the other located in Rogers, Arkansas, which we refer to as our Razorback terminals. These terminals have an aggregate active storage capacity of approximately 406,000 barrels and are leased to Magellan Pipeline Company, L.P. under a ten-year capacity agreement;

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 Shell Oil Products U.S.;

One refined product terminal located in Brownsville, Texas with aggregate active storage capacity of approximately 919,000 barrels that provides integrated terminaling services to Nieto Trading, B.V. and PMI Trading Ltd. and other distribution and marketing companies;

A 16‑mile LPG pipeline, which we refer to as the Diamondback pipeline, that extends from our Brownsville, Texas facility to the U.S. border. At the U.S. border the Diamondback pipeline connects to a pipeline and storage terminal in Matamoros, Mexico, owned by Nieto Trading, B.V.;

A pipeline leased from the Seadrift Pipeline Corporation, which we refer to as the Ella‑Brownsville

50


 

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

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 1.5 million barrels that provides services to PMI Trading Ltd. and other distribution and marketing companies;

Twelve refined product terminals located along the Mississippi and Ohio rivers (“River terminals”) with aggregate active storage capacity of approximately 2.7 million barrels and the Baton Rouge, Louisiana dock facility that provide integrated terminaling services to Valero Marketing and Supply Company 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 NGL, 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 is directly affected by the level of supply and demand in the wholesale markets served by our terminals and pipelines. Overall supply of refined products in the wholesale markets is influenced by the products’ absolute prices, the availability of capacity on delivering pipelines and vessels, fluctuating refinery margins and the markets’ perception of future product prices. The demand for gasoline typically peaks during the summer driving season, which extends from April to September, and declines during the fall and winter months. The demand for marine fuels typically peaks in the winter months due to the increase in the number of cruise ships originating from 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 LLC.

A significant amount of our business is devoted to providing terminaling services to NGL and TransMontaigne LLC, which currently rely on us to provide substantially all the integrated terminaling services they require to support their refined products operations along the Gulf Coast and along the Colonial and Plantation pipelines. TransMontaigne LLC, a wholly owned subsidiary of NGL,  was formed in 1995 as 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, however currently primarily in the Southeast region.

While our customer base has been diversified over the past year away from affiliates to external, third party customers, affiliates are still our largest customers and our agreements with them provide a substantial amount of our revenue, representing approximately 49%, 66%, and 71%,  of our revenue for the years ended December 31, 2014, 2013 and 2012, respectively. Our revenue from affiliate customers is primarily earned pursuant to terminaling services agreements.  See Note 2 of Notes to consolidated financial statements in this Form 10‑K for additional descriptions of these agreements.

51


 

SIGNIFICANT DEVELOPMENTS

Change in control of the ownership of our general partner.    Effective July 1, 2014, Morgan Stanley consummated the sale of its 100% ownership interest in TransMontaigne LLC to NGL. TransMontaigne LLC is the indirect parent and sole member of TransMontaigne GP, which is our general partner. The sale resulted in a change in control of Partners.

In addition to the sale of our general partner to NGL, NGL acquired the common units owned by TransMontaigne LLC and affiliates of Morgan Stanley, representing approximately 20% of our outstanding common units, and assumed Morgan Stanley Capital Group’s obligations under our light oil terminaling services agreements in Florida and the Southeast regions, excluding the Collins/Purvis tankage. The NGL Acquisition did not involve the sale or purchase of any of our common units held by the public and our common units continue to trade on the New York Stock Exchange.

Termination of discussions to exchange our common units for NGL common units.  On July 10, 2014, NGL submitted a non-binding, unsolicited proposal (the “Proposal”) to the Conflicts Committee of the board of directors of TransMontaigne GP, pursuant to which each outstanding common unit of Partners would have been exchanged for one common unit of NGL.  On August 15, 2014, NGL and our Conflicts Committee jointly announced, that after several discussions, an agreement on the price to be offered to Partners’ unitholders could not be reached, and both parties had terminated discussions regarding the Proposal to acquire the outstanding common units of Partners.  We do not know whether or when NGL may make another proposal similar to, or with similar objectives as, the Proposal.

