10-K 1 tlp-20171231x10k.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, 2017

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 Units Representing Limited Partner Interests

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 registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10‑K or any amendment to this Form 10‑K. 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non‑accelerated filer, a smaller reporting company, or emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth 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 ☐

 

Emerging growth company ☐

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

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 units held by non‑affiliates of the registrant on June 30, 2017 was $543,133,822 computed by reference to the last sale price ($42.00 per common unit) of the registrant’s common units on the New York Stock Exchange on June 30, 2017.

The number of the registrant’s common units outstanding on March 9, 2018 was 16,200,485.

DOCUMENTS INCORPORATED BY REFERENCE

None.

 

 

 


 

TABLE OF CONTENTS

 

 

 

 

 

 

Item

    

    

    

Page No.

 

 

 

Part I

 

 

 

1 and 2. 

 

Business and Properties

 

 

1A. 

 

Risk Factors

 

23 

 

1B. 

 

Unresolved Staff Comments

 

40 

 

3. 

 

Legal Proceedings

 

40 

 

4. 

 

Mine Safety Disclosures

 

40 

 

 

 

Part II

 

 

 

5. 

 

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

 

41 

 

6. 

 

Selected Financial Data

 

43 

 

7. 

 

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

 

44 

 

7A. 

 

Quantitative and Qualitative Disclosures About Market Risks

 

58 

 

8. 

 

Financial Statements and Supplementary Data

 

59 

 

9. 

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

91 

 

9A. 

 

Controls and Procedures

 

91 

 

9B. 

 

Other Information

 

93 

 

 

 

Part III

 

 

 

10. 

 

Directors, Executive Officers of Our General Partner and Corporate Governance

 

93 

 

11. 

 

Executive Compensation

 

99 

 

12. 

 

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

 

102 

 

13. 

 

Certain Relationships and Related Transactions, and Director Independence

 

105 

 

14. 

 

Principal Accounting Fees and Services

 

108 

 

 

 

Part IV

 

 

 

15. 

 

Exhibits, Financial Statement Schedules

 

109 

 

16. 

 

Form 10-K Summary

 

126 

 

 

 

2


 

 

CAUTIONARY STATEMENT REGARDING FORWARD‑LOOKING STATEMENTS

This Annual Report on Form 10-K (this “Annual Report”) contains “forward-looking statements” within the meaning of federal securities laws. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. When used in this Annual Report, the words “could,” “may,” “should,” “will,” “seek,” “believe,” “expect,” “anticipate,” “intend,” “continue,” “estimate,” “plan,” “target,” “predict,” “project,” “attempt,” “is scheduled,” “likely,” “forecast,” the negatives thereof and other similar expressions are used to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. You are cautioned not to place undue reliance on any forward-looking statements. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors” included in this Annual Report. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

·

our ability to successfully implement our business strategy;

·

competitive conditions in our industry;

·

actions taken by third-party customers, producers, operators, processors and transporters;

·

pending legal or environmental matters;

·

costs of conducting our operations;

·

our ability to complete internal growth projects on time and on budget;

·

general economic conditions;

·

the price of oil, natural gas, natural gas liquids and other commodities in the energy industry;

·

the price and availability of debt and equity financing;

·

large customer defaults; 

·

interest rates;

·

operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;

·

uncertainty regarding our future operating results;

·

changes in tax status;

·

effects of existing and future laws and governmental regulations;

·

the effects of future litigation; and

·

plans, objectives, expectations and intentions contained in this Annual Report that are not historical.

All forward-looking statements, expressed or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

 

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Annual Report.

 

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Part I

As used in this Annual Report, unless the context requires otherwise, references to “we,” “us,” “our,” “TransMontaigne Partners” or the ‘‘Partnership’’ are intended to mean TransMontaigne Partners L.P. and our wholly owned and controlled operating subsidiaries. References to ‘‘TransMontaigne GP’’ or ‘‘our general partner’’ are intended to mean TransMontaigne GP L.L.C., our general partner. References to ‘‘ArcLight’’ are

intended to mean ArcLight Energy Partners Fund VI, L.P., its affiliates and subsidiaries other than TransMontaigne GP, us and our subsidiaries.

 

ITEMS 1 AND 2.  BUSINESS AND PROPERTIES

Overview

We are a terminaling and transportation company with assets and operations in the United States along the Gulf Coast, in the Midwest, in Houston and Brownsville, Texas, along the Mississippi and Ohio Rivers, in the Southeast and on the West Coast. We provide integrated terminaling, storage, transportation and related services for customers engaged in the distribution and marketing of light refined petroleum products, heavy refined petroleum products, crude oil, chemicals, fertilizers and other liquid products. Light refined products include gasolines, diesel fuels, heating oil and jet fuels. Heavy refined products include residual fuel oils and asphalt. We do not purchase or market products that we handle or transport. Therefore, we do not have 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, which accounts for a small portion of our revenue.

 

We use our owned and operated 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; heat residual fuel oils and asphalt stored in our tanks; and provide other ancillary services related to the throughput process.

Recent Developments

West Coast terminals acquisition. On December 15, 2017, we acquired the West Coast terminals from a third party for a total purchase price of approximately $276.8 million. The West Coast terminals represent two waterborne refined product and crude oil terminals located in the San Francisco Bay Area refining complex with a total of 64 storage tanks with approximately 5.0 million barrels of active storage capacity. The West Coast terminals have access to domestic and international crude oil and refined products markets through marine, pipeline, truck and rail logistics capabilities. Pursuant to a new long-term terminaling services agreement with a third party customer, we have begun the construction of an additional 125,000 barrels of storage capacity at one of the terminals. The acquisition of the West Coast terminals was financed with borrowings under our credit facility and, in connection with the acquisition, we entered into an amendment to our revolving credit facility on December 14, 2017, which increased the lender commitments under our revolving credit facility from $600 million to $850 million.

 

Expansion of our Collins bulk storage terminal. Our Collins/Purvis, Mississippi terminal complex is strategically located for the bulk storage market and is the only independent terminal capable of receiving from, delivering to, and transferring refined petroleum products between the Colonial and Plantation pipeline systems. We previously entered into long-term terminaling services agreements with various customers for approximately 2 million barrels of new tank capacity at our Collins, terminal. The revenue associated with these agreements came on-line upon completion of the construction of the new tank capacity at various stages beginning in the fourth quarter of 2016 through the second quarter of 2017. The aggregate cost of the approximately 2.0 million barrels of new tank capacity was approximately $75 million. With the completion of our Phase I expansion, our Collins/Purvis terminal complex has current active storage capacity of approximately 5.4 million barrels.

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In addition to the Phase I expansion at our Collins terminal, in the second half of 2017 we obtained an air permit for an additional 5.0 million barrels of capacity for a Phase II buildout. We have started the design and construction of 870,000 barrels of new storage capacity supported by the execution of a new long-term, fee-based terminaling services agreement with a third party customer, which constitutes the beginning of a Phase II buildout. To facilitate our further expansion of tankage at Collins, we also recently entered into an agreement with Colonial Pipeline Company for significant improvements to the Colonial Pipeline receipt and delivery manifolds and our related receipt and delivery facilities. The improvements will result in significant increased flexibility for our Collins customers including the simultaneous receipt and delivery of gasoline from and to Colonial’s Line 1 at full line rates including the ability to receive and deliver segregated batches at these rates; a dedicated and segregated line for the receipt and delivery of distillates from and to Colonial’s Line 2; and a dedicated and segregated line for the receipt and delivery of jet fuel from and to Colonial’s Line 2. The anticipated cost of the approximately 870,000 barrels of new storage capacity and our share of the improvements to the pipeline connections is approximately $55 million, with expected annual cash returns in the low-teens. We are currently in active discussions with several other existing and prospective customers regarding additional future capacity at our Collins terminal.

Public offering of senior notes.  On February 12, 2018, the Partnership and TLP Finance Corp., our wholly owned subsidiary completed the issuance and sale of $300 million in aggregate principal amount of 6.125% senior notes, issued at par and due 2026 (the “senior notes”). The senior notes are guaranteed on a senior unsecured basis by each of our wholly owned subsidiaries that guarantee obligations under our revolving credit facility. The net proceeds were used primarily to repay indebtedness under our revolving credit facility.

