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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.

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TABLE OF CONTENTS


Item		Page No.
	Part I
1 and 2.	Business and Properties	4
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

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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.

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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

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		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

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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,

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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.

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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.

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.

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Part II

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

MARKET FOR COMMON UNITS

The common units are listed and traded on the New York Stock Exchange under the symbol “TLP.” On 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;

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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.

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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.

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(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

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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).

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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.

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.

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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

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.

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

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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 Commission regulates the tariff on our pipelines. The pipeline transportation fees by business segments were as follows (in thousands):


	Pipeline Transportation Fees
	by Business Segment
	Year ended		Year ended		Year ended
	December 31,		December 31,		December 31,
	2017		2016		2015
Gulf Coast terminals	$	—	$	—	$	—
Midwest terminals and pipeline system		1,732		1,732		1,694
Brownsville terminals		3,987		5,057		4,919
River terminals		—		—		—
Southeast terminals		—		—		—
West Coast terminals		—		—		—
Pipeline transportation fees	$	5,719	$	6,789	$	6,613

Included in pipeline transportation fees for the each of the years ended December 31, 2017, 2016 and 2015 are fees charged to affiliates of approximately $nil.

Management fees and reimbursed costs. We manage and operate for a major oil company certain tank capacity at our Port Everglades (South) terminal and receive reimbursement of their proportionate share of operating and maintenance costs. We manage and operate for an affiliate of Mexico’s state‑owned petroleum company a bi‑directional products pipeline connected to our Brownsville, Texas terminal facility and receive a management fee and reimbursement of costs. We 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 the Frontera terminal facility located in Brownsville, Texas for a management fee based on our costs incurred. Frontera is an unconsolidated affiliate for which we have a 50% ownership interest. 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. The management fees and reimbursed costs by business segments were as follows (in thousands):


	Management Fees and Reimbursed Costs
	by Business Segment
	Year ended		Year ended		Year ended
	December 31,		December 31,		December 31,
	2017		2016		2015
Gulf Coast terminals	$	983	$	1,108	$	897
Midwest terminals and pipeline system		—		—		—
Brownsville terminals		7,472		7,326		6,729
River terminals		—		—		—
Southeast terminals		747		410		—
West Coast terminals		—		—		—
Management fees and reimbursed costs	$	9,202	$	8,844	$	7,626

Included in management fees and reimbursed costs for the years ended December 31, 2017, 2016 and 2015 are fees charged to affiliates of approximately $5.3 million, $5.0 million and $4.4 million, respectively.

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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 product gained resulting from differences in the measurement of product volumes received and distributed at our terminaling facilities. Consistent with recognized industry practices, measurement differentials occur as the result of the inherent variances in measurement devices and methodology. We recognize as revenue the net proceeds from the sale of the product gained. Other revenue is composed of the following (in thousands):


	Principal Components of Other Revenue
	Year ended		Year ended		Year ended
	December 31,		December 31,		December 31,
	2017		2016		2015
Product gains	$	10,718	$	6,746	$	7,526
Steam heating fees		3,124		2,811		4,042
Product transfer services		882		1,135		1,371
Butane blending fees		2,387		1,810		1,360
Railcar handling		289		293		565
Other		5,407		10,406		9,172
Other revenue	$	22,807	$	23,201	$	24,036

For the years ended December 31, 2017, 2016 and 2015, we sold approximately 171,000, 119,000 and 117,000 barrels, respectively, of product gained resulting from differences in the measurement of product volumes received and distributed at our terminaling facilities at average prices of $69, $57 and $64 per barrel, respectively. Pursuant to our terminaling services agreement related to the Southeast terminals, we rebate our customer 50% of the proceeds we receive annually in excess of $4.2 million from the sale of product gains at our Southeast terminals. For the years ended December 31, 2017 and 2016, we have accrued a liability due to our customer of approximately $1.1 million and $nil, representing our rebate liability.

The decrease in other, included in other revenue, for the year ended December 31, 2017 is primarily due to an approximately $1.9 million one-time payment to us at our Brownsville terminals related to the settlement of litigation with our LPG customer, an approximately $1.7 million one-time payment to us at our River terminals related to property damage caused by a customer and an approximately $0.9 million one-time payment to us at our Gulf Coast terminals related to property damage caused by a customer during the prior year ended December 31, 2016.

Included in other revenue for the years ended December 31, 2017, 2016 and 2015 are amounts charged to affiliates of approximately $0.3 million, $0.3 million and $3.7 million, respectively.

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


	Other Revenue by Business Segment
	Year ended		Year ended		Year ended
	December 31,		December 31,		December 31,
	2017		2016		2015
Gulf Coast terminals	$	11,345	$	9,699	$	10,762
Midwest terminals and pipeline system		822		879		1,398
Brownsville terminals		1,595		4,868		6,018
River terminals		773		2,914		878
Southeast terminals		7,934		4,841		4,980
West Coast terminals		338		—		—
Other revenue	$	22,807	$	23,201	$	24,036

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ANALYSIS OF COSTS AND EXPENSES

The direct operating costs and expenses of our operations include the directly related wages and employee benefits, utilities, communications, repairs and maintenance, rent, property taxes, vehicle expenses, environmental compliance costs, materials and supplies. Consistent with historical trends, repairs and maintenance expenses can vary year-to-year based on the timing of scheduled maintenance and unforeseen circumstances necessitating repairs to our terminals and pipelines. The direct operating costs and expenses of our operations were as follows (in thousands):


	Direct Operating Costs and Expenses
	Year ended		Year ended		Year ended
	December 31,		December 31,		December 31,
	2017		2016		2015
Wages and employee benefits	$	24,923	$	24,119	$	22,348
Utilities and communication charges		8,335		7,677		7,607
Repairs and maintenance		12,259		15,432		14,657
Office, rentals and property taxes		10,117		9,494		9,169
Vehicles and fuel costs		714		838		964
Environmental compliance costs		2,696		3,403		2,618
Other		8,656		7,452		6,670
Direct operating costs and expenses	$	67,700	$	68,415	$	64,033

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


	Direct Operating Costs and Expenses
	by Business Segment
	Year ended		Year ended		Year ended
	December 31,		December 31,		December 31,
	2017		2016		2015
Gulf Coast terminals	$	22,829	$	22,952	$	19,147
Midwest terminals and pipeline system		2,859		3,220		3,000
Brownsville terminals		10,447		11,338		12,152
River terminals		6,624		7,957		7,126
Southeast terminals		24,302		22,948		22,608
West Coast terminals		639		—		—
Direct operating costs and expenses	$	67,700	$	68,415	$	64,033

General and administrative expenses include an administrative fee paid to the owner of TransMontainge GP for indirect corporate overhead to cover costs of centralized corporate functions such as legal, accounting, treasury, insurance administration and claims processing, health, safety and environmental, information technology, human resources, credit, payroll, taxes, engineering and other corporate services. The administrative fee paid to the owner of TransMontainge GP for the years ended December 31, 2017, 2016 and 2015 were approximately $12.8 million, $11.4 million and $11.3 million, respectively. 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. The direct general and administrative expenses for the years ended December 31, 2017, 2016 and 2015 were approximately $6.6 million, $2.7 million and $3.5 million, respectively. The increase in direct general and administrative expenses for the year ended December 31, 2017 is primarily attributable to pursuing acquisition opportunities.

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. Prior to October 31, 2016, we paid the owner of TransMontainge GP for insurance policies purchased on our behalf to cover our facilities and operations. For the years ended December 31, 2017, 2016 and 2015, the insurance expense paid to the owner of TransMontaigne GP was approximately $nil, $3.1 million and $3.8 million, respectively. On October 31, 2016, we

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contracted directly with insurance carriers for the majority of our insurance requirements. For the years ended December 31, 2017, 2016 and 2015, the expense associated with insurance contracted directly by us was $4.1 million, $1.0 million and $nil, respectively.

Equity-based compensation expense includes expense associated with us reimbursing an affiliate of TransMontaigne GP for awards granted by them to certain key officers and employees who provide service to us that vest over future service periods and grants to the independent directors of our general partner under our long-term incentive plan. We have the intent and ability to settle our reimbursement for the bonus awards by issuing additional common units, and accordingly, we account for the bonus awards as an equity award. The expenses associated with these reimbursements were approximately $3.0 million, $3.3 million and $1.4 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Depreciation and amortization expenses for the years ended December 31, 2017, 2016 and 2015 were approximately $36.0 million, $32.4 million and $30.7 million, respectively. The increase in Depreciation and amortization expense for the year ended December 31, 2017 is primarily attributable to placing the Collins, Mississippi expansion project in service in various stages beginning in the fourth quarter of 2016 through the second quarter of 2017.

Interest expense for the years ended December 31, 2017, 2016 and 2015 was approximately $10.5 million, $7.8 million and $7.4 million, respectively. The increase in interest expense for the year ended December 31, 2017 is primarily attributable to increased spend on the Collins, Mississippi expansion project, the acquisition of the West Coast terminals and an increase in LIBOR.