Changes in our board composition and management team.  In connection with the consummation of the NGL Acquisition, on July 1, 2014, Stephen R. Munger, Goran Trapp and Martin S. Mitchell, each employees of Morgan Stanley, resigned from the board of directors of TransMontaigne GP. To fill the vacancies resulting from the resignation of the Morgan Stanley directors, Atanas H. Atanasov, Benjamin Borgen, David C. Kehoe and Donald M. Jensen, each employees of NGL, were appointed to the board of directors of TransMontaigne GP effective July 1, 2014.

On August 25, 2014, Jerry R. Masters, David A. Peters and Jay A. Wiese, who qualified as independent directors under the applicable listing standards of the New York Stock Exchange, resigned from the board of directors of TransMontaigne GP.  Mr. Masters served as the Chairman of the Audit and Compensation Committees and as a member of the Conflicts Committee. Mr. Peters served as the Chairman of the Conflicts Committee and as a member of the Audit and Compensation Committees. Mr. Wiese served as a member of the Audit, Compensation and Conflicts Committees.

On September 4, 2014, the board of directors of TransMontaigne GP appointed Robert A. Burk to serve as a director.  Mr. Burk serves as a member of the Audit and Compensation Committees, as the chair of the Conflicts Committee, and as the presiding director over non-management and independent directors.  Mr. Burk qualifies as an independent director under the applicable listing standards of the New York Stock Exchange.

On September 24, 2014, the board of directors of TransMontaigne GP appointed Steven A. Blank and Lawrence C. Ross to serve as directors. Mr. Blank serves as the chair of the Audit Committee and as a member of the Compensation and Conflicts Committees. Based upon his education and employment experience, Mr. Blank qualifies as an “audit committee financial expert” as defined by the Securities and Exchange Commission.  Mr. Ross serves as the chair of the Compensation Committee and as a member of the Audit and Conflicts Committees.  Mr. Blank and Mr. Ross both qualify as independent directors under the applicable listing standards of the New York Stock Exchange.

On October 16, 2014, Charles L. Dunlap notified Partners of his intention to retire from his position as Chief Executive Officer of our general partner and as President, Chief Executive Officer and member of the board of directors of TransMontaigne LLC, and the other subsidiaries of Partners and TransMontaigne LLC, each to be effective November 7, 2014.  As a result of Mr. Dunlap’s resignation, on October 20, 2014, the board of directors of TransMontaigne GP appointed Frederick W. Boutin to serve as Chief Executive Officer of our general partner, effective November 7, 2014. Mr. Boutin was also appointed to serve as the President and Chief Executive Officer of TransMontaigne LLC, effective November 7, 2014.  In connection with Mr. Boutin’s appointment to Chief Executive Officer, on October 20, 2014, the board of directors of TransMontaigne GP appointed Robert T. Fuller to serve as the Executive Vice President, Chief Financial Officer, Chief Accounting Officer and Treasurer of our general partner,

52


 

effective November 7, 2014. Mr. Fuller was also appointed to serve as the Executive Vice President, Chief Financial Officer and Treasurer of TransMontaigne LLC, effective November 7, 2014.

Commercial activity.    On January 10, 2014, we entered into a ten-year capacity agreement with Magellan Pipeline Company, L.P., effective March 1, 2014, covering 100% of the capacity of our Razorback terminals and the use of our Razorback Pipeline, which runs from Mount Vernon, Missouri to Rogers, Arkansas. The existing agreement for these facilities with Morgan Stanley Capital Group terminated effective February 28, 2014. We expect this new agreement will generate approximately the same total annual revenue as the Morgan Stanley Capital Group agreement.

On February 12, 2014, we entered into a two year terminaling services agreement with Glencore Ltd. for most of the bunker fuel storage capacity at our Port Everglades North, Florida and Fisher Island, Florida terminals. The agreement provides Glencore Ltd. the option to extend for an additional three years. The agreement replaced Morgan Stanley Capital Group as the bunker fuels customer at these two terminals effective June 1, 2014. The remaining Florida bunker fuels agreement with Morgan Stanley Capital Group at our Port Manatee, Florida and Cape Canaveral, Florida terminals terminated on May 31, 2014.