5


 

Our Assets and Operations

Our terminals are located in six geographic regions, which we refer to as our Gulf Coast, Midwest, Brownsville, River, Southeast and West Coast terminals. In addition, we have unconsolidated investments in BOSTCO and Frontera (each defined below).The locations and approximate aggregate active storage capacity at our owned and joint venture terminal facilities as of December 31, 2017 are as follows:

 

 

 

 

 

    

Active storage

 

 

 

capacity

 

 

 

(shell bbls)

 

Our Terminals by Region:

 

 

 

Gulf Coast Terminals:

 

 

 

Port Everglades North, FL

 

2,408,000

 

Port Everglades South, FL (1)

 

376,000

 

Jacksonville, FL

 

271,000

 

Cape Canaveral, FL

 

724,000

 

Port Manatee, FL

 

1,492,000

 

Pensacola, FL

 

270,000

 

Fisher Island, FL

 

673,000

 

Tampa, FL

 

760,000

 

Gulf Coast Total

 

6,974,000

 

Midwest Terminals:

 

 

 

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

 

421,000

 

Cushing, OK

 

1,005,000

 

Oklahoma City, OK

 

158,000

 

Midwest Total

 

1,584,000

 

Brownsville Terminal

 

891,000

 

River Terminals:

 

 

 

Arkansas City, AR

 

446,000

 

Evansville, IN

 

245,000

 

New Albany, IN

 

201,000

 

Greater Cincinnati, KY

 

189,000

 

Henderson, KY

 

170,000

 

Louisville, KY

 

183,000

 

Owensboro, KY

 

154,000

 

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

 

228,000

 

River Total

 

2,684,000

 

 

6


 

 

 

 

 

 

    

Active storage

 

 

 

capacity

 

 

 

(shell bbls)

 

Southeast Terminals:

 

 

 

Albany, GA

 

203,000

 

Americus, GA

 

98,000

 

Athens, GA

 

203,000

 

Bainbridge, GA

 

367,000

 

Belton, SC

 

 —

 

Birmingham, AL

 

178,000

 

Charlotte, NC

 

121,000

 

Collins/Purvis, MS (bulk storage)

 

5,367,000

 

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

 

448,000

 

Rome, GA

 

152,000

 

Selma, NC

 

529,000

 

Spartanburg, SC

 

166,000

 

Southeast Total

 

11,940,000

 

West Coast Terminals:

 

 

 

Martinez, CA

 

4,542,000

 

Richmond, CA

 

498,000

 

West Coast Total

 

5,040,000

 

Our Joint Ventures Terminals:

 

 

 

Frontera Joint Venture Terminal (2)

 

1,479,000

 

    BOSTCO Joint Venture Terminal (3)

 

7,080,000

 

TOTAL CAPACITY

 

37,672,000

 

 

(1)

Reflects our ownership interest net of a major oil company’s ownership interest in certain tank capacity.

(2)

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

(3)

Reflects the total active storage capacity of Battleground Oil Specialty Terminal Company LLC (“BOSTCO”), of which we have a 42.5%, general voting, Class A Member interest.

Gulf Coast Operations.  Our Gulf Coast terminals consist of eight refined product terminals and is the largest terminal network in Florida. These terminals have approximately 7.0 million barrels of aggregate active storage capacity in ports including Fort Lauderdale, Miami and Cape Canaveral, which are among the busiest cruise ship ports in the nation. 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. 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

7


 

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.

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 a third party, to our terminal at Rogers. The Razorback pipeline has a capacity of approximately 30,000 barrels per day. The facilities include two refined product terminals with approximately 0.4 million barrels of aggregate active storage capacity. Our Rogers facility is the only refined products terminal located in Northwest Arkansas.

We also own and operate a terminal facility at Oklahoma City, Oklahoma with approximately 0.2 million barrels of aggregate active storage capacity. Our Oklahoma City terminal receives gasolines and diesel fuels from a pipeline system owned by a third party for delivery via our truck rack for redistribution to locations throughout the Oklahoma City region.

We leased a portion of land in Cushing, Oklahoma and constructed storage tanks and associated infrastructure on the 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.

Brownsville, Texas Operations.  We own and operate a refined product terminal with approximately 0.9 million barrels of aggregate active storage capacity 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 refined products 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 refined products to Matamoros, Mexico. 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. Operations on the Diamondback pipeline were shut down in the first quarter of 2018; however, we expect to recommission the Diamondback pipeline and resume operations by the end of 2019.

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.

We also operate and maintain the United States portion of a 174-mile bi-directional refined products pipeline owned by a third party. This pipeline connects our Brownsville terminal complex to a pipeline in Mexico that delivers to a third party terminal located in Reynosa, Mexico and terminates at the third party’s refinery, located in Cadereyta, Nuevo Leon, Mexico, a suburb of the large industrial city of Monterrey. The pipeline transports refined products and blending components. We operate and manage the 18-mile portion of the pipeline located in the United States for a fee that is based on the average daily volume handled during the month. Additionally, we are reimbursed for non-routine maintenance expenses based on the actual costs plus a fee based on a fixed percentage of the expense. We expect this operating agreement to expire in the second quarter of 2018, after which it is anticipated a third party will take operatorship of the pipeline.

River Operations.  Our River terminals 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 operations also include a dock facility in Baton Rouge, Louisiana, which is the only direct waterborne connection between the Colonial pipeline and Mississippi River waterborne transportation. At our River terminals, we handle gasolines, diesel fuels, heating oil, chemicals and fertilizers on behalf of, and provide integrated terminaling services to,

8


 

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.

Southeast Operations.  Our Southeast terminals 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 11.9 million barrels. 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 with the exception of the Collins/Purvis bulk storage terminal. The Collins terminal, currently going through expansions, is the only independent terminal capable of storing and redelivering product to, from and between the Colonial and Plantation pipelines.

West Coast Operations. Our West Coast terminals consist of two refined product terminals with approximately 5.0 million barrels of active storage capacity and 5.4 million barrels of aggregate storage capacity. The terminals are strategically located in close proximity to three San Francisco Bay refineries and the origin of the North California products pipeline distribution system. At our West Coast terminals, we handle crude oil, gasoline, diesel, jet fuel, gasoline blend stocks fuel oil, Avgas and ethanol on behalf of, and provide integrated terminaling services to, customers engaged in the distribution and marketing of refined products. Our West Coast terminals primarily receive products from marine, pipeline and rail facilities on behalf of our customers and distribute products primarily via marine, pipeline, truck and rail facilities. We acquired the West Coast terminals in December 2017.

Investment in Frontera. On April 1, 2011, 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 in the Frontera joint venture. PMI Trading Ltd. 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. Frontera has approximately 1.5 million barrels of aggregate active storage capacity. Our 50% ownership interest does not allow us to control Frontera, but does allow us to exercise significant influence over its operations. Accordingly, we account for our investment in Frontera under the equity method of accounting.

 

Investment in BOSTCO.    On December 20, 2012, we acquired a 42.5% Class A ownership interest in BOSTCO from Kinder Morgan Battleground Oil, LLC, a wholly owned subsidiary of Kinder Morgan. BOSTCO is a 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.

In the second quarter of 2013 work began on a 900,000 barrel expansion that was placed into service at the end of the third quarter of 2014. 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. 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 $539 million. Our total payments for the initial and the expansion projects were approximately $237 million. We have primarily funded our payments for BOSTCO by utilizing borrowings under our revolving 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% Class A 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.

9


 

Our Services and Revenue Streams

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 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 Diamondback pipeline based on the volume of product transported and the distance from the origin point to the delivery point. We earn pipeline transportation fees at our Razorback pipeline based on an allocation of the aggregate fees charged under the capacity agreement with our customer who has contracted for 100% of our Razorback system. Federal Energy Regulatory Commission, or FERC, regulates the tariff on these 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 Frontera and receive a management fee based on our costs incurred. We also currently 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. We expect this operating arrangement to expire in the second quarter of 2018, after which it is anticipated that a third party will take operatorship of the pipeline. We manage and operate rail sites at certain Southeast terminals on behalf of a major oil company and receive reimbursement for operating and maintenance costs.

·

Other Revenue.  We provide ancillary services including heating and mixing of stored products, product transfer, railcar handling, butane blending, wharfage and vapor recovery. Pursuant to terminaling services agreements with certain 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.

Further detail regarding our financial information can be found under Item 8. “Financial Statements and Supplementary Data” of this Annual Report.

 

Business Strategies

Generate stable cash flows through the use of long-term contracts with our customers. We intend to continue to generate stable and predictable cash flows by capitalizing on our high quality, well positioned and geographically diverse asset base, which is critical infrastructure for our customers. In addition, we seek to continue to enhance the stability of our business by focusing on our highly contracted assets, long-term relationships with high quality customers, fee-based cash flows and multi-year minimum revenue commitments. We generate revenue from customers who pay us fees based on the volume of terminal capacity contracted for, volume of refined products throughput at our terminals or volume of refined products transported in our pipelines.

Attract additional volumes to our systems. We intend to attract new volumes of refined products, crude oil and specialty chemicals to our systems and terminals from existing and new customers by leveraging our asset base, continuing to provide superior customer service and through aggressively marketing our services to additional customers in our areas of operation. We have available capacity at certain terminal locations; as a result, we can accommodate additional volumes at a minimal incremental cost.

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Capitalize on organic growth opportunities associated with our existing assets. We continually seek to identify and evaluate economically attractive organic expansion and asset enhancement opportunities that leverage our existing asset footprint and strategic relationships with our customers. We intend to focus on projects that can be completed at a relatively low cost and that have potential for attractive returns. For example, we previously entered into long-term terminaling services agreements with various customers for approximately 2.0 million barrels of new tank capacity at our Collins terminal. The revenue associated with these agreements came on-line upon completion of the construction of the new tank capacity at various stages beginning in the fourth quarter of 2016 through the second quarter of 2017. The aggregate cost of the approximately 2.0 million barrels of new tank capacity was approximately $75 million, with expected annual cash returns in the high-teens. With the completion of our Phase I expansion, our Collins/Purvis terminal complex has current active storage capacity of approximately 5.4 million barrels.