ANALYSIS OF INVESTMENTS IN UNCONSOLIDATED AFFILIATES

At December 31, 2017, 2016 and 2015, our investments in unconsolidated affiliates include a 42.5% Class A ownership interest in BOSTCO and a 50% ownership interest in Frontera. BOSTCO is a terminal facility located on the Houston Ship Channel that encompasses approximately 7.1 million barrels of distillate, residual and other black oil product storage. Class A and Class B ownership interests share in cash distributions on a 96.5% and 3.5% basis, respectively. Class B ownership interests do not have voting rights and are not required to make capital investments. Frontera is a terminal facility located in Brownsville, Texas that encompasses approximately 1.5 million barrels of light petroleum product storage, as well as related ancillary facilities.

The following table summarizes our investments in unconsolidated affiliates:


	Percentage of				Carrying value
	ownership				(in thousands)
	December 31,		December 31,		December 31,		December 31,
	2017		2016		2017		2016
BOSTCO	42.5	%	42.5	%	$	209,373	$	217,941
Frontera	50	%	50	%		23,808		23,152
Total investments in unconsolidated affiliates					$	233,181	$	241,093

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


	December 31,		December 31,		December 31,
	2017		2016		2015
BOSTCO	$	3,543	$	6,933	$	9,968
Frontera		3,528		3,096		1,980
Total earnings from investments in unconsolidated affiliates	$	7,071	$	10,029	$	11,948

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The decrease in earnings from our investment in BOSTCO for the year ended December 31, 2017 is primarily attributable to increased dredging costs and the terminal being offline revenue for a few days due to Hurricane Harvey. There was no damage to the terminal as a result of Hurricane Harvey. The decrease in earnings from our investment in BOSTCO for the year ended December 31, 2016 is primarily attributable to a one-time gain resulting from a contract buy-out by one of the BOSTCO customers in April of 2015. Our share of the gain during 2015 was approximately $3.4 million.

Additional capital investments in unconsolidated affiliates were as follows (in thousands):


	December 31,		December 31,		December 31,
	2017		2016		2015
BOSTCO	$	145	$	2,125	$	4,226
Frontera		2,000		100		500
Additional capital investments in unconsolidated affiliates	$	2,145	$	2,225	$	4,726

Cash distributions received from unconsolidated affiliates were as follows (in thousands):


	December 31,		December 31,		December 31,
	2017		2016		2015
BOSTCO	$	12,256	$	14,331	$	16,900
Frontera		4,872		3,530		2,749
Cash distributions received from unconsolidated affiliates	$	17,128	$	17,861	$	19,649

The decrease in distributions received from our investment in BOSTCO for the year ended December 31, 2017 is primarily attributable to increased dredging costs and the terminal being offline revenue for a few days due to Hurricane Harvey. There was no damage to the terminal as a result of Hurricane Harvey. The decrease in distributions received from our investment in BOSTCO for the year ended December 31, 2016 is primarily attributable to a one-time gain resulting from a contract buy-out by one of the BOSTCO customers in April of 2015. Our share of the gain during 2015 was approximately $3.4 million, which we received in cash as a component of our third quarter 2015 distribution from BOSTCO.

LIQUIDITY AND CAPITAL RESOURCES

Our primary liquidity needs are to fund our working capital requirements, distributions to unitholders, approved investments, approved capital projects and approved future expansion, development and acquisition opportunities. We expect to initially fund any investments, capital projects and future expansion, development and acquisition opportunities with undistributed cash flows from operations and additional borrowings under our revolving credit facility. After initially funding expenditures with borrowings under our revolving credit facility, we may raise funds through additional equity offerings and debt financings. The proceeds of such equity offerings and debt financings may then be used to reduce our outstanding borrowings under our revolving credit facility.

Net cash provided by (used in) operating activities, investing activities and financing activities were as follows (in thousands):


	Year ended December 31,
	2017		2016		2015
Net cash provided by operating activities	$	103,704	$	79,107	$	87,480
Net cash used in investing activities	$	(337,070)	$	(69,089)	$	(34,153)
Net cash provided by (used in) financing activities	$	233,696	$	(10,106)	$	(55,950)

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The increase in net cash provided by operating activities for the year ended December 31, 2017 is primarily attributable to increased revenue related to placing 2.0 million barrels of new tank capacity at our Collins, Mississippi bulk storage terminal into service in various stages beginning in the fourth quarter of 2016 through the second quarter of 2017, re-contracting of available storage capacity throughout the past year and the timing of working capital requirements. The decrease in net cash provided by operating activities for the year ended December 31, 2016 as compared to December 31, 2015 is attributable to a decrease in distributions received from our investment in BOSTCO, which is primarily attributable to a one-time gain resulting from a contract buy-out by one of the BOSTCO customers in April of 2015. Our share of the gain during 2015 was approximately $3.4 million, which we received in cash as a component of our third quarter 2015 distribution from BOSTCO. The change in net cash provided by operating activities was also impacted by the timing of working capital requirements and increased revenue.

The increase in net cash used in investing activities for the year ended December 31, 2017 includes an increase of $276.8 million for the acquisition of the West Coast terminals in December 2017. The increase in net cash used in investing activities for the year ended December 31, 2016 as compared to December 31, 2015 includes an increase of $12.0 million for the acquisition of the Port Everglades, Florida hydrant system and an increase of approximately $25.4 million in capital expenditures, primarily related to the construction of approximately 2.0 million barrels of new storage capacity at our Collins/Purvis, Mississippi bulk storage terminal. Management and the board of directors of our general partner have approved additional investments and expansion capital projects at our terminals that currently are, or will be, under construction with estimated completion dates that extend through the first quarter of 2019. At December 31, 2017, the remaining expenditures to complete the approved projects are estimated to be approximately $70 million, which primarily relates to the construction costs associated with the approximately 870,000 barrels of new storage capacity and improvements to the pipeline connections at our Collins/Purvis bulk storage terminal.

The increase in net cash provided by financing activities for the year ended December 31, 2017 includes an increase of $257.6 million in net borrowings under our revolving credit facility to help fund the increase in investing activities. The decrease in net cash used in financing activities for the year ended December 31, 2016 as compared to December 31, 2015 includes an increase of $47.8 million in net borrowings under our revolving credit facility to help fund the increase in investing activities.

Third amended and restated senior secured credit facility. On March 13, 2017, we entered into the third amended and restated senior secured revolving credit facility, or our “revolving credit facility,” which provided for a maximum borrowing line of credit equal to $600 million. On December 14, 2017 we amended our revolving credit facility, which increased the maximum borrowing line of credit to $850 million, in connection with the acquisition of the West Coast terminals. At our request, the maximum borrowing line of credit may be increased by an additional $250 million, subject to the approval of the administrative agent and the receipt of additional commitments from one or more lenders. The terms of our revolving credit facility include covenants that restrict our ability to make cash distributions, acquisitions and investments, including investments in joint ventures. We may make distributions of cash to the extent of our “available cash” as defined in our partnership agreement. We may make acquisitions and investments that meet the definition of “permitted acquisitions”; “other investments” which may not exceed 5% of “consolidated net tangible assets”; and additional future “permitted JV investments” up to $175 million, which may include additional investments in BOSTCO. The principal balance of loans and any accrued and unpaid interest are due and payable in full on the maturity date, March 13, 2022.

We may elect to have loans under our revolving credit facility bear interest either (i) at a rate of LIBOR plus a margin ranging from 1.75% to 2.75% depending on the total leverage ratio then in effect, or (ii) at the base rate plus a margin ranging from 0.75% to 1.75% depending on the total leverage ratio then in effect. We also pay a commitment fee on the unused amount of commitments, ranging from 0.375% to 0.5% per annum, depending on the total leverage ratio then in effect. Our obligations under our revolving credit facility are secured by a first priority security interest in favor of the lenders in the majority of our assets, including our investments in unconsolidated affiliates. At December 31, 2017, our outstanding borrowings under our revolving credit facility were $593.2 million.

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Our revolving credit facility also contains customary representations and warranties (including those relating to organization and authorization, compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults, covenant defaults, cross defaults and bankruptcy events). The primary financial covenants contained in our revolving credit facility are (i) a total leverage ratio test (not to exceed 5.25 to 1.0), (ii) a senior secured leverage ratio test (not to exceed 3.75 to 1.0), and (iii) a minimum interest coverage ratio test (not less than 3.0 to 1.0; however while any Qualified Senior Notes are outstanding not less than 2.75 to 1.0). These financial covenants are based on a non-GAAP, defined financial performance measure within our revolving credit facility known as “Consolidated EBITDA.” As of December 31, 2017, we were in compliance with all financial covenants under our revolving credit facility.