Effective December 23, 2014, we re-contracted the bunker fuel capacity at our Cape Canaveral terminal to World Fuel Services Corporation for a three year term at similar rates to the preceding agreement with Morgan Stanley Capital Group. We are currently in the process of identifying other potential parties to re‑contract available bunker fuel capacity at Fisher Island and Port Manatee, however, at this time we are unsure if we will be successful in our re‑contracting efforts.

Effective September 16, 2014, we amended our long-term terminaling services agreement with RaceTrac Petroleum Inc. to include the use of gasoline, ethanol and diesel tankage at our Cape Canaveral, Port Manatee and Port Everglades South terminals located in Florida.  The tankage at Cape Canaveral and Port Everglades South became immediately available to RaceTrac Petroleum Inc. on September 16, 2014.  The tankage at Port Manatee is expected to become available to RaceTrac Petroleum Inc. by the fall of 2015, upon the completion of certain enhancements by us at this facility. We had previously entered into an agreement with RaceTrac Petroleum Inc. that was effective in September of 2013 relating to the use of storage capacity at our Tampa, Florida terminal.  The amended agreement brings the aggregate capacity of our tankage under contract with RaceTrac Petroleum Inc. in Florida to approximately 2.2 million barrels.

The tankage related to this new amendment with RaceTrac Petroleum Inc. was previously used by NGL, which had been assigned from Morgan Stanley Capital Group as part of the NGL Acquisition. Simultaneous with the entry into the RaceTrac Petroleum Inc. agreement, we amended the Florida terminaling services agreement to immediately terminate NGL’s obligations relating to the tank capacity at our Cape Canaveral and Port Everglades South terminals, and to terminate NGL’s obligation at our Port Manatee terminal effective March 14, 2015.  We expect that the amendments to the RaceTrac Petroleum Inc. agreement will generate approximately the same annual revenue as the NGL agreement generated with respect to those tanks.

On October 31, 2014, NGL provided us the required 18 months’ prior notice that it will terminate its remaining obligations under its Florida terminaling services agreement effective April 30, 2016, which constitutes NGL’s light oil terminaling capacity for approximately 1.1 million barrels at our Port Everglades North, Florida terminal. On November 24, 2014, we re-contracted approximately 0.4 million barrels of this capacity to World Fuel Services Corporation at similar rates charged to NGL. The tankage is expected to become available to World Fuel Services Corporation in the second quarter of 2015, upon the completion of certain enhancements by us at this facility.  We expect to re-contract the  remaining available space at Port Everglades North prior to April 30, 2016 and at rates that are at least similar to the current rates charged to NGL.

Effective October 6, 2014, we re-contracted 119,000 barrels of available capacity at our Louisville and Greater Cincinnati, Kentucky terminals to a third party for a three year term commencing May 1, 2015. The majority of this capacity had been unsubscribed since the beginning of 2012.

As of September 30, 2014, the second phase of the BOSTCO construction project, encompassing 900,000 barrels of diesel storage, has been placed into service.  With the addition of this second phase, combined with the initial

53


 

phase becoming fully operational in the second quarter of 2014, BOSTCO has 57 storage tanks that are operational, with a fully subscribed capacity of approximately 7.1 million barrels.

Credit Facility Amendment.  On February 26, 2015, we amended our credit facility to extend the maturity date to July 31, 2018, increase the maximum borrowing line of credit from $350 million to $400 million, and allow for up to $125 million in additional future “permitted JV investments”, which may include additional investments in BOSTCO.  In addition, the amendment allows for, at our request, the maximum borrowing line of credit to be increased by an additional $100 million, subject to the approval of the administrative agent and the receipt of additional commitments from one or more lenders.

Quarterly distributions.    On January 13, 2014, we announced a distribution of $0.65 per unit for the period from October 1, 2013 through December 31, 2013.  This distribution was paid on February 11, 2014 to unitholders of record on January 31, 2014.  On April 14, 2014, we announced a distribution of $0.66 per unit for the period from January 1, 2014 through March 31, 2014.  This distribution was paid on May 8, 2014 to unitholders of record on April 30, 2014.  On July 16, 2014, we announced a distribution of $0.665 per unit for the period from April 1, 2014 through June 30, 2014. This distribution was paid on August 7, 2014 to unitholders of record on July 31, 2014. On October 13, 2014, we announced a distribution of $0.665 per unit for the period from July 1, 2014 through September 30, 2014. This distribution was paid on November 7, 2014 to unitholders of record on October 31, 2014. On January 8, 2015, we announced a distribution of $0.665 per unit for the period from October 1, 2014 through December 31, 2014. This distribution was paid on February 6, 2015 to unitholders of record on January 30, 2015.