In addition to the Phase I expansion at our Collins terminal, in the second half of 2017 we obtained an air permit for an additional 5.0 million barrels of capacity for a Phase II buildout. We have started the design and construction of 870,000 barrels of new storage capacity supported by the  execution of a new  long-term, fee-based terminaling services agreement with a third party customer, which constitutes the beginning of a Phase II buildout. To facilitate our further expansion of tankage at Collins, we also recently entered into an agreement with Colonial Pipeline Company for significant improvements to the Colonial Pipeline receipt and delivery manifolds and our related receipt and delivery facilities. The improvements will result in significant increased flexibility for our Collins customers including the simultaneous receipt and delivery of gasoline from and to Colonial’s Line 1 at full line rates including the ability to receive and deliver segregated batches at these rates; a dedicated and segregated line for the receipt and delivery of distillates from and to Colonial’s Line 2; and a dedicated and segregated line for the receipt and delivery of jet fuel from and to Colonial’s Line 2. The anticipated cost of the approximately 870,000 barrels of new storage capacity and our share of the improvements to the pipeline connections is approximately $55 million, with expected annual cash returns in the low-teens. We are currently in active discussions with several other existing and prospective customers regarding additional future capacity at our Collins terminal.

Pursue strategic and accretive acquisitions, including acquisitions from ArcLight and its affiliates in drop down transactions. We plan to pursue accretive acquisitions of high quality, critical energy infrastructure assets, including drop down transactions from ArcLight, which controls our general partner, and its affiliates, that are complementary to our existing asset base or that provide attractive returns in new operating regions or business lines. We will pursue acquisitions in our areas of operation that we believe will allow us to realize operational efficiencies by capitalizing on our existing infrastructure, personnel and customer relationships. We will also seek acquisitions in new geographic areas or new but related business lines to the extent that we believe we can utilize our operational expertise to enhance our business with these acquisitions.

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. We believe this conservative capital structure will allow us to consider attractive growth projects and acquisitions even in challenging commodity price or capital market environments.

Competitive Strengths

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

Our long-term relationships with our high-quality, creditworthy customers provide us with stable cash flows. We have strong relationships with high-quality, creditworthy counterparties. Our highly contracted assets are generally utilized by long tenured customers and have high contract renewal rates. Our actual revenue for a given 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.

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We have a high quality, well positioned and diversified asset base. We believe that our substantial and geographically diverse asset base will provide us with stable cash flows. Our terminals and truck loading racks with blending capabilities have substantial connectivity to major liquids pipelines in the Northeast, Southeast, Gulf Coast, Midwest and West Coast regions and provide critical services to our customers. 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.

We have minimal direct commodity price risk. Our highly contracted terminaling and transportation asset base mitigates volatility in our cash flows by limiting our direct exposure to commodity prices. Our throughput and related services fees in these businesses primarily provide us with fee-based cash flows and multi-year minimum revenue commitments. For the year ended December 31, 2017, 74% of our revenue was generated from fee-based contracts, 7% of our revenue was based on product and volumes gains including butane blending fees and the remaining 19% of our revenue was generated from ratable revenue sources.

Our Relationship with our General Partner and its Affiliates

We are controlled by our general partner, TransMontaigne GP, which is a wholly‑owned subsidiary of ArcLight. ArcLight is a private equity firm focused on North American and Western European energy assets. Since its establishment in 2001, ArcLight has invested over $19 billion across multiple energy cycles in more than 100 investments. Headquartered in Boston, MA with an additional office in Luxembourg, the firm’s investment team brings extensive energy expertise, industry relationships and specialized value creation capabilities to its portfolio. ArcLight controls our general partner and has a proven track record of investments across the energy industry value chain. ArcLight bases its investments on fundamental asset values and execution of defined growth strategies with a focus on cash flow generating assets and service companies with conservative capital structures.

ArcLight acquired its 100% interest in our general partner from NGL Energy Partners LP, or NGL, on February 1, 2016.  That transaction did not involve any acquisition of any of the Partnership’s common units that were held by the public, but ArcLight separately acquired approximately 3.2 million of our common units from NGL on April 1, 2016. As a result of these acquisitions, ArcLight’s ownership in us consists of 100% of our general partner interest and incentive distribution rights and approximately 19.2% of our common units.

 

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The following diagram depicts our organization and structure as of December 31, 2017:

 

 

M:\Merrill Bridge\FS\2017\Q4 2017\CHART 3.14.18.jpg

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Competition

We face competition from other terminals and pipelines that may be able to supply our customers with integrated terminaling and transportation services on a more competitive basis. We compete with national, regional and local terminal and transportation companies, including the major integrated oil companies, of widely varying sizes, financial resources and experience. These competitors include BP p.l.c., Buckeye Partners, L.P., Chevron U.S.A. Inc., CITGO Petroleum Corporation, Exxon Mobil Oil 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 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 that made up 83% of the total revenue for the year ended December 31, 2017. These relationships include: NGL Energy Partners LP, Castleton Commodities International LLC, RaceTrac Petroleum Inc., Glencore Ltd., Trafigura, Magellan Pipeline Company, L.P., United States Government, Valero Marketing and Supply Company, PMI Trading Ltd., Exxon Mobil Oil Corporation, World Fuel Services Corporation, Chevron Corporation and Andeavor.

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.

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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 for resale.

Transportation.  Before an independent distribution and marketing company 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 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.

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, biodiesel 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.

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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 up to 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.

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/Purvis, Mississippi bulk storage 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 bulk storage 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. We expect this operating arrangement to expire in the second quarter of 2018, after which it is anticipated that a third party will take operatorship of the pipeline. The maintenance of structural integrity includes a program of integrity management that conforms to Federal and State regulations and follows industry periodic inspection and testing guidelines. Beginning in 2002, the DOT required internal inspections or other integrity testing of all DOT‑regulated crude oil and refined product pipelines that affect or could affect high consequence areas, or HCA’s. We believe that the pipelines we own and manage meet or exceed all DOT inspection requirements for pipelines located in the United States.

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.

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At our terminals, tanks designed for gasoline storage are equipped with internal or external floating roofs or alternative vapor control devices 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 and believe that we are in material compliance with these PHMSA regulations.

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

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

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

Environmental Matters

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

·

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

·

requiring capital expenditures to comply with environmental control requirements; and

·

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

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to 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 material compliance with effluent limitations at our facilities and with the CWA generally.

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

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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 Office of Pipeline Safety 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 material 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 material 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.

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

In connection with our acquisition of the Florida and Midwest terminals on May 27, 2005, 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.

In connection with our acquisition of 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.

In connection with our acquisition of 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.

In connection with our acquisition of 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.

The forgoing environmental indemnification obligations of TransMontaigne LLC to us remain in place and were not affected by the ArcLight acquisition.  

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.

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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 of our 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.

Tariff Regulation

The Razorback pipeline, which runs between Mount Vernon, Missouri and Rogers, Arkansas and the Diamondback pipeline, which runs between Brownsville, Texas and the United States‑Mexico border, transport petroleum products subject to regulation by the FERC under the Interstate Commerce Act and the Energy Policy Act of 1992 and rules and orders promulgated under those statutes. FERC regulation requires that the rates of pipelines providing interstate service, such as the Razorback and Diamondback pipelines, be filed at FERC and posted publicly, and that these rates be “just and reasonable” and nondiscriminatory. Such rates are currently regulated by the FERC primarily through an index methodology, whereby a pipeline is allowed to change its rates based on the change from year to year in the Producer Price Index for Finished Goods (PPI‑FG), plus a 1.23 percent adjustment for the five‑year period beginning July 1, 2016. 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.  On October 20, 2016, the FERC issued an Advanced Notice of Proposed Rulemaking (ANOPR) to consider modifications to its current policies for evaluating oil pipeline index rate changes for the purpose of ensuring that index rate increases do not cause pipeline revenues to substantially deviate from costs.  Specifically, FERC is considering the following changes to their current indexing methodologies for oil pipelines: (A) deny index increases to rates for any pipeline whose FERC Form No. 6, Page 700 revenues exceed costs by fifteen percent for both of the prior two years; (B) deny index increases to rates that exceed by five percent the cost changes reported on Page 700; and (C) apply these reforms to costs more closely associated with the proposed indexed rate rather than total company-wide cost and revenue data currently reported on Page 700.  Initial comments were filed on January 19, 2017, and reply comments were due on March 6, 2017. It is premature to know what, if any, impact these proposed regulatory changes may have, or whether the proposal will be modified or even adopted all.

 

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 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.

 

Under current FERC policy, interstate oil and gas pipelines, including those owned by master limited partnerships, may include an income tax allowance in their cost of service used to calculate cost-based transportation rates to reflect the actual or potential income tax liability attributable to their public utility income, regardless of the form

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of ownership. FERC is currently reviewing and may modify its tax allowance policy used in formulating rates charged by pipelines owned by partnerships.  On July 1, 2016, in United Airlines, Inc. v FERC, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated a pair of FERC orders to the extent they permitted an interstate refined petroleum products pipeline owned by a master limited partnership to include an income tax allowance in its cost-of-service-based rates.  In that case, interstate shippers argued that FERC’s discounted cash flow methodology provides for a sufficient after-tax return on equity (ROE) to attract investment in partnerships not taxed at the partnership level.  The shippers claimed that the combination of the ROE allowed by FERC, based in part on the equity returns of entities taxed as corporations, and FERC’s tax allowance policy resulted in “double recovery” of taxes by the partners in the partnership in that case. The D.C. Circuit agreed, finding that FERC failed to provide sufficient evidence that granting the tax allowance to the pipeline partnership would not result in double recovery.  The D.C. Circuit remanded the case to FERC, ordering FERC to demonstrate that the allowance does not permit double recovery, remove any instances of duplicative recovery or develop a new methodology for ratemaking that does not result in double recovery.  On December 15, 2016, FERC issued a Notice of Inquiry seeking advice from energy industry participants on how to address the potential for over-recovery of income tax costs from Master Limited Partnerships under FERC’s current ratemaking policy. Initial comments were due March 8, 2017, and reply comments were due April 7, 2017. The outcome of this proceeding could affect FERC’s income tax allowance policy for cost-based rates charged by regulated pipelines going forward.  The current tariff rates for each of the Razorback and Diamondback pipelines were established via agreement with non-affiliated shippers. If the FERC were to substantially reduce or eliminate the right of a master limited partnership to include in its cost‑of‑service rate an income tax allowance, it may affect the Razorback, and Diamondback pipelines’ ability in the future to justify, on a cost-of-service basis, their tariff 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 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 encumbrances to which the underlying properties were subject at the time of our acquisition, our general partner believes

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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

We do not have any direct officers or employees. Pursuant to our omnibus agreement with ArcLight, all of the officers of our general partner and employees who provide services to the Partnership are employed by TLP Management Services, a wholly owned subsidiary of ArcLight. TLP Management Services provides payroll and maintains all employee benefits programs on behalf of our general partner and the Partnership.