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

Common unit offering program. On September 2, 2016, the SEC declared effective a universal shelf registration statement, which replaced our prior shelf registration statement that previously expired. As with the prior shelf registration statement, the new shelf registration statement allows us to issue common units and debt securities. In connection with the shelf registration statement, we established a common unit offering program under which we may issue and sell common units from time to time, representing limited partner interests, up to an aggregate gross sales amount of $50 million. We intend to use the net proceeds from any equity sales pursuant to the common unit offering program, after deducting the agent’s commissions and the partnership’s offering expenses, for general partnership purposes, which may include, among other things, repayment of indebtedness, capital expenditures, working capital or acquisitions. As of December 31, 2017, we had not issued any common units or debt securities under the common unit offering program or the registration statement. In February 2018, we used the shelf registration statement to issue senior notes (see Note 20 of Notes to consolidated financial statements).

Contractual obligations and contingencies. We have contractual obligations that are required to be settled in cash. The amounts of our contractual obligations at December 31, 2017 are as follows (in thousands):


	Years ending December 31,
	2018		2019		2020		2021		2022		Thereafter
Additions to property, plant and equipment under contract	$	8,257	$	—	$	—	$	—	$	—	$	—
Operating leases—property and equipment		3,160		3,301		1,960		1,878		958		4,259
Long-term debt		—		—		—		—		593,200		—
Interest expense on debt (1)		21,059		21,059		21,059		21,059		4,154		—
Total contractual obligations to be settled in cash	$	32,476	$	24,360	$	23,019	$	22,937	$	598,312	$	4,259

(1)

Assumes that our outstanding long‑term debt at December 31, 2017 remains outstanding until its maturity date under our credit facility and we incur interest expense at the weighted average interest rate on our borrowings outstanding for the three months ended December 31, 2017, which is 3.55% per year.

We believe that our future cash expected to be provided by operating activities, available borrowing capacity under our revolving credit facility, and our relationship with institutional lenders and equity investors should enable us to meet our committed capital and our essential liquidity requirements for the next twelve months.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Market risk is the risk of loss arising from adverse changes in market rates and prices. A principal market risk to which we are exposed is interest rate risk associated with borrowings under our revolving credit facility. Borrowings under our revolving credit facility bear interest at a variable rate based on LIBOR or the lender’s base rate. We manage

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a portion of our interest rate risk with interest rate swaps, which reduce our exposure to changes in interest rates by converting variable interest rates to fixed interest rates. At December 31, 2017, we are party to interest rate swap agreements with an aggregate notional amount of $125.0 million that expire between March 25, 2018 and March 11, 2019. Pursuant to the terms of the interest rate swap agreements, we pay a blended fixed rate of approximately 1.01% and receive interest payments based on the one-month LIBOR. The net difference to be paid or received under the interest rate swap agreements is settled monthly and is recognized as an adjustment to interest expense. At December 31, 2017, we had outstanding borrowings of $593.2 million under our revolving credit facility. Based on the outstanding balance of our variable‑interest‑rate debt at December 31, 2017, the terms of our interest rate swap agreements and assuming market interest rates increase or decrease by 100 basis points, the potential annual increase or decrease in interest expense is approximately $4.7 million.

We do not purchase or market products that we handle or transport and, therefore, we do not have material direct exposure to changes in commodity prices, except for the value of product gains arising from certain of our terminaling services agreements with our customers. Pursuant to our Southeast terminaling services agreement, we rebate to our customer 50% of the proceeds we receive annually in excess of $4.2 million from the sale of product gains at our Southeast terminals. We do not use derivative commodity instruments to manage the commodity risk associated with the product we may own at any given time. Generally, to the extent we are entitled to retain product pursuant to terminaling services agreements with our customers, we sell the product to our customers on a contractually established periodic basis; the sales price is based on industry indices. For the years ended December 31, 2017, 2016 and 2015, we sold approximately 171,000, 119,000 and 117,000 barrels, respectively, of product gained resulting from differences in the measurement of product volumes received and distributed at our terminaling facilities at average prices of $69, $57 and $64 per barrel, respectively.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The following consolidated financial statements should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this Annual Report.

TransMontaigne Partners L.P. and Subsidiaries:


Report of Independent Registered Public Accounting Firm		60
Consolidated balance sheets as of December 31, 2017 and 2016		61
Consolidated statements of income for the years ended December 31, 2017, 2016 and 2015		62
Consolidated statements of partners’ equity for the years ended December 31, 2017, 2016 and 2015		63
Consolidated statements of cash flows for the years ended December 31, 2017, 2016 and 2015		64
Notes to consolidated financial statements		65

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Report of Independent Registered Public Accounting Firm

To the Board of Directors of TransMontaigne GP L.L.C. and

The Unitholders of TransMontaigne Partners L.P.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of TransMontaigne Partners L.P. and subsidiaries (the "Partnership") as of December 31, 2017 and 2016, the related consolidated statements of income, partners' equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 15, 2018, expressed an unqualified opinion on the Partnership’s internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the Partnership's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Deloitte & Touche LLP

Denver, Colorado

March 15, 2018

We have served as the Partnership’s auditor since 2012.

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TransMontaigne Partners L.P. and subsidiaries

Consolidated balance sheets

(Dollars in thousands)


	December 31,		December 31,
	2017		2016
ASSETS
Current assets:
Cash and cash equivalents	$	923	$	593
Trade accounts receivable, net		11,017		9,297
Due from affiliates		1,509		653
Other current assets		20,654		9,903
Total current assets		34,103		20,446
Property, plant and equipment, net		655,053		416,748
Goodwill		9,428		8,485
Investments in unconsolidated affiliates		233,181		241,093
Other assets, net		55,238		2,922
	$	987,003	$	689,694
LIABILITIES AND EQUITY
Current liabilities:
Trade accounts payable	$	8,527	$	7,928
Accrued liabilities		17,426		13,998
Total current liabilities		25,953		21,926
Other liabilities		3,633		3,234
Long-term debt		593,200		291,800
Total liabilities		622,786		316,960
Commitments and contingencies (Note 16)
Partners’ equity:
Common unitholders (16,177,353 units issued and outstanding at December 31, 2017 and 16,137,650 units issued and outstanding at December 31, 2016)		310,769		320,042
General partner interest (2% interest with 330,150 equivalent units outstanding at December 31, 2017 and 329,339 equivalent units outstanding at December 31, 2016)		53,448		52,692
Total partners’ equity		364,217		372,734
	$	987,003	$	689,694

See accompanying notes to consolidated financial statements.

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TransMontaigne Partners L.P. and subsidiaries

Consolidated statements of operations

(In thousands, except per unit amounts)


	Year ended		Year ended		Year ended
	December 31,		December 31,		December 31,
	2017		2016		2015
Revenue:
External customers	$	176,079	$	156,506	$	109,557
Affiliates		7,193		8,418		42,953
Total revenue		183,272		164,924		152,510
Operating costs and expenses and other:
Direct operating costs and expenses		(67,700)		(68,415)		(64,033)
General and administrative expenses		(19,433)		(14,100)		(14,749)
Insurance expenses		(4,064)		(4,081)		(3,756)
Equity-based compensation expense		(2,999)		(3,263)		(1,411)
Depreciation and amortization		(35,960)		(32,383)		(30,650)
Earnings from unconsolidated affiliates		7,071		10,029		11,948
Total operating costs and expenses and other		(123,085)		(112,213)		(102,651)
Operating income		60,187		52,711		49,859
Other expenses:
Interest expense		(10,473)		(7,787)		(7,396)
Amortization of deferred financing costs		(1,221)		(818)		(774)
Total other expenses		(11,694)		(8,605)		(8,170)
Net earnings		48,493		44,106		41,689
Less—earnings allocable to general partner interest including incentive distribution rights		(12,705)		(9,340)		(7,506)
Net earnings allocable to limited partners	$	35,788	$	34,766	$	34,183
Net earnings per limited partner unit—basic	$	2.20	$	2.14	$	2.12
Net earnings per limited partner unit—diluted	$	2.20	$	2.14	$	2.12

See accompanying notes to consolidated financial statements.