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 earn pipeline transportation fees at our Razorback, Diamondback and Ella‑Brownsville pipelines based on the volume of product transported and the distance from the origin point to the delivery point. We own the Razorback and Diamondback pipelines, and we began leasing the Ella‑Brownsville pipeline from a third party in January 2013. The Federal Energy Regulatory Commission regulates the tariff on our 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 Mexicos 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, 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.

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.

54


 

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, 2014, we have an accrued liability of approximately $1.5 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 LLC have been, and are expected in the future to be, insignificant. Pursuant to agreements with TransMontaigne LLC, TransMontaigne LLC 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 LLC, up to a maximum liability for these indemnification obligations (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).

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. 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, 2014. The

55


 

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, 2014 we discounted the estimated net cash flows at an assumed market participant weighted average cost of capital. The aggregate fair value of our reporting units was reconciled to the fair value of our partners equity.

At December 31, 2014, our only reporting unit that contained goodwill was our Brownsville terminals. Our estimate of the fair value of our Brownsville terminals at December 31, 2014 exceeded its carrying amount. Accordingly, we did not recognize any goodwill impairment charges during the year ended December 31, 2014 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.

RESULTS OF OPERATIONSYEARS ENDED DECEMBER 31, 2014, 2013 AND 2012

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

    

Year ended

    

Year ended

 

 

 

December 31,

 

December 31,

 

December 31,

 

 

 

2014

 

2013

 

2012

 

Terminaling services fees, net

    

$

111,857 

    

$

118,585 

    

$

119,465 

 

Pipeline transportation fees

 

 

3,314 

 

 

7,600 

 

 

5,656 

 

Management fees and reimbursed costs

 

 

7,053 

 

 

6,281 

 

 

5,806 

 

Other

 

 

27,838 

 

 

26,420 

 

 

25,312 

 

Revenue

 

$

150,062 

 

$

158,886 

 

$

156,239 

 

 

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):

 

 

 

 

 

 

 

 

 

 

 

 

 

    

Year ended

    

Year ended

    

Year ended

 

 

 

December 31,

 

December 31,

 

December 31,

 

 

 

2014

 

2013

 

2012

 

Gulf Coast terminals

    

$

55,209 

 

$

56,297 

 

$

57,752 

 

Midwest terminals and pipeline system

 

 

11,813 

 

 

11,561 

 

 

10,553 

 

Brownsville terminals

 

 

21,439 

 

 

24,900 

 

 

18,614 

 

River terminals

 

 

9,308 

 

 

10,955 

 

 

14,161 

 

Southeast terminals

 

 

52,293 

 

 

55,173 

 

 

55,159 

 

Revenue

 

$

150,062 

 

$

158,886 

 

$

156,239 

 

 

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

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Terminaling Services Fees, Net,

 

 

 

by Business Segment

 

 

    

Year ended

    

Year ended

    

Year ended

 

 

 

December 31,

 

December 31,

 

December 31,

 

 

 

2014

 

2013

 

2012

 

Gulf Coast terminals

    

$

43,777 

 

$

47,143 

 

$

47,692 

 

Midwest terminals and pipeline system

 

 

8,164 

 

 

7,926 

 

 

5,381 

 

Brownsville terminals

 

 

6,280 

 

 

7,412 

 

 

6,398 

 

River terminals

 

 

8,566 

 

 

10,093 

 

 

13,219 

 

Southeast terminals

 

 

45,070 

 

 

46,011 

 

 

46,775 

 

Terminaling services fees, net

 

$

111,857 

 

$

118,585 

 

$

119,465 

 

 

The decrease in terminaling services fees, net at our Gulf Coast terminals for the year ended December 31, 2014 as compared to