As of March 9, 2018, approximately 504 employees of TLP Management Services provided services directly to us. As of March 15, 2018, none of TLP Management Services employees who provide services directly to us were covered by a collective bargaining agreement.

ITEM 1A.  RISK FACTORS

Our business, operations and financial condition are subject to various risks. You should carefully consider the following risk factors together with all of the other information set forth in this Annual Report, including the matters addressed under “Cautionary Statement Regarding Forward-Looking Statements,” 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 occurring, the market value of our common units 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;

·

the cost of acquisitions, if any;

·

the fees and expenses of our general partner and its affiliates that we are required to reimburse; and

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·

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 earnings, 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 with cash generated by our operations and borrowings under our revolving 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.  For example, in 2017 NGL accounted for approximately 26% of our annual revenue. Events that adversely affect the business operations of any one or more of our significant customers may adversely affect our financial condition or results of operations. Therefore, we are indirectly subject to the business risks of our significant customers, many of which are similar to the business risks we face. For example, a material decline in refined petroleum product supplies available to our customers, or a significant decrease in our customers’ ability to negotiate marketing contracts on favorable terms, could result in a material decline in the use of our tank capacity or throughput of product at our terminal facilities, which would likely cause our revenue and results of operations to decline. In addition, if any of our significant customers were unable to meet their contractual commitments to us for any reason, then our revenue and cash flow would decline.

We are exposed to the credit risks of our 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.

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 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 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.

Our continued expansion programs may require access to additional capital. Tightened capital 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 approved capital projects and future expansion. Our revolving credit facility provides for a maximum borrowing line of credit equal to $850 million. At December 31, 2017, our outstanding borrowings were $593.2 million. At December 31, 2017, the capital expenditures to complete the approved additional investments and expansion capital projects are estimated to be approximately $70 million. We expect to fund our future investments and expansion capital expenditures with additional borrowings under our revolving 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.

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

As of December 31, 2017, we had total long-term debt of $593.2 million and we had an unused borrowing base availability of $256.8 million under our revolving credit facility. Our level of debt could have important consequences to us. For example our level of debt could:

·

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

·

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

·

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

·

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

·

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.

Restrictive covenants in our revolving credit facility, the indenture governing our senior notes and future debt instruments may limit our ability to respond to changes in market conditions or pursue business opportunities.

Our revolving credit facility and the indenture governing our senior notes contain, and the terms of any future indebtedness may contain, restrictive covenants that limit our ability to, among other things:

·

incur or guarantee additional debt;

·

redeem or repurchase units or make distributions under certain circumstances;

·

make certain investments and acquisitions;

·

incur certain liens or permit them to exist;

·

enter into certain types of transactions with affiliates;

·

merge or consolidate with another company; and

·

transfer, sell or otherwise dispose of assets.

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Our revolving credit facility also contains covenants requiring us to maintain certain financial ratios and tests. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and there is no assurance that that we will meet any such ratios and tests.

The provisions of our revolving credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our revolving credit facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

We may incur substantial additional indebtedness, which could further exacerbate the risks that we may face.

Subject to the restrictions in the instruments governing our outstanding indebtedness (including our revolving credit facility and senior notes), we may incur substantial additional indebtedness (including secured indebtedness) in the future. Although the instruments governing our outstanding indebtedness do contain restrictions on the incurrence of additional indebtedness, these restrictions will be subject to waiver and a number of significant qualifications and exceptions, and indebtedness incurred in compliance with these restrictions could be substantial. As of December 31, 2017, we had additional borrowing capacity of $256.8 million under our revolving credit facility, all of which would be secured if borrowed.

Any increase in our level of indebtedness will have several important effects on our future operations, including, without limitation:

·

we will have additional cash requirements in order to support the payment of interest on our outstanding indebtedness;

·

increases in our outstanding indebtedness and leverage will increase our vulnerability to adverse changes in general economic and industry conditions, as well as to competitive pressure; and

·

depending on the levels of our outstanding indebtedness, our ability to obtain additional financing for working capital, capital expenditures and general partnership purposes may be limited.

The obligations of our 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 our 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.

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

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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.

In addition, our general partner’s affiliates, including ArcLight, may engage in competition with us. If we are unable to compete with services offered by our competitors, including ArcLight and its affiliates, it could have a material adverse effect on our financial condition, results of operations and cash flows.

Many of our terminal facilities are connected to, and rely on, pipelines owned and operated by third parties for the receipt and distribution of refined petroleum products, and such pipeline operators may compete with us, make changes to their transportation service offerings or their pipeline tariffs, or suffer outages or reduced product transportation, which in each case would adversely affect our financial condition and results of operations. 

Our Southeast facilities include 22 refined product terminals located along the Plantation and Colonial pipeline systems and primarily receive products from Plantation and Colonial on behalf of our customers. In addition, the Collins/Purvis bulk storage terminal receives from, delivers to, and transfers refined petroleum products between the Colonial and Plantation pipeline systems. In these instances, we depend on our terminals’ connections to such petroleum pipelines owned and operated by third parties to supply our terminal facilities. Our ability to compete in a particular terminal market could be harmed by factors we cannot control, including changes in pipeline service offerings at one or more of our terminals or changes in pipeline tariffs that make alternative third party terminal locations or different transportation options more attractive to our current or prospective customers.  

The FERC regulates the rates the pipeline operators can charge, and the terms and conditions they can offer, for interstate transportation service on refined products pipelines that connect to our terminals.  Generally, petroleum products pipelines may change their rates within prescribed levels, which could lead our current or prospective customers to seek alternative delivery methods or destinations. Moreover, we cannot control or predict the amount of refined petroleum products that our customers are able to transport on the third party pipelines connecting into our terminals. The level of throughput on these pipelines can be impacted by a number of factors, including the quality or quantity of refined product produced, pipeline outages or interruptions due to weather-related or other natural causes, competitive forces, testing, line repair, damage, reduced operating pressures or other causes any of which could

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negatively impact our customers’ shipments to our terminals. As a result, our revenue and results of operations could be materially adversely affected.

If we are unable to make acquisitions on economically acceptable terms, the future growth of our business will be limited, and the acquisitions we do make may reduce, rather than increase, our cash available for distribution on a per unit basis.

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. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash available for distribution on a per unit basis.

In addition, we may be unable to make attractive acquisitions for a number of reasons, including:

·

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

·

we may be unable to identify attractive acquisition candidates;

·

we may be unable to negotiate acceptable purchase contracts with the seller;

·

we may be unable to obtain financing for such acquisitions on economically acceptable terms; or

·

we may be unable to obtain necessary governmental or third-party consents.

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;

·

be unable to secure adequate customer commitments to use the acquired systems or facilities;

·

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;

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·

be unable to successfully integrate the assets or businesses we acquire;

·

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

·

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

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

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.

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 the 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, and earthquakes, which are common along the West Coast;

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·

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

·

acts of terrorism or vandalism.

If any of these events were to occur, we could suffer substantial losses because of personal injury or loss of life, severe damage to and destruction of storage tanks, pipelines and related property and equipment, and pollution or other environmental damage resulting in curtailment or suspension of our related operations and potentially substantial unanticipated costs for the repair or replacement of property and environmental cleanup. In addition, if we suffer accidental releases or spills of products at our terminals or pipelines, we could be faced with material third‑party costs and liabilities, including those relating to claims for damages to property and persons and governmental claims for natural resource damages or fines or penalties for related violations of environmental laws or regulations. We are not fully insured against all risks to our business and if losses in excess of our insurance coverage were to occur, they could have a material adverse effect on our operations. Furthermore, events like hurricanes can affect large geographical areas which can cause us to suffer additional costs and delays in connection with subsequent repairs and operations because contractors and other resources are not available, or are only available at substantially increased costs following widespread catastrophes.

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

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

Our insurance policies each contain caps on the insurer’s maximum liability under the policy, and claims made by 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.

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,

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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.

Cyber-attacks that circumvent our security measures and other breaches of our information technology systems 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 TLP Management Services, 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.

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

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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.