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TransMontaigne Partners L.P. and subsidiaries

Consolidated statements of partners’ equity

(Dollars in thousands)



			General
	Common		partner
	units		interest		Total
Balance December 31, 2014	$	333,619	$	57,846	$	391,465
Distributions to unitholders		(42,897)		(7,605)		(50,502)
Equity-based compensation		1,411		—		1,411
Purchase of 2,668 common units by our long-term incentive plan		(92)		—		(92)
Net earnings for year ended December 31, 2015		34,183		7,506		41,689
Balance December 31, 2015		326,224		57,747		383,971
Distributions to unitholders		(44,211)		(8,898)		(53,109)
Equity-based compensation		3,128		—		3,128
Issuance of 19,008 common units pursuant to our long-term incentive plan		135		—		135
Issuance of 2,094 common units pursuant to our savings and retention program		—		—		—
Contribution of cash by TransMontaigne GP to maintain its 2% general partner interest		—		9		9
Excess of $12.0 million purchase price of hydrant system from TransMontaigne LLC over the carryover basis of the net assets		—		(5,506)		(5,506)
Net earnings for year ended December 31, 2016		34,766		9,340		44,106
Balance December 31, 2016		320,042		52,692		372,734
Distributions to unitholders		(47,349)		(11,985)		(59,334)
Equity-based compensation		2,729		—		2,729
Issuance of 6,498 common units pursuant to our long-term incentive plan		270		—		270
Issuance of 33,205 common units pursuant to our savings and retention program		—		—		—
Settlement of tax withholdings on equity-based compensation		(711)		—		(711)
Contribution of cash by TransMontaigne GP to maintain its 2% general partner interest		—		36		36
Net earnings for year ended December 31, 2017		35,788		12,705		48,493
Balance December 31, 2017	$	310,769	$	53,448	$	364,217

See accompanying notes to consolidated financial statements.

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TransMontaigne Partners L.P. and subsidiaries

Consolidated statements of cash flows

(Dollars in thousands)


	Year ended		Year ended		Year ended
	December 31,		December 31,		December 31,
	2017		2016		2015
Cash flows from operating activities:
Net earnings	$	48,493	$	44,106	$	41,689
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation and amortization		35,960		32,383		30,650
Earnings from unconsolidated affiliates		(7,071)		(10,029)		(11,948)
Distributions from unconsolidated affiliates		17,128		17,861		19,649
Equity-based compensation		2,999		3,263		1,411
Amortization of deferred financing costs		1,221		818		774
Amortization of deferred revenue		(333)		(248)		(1,268)
Unrealized gain on derivative instruments		(232)		(344)		—
Changes in operating assets and liabilities, net of effects from acquisitions and dispositions:
Trade accounts receivable, net		(1,593)		(2,987)		3,386
Due from affiliates		(856)		427		236
Other current assets		1,457		(7,082)		655
Amounts due under long-term terminaling services agreements, net		801		337		1,144
Deposits		—		(193)		(19)
Trade accounts payable		2,522		(2,092)		(155)
Accrued liabilities		3,208		2,887		1,276
Net cash provided by operating activities		103,704		79,107		87,480
Cash flows from investing activities:
Acquisition of terminal assets		(276,760)		(12,000)		—
Investments in unconsolidated affiliates		(2,145)		(2,225)		(4,726)
Capital expenditures		(58,165)		(54,864)		(29,427)
Net cash used in investing activities		(337,070)		(69,089)		(34,153)
Cash flows from financing activities:
Borrowings of debt under credit facility		442,100		199,900		101,900
Repayments of debt under credit facility		(140,700)		(156,100)		(105,900)
Deferred financing costs		(6,703)		(395)		(1,356)
Deferred issuance costs		(992)		(411)		—
Settlement of tax withholdings on equity-based compensation		(711)		—		—
Distributions paid to unitholders		(59,334)		(53,109)		(50,502)
Purchase of common units by our long-term incentive plan		—		—		(92)
Contribution of cash by TransMontaigne GP		36		9		—
Net cash provided by (used in) financing activities		233,696		(10,106)		(55,950)
Increase (decrease) in cash and cash equivalents		330		(88)		(2,623)
Cash and cash equivalents at beginning of period		593		681		3,304
Cash and cash equivalents at end of period	$	923	$	593	$	681
Supplemental disclosures of cash flow information:
Cash paid for interest	$	10,077	$	8,097	$	7,298
Property, plant and equipment acquired with accounts payable	$	3,207	$	5,114	$	5,966

See accompanying notes to consolidated financial statements.

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TransMontaigne Partners L.P. and subsidiaries

Notes to Consolidated Financial Statements

Years ended December 31, 2017, 2016 and 2015

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a) Nature of business

TransMontaigne Partners L.P. (“we,” “us,” “our,” “the Partnership”) was formed in February 2005 as a Delaware limited partnership. We provide integrated terminaling, storage, transportation and related services for companies engaged in the trading, distribution and marketing of light refined petroleum products, heavy refined petroleum products, crude oil, chemicals, fertilizers and other liquid products. We conduct our 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 West Coast.

We are controlled by our general partner, TransMontaigne GP (“TransMontaigne GP”), which as of February 1, 2016 is a wholly‑owned indirect subsidiary of ArcLight Energy Partners Fund VI, L.P. (“ArcLight”). Prior to February 1, 2016, TransMontaigne LLC, a wholly-owned subsidiary of NGL Energy Partners LP (“NGL”), owned all the issued and outstanding ownership interests of TransMontaigne GP.

(b) Basis of presentation and use of estimates

Our accounting and financial reporting policies conform to accounting principles generally accepted in the United States of America (“GAAP”). The accompanying consolidated financial statements include the accounts of TransMontaigne Partners L.P., a Delaware limited partnership, and its controlled subsidiaries. Investments where we do not have the ability to exercise control, but do have the ability to exercise significant influence, are accounted for using the equity method of accounting. All inter‑company accounts and transactions have been eliminated in the preparation of the accompanying consolidated financial statements. Certain reclassifications of previously reported amounts have been made to conform to the current year presentation.

The preparation of financial statements in conformity with “GAAP” requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting periods. The following estimates, in management’s opinion, are subjective in nature, require the exercise of judgment, and/or involve complex analyses: useful lives of our plant and equipment and accrued environmental obligations. Changes in these estimates and assumptions will occur as a result of the passage of time and the occurrence of future events. Actual results could differ from these estimates.

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

Pursuant to terminaling services agreements with certain of our throughput customers, we are entitled to the volume of product gained resulting from differences in the measurement of product volumes received and distributed at our terminaling facilities. Consistent with recognized industry practices, measurement differentials occur as the result of

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TransMontaigne Partners L.P. and subsidiaries

Notes to Consolidated Financial Statements (continued)

Years ended December 31, 2017, 2016 and 2015

the inherent variances in measurement devices and methodology. We recognize as revenue the net proceeds from the sale of the net product gained. For the years ended December 31, 2017, 2016 and 2015, we recognized revenue of approximately $10.7 million, $6.7 million and $7.5 million, respectively, for net product gained. Within these amounts, approximately $nil, $0.3 million and $2.9 million, respectively, were pursuant to terminaling services agreements with affiliate customers.

(d) Cash and cash equivalents

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

(e) Property, plant and equipment

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

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

(f) Investments in unconsolidated affiliates

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

(g) Environmental obligations

We accrue for environmental costs that relate to existing conditions caused by past operations when probable and reasonably estimable (see Note 10 of Notes to consolidated financial statements). Environmental costs include initial site surveys and environmental studies of potentially contaminated sites, costs for remediation and restoration of sites determined to be contaminated and ongoing monitoring costs, as well as fines, damages and other costs, including direct legal costs. Liabilities for environmental costs at a specific site are initially recorded, on an undiscounted basis, when it is probable that we will be liable for such costs, and a reasonable estimate of the associated costs can be made based on available information. Such an estimate includes our share of the liability for each specific site and the sharing of the amounts related to each site that will not be paid by other potentially responsible parties, based on enacted laws and adopted regulations and policies. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods. Estimates of our ultimate liabilities associated with environmental costs are difficult to make with certainty due to the number of variables involved, including the early stage of investigation at certain sites, the lengthy time frames required to complete remediation, technology changes, alternatives available and the evolving nature of environmental laws and regulations.

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TransMontaigne Partners L.P. and subsidiaries

Notes to Consolidated Financial Statements (continued)

Years ended December 31, 2017, 2016 and 2015

We periodically file claims for insurance recoveries of certain environmental remediation costs with our insurance carriers under our comprehensive liability policies (see Note 5 of Notes to consolidated financial statements). We recognize our insurance recoveries as a credit to income in the period that we assess the likelihood of recovery as being probable (i.e., likely to occur).

In connection with our previous acquisitions of certain terminals from TransMontaigne LLC, TransMontaigne LLC has agreed to indemnify us against certain potential environmental claims, losses and expenses at those terminals (see Note 2 of Notes to consolidated financial statements).

(h) Asset retirement obligations

Asset retirement obligations are legal obligations associated with the retirement of long‑lived assets that result from the acquisition, construction, development or normal use of the asset. Generally accepted accounting principles require that the fair value of a liability related to the retirement of long‑lived assets be recorded at the time a legal obligation is incurred. Once an asset retirement obligation is identified and a liability is recorded, a corresponding asset is recorded, which is depreciated over the remaining useful life of the asset. After the initial measurement, the liability is adjusted to reflect changes in the asset retirement obligation. If and when it is determined that a legal obligation has been incurred, the fair value of any liability is determined based on estimates and assumptions related to retirement costs, future inflation rates and interest rates. Our long‑lived assets consist of above‑ground storage facilities and underground pipelines. We are unable to predict if and when these long‑lived assets will become completely obsolete and require dismantlement. We have not recorded an asset retirement obligation, or corresponding asset, because the future dismantlement and removal dates of our long‑lived asset subject to legal obligation is indeterminable and the amount of any associated costs are believed to be insignificant. Changes in our assumptions and estimates may occur as a result of the passage of time and the occurrence of future events.

(i) Equity-based compensation

Generally accepted accounting principles require us to measure the cost of services received in exchange for an award of equity instruments based on the measurement‑date fair value of the award. That cost is recognized during the period services are provided in exchange for the award.

(j) Accounting for derivative instruments

Generally accepted accounting principles require us to recognize all derivative instruments at fair value in the consolidated balance sheets as assets or liabilities (see Note 9 of Notes to consolidated financial statements). Changes in the fair value of our derivative instruments are recognized in earnings.

At December 31, 2017, 2016 and 2015, our derivative instruments were limited to interest rate swap agreements with an aggregate notional amount of $125.0 million, $125.0 million and $75 million. Our derivative instruments at December 31, 2017 expire between March 25, 2018 and March 11, 2019. Pursuant to the terms of the interest rate swap agreements, we pay a blended fixed rate of approximately 1.01% and receive interest payments based on the one-month LIBOR. The net difference to be paid or received under the interest rate swap agreements is settled monthly and is recognized as an adjustment to interest expense. The fair value of our interest rate swap agreements are determined using a pricing model based on the LIBOR swap rate and other observable market data. At December 31, 2017, 2016 and 2015 the fair value of our interest rate swaps was approximately $0.6 million, $0.3 million and $nil, respectively.

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TransMontaigne Partners L.P. and subsidiaries

Notes to Consolidated Financial Statements (continued)

Years ended December 31, 2017, 2016 and 2015

(k) Income taxes

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

(l) Net earnings per limited partner unit

Net earnings allocable to the limited partners, for purposes of calculating net earnings per limited partner unit, are calculated under the two-class method and accordingly are net of the earnings allocable to the general partner interest and distributions payable to any restricted phantom units granted under our equity-based compensation plans that participate in our distributions. The earnings allocable to the general partner interest include the distributions of available cash (as defined by our partnership agreement) attributable to the period to the general partner interest, net of adjustments for the general partner’s share of undistributed earnings, and the incentive distribution rights. Undistributed earnings are the difference between the earnings and the distributions attributable to the period. Undistributed earnings are allocated to the limited partners and general partner interest based on their respective sharing of earnings or losses specified in the partnership agreement, which is based on their ownership percentages of 98% and 2%, respectively. The incentive distribution rights are not allocated a portion of the undistributed earnings given they are not entitled to distributions other than from available cash. Further, the incentive distribution rights do not share in losses under our partnership agreement. Basic net earnings per limited partner unit is computed by dividing net earnings allocable to the limited partners by the weighted average number of limited partner units outstanding during the period. Diluted net earnings per limited partner unit is computed by dividing net earnings allocable to the limited partners by the weighted average number of limited partner units outstanding during the period and any potential dilutive securities outstanding during the period.

(m) Comprehensive Income

Entities that report items of other comprehensive income have the option to present the components of net income and comprehensive income in either one continuous financial statement, or two consecutive financial statements. As the Partnership has no components of comprehensive income other than net income, no statement of comprehensive income has been presented.

(n) Recent accounting pronouncements

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The objective of this update is to clarify the principles for recognizing revenue and to develop a common revenue standard. The core principle of the ASU is that an entity should recognize revenue for the transfer of goods or services equal to the amount that it expects to be entitled to receive for those goods or services. The ASU requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments. The ASU is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period.

We adopted the new standard, effective January 1, 2018, using the modified retrospective method described within the ASU. This approach requires us to apply the new revenue standard to (i) all new revenue contracts entered into after January 1, 2018 and (ii) all existing revenue contracts as of January 1, 2018 through a cumulative adjustment to equity. During the evaluation of the standard, we reviewed our existing revenue streams, including evaluating contracts and identification of the types of arrangements where differences may arise in the conversion to the new standard. We did not identify any material differences in our existing revenue recognition methods that require modification under the new standard, we do not expect to record a material cumulative adjustment to equity and our

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TransMontaigne Partners L.P. and subsidiaries

Notes to Consolidated Financial Statements (continued)

Years ended December 31, 2017, 2016 and 2015

prior period financial statements will not be restated. The standard’s most significant impact to us relates to enhanced disclosure requirements.

In February 2016, the FASB issued ASU 2016-02, Leases. The objective of this update is to improve financial reporting about leasing transactions. ASU 2016-02 is effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period. We are currently evaluating the potential impact that the adoption will have on our disclosures and financial statements.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipt and Cash Payments, to add or clarify guidance on the classification of certain cash receipts and payments in the statement of cash flows. ASU 2016-15 is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. We do not expect the adoption of this ASU to have a material impact on our consolidated financial statements.

In January 2017, the FASB issued ASU 2017-04, Intangibles-Goodwill and Other: Simplifying the Test for Goodwill Impairment, to simplify the accounting for goodwill impairment by eliminating step 2 from the goodwill impairment test. ASU 2017-04 is effective for annual reporting periods beginning after December 15, 2019, including interim periods within that reporting period. We are currently evaluating the potential impact that the adoption will have on our disclosures and financial statements.

(2) TRANSACTIONS WITH AFFILIATES

Omnibus agreement. On May 27, 2005 we entered into an omnibus agreement with TransMontaigne LLC and our general partner, which agreement has been subsequently amended from time to time. In connection with the ArcLight acquisition of our general partner, effective February 1, 2016, we entered into the second amended and restated omnibus agreement to consent to the assignment of the omnibus agreement from TransMontaigne LLC to Gulf TLP Holdings LLC, an ArcLight subsidiary, to waive the automatic termination that would have occurred at such time as TransMontaigne LLC ceased to control our general partner and to remove certain legacy provisions that were no longer applicable to the Partnership. The omnibus agreement will continue in effect until the earlier of (i) ArcLight ceasing to control our general partner or (ii) the election of either us or the owner, following at least 24 months’ prior written notice to the other parties.

Under the omnibus agreement we pay Gulf TLP Holdings, the owner of TransMontaigne GP, an administrative fee for the provision of various general and administrative services for our benefit. For the years ended December 31, 2017, 2016 and 2015, the annual administrative fee paid to the owner of TransMontaigne GP was approximately $12.8 million, $11.4 million and $11.3 million, respectively. If we acquire or construct additional facilities, the owner of TransMontaigne GP may propose a revised administrative fee covering the provision of services for such additional facilities, subject to approval by the conflicts committee of our general partner. For example, effective May 3, 2017 the board of TransMontaigne GP, with the concurrence of the conflicts committee, approved a $1.8 million annual increase (or $150,000 monthly) to the administrative fee related to the construction of approximately 2.0 million barrels of new tank capacity at our Collins, Mississippi bulk storage terminal. The increase was ratably applied monthly beginning May 3, 2017 based on the percentage of the approximately 2.0 million barrels of new tank capacity placed into service. The administrative fee is recognized as a component of general and administrative expense and encompasses services to perform centralized corporate functions, such as legal, accounting, treasury, insurance administration and claims processing, health, safety and environmental, information technology, human resources, credit, payroll, taxes, engineering and other corporate services.

The omnibus agreement further provides that we pay the owner of TransMontaigne GP for insurance policies purchased on our behalf to cover our facilities and operations. For the years ended December 31, 2017, 2016 and 2015,

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TransMontaigne Partners L.P. and subsidiaries

Notes to Consolidated Financial Statements (continued)

Years ended December 31, 2017, 2016 and 2015

the insurance expense paid to the owner of TransMontaigne GP was approximately $nil, $3.1 million and $3.8 million, respectively. Beginning October 31, 2016, we contracted directly with insurance carriers for the majority of our insurance requirements. For the years ended December 31, 2017, 2016 and 2015, the expense associated with insurance contracted directly by us was $4.1 million, $1.0 million and $nil, respectively. We also pay the owner of TransMontaigne GP for direct operating costs and expenses, such as salaries of operational personnel performing services on‑site at our terminals and pipelines and the cost of their employee benefits, including 401(k) and health insurance benefits.

Under the omnibus agreement we have agreed to reimburse the owner of TransMontaigne GP for bonus awards made to key employees under the owner of TransMontaigne GP’s savings and retention program, provided the compensation committee and the conflicts committee of our general partner approve the annual awards granted under the plan. Effective April 13, 2015 and beginning with the 2015 incentive bonus award, we have the option to provide the reimbursement in either a cash payment or the delivery of our common units to the owner of TransMontaigne GP or directly to the award recipients, with the reimbursement made in accordance with the underlying vesting and payment schedule of the savings and retention program. We have the intent and ability to settle our reimbursement for bonus awards in our common units, and accordingly, effective April 13, 2015, we began accounting for the bonus awards as an equity award. Prior to the 2015 bonus award, we reimbursed our portion of the bonus awards by making cash payments to the owner of TransMontaigne GP over the first year that each applicable award was granted. For the years ended December 31, 2017, 2016 and 2015, the expense associated with the reimbursement of bonus awards was approximately $2.7 million, $2.5 million and $1.3 million, respectively.