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 revolving credit facility matures in March 2022, and our senior notes mature in February 2026. At December 31, 2017 and February 12, 2018, we had outstanding borrowings under our revolving credit facility of $593.2 million and outstanding senior notes of $300 million outstanding, respectively. Our revolving credit facility provides that we pay interest on outstanding balances at interest rates based on market rates plus specified margins, ranging from 1.75% to 2.75% depending on the total leverage ratio in the case of loans with interest rates based on LIBOR, or ranging from 0.75% to 1.75% depending on the total leverage ratio in the case of loans with interest rates based on the base rate. We pay a fixed 6.125% interest rate on our senior notes. In the event we are required to refinance our revolving credit facility or our senior notes in unfavorable market conditions, we may have to pay interest at higher rates 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.

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.

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to human health and the environment, the U.S. Environmental Protection Agency (“EPA”) has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish pre-construction and operating permit requirements for certain large stationary sources.  The EPA has also adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified onshore and offshore natural gas and oil sources in

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the United States on an annual basis. 

 

Although Congress has from time to time considered legislation to reduce emissions of greenhouse gases, there has not been significant activity in the form of adopted legislation to reduce greenhouse gas emissions at the federal level in recent years.  In the absence of such federal climate change legislation, a number of states, including states in which we operate, have enacted or passed measures to track and reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and regional greenhouse gas cap-and-trade programs.  Most of these cap-and-trade programs require major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall greenhouse gas emission reduction goal is achieved. 

 

In addition, in December 2015, over 190 countries, including the United States, reached an agreement to reduce global greenhouse gas emissions (the “Paris Agreement”).  The Paris Agreement entered into force in November 2016 after more than 170 nations, including the United States, ratified or otherwise indicated their intent to be bound by the agreement.  However, in June 2017, President Trump announced that the United States intends to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or a separate agreement.  In August 2017, the U.S. Department of State officially informed the United Nations of the United States’ intent to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time.  To the extent that the United States and other countries implement this agreement or impose other climate change regulations on the oil and natural gas industry, it could have an adverse effect on our business.

 

In particular, the adoption and implementation of regulations that require the reporting of greenhouse gases or otherwise limit emissions of greenhouse gases from our equipment and operations could require us to incur costs to monitor and report on greenhouse gas emissions or install new equipment to reduce emissions of greenhouse gases associated with our operations. In addition, these regulatory initiatives could drive down demand for the refined petroleum products, natural gas and other hydrocarbon products we transport, store or otherwise handle in connection with our business by stimulating demand for alternative forms of energy that do not rely on the combustion of fossil fuels. Such decreased demand could have a material adverse effect on our business, financial condition, results of operations and 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

ArcLight indirectly controls our general partner, which has sole responsibility for conducting our business and managing our operations. ArcLight has conflicts of interest with and limited fiduciary duties to us, which may permit them to favor their own interests to our detriment.

TransMontaigne GP is our general partner and manages our operations and activities. ArcLight owns our general partner and is responsible under our omnibus agreement for providing the personnel who provide support to our operations. 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 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 ArcLight other than the indemnification provisions, will be terminable by ArcLight 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

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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.

Four of our general partner’s directors are affiliated with ArcLight. Therefore, conflicts of interest may arise between ArcLight and its affiliates and subsidiaries, and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving those conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders.

These conflicts include, among others, the following potential conflicts of interest:

·

ArcLight and its affiliates may engage in competition with us under certain circumstances;

·

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;

·

Neither our partnership agreement nor any other agreement requires ArcLight or its affiliates 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. ArcLight’s directors and officers have fiduciary duties to make decisions in the best interests of ArcLight, which may be contrary to our interests or the interests of our customers;

·

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

·

Our general partner is allowed to take into account the interests of parties other than us, such as ArcLight, or its affiliates, 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;

·

Certain directors of our general partner are officers or directors of affiliates of our general partner, including ArcLight, and also devote significant time to the business of these entities and are compensated accordingly;

·

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

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in the immediately preceding quarter. As of December 31, 2017, that amount was $62.3 million, $23.0 million of which would go to our general partner in the form of distributions on their general partner interest and incentive distribution rights;

·

Our general partner determines which out‑of‑pocket costs incurred by TLP Management Services are reimbursable by us;

·

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; or

·

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

 

Upon the expiration or earlier termination of the omnibus agreement, we may incur additional costs to replicate the services currently provided thereunder, in which event our financial condition and results of operations could be materially adversely affected.

Our partnership has no officers or employees and all of our management and operational activities are provided by officers and employees of TLP Management Services, a wholly owned indirect subsidiary of ArcLight. Under the omnibus agreement we pay TLP Management Services an annual administrative fee for the provision of various general and administrative services for our benefit.

The omnibus agreement expires on the earlier to occur of ArcLight ceasing to control our general partner or following at least 24 months’ prior written notice to the other parties. We cannot predict whether a change of control will occur, or whether our general partner will seek to terminate, amend or modify the terms of the omnibus agreement.  Following the expiration or the earlier termination of the omnibus agreement, the partnership will be required to assume directly or indirectly through one or more service providers, the scope of the services provided to the partnership under the omnibus agreement.  If we are unsuccessful in negotiating acceptable terms with a successor service provider, if we are required to pay a higher administrative fee or if we must incur substantial costs to replicate the services currently provided by ArcLight and its affiliates under the omnibus agreement, our financial condition and results of operations could be materially adversely affected.

Affiliates of our general partner, including ArcLight, may compete with us and do not have any obligation to present business opportunities to us.

Neither our partnership agreement nor any other agreement will prohibit affiliates of our general partner, including ArcLight, from owning assets or engaging in businesses that compete directly or indirectly with us. For example, an affiliate of ArcLight is the majority owner of the general partner of another publicly traded master limited partnership in the midstream segment of the energy industry, which may compete with us in the future. In addition, ArcLight and other affiliates of our general partner may acquire, construct or dispose of midstream assets or other assets in the future without any obligation to offer us the opportunity to purchase any of those assets. ArcLight and its affiliates are large, established participants in the energy industry and may have greater resources than we have, which may make it more difficult for us to compete with these entities with respect to commercial activities as well as for acquisition opportunities. As a result, competition from affiliates of our general partner, including ArcLight, could materially adversely impact our results of operations and distributable cash flow.

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

Our general partner may transfer its general partner interest in TransMontaigne Partners 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 the partnership. Furthermore, our partnership agreement does not restrict the ability of ArcLight, the owner of our general partner, from transferring its limited liability company interest in our general partner

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to a third party. The new owner of our general partner could then be in a position to replace the board of directors and officers of our general partner with their own choices and to control the decisions taken by the board of directors and officers.  In that event, our general partner would be able to take steps to protect the interests of the partnership.

Fees due to our general partner and its affiliates for services provided under the omnibus agreement 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, 2017, we paid affiliates of our general partner an administrative fee of approximately $12.8 million pursuant to the omnibus agreement.  The administrative fee is subject to increase at the request of ArcLight in the event we acquire or construct facilities. 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.

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

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

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.

The market price of our common units may be adversely affected by the future issuance and sale of additional common units or by our announcement that such issuances and sales may occur.

We have an effective universal shelf‑registration statement on Form S‑3 and an existing sales agreement filed with the SEC in our Prospectus Supplement to Prospectus dated September 2, 2016, which sales agreement covers “at-the-market” equity issuances that may be made from time to time through our sales agent.  We cannot predict the size of future issuances or sales of our common units, including, pursuant to our outstanding sales agreement, or in connection with future acquisitions or capital raising activities, or the effect, if any, that such issuances or sales may have on the market price of our common units.  In addition, under the sales agreement, the sales agent will not engage in any transactions that stabilize the price of our common units.  The issuance and sale of substantial amounts of common units, including issuances and sales pursuant to the sales agreement, or announcement that such issuances and sales may occur, could adversely affect the market price of our common units.

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.

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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 us 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 the 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 21%. In such a circumstance, distributions to our unitholders would generally be taxed again as corporate distributions (if such distributions were less than our earnings and profits) and no income, gains, losses, deductions or credits would flow through to our unitholders. Imposition of a corporate tax would substantially reduce our cash flows and after‑tax return to our unitholders. This likely would cause a substantial reduction in the value of the common units.

Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the qualifying income requirements, affect or cause us to change our business activities, affect the tax considerations of an investment in a publicly traded partnership, including us, change the character or treatment of portions of our income and adversely affect an investment in our common units. We are unable to predict whether any current or future proposed federal income tax law changes will ultimately be enacted.

In addition, some states have subjected partnerships to entity‑level taxation through the imposition of state income, franchise or other forms of taxation, and other states may follow this trend. If any state were to impose a tax upon us as an entity, our cash flows would be reduced. For example, under current legislation, we are subject to an entity‑level tax on the portion of our total revenue (as that term is defined in the legislation) that is generated in Texas. For the year ended December 31, 2017, we recognized a liability of approximately $0.1 million for the Texas margin tax, which is imposed at a maximum effective rate of 0.75% of our total revenue and tax gains from Texas. Imposition of such a tax on us by Texas, or any other state, will reduce the cash available for distribution to our unitholders. The partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity‑level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amounts will be reduced to reflect the impact of that law on us.

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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 has previously experienced three deemed technical terminations.  The first deemed technical termination experienced by the partnership was for the period ended December 30, 2007, due to a change in our ownership structure effective December 31, 2007.  The second deemed technical termination experienced by the partnership was for the period ended December 30, 2014, due to 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 effective 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 the restructuring of Kinder Morgan Energy Partners, L.P. and its affiliates.