Environmental indemnification. In connection with our acquisition of the Florida and Midwest terminals on May 27, 2005, TransMontaigne LLC agreed to indemnify us against certain potential environmental claims, losses and expenses that were identified on or before May 27, 2010, and that were associated with the ownership or operation of the Florida and Midwest terminals prior to May 27, 2005. TransMontaigne LLC’s maximum liability for this indemnification obligation is $15.0 million. TransMontaigne LLC has no obligation to indemnify us for losses until such aggregate losses exceed $250,000. 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 terminals on December 31, 2006, 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. TransMontaigne LLC’s maximum liability for this indemnification obligation is $15.0 million. TransMontaigne LLC has no obligation to indemnify us for losses until such aggregate losses exceed $250,000. The deductible amount, cap amount and limitation of time for indemnification do not apply to any environmental liabilities known to exist as of December 31, 2006. TransMontaigne LLC has no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after December 31, 2006.

In connection with our acquisition of the Southeast terminals on December 31, 2007, TransMontaigne LLC agreed to indemnify us against potential environmental claims, losses and expenses that were identified on or before December 31, 2012, and that were associated with the ownership or operation of the Southeast terminals prior to December 31, 2007. TransMontaigne LLC’s maximum liability for this indemnification obligation is $15.0 million. TransMontaigne LLC has no obligation to indemnify us for losses until such aggregate losses exceed $250,000. The deductible amount, cap amount and limitation of time for indemnification do not apply to any environmental liabilities known to exist as of December 31, 2007. TransMontaigne LLC has no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after December 31, 2007.

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TransMontaigne Partners L.P. and subsidiaries

Notes to Consolidated Financial Statements (continued)

Years ended December 31, 2017, 2016 and 2015

In connection with our acquisition of the Pensacola terminal on March 1, 2011, TransMontaigne LLC agreed to indemnify us against potential environmental claims, losses and expenses that were 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. TransMontaigne LLC’s maximum liability for this indemnification obligation is $2.5 million. TransMontaigne LLC has no obligation to indemnify us for losses until such aggregate losses exceed $200,000. The deductible amount, cap amount and limitation of time for indemnification do not apply to any environmental liabilities known to exist as of March 1, 2011. TransMontaigne LLC has no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after March 1, 2011.

The forgoing environmental indemnification obligations of TransMontaigne LLC to us remain in place and were not affected by ArcLight’s acquisition of our general partner.

Terminaling services agreement—Brownsville terminals. In September 2016, we entered into a terminaling services agreement with Frontera relating to our Brownsville, Texas facility that will expire in June 2019, subject to a two-year automatic renewal unless terminated by either party upon 180 days’ prior notice. Under this agreement, Frontera has agreed to throughput a volume of light oil product at our terminal that, at the fee schedule contained in the agreement, will result in minimum throughput payments to us of approximately $1.3 million per year. In exchange for its minimum throughput commitment, we have agreed to provide Frontera with approximately 151,000 barrels of storage capacity.

For the years ended December 31, 2017, 2016 and 2015, we recognized approximately $1.5 million, $0.5 million and $nil, respectively, of revenue related to this agreement.

Terminaling services agreement—Brownsville terminals. In June 2017, we entered into a terminaling services agreement with Frontera relating to our Brownsville, Texas facility that will expire in June 2020, subject to a three-year automatic renewal unless terminated by either party upon 90 days’ prior notice. Under this agreement, Frontera has agreed to throughput a volume of light oil product at our terminal that, at the fee schedule contained in the agreement, will result in minimum throughput payments to us of approximately $1.0 million per year. In exchange for its minimum throughput commitment, we have agreed to provide Frontera with approximately 150,000 barrels of storage capacity.

For the years ended December 31, 2017, 2016 and 2015, we recognized approximately $0.4 million, $nil and $nil, respectively, of revenue related to this agreement.

Operations and reimbursement agreement—Frontera. We have a 50% ownership interest in Frontera Brownsville LLC joint venture, or “Frontera”. We have agreed to operate Frontera, in accordance with an operations and reimbursement agreement executed between us and Frontera, for a management fee that is based on our costs incurred. Our agreement with Frontera stipulates that we may resign as the operator at any time with the prior written consent of Frontera, or that we may be removed as the operator for good cause, which includes material noncompliance with laws and material failure to adhere to good industry practice regarding health, safety or environmental matters. For the years ended December 31, 2017, 2016 and 2015, we recognized approximately $5.3 million, $5.0 million and $4.4 million, respectively, of revenue related to this operations and reimbursement agreement.

Terminaling services agreement—Southeast terminals. We have a terminaling services agreement with NGL relating to our Southeast terminals. In connection with the ArcLight acquisition of our general partner, our Southeast terminaling services agreement with NGL was amended to extend the term of the agreement through July 31, 2040 at the prevailing contract rate terms contained within the agreement. Subsequent to January 31, 2023, NGL has the ability to terminate the agreement at any time upon at least 24 months’ prior notice of its intent to terminate the agreement. Subsequent to the ArcLight acquisition, effective February 1, 2016, revenue associated with the Southeast terminaling services agreement is recorded as revenue from external customers as opposed to revenue from affiliates.

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TransMontaigne Partners L.P. and subsidiaries

Notes to Consolidated Financial Statements (continued)

Years ended December 31, 2017, 2016 and 2015

Under this agreement, NGL was obligated to throughput a volume of refined product at our Southeast terminals that, at the fee schedule contained in the agreement, resulted in minimum throughput payments to us of approximately $27.0 million, for each of the years ended December 31, 2017, 2016 and 2015.

(3)

BUSINESS COMBINATION AND TERMINAL ACQUISITION

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.

The purchase price and estimated assessment of the fair value of the assets acquired and liabilities assumed in the business combination were as follows (in thousands):


Other current assets	$	1,037
Property, plant and equipment		228,000
Goodwill		943
Customer relationships		47,000
Total assets acquired		276,980
Environmental obligation		220
Total liabilities assumed		220
Allocated purchase price	$	276,760

Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill represents the premium we paid to acquire the skilled workforce.

These unaudited pro forma results are for comparative purposes only and may not be indicative of the results that would have occurred had this acquisition been completed on January 1, 2016 or the results that will be attained in the future (in thousands):


	ProForma year ended December 31,
		2017		2016
Revenue	$	226,653	$	205,605
Net earnings	$	55,856	$	46,276

Significant pro forma adjustments include depreciation expense and interest expense on the incremental borrowings necessary to finance this acquisition as well as adjustments to remove the related party transactions included in the historical financial statements of the West Coast terminals.

On January 28, 2016, we acquired from TransMontaigne LLC its Port Everglades, Florida hydrant system for a cash payment of $12.0 million. The hydrant system encompasses a system for fueling cruise ships. The acquisition of the hydrant system from TransMontaigne LLC has been recorded at the carryover basis in a manner similar to a reorganization of entities under common control. Accordingly, we recorded the assets at their net book value of $6.5 million with the remaining purchase price of $5.5 million recorded as a reduction to the general partner equity interest. TransMontaigne LLC controlled our general partner on the acquisition date, the difference between the consideration we

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TransMontaigne Partners L.P. and subsidiaries

Notes to Consolidated Financial Statements (continued)

Years ended December 31, 2017, 2016 and 2015

paid to TransMontaigne LLC and the carryover basis of the net assets purchased has been reflected in the accompanying consolidated balance sheets and statement of partners’ equity as a decrease to the general partner’s interest. The accompanying consolidated financial statements include the assets, liabilities and results of operations of the hydrant system from January 28, 2016. As this transaction is not considered material to our consolidated financial statements we did not recast prior period consolidated financial statements.

(4) CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE

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

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


	December 31,		December 31,
	2017		2016
Trade accounts receivable	$	11,128	$	9,416
Less allowance for doubtful accounts		(111)		(119)
	$	11,017	$	9,297

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


	Balance at						Balance at
	beginning		Charged to				end of
	of period		expenses		Deductions		period
2017	$	119	$	—	$	(8)	$	111
2016	$	475	$	298	$	(654)	$	119
2015	$	464	$	11	$	—	$	475

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


	Year ended		Year ended		Year ended
	December 31,		December 31,		December 31,
	2017		2016		2015
NGL Energy Partners LP	26	%	23	%	25	%
Castleton Commodities International LLC	13	%	14	%	—	%
RaceTrac Petroleum Inc.	13	%	12	%	11	%
Morgan Stanley Capital Group	—	%	—	%	10	%

On October 27, 2015, upon the sale of Morgan Stanley’s global physical oil merchanting business to Castleton Commodities International LLC, Morgan Stanley Capital Group, with our consent, assigned all its remaining terminaling services agreements with us to Castleton Commodities International LLC.

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TransMontaigne Partners L.P. and subsidiaries

Notes to Consolidated Financial Statements (continued)

Years ended December 31, 2017, 2016 and 2015

(5) OTHER CURRENT ASSETS

Other current assets are as follows (in thousands):


	December 31,		December 31,
	2017		2016
Amounts due from insurance companies	$	1,981	$	1,810
Additive detergent		1,715		1,364
Prepaid insurance		4,151		4,684
Deposits and other assets		12,807		2,045
	$	20,654	$	9,903

Amounts due from insurance companies. We periodically file claims for recovery of environmental remediation costs with our insurance carriers under our comprehensive liability policies. We recognize our insurance recoveries in the period that we assess the likelihood of recovery as being probable (i.e., likely to occur). At December 31, 2017 and 2016, we have recognized amounts due from insurance companies of approximately $2.0 million and $1.8 million, respectively, representing our best estimate of our probable insurance recoveries. During the year ended December 31, 2017, we received reimbursements from insurance companies of approximately $1.1 million. During the year ended December 31, 2017 we increased our estimate of probable future insurance recoveries by approximately $1.3 million.

Deposits and other assets. Deposits and other assets at December 31, 2017 includes a deposit of approximately $10.2 million paid during the fourth quarter 2017 related to future expansion opportunities that closed in the first quarter of 2018.

(6) PROPERTY, PLANT AND EQUIPMENT, NET

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


	December 31,		December 31,
	2017		2016
Land	$	83,310	$	53,079
Terminals, pipelines and equipment		885,429		651,783
Furniture, fixtures and equipment		4,430		4,100
Construction in progress		21,575		11,715
		994,744		720,677
Less accumulated depreciation		(339,691)		(303,929)
	$	655,053	$	416,748

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TransMontaigne Partners L.P. and subsidiaries

Notes to Consolidated Financial Statements (continued)

Years ended December 31, 2017, 2016 and 2015

(7) GOODWILL

Goodwill is as follows (in thousands):


	December 31,		December 31,
	2017		2016
Brownsville terminals	$	8,485	$	8,485
West Coast terminals		943		—
	$	9,428	$	8,485

Goodwill is required to be tested for impairment annually unless events or changes in circumstances indicate it is more likely than not that an impairment loss has been incurred at an interim date. Our annual test for the impairment of goodwill is performed as of December 31. The impairment test is performed at the reporting unit level. Our reporting units are our operating segments (see Note 18 of Notes to consolidated financial statements). The fair value of each reporting unit is determined on a stand‑alone basis from the perspective of a market participant and represents an estimate of the price that would be received to sell the unit as a whole in an orderly transaction between market participants at the measurement date. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered to be impaired.

At December 31, 2017 our Brownsville terminals and West Coast terminals contained goodwill. At December 31, 2016, our only reporting unit that contained goodwill was our Brownsville terminals. Our estimate of the fair value of our Brownsville terminals at December 31, 2017 and 2016 substantially exceeded its carrying amount. Accordingly, we did not recognize any goodwill impairment charges during the years ended December 31, 2017 and 2016, respectively. The purchase price and estimated assessment of the fair value of the assets acquired and liabilities assumed in our acquisition of the West Coast terminals was performed as of the acquisition date, December 15, 2017, as such the estimated fair value equaled its carrying amount. Accordingly, we did not recognize any goodwill impairment charges during the year ended December 31, 2017. However, a significant decline in the price of our common units with a resulting increase in the assumed market participants’ weighted average cost of capital, the loss of a significant customer, the disposition of significant assets, or an unforeseen increase in the costs to operate and maintain the Brownsville and West Coast terminals, could result in the recognition of an impairment charge in the future.

(8) INVESTMENTS IN UNCONSOLIDATED AFFILIATES

At December 31, 2017 and 2016, our investments in unconsolidated affiliates include a 42.5% Class A ownership interest in Battleground Oil Specialty Terminal Company LLC (“BOSTCO”) and a 50% ownership interest in Frontera Brownsville LLC (“Frontera”). BOSTCO is a terminal facility located on the Houston Ship Channel that encompasses approximately 7.1 million barrels of distillate, residual and other black oil product storage. Class A and Class B ownership interests share in cash distributions on a 96.5% and 3.5% basis, respectively. Class B ownership interests do not have voting rights and are not required to make capital investments. Frontera is a terminal facility located in Brownsville, Texas that encompasses approximately 1.5 million barrels of light petroleum product storage, as well as related ancillary facilities.

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TransMontaigne Partners L.P. and subsidiaries

Notes to Consolidated Financial Statements (continued)

Years ended December 31, 2017, 2016 and 2015

The following table summarizes our investments in unconsolidated affiliates:


	Percentage of				Carrying value
	ownership				(in thousands)
	December 31,		December 31,		December 31,		December 31,
	2017		2016		2017		2016
BOSTCO	42.5	%	42.5	%	$	209,373	$	217,941
Frontera	50	%	50	%		23,808		23,152
Total investments in unconsolidated affiliates					$	233,181	$	241,093

At December 31, 2017 and 2016, our investment in BOSTCO includes approximately $7.0 million and $7.2 million, respectively, of excess investment related to a one time buy-in fee to acquire our 42.5% interest and capitalization of interest on our investment during the construction of BOSTCO amortized over the useful life of the assets. Excess investment is the amount by which our investment exceeds our proportionate share of the book value of the net assets of the BOSTCO entity.

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


	Year ended		Year ended		Year ended
	December 31,		December 31,		December 31,
	2017		2016		2015
BOSTCO	$	3,543	$	6,933	$	9,968
Frontera		3,528		3,096		1,980
Total earnings from investments in unconsolidated affiliates	$	7,071	$	10,029	$	11,948

Additional capital investments in unconsolidated affiliates were as follows (in thousands):


	Year ended		Year ended		Year ended
	December 31,		December 31,		December 31,
	2017		2016		2015
BOSTCO	$	145	$	2,125	$	4,226
Frontera		2,000		100		500
Additional capital investments in unconsolidated affiliates	$	2,145	$	2,225	$	4,726

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TransMontaigne Partners L.P. and subsidiaries

Notes to Consolidated Financial Statements (continued)

Years ended December 31, 2017, 2016 and 2015

Cash distributions received from unconsolidated affiliates were as follows (in thousands):


	Year ended		Year ended		Year ended
	December 31,		December 31,		December 31,
	2017		2016		2015
BOSTCO	$	12,256	$	14,331	$	16,900
Frontera		4,872		3,530		2,749
Cash distributions received from unconsolidated affiliates	$	17,128	$	17,861	$	19,649

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

Balance sheets:


	BOSTCO				Frontera
	December 31,		December 31,		December 31,		December 31,
	2017		2016		2017		2016
Current assets	$	24,976	$	23,237	$	5,649	$	5,779
Long-term assets		469,348		485,331		44,292		41,966
Current liabilities		(17,550)		(12,799)		(2,147)		(1,172)
Long-term liabilities		—		—		(178)		(269)
Net assets	$	476,774	$	495,769	$	47,616	$	46,304

Statements of income:


	BOSTCO						Frontera
	Year ended						Year ended
	December 31,						December 31,
	2017		2016		2015		2017		2016		2015
Revenue	$	66,235	$	66,863	$	70,710	$	22,193	$	18,958	$	16,083
Expenses		(55,687)		(48,149)		(45,787)		(15,137)		(12,766)		(12,121)
Net earnings	$	10,548	$	18,714	$	24,923	$	7,056	$	6,192	$	3,962

(9) OTHER ASSETS, NET

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


	December 31,		December 31,
	2017		2016
Customer relationships, net of accumulated amortization of $2,294 and $2,092, respectively	$	47,136	$	338
Deferred financing costs, net of accumulated amortization of $5,984 and $4,763, respectively		6,778		1,298
Amounts due under long-term terminaling services agreements		460		656
Unrealized gain on derivative instruments		576		344
Deposits and other assets		288		286
	$	55,238	$	2,922

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TransMontaigne Partners L.P. and subsidiaries

Notes to Consolidated Financial Statements (continued)

Years ended December 31, 2017, 2016 and 2015

Customer relationships. Other assets, net primarily include certain customer relationships at our West Coast terminals. These customer relationships are being amortized on a straight‑line basis over approximately twenty years. Expected future amortization expense for the customer relationships as of December 31, 2017 is as follows (in thousands):


	Years ending December 31,
	2018		2019		2020		2021		2022		Thereafter
Amortization expense	$	2,592	$	2,350	$	2,350	$	2,350	$	2,350	$	35,144

Deferred financing costs. Deferred financing costs are amortized using the effective interest method over the term of the related credit facility.