Pursuant to the Arclight acquisition, on April 1, 2016, affiliates of ArcLight acquired approximately 3.2 million of our common limited partnership units from NGL.  As a result of this transaction, combined with the Arclight acquisition on February 1, 2016 and the other exchanges of our common units within the 12-month prior period, the partnership experienced a third technical termination as of April 1, 2016.  Further, as a result of TransMontaigne Partners’ technical termination, Frontera also experienced a technical termination on April 1, 2016.  Due to these technical terminations experienced for federal income tax purposes, our partnership and the Frontera joint venture will 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.

If we are unable to make acquisitions and investments to increase our capital asset base, we may encounter 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 from third parties, limiting additions to our capital assets primarily to additions and improvements that we constructed or added to our existing facilities. Although we are no longer under such regulatory constraints, if we do not grow our capital asset base quickly enough to avoid our tax depreciation from declining in the future, some unitholders may 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.

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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.

We may be required to deduct and withhold amounts from distributions to foreign unitholders related to withholding tax obligations arising from the sale or disposition of our units by foreign unitholders.

 

Upon the sale, exchange or other disposition of a unit by a foreign unitholder, the transferee is generally required to withhold 10% of the amount realized on such sale, exchange or other disposition if any portion of the gain on such sale, exchange or other disposition would be treated as effectively connected with a U.S. trade or business. If the transferee fails to satisfy this withholding requirement, we will be required to deduct and withhold such amount (plus interest) from future distributions to the transferee. Because the “amount realized” would include a unitholder’s share of our nonrecourse liabilities, 10% of the amount realized could exceed the total cash purchase price for such disposed units. Due to this fact, our inability to match transferors and transferees of units, and other uncertainty surrounding the application of these withholding rules, the U.S. Department of the Treasury and the IRS have currently suspended these rules for transfers of certain publicly traded partnership interests, including transfers of our units, until regulations or other guidance has been issued. It is unclear when such regulations or other guidance will be issued.

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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 common 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

We are party to various legal, regulatory and other matters arising from the day-to-day operations of our business that may result in claims against us. While the ultimate impact of any proceedings cannot be predicted with certainty, our management believes that the resolution of any of our pending legal proceedings will not have a material adverse effect on our business, financial position, results of operations or cash flows.

ITEM 4.  MINE SAFETY DISCLOSURES

Not applicable.

40


 

Part II

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

MARKET FOR COMMON UNITS

The common units are listed and traded on the New York Stock Exchange under the symbol “TLP.” On March 9, 2018, there were 52 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, 2016 through March 31, 2016

 

$

25.08

 

$

41.21

 

April 1, 2016 through June 30, 2016

 

$

35.30

 

$

42.77

 

July 1, 2016 through September 30, 2016

 

$

38.38

 

$

46.45

 

October 1, 2016 through December 31, 2016

 

$

36.93

 

$

45.74

 

January 1, 2017 through March 31, 2017

 

$

43.15

 

$

49.31

 

April 1, 2017 through June 30, 2017

 

$

39.36

 

$

46.67

 

July 1, 2017 through September 30, 2017

 

$

41.75

 

$

47.45

 

October 1, 2017 through December 31, 2017

 

$

37.40

 

$

43.99

 

 

DISTRIBUTIONS OF AVAILABLE CASH

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

 

 

 

 

 

 

    

Distribution

 

January 1, 2016 through March 31, 2016

 

$

0.680

 

April 1, 2016 through June 30, 2016

 

$

0.690

 

July 1, 2016 through September 30, 2016

 

$

0.700

 

October 1, 2016 through December 31, 2016

 

$

0.710

 

January 1, 2017 through March 31, 2017

 

$

0.725

 

April 1, 2017 through June 30, 2017

 

$

0.740

 

July 1, 2017 through September 30, 2017

 

$

0.755

 

October 1, 2017 through December 31, 2017

 

$

0.770

 

 

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;

41


 

·

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 revolving credit facility may limit our ability to distribute cash under certain circumstances as discussed under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” of this Annual Report.

INCENTIVE DISTRIBUTION RIGHTS

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

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

 

 

 

 

 

 

 

 

 

 

 

 

Marginal percentage

 

 

 

 

 

interest in

 

 

 

 

 

distributions

 

 

    

Total per unit

    

 

 

General

 

 

 

quarterly distribution

 

Unitholders

 

partner

 

Minimum quarterly distribution

    

$0.40

    

98

%  

 2

%  

First target distribution

 

up to $0.44

 

98

%  

 2

%  

Second target distribution

 

above $0.44 up to $0.50

 

85

%  

15

%  

Third target distribution

 

above $0.50 up to $0.60

 

75

%  

25

%  

Thereafter

 

above $0.60

 

50

%  

50

%  

 

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

42


 

ITEM 6.  SELECTED FINANCIAL DATA

The following table sets forth our selected historical consolidated financial data 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, 2017, has been derived from our consolidated financial statements. You should not expect the results for any prior periods to be indicative of the results that may be achieved in future periods. You should read the following information together with our historical consolidated financial statements and related notes and with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this Annual Report

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Years ended December 31,

 

 

2017 (2)

 

2016

 

2015

 

2014 (1)

 

2013 (1)

 

 

(dollars in thousands except per unit amounts)

 

Operations Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenue

$

183,272

    

$

164,924

    

$

152,510

    

$

150,062

    

$

158,886

 

Direct operating costs and expenses

 

(67,700)

 

 

(68,415)

 

 

(64,033)

 

 

(66,183)

 

 

(69,390)

 

General and administrative expenses

 

(19,433)

 

 

(14,100)

 

 

(14,749)

 

 

(13,941)

 

 

(14,525)

 

Insurance expenses

 

(4,064)

 

 

(4,081)

 

 

(3,756)

 

 

(3,711)

 

 

(3,763)

 

Equity-based compensation expense

 

(2,999)

 

 

(3,263)

 

 

(1,411)

 

 

(2,221)

 

 

(1,599)

 

Depreciation and amortization

 

(35,960)

 

 

(32,383)

 

 

(30,650)

 

 

(29,522)

 

 

(29,568)

 

Loss on disposition of assets

 

 —

 

 

             —

 

 

              —

 

 

            —

 

 

(1,294)

 

Earnings (loss) from unconsolidated affiliates

 

7,071

 

 

10,029

 

 

11,948

 

 

4,443

 

 

(321)

 

Operating income

 

 60,187

 

 

52,711

 

 

49,859

 

 

38,927

 

 

38,426

 

Other expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

(10,473)

 

 

(7,787)

 

 

(7,396)

 

 

(5,489)

 

 

(2,712)

 

Amortization of deferred financing costs

 

(1,221)

 

 

(818)

 

 

(774)

 

 

(975)

 

 

(975)

 

Foreign currency transaction loss

 

 —

 

 

             —

 

 

              —

 

 

            —

 

 

(13)

 

Net earnings

 

48,493

 

 

44,106

 

 

41,689

 

 

32,463

 

 

34,726

 

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

 

(12,705)

 

 

(9,340)

 

 

(7,506)

 

 

(7,167)

 

 

(5,929)

 

Net earnings allocable to limited partners

$

35,788

 

$

34,766

 

$

34,183

 

$

25,296

 

$

28,797

 

Net earnings per limited partner unit—basic

$

2.20

 

$

2.14

 

$

2.12

 

$

1.57

 

$

1.90

 

Net earnings per limited partner unit—diluted

$

2.20

 

$

2.14

 

$

2.12

 

$

1.57

 

$

1.90

 

Other Financial Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

$

103,704

 

$

79,107

 

$

87,480

 

$

60,929

 

$

64,235

 

Net cash used in investing activities

$

(337,070)

 

$

(69,089)

 

$

(34,153)

 

$

(50,702)

 

$

(119,958)

 

Net cash provided by (used in) financing activities

$

233,696

 

$

(10,106)

 

$

(55,950)

 

$

(10,186)

 

$

52,192

 

Cash distributions declared per common unit attributable to the period

$

2.990

 

$

2.780

 

$

2.665

 

$

2.655

 

$

2.590

 

Balance Sheet Data (at period end):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property, plant and equipment, net

$

655,053

 

$

416,748

 

$

388,423

 

$

385,301

 

$

407,045

 

Investments in unconsolidated affiliates(1)

$

233,181

 

$

241,093

 

$

246,700

 

$

249,676

 

$

211,605

 

Total assets

$

987,003

 

$

689,694

 

$

656,687

 

$

664,057

 

$

648,432

 

Long-term debt

$

593,200

 

$

291,800

 

$

248,000

 

$

252,000

 

$

212,000

 

Partners’ equity

$

364,217

 

$

372,734

 

$

383,971

 

$

391,465

 

$

408,467

 


(1)

Our investments in unconsolidated affiliates include a 42.5% ownership interest in BOSTCO and a 50% ownership interest in Frontera. BOSTCO is a terminal facility located on the Houston Ship Channel with approximately 7.1 million barrels of storage capacity at a construction cost of approximately $539 million. Our total contributions were approximately $237 million. We funded our payments for BOSTCO primarily utilizing borrowings under our revolving credit facility. The BOSTCO facility began initial commercial operation in the fourth quarter of 2013. Completion of the approximately 7.1 million barrels of storage capacity and related infrastructure occurred in the third quarter of 2014.

43


 

(2)

On December 15, 2017, we acquired the West Coast terminals from a third party for a total purchase price of $276.8 million. The West Coast terminals represent two waterborne refined product and crude oil terminals located in the San Francisco Bay Area refining complex with a total of 64 storage tanks with approximately 5.0 million barrels of active storage capacity. The West Coast terminals have access to domestic and international crude oil and refined products markets through marine, pipeline, truck and rail logistics capabilities. The accompanying consolidated financial statements include the assets, liabilities and results of operations of the West Coast terminals from December 15, 2017.  

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

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

OVERVIEW

We are a refined petroleum products terminaling and pipeline transportation company formed in February 2005 as a Delaware limited partnership. We are controlled by our general partner, TransMontaigne GP, which is a wholly‑owned indirect subsidiary of ArcLight. Prior to February 1, 2016, TransMontaigne LLC, a wholly owned subsidiary of NGL, owned all of the issued and outstanding ownership interests of TransMontaigne GP. At December 31, 2017, our operations are composed of:

·

Eight refined product terminals located in Florida (“Gulf Coast terminals”), with an aggregate active storage capacity of approximately 7.0 million barrels, that provide integrated terminaling services to NGL, RaceTrac Petroleum Inc., Glencore Ltd., Trafigura, World Fuel Services Corporation, ExxonMobil Oil Corporation, United States Government, Motiva Enterprises LLC, 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 0.4 million 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 an aggregate active storage capacity of approximately 1.0 million barrels that provides integrated terminaling services to Castleton Commodities International LLC.

·

One refined product terminal located in Oklahoma City, Oklahoma, with aggregate active storage capacity of approximately 0.2 million barrels, that provides integrated terminaling services to a third party distribution and marketing company.

·

One refined product terminal located in Brownsville, Texas with aggregate active storage capacity of approximately 0.9 million barrels that provides integrated terminaling services to 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./Mexico border. At the U.S. border the Diamondback pipeline connects to a pipeline and storage terminal in Matamoros, Mexico, owned by a third party.

·

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

44


 

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

·

A 42.5%, general voting, Class A Member ownership interest in BOSTCO. BOSTCO is a 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 operations in the fourth quarter of 2013.  Completion of the approximately 7.1 million barrels of storage capacity and related infrastructure occurred at the end of the third quarter of 2014.

·

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.

·

Twenty‑two refined product terminals located along the Colonial and Plantation pipelines (“Southeast terminals”) with aggregate active storage capacity of approximately 11.9 million barrels that provides integrated terminaling services to NGL, Castleton Commodities International LLC and the United States Government.

·

Two refined product terminals located in close proximity to three San Francisco Bay refineries and the origin of the North California products pipeline distribution system, which we refer to as the West Coast terminals. These terminals have aggregate active storage capacity of approximately 5.0 million barrels. We acquired the West Coast terminals in December 2017.

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.

Our customer base has diversified over the past few years away from affiliates to third party customers. As of December 31, 2017 affiliates are no longer our largest customers and our agreements with them do not provide a substantial amount of our revenue. Our revenue from affiliates represents approximately 4%, 5% and 28%,  of our revenue for the years ended December 31, 2017, 2016 and 2015, respectively, and is primarily earned pursuant to terminaling services agreements (see Note 2 of Notes to consolidated financial statements).

45


 

SIGNIFICANT DEVELOPMENTS SINCE THE FILING OF OUR PRIOR YEAR FORM 10-K

EXPANSION OF ASSETS

 West Coast terminals acquisition. On December 15, 2017, we acquired the West Coast terminals from a third party for a total purchase price of approximately $276.8 million. The West Coast terminals represent two waterborne refined product and crude oil terminals located in the San Francisco Bay Area refining complex with a total of 64 storage tanks with approximately 5.0 million barrels of active storage capacity. The West Coast terminals have access to domestic and international crude oil and refined products markets through marine, pipeline, truck and rail logistics capabilities.. Pursuant to a new long-term terminaling services agreement with a third party customer, we have begun the construction of an additional 125,000 barrels of storage capacity at one of the terminals. The acquisition of the West Coast terminals was financed with borrowings under our credit facility and, in connection with the acquisition, we entered into an amendment to our revolving credit facility on December 14, 2017, which increased the lender commitments under our revolving credit facility from $600 million to $850 million.

 

Expansion of our Collins bulk storage terminal. Our Collins/Purvis, Mississippi terminal complex is strategically located for the bulk storage market and is the only independent terminal capable of receiving from, delivering to, and transferring refined petroleum products between the Colonial and Plantation pipeline systems. We previously entered into long-term terminaling services agreements with various customers for approximately 2 million barrels of new tank capacity at our Collins, terminal. The revenue associated with these agreements came on-line upon completion of the construction of the new tank capacity at various stages beginning in the fourth quarter of 2016 through the second quarter of 2017. The aggregate cost of the approximately 2.0 million barrels of new tank capacity was approximately $75 million. With the completion of our Phase I expansion, our Collins/Purvis terminal complex has current active storage capacity of approximately 5.4 million barrels.

In addition to the Phase I expansion at our Collins terminal, in the second half of 2017 we obtained an air permit for an additional 5.0 million barrels of capacity for a Phase II buildout. We have started the design and construction of 870,000 barrels of new storage capacity supported by the execution of a new long-term, fee-based terminaling services agreement with a third party customer, which constitutes the beginning of a Phase II buildout. To facilitate our further expansion of tankage at Collins, we also recently entered into an agreement with Colonial Pipeline Company for significant improvements to the Colonial Pipeline receipt and delivery manifolds and our related receipt and delivery facilities. The improvements will result in significant increased flexibility for our Collins customers including the simultaneous receipt and delivery of gasoline from and to Colonial’s Line 1 at full line rates including the ability to receive and deliver segregated batches at these rates; a dedicated and segregated line for the receipt and delivery of distillates from and to Colonial’s Line 2; and a dedicated and segregated line for the receipt and delivery of jet fuel from and to Colonial’s Line 2. The anticipated cost of the approximately 870,000 barrels of new storage capacity and our share of the improvements to the pipeline connections is approximately $55 million, with expected annual cash returns in the low-teens. We are currently in active discussions with several other existing and prospective customers regarding additional future capacity at our Collins terminal.

Right of first offer agreements with Pike West Coast Holdings. On August 4, 2017 we entered into a right of first offer agreement with Pike West Coast Holdings, LLC, or Pike, a subsidiary of ArcLight. Pike owns 100% of the outstanding membership interests in SeaPort Midstream Holdings, LLC, or SMH, which owns an equity interest in SeaPort Midstream Partners, LLC, or SMP. SMH and BP West Coast Products LLC formed SMP as a joint venture that focuses on refined product logistics infrastructure assets in the U.S. Pacific Northwest, including two refined product terminals in Seattle, Washington and Portland, Oregon. TLP Management Services, LLC an ArcLight subsidiary, operates the terminals under a multi-year operating agreement. In addition, on September 12, 2017 we entered into a separate right of first offer agreement with Pike relating to Pike’s ownership of 100% of the outstanding membership interests of SeaPort Pipeline Holdings, LLC, or SPH, which owns a 30% membership interest in Olympic Pipe Line Company LLC. The Olympic Pipeline is a regulated interstate refined products pipeline system that spans approximately 400 miles across the states of Washington and Oregon. Pursuant to these agreements Pike granted us a right of first offer to acquire its 100% ownership interests in SMH and/or SPH.

46


 

FINANCING

Credit facility amendment. In connection with our West Coast Acquisition, we entered into an amendment to our revolving credit facility on December 14, 2017, which increased the lender commitments under our revolving credit facility from $600 million to $850 million (the “Credit Facility Amendment”).

Ninth consecutive increase in quarterly distribution.  On January 16, 2018, we announced a quarterly distribution of $0.77 per unit for the three months ended December 31, 2017. This $0.015 increase over the previous quarter reflects the ninth consecutive increase in our distribution and represents annual growth of 8.5% over the fourth quarter of last year. This distribution was paid on February 8, 2018 to unitholders of record on January 31, 2018.

Public offering of senior notes.  On February 12, 2018, the Partnership and TLP Finance Corp., our wholly owned subsidiary completed the issuance and sale of $300 million in aggregate principal amount of 6.125% senior notes, issued at par and due 2026 (the “senior notes”). The senior notes were guaranteed on a senior unsecured basis by each of our wholly owned subsidiaries that guarantee obligations under our revolving credit facility. The net proceeds were used primarily to repay indebtedness under our revolving credit facility.

NATURE OF REVENUE AND EXPENSES

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

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 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 Diamondback pipeline based on the volume of product transported and the distance from the origin point to the delivery point. We earn pipeline transportation fees at our Razorback pipeline based on an allocation of the aggregate fees charged under the capacity agreement with our customer who has contracted for 100% of our Razorback system. Federal Energy Regulatory Commission, or FERC regulates the tariff on these 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 Frontera and receive a management fee based on our costs incurred. We also currently 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. This operating arrangement will expire in the second quarter of 2018, after which a third party will take operatorship of the pipeline. We manage and operate rail sites at certain Southeast terminals on behalf of a major oil company and receive reimbursement for operating and maintenance costs.

Other revenue.  We provide ancillary services including heating and mixing of stored products, product transfer, railcar handling, butane blending, wharfage and vapor recovery. Pursuant to terminaling services agreements with certain 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.

Direct operating costs and expenses.  The direct operating costs and expenses of our operations include the directly related wages and employee benefits, utilities, communications, maintenance and repairs, property taxes, rent, vehicle expenses, environmental compliance costs, materials and supplies needed to operate our terminals and pipelines.

General and administrative expenses.  The general and administrative expenses of our operations include an administrative fee paid to the owner of TransMontaigne GP for indirect corporate overhead to cover costs of centralized

47


 

corporate functions such as legal, accounting, treasury, insurance administration and claims processing, health, safety and environmental, information technology, human resources, credit, payroll, taxes, engineering and other corporate services. General and administrative expenses also include direct general and administrative expenses for third party accounting costs associated with annual and quarterly reports and tax return and Schedule K‑1 preparation and distribution and legal fees.

Insurance expenses. Insurance expenses include charges for insurance premiums to cover costs of insuring activities such as property, casualty, pollution, automobile, directors’ and officers’ liability, and other insurable risks.

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. The following estimates, in management’s opinion, are subjective in nature, require the exercise of judgment and involve complex analyses: useful lives of our plant and equipment and accrued environmental obligations. These estimates are based on our knowledge and understanding of current conditions and actions we may take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our financial condition and results of operations (see Note 1 of Notes to consolidated financial statements).

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

Accrued environmental obligations.  At December 31, 2017, we have an accrued liability of approximately $1.9 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). The forgoing environmental indemnification obligations of TransMontaigne LLC to us remain in place and were not affected by the ArcLight acquisition.  

Business combination estimates and assumptions. The application of business combination and impairment accounting requires us to use significant estimates and assumptions in determining the fair value of assets and liabilities. The acquisition method of accounting for business combinations requires us to estimate the fair value of assets acquired and liabilities assumed to allocate the proper amount of the purchase price consideration between goodwill and the assets that are depreciated and amortized. We record intangible assets separately from goodwill and amortize intangible assets

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with finite lives over their estimated useful life as determined by management. We do not amortize goodwill but instead periodically assess goodwill for impairment.

For all material acquisitions, we engage the services of an independent appraiser to assist us in determining the fair value of the acquired assets and liabilities, including goodwill; however, the ultimate determination of those values is the responsibility of our management. We base our estimates on assumptions believed to be reasonable, but which are inherently uncertain. These valuations require the use of management’s assumptions, which would not reflect unanticipated events and circumstances that may occur.

RESULTS OF OPERATIONS—YEARS ENDED DECEMBER 31, 2017, 2016 AND 2015

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,

 

 

    

2017

    

2016

    

2015

 

Terminaling services fees

 

$

145,544

 

$

126,090

 

$

114,235

 

Pipeline transportation fees

 

 

5,719

 

 

6,789

 

 

6,613

 

Management fees and reimbursed costs

 

 

9,202

 

 

8,844

 

 

7,626

 

Other

 

 

22,807

 

 

23,201

 

 

24,036

 

Revenue

 

$

183,272

 

$

164,924

 

$

152,510

 

 

See discussion below for a detailed analysis of terminaling services fees, 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 six principal business segments: (i) Gulf Coast terminals, (ii) Midwest terminals and pipeline system, (iii) Brownsville terminals, (iv) River terminals, (v) Southeast terminals and (vi) West Coast 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,

 

 

    

2017

    

2016

    

2015

 

Gulf Coast terminals

 

$

62,941

 

$

56,710

 

$

53,708

 

Midwest terminals and pipeline system

 

 

10,997

 

 

11,201

 

 

11,422

 

Brownsville terminals

 

 

20,645

 

 

25,485

 

 

25,703

 

River terminals

 

 

10,947

 

 

12,578

 

 

10,194

 

Southeast terminals

 

 

76,004

 

 

58,950

 

 

51,483

 

West Coast terminals

 

 

1,738

 

 

 —

 

 

 —

 

Revenue

 

$

183,272

 

$

164,924

 

$

152,510

 

 

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

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

 

 

 

 

 

 

 

 

 

 

 

 

 

Terminaling Services Fees

 

 

 

by Business Segment

 

 

 

Year ended

 

Year ended

 

Year ended

 

 

 

December 31,

 

December 31,

 

December 31,

 

 

    

2017

    

2016

    

2015

 

Gulf Coast terminals

 

$

50,613

 

$

45,903

 

$

42,049

 

Midwest terminals and pipeline system

 

 

8,443

 

 

8,590

 

 

8,330

 

Brownsville terminals

 

 

7,591

 

 

8,234

 

 

8,037

 

River terminals

 

 

10,174

 

 

9,664

 

 

9,316

 

Southeast terminals

 

 

67,323

 

 

53,699

 

 

46,503

 

West Coast terminals (1)

 

 

1,400

 

 

 —

 

 

 —

 

Terminaling services fees

 

$

145,544

 

$

126,090

 

$

114,235

 

The increase in terminaling services fees at our Gulf Coast terminals for the year ended December 31, 2017 includes an increase of approximately $1.4 million resulting from re-contracting capacity at Port Manatee, Florida in July 2016 and November 2016. The increase in terminaling services fees at our Gulf Coast terminals also includes an increase of approximately $1.4 million resulting from increased throughput by various customers and $0.7 million resulting from contracting refurbished capacity at Port Manatee and Jacksonville, Florida in May 2017. The increase in terminaling services fees at our Gulf Coast terminals for the year ended December 31, 2016 includes an increase of approximately $1.4 million resulting from the majority of the light oil tankage at our Port Manatee terminal being offline for approximately four months during the year ended December 31, 2015 in order to complete enhancements for a new customer at this facility. The enhanced tankage at Port Manatee became available to the third party customer in July of 2015. The increase in terminaling services fees at our Gulf Coast terminals also includes an increase of approximately $1.1 million resulting from the acquisition of the Port Everglades, Florida hydrant system on January 28, 2016 and an increase of approximately $0.8 million due to re-contracting our bunker fuel capacity at Port Manatee, vacant since May 31, 2014, to third party customers.

The increase in terminaling services fees at our Southeast terminals for the year ended December 31, 2017 includes an increase of approximately $12.9 million resulting from placing into service  approximately 2.0 million barrels of new tank capacity at our Collins, MS bulk storage terminal in various stages beginning in the fourth quarter of 2016 through the second quarter of 2017. The increase in terminaling services fees at our Southeast terminals for the year ended December 31, 2016 includes an increase of approximately $4.6 million resulting from us entering into a new five year agreement with a third party customer for approximately 2.7 million barrels of existing capacity at our Collins/Purvis, Mississippi bulk storage terminal, commencing January 1, 2016. The new agreement replaced the previous agreement we had with the third party customer for this tankage and contains an increase to the minimum throughput fees. The increase in terminaling services fees at our Southeast terminals also includes an increase of approximately $1.3 million from us entering into a new five year agreement with a third party customer for approximately 1.2 million barrels of existing and new capacity at our Collins/Purvis, Mississippi bulk storage terminal, commencing January 1, 2016.

The increase in terminaling services fees at our West Coast terminals for the year ended December 31, 2017 is a result of the West Coast terminals acquisition on December 15, 2017.

Included in terminaling services fees for the years ended December 31, 2017, 2016 and 2015 are fees charged to affiliates of approximately $1.6 million, $3.1 million and $34.8 million, respectively.

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Our terminaling services agreements are structured as either throughput agreements or storage agreements. Most of our throughput agreements contain provisions that require our customers to make minimum payments, which are based on contractually established minimum volume of throughput of the customer’s product at our facilities over the term of the respective agreement. Due to this minimum payment arrangement, we recognize a fixed amount of revenue from the customer over the term of the respective agreement, even if the customer throughputs less than the minimum volume of product during that period. If a customer throughputs a volume of product that exceeds the contractually established minimum volume, we would recognize additional revenue on this incremental volume. Our storage agreements require our customers to make minimum payments based on the volume of storage capacity available to the customer under the agreement, which results in a fixed amount of revenue recognized.

We refer to the fixed amount of revenue recognized pursuant to our terminaling services agreements as being “firm commitments.” Revenue recognized in excess of firm commitments and revenue recognized based solely on the volume of product distributed or injected at our facilities are referred to as “ancillary.” The majority of our “ancillary” terminaling services fees for each of the last three years ended December 31, 2017 have been derived from fees we charge to our customers to inject additive compounds into product that the customer is storing at our terminals. The “firm commitments” and “ancillary” revenue included in terminaling services fees were as follows (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

Firm Commitments and Ancillary Terminaling Services Fees

 

 

 

Year ended

    

Year ended

    

Year ended

 

 

 

December 31,

 

December 31,

 

December 31,

 

 

 

2017

 

2016

 

2015

 

Firm commitments

 

$

135,197

 

$

116,341

 

$

107,074

 

Ancillary

 

 

10,347

 

 

9,749

 

 

7,161

 

Terminaling services fees

 

$

145,544

 

$

126,090

 

$

114,235

 

 

The remaining terms on the terminaling services agreements that generated “firm commitments” for the year ended December 31, 2017 were as follows (in thousands):

 

 

 

 

 

Less than 1 year remaining

 

$

7,223

 

1 year or more, but less than 3 years remaining

 

 

40,510

 

3 years or more, but less than 5 years remaining

 

 

51,568

 

5 years or more remaining

 

 

35,896

 

Total firm commitments for the year ended December 31, 2017

 

$

135,197

 

 

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Pipeline transportation fees.  We earned pipeline transportation fees at our Diamondback and Ella‑Brownsville pipelines based on the volume of product transported and the distance from the origin point to the delivery point. We earn pipeline transportation fees at our Razorback pipeline based on an allocation of the aggregate fees charged under the capacity agreement with our customer who has contracted for 100% of our Razorback system. We own the Razorback and Diamondback pipelines, and we leased the Ella‑Brownsville pipeline from a third party. The Federal Energy Regulatory