Amounts due under long‑term terminaling services agreements. We have long‑term terminaling services agreements with certain of our customers that provide for minimum payments that increase at stated amounts over the terms of the respective agreements. We recognize as revenue the minimum payments under the long‑term terminaling services agreements on a straight‑line basis over the terms of the respective agreements. At December 31, 2017 and 2016, we have recognized revenue in excess of the minimum payments that are due through those respective dates under the long‑term terminaling services agreements resulting in an asset of approximately $0.5 million and $0.7 million, respectively.

(10) ACCRUED LIABILITIES

Accrued liabilities are as follows (in thousands):


	December 31,		December 31,
	2017		2016
Customer advances and deposits	$	10,265	$	8,710
Accrued property taxes		1,381		1,061
Accrued environmental obligations		1,855		2,107
Interest payable		982		232
Accrued expenses and other		2,943		1,888
	$	17,426	$	13,998

Customer advances and deposits. We bill certain of our customers one month in advance for terminaling services to be provided in the following month. At December 31, 2017 and 2016, we have billed and collected from certain of our customers approximately $10.3 million and $8.7 million, respectively, in advance of the terminaling services being provided.

Accrued environmental obligations. At December 31, 2017 and 2016, we have accrued environmental obligations of approximately $1.9 million and $2.1 million, respectively, representing our best estimate of our remediation obligations. Changes in our estimates of our future environmental remediation obligations may occur as a result of the passage of time and the occurrence of future events.

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TransMontaigne Partners L.P. and subsidiaries

Notes to Consolidated Financial Statements (continued)

Years ended December 31, 2017, 2016 and 2015

The following table presents a rollforward of our accrued environmental obligations (in thousands):


	Balance at						Balance at
	beginning				Increase		end of
	of period		Payments		in estimate		period
2017	$	2,107	$	(1,204)	$	952	$	1,855
2016	$	1,047	$	(1,322)	$	2,382	$	2,107
2015	$	1,524	$	(513)	$	36	$	1,047

(11) OTHER LIABILITIES

Other liabilities are as follows (in thousands):


	December 31,		December 31,
	2017		2016
Advance payments received under long-term terminaling services agreements	$	1,599	$	994
Deferred revenue—ethanol blending fees and other projects		2,034		2,240
	$	3,633	$	3,234

Advance payments received under long‑term terminaling services agreements. We have long‑term terminaling services agreements with certain of our customers that provide for advance minimum payments. We recognize the advance minimum payments as revenue either on a straight‑line basis over the term of the respective agreements or when services have been provided based on volumes of product distributed. At December 31, 2017 and 2016, we have received advance minimum payments in excess of revenue recognized under these long‑term terminaling services agreements resulting in a liability of approximately $1.6 million and $1.0 million, respectively.

Deferred revenue—ethanol blending fees and other projects. Pursuant to historical agreements with our customers, we agreed to undertake certain capital projects that primarily pertain to providing ethanol blending functionality at certain of our Southeast terminals. Upon completion of the projects, our customers have paid us lump‑sum amounts that will be recognized as revenue on a straight‑line basis over the remaining term of the agreements. At December 31, 2017 and 2016, we have unamortized deferred revenue of approximately $2.0 million and $2.2 million, respectively, for completed projects. During the years ended December 31, 2017, 2016 and 2015, we billed our customers approximately $0.5 million, $0.5 and $nil, respectively, for completed projects. During the years ended December 31, 2017, 2016 and 2015, we recognized revenue on a straight‑line basis of approximately $0.7 million, $0.5 million and $1.3 million, respectively, for completed projects.

(12) LONG‑TERM DEBT

Our senior secured revolving credit facility, or our “revolving credit facility,” provided for a maximum borrowing line of credit equal to $850 million at December 31, 2017. The terms of our revolving credit facility include covenants that restrict our ability to make cash distributions, acquisitions and investments, including investments in joint ventures. We may make distributions of cash to the extent of our “available cash” as defined in our partnership agreement. We may make acquisitions and investments that meet the definition of “permitted acquisitions”; “other investments” which may not exceed 5% of “consolidated net tangible assets”; and additional future “permitted JV investments” up to $125 million, which may include additional investments in BOSTCO. The primary financial covenants contained in our revolving credit facility are (i) a total leverage ratio test (not to exceed 5.25 to 1.0), (ii) a senior secured leverage ratio test (not to exceed 3.75 to 1.0), and (iii) a minimum interest coverage ratio test (not less than 3.0 to 1.0; however while any Qualified Senior Notes are outstanding not less than 2.75 to 1.0). We were in

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TransMontaigne Partners L.P. and subsidiaries

Notes to Consolidated Financial Statements (continued)

Years ended December 31, 2017, 2016 and 2015

compliance with all financial covenants as of and during the years ended December 31, 2017 and 2016. The principal balance of loans and any accrued and unpaid interest as of December 31, 2017 are due and payable in full on March 13, 2022, the maturity date for our revolving credit facility.

As of December 31, 2017 we had the option to have loans under our revolving credit facility bear interest either (i) at a rate of LIBOR plus a margin ranging from 1.75% to 2.75% depending on the total leverage ratio then in effect, or (ii) at the base rate plus a margin ranging from 0.75% to 1.75% depending on the total leverage ratio then in effect. We also pay a commitment fee on the unused amount of commitments, ranging from 0.375% to 0.5% per annum, depending on the total leverage ratio then in effect. Our obligations under our revolving credit facility are secured by a first priority security interest in favor of the lenders in the majority of our assets, including our investments in unconsolidated affiliates. For the years ended December 31, 2017, 2016 and 2015, the weighted average interest rate on borrowings under our revolving credit facility was approximately 3.5%, 3.1% and 2.7%, respectively. At December 31, 2017 and 2016, our outstanding borrowings under our revolving credit facility were $593.2 million and $291.8 million, respectively. At both December 31, 2017 and 2016, our outstanding letters of credit were $0.4 million.

We have an effective universal shelf‑registration statement and prospectus on Form S‑3 with the SEC that expires in September 2019. In February 2018, we and TLP Finance Corp., our 100% owned subsidiary, used the shelf registration statement to issue senior notes that were guaranteed on a senior unsecured basis by each of our 100% owned subsidiaries that guarantee obligations under our revolving credit facility (see Note 20 of Notes to consolidated financial statements). In the future, we and TLP Finance Corp. may issue additional debt securities pursuant to that registration statement. TransMontaigne Partners L.P. has no independent assets or operations unrelated to its investments in its consolidated subsidiaries. TLP Finance Corp. has no assets or operations. Our operations are conducted by subsidiaries of TransMontaigne Partners L.P. through our 100% owned operating company subsidiary, TransMontaigne Operating Company L.P. Each of TransMontaigne Operating Company L.P.s’ and our other 100% owned subsidiaries (other than TLP Finance Corp., whose sole purpose is to act as co‑issuer of any debt securities) may guarantee any future debt securities we issue. We expect that any guarantees associated with future debt securities will be full and unconditional and joint and several, subject to certain automatic customary releases, including sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, exercise of legal defeasance option or covenant defeasance option, and designation of a subsidiary guarantor as unrestricted in accordance with the indenture. There are no significant restrictions on the ability of TransMontaigne Partners L.P. or any guarantor to obtain funds from its subsidiaries by dividend or loan. None of the assets of TransMontaigne Partners L.P. or a guarantor represent restricted net assets pursuant to the guidelines established by the SEC.

(13) PARTNERS’ EQUITY

The number of units outstanding is as follows:


		General
	Common	partner
	units	equivalent units
Units outstanding at December 31, 2015	16,124,566	329,073
Issuance of common units by our long-term incentive plan	10,990	—
Issuance of common units pursuant to our savings and retention program	2,094	—
Contribution of cash by TransMontaigne GP to maintain its 2% general partner interest	—	266
Units outstanding at December 31, 2016	16,137,650	329,339
Issuance of common units by our long-term incentive plan	6,498	—
Issuance of common units pursuant to our savings and retention program	33,205	—
Contribution of cash by TransMontaigne GP to maintain its 2% general partner interest	—	811
Units outstanding at December 31, 2017	16,177,353	330,150

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TransMontaigne Partners L.P. and subsidiaries

Notes to Consolidated Financial Statements (continued)

Years ended December 31, 2017, 2016 and 2015

TransMontaigne GP had historically acquired outstanding common units on the open market under a purchase program for purposes of delivering vested units to the independent directors of our general partner on behalf of TransMontaigne Services LLC’s long‑term incentive plan. The purchase program concluded with its final purchase of 667 units on the program’s scheduled termination date of April 1, 2015. Beginning in 2016, grants of restricted phantom units under the TLP Management Services long-term incentive plan are to be settled by us through the issuance of common units pursuant to our registration statement on Form S-8.

At both December 31, 2017 and 2016, common units outstanding include nil common units, held on behalf of TransMontaigne Services LLC’s long‑term incentive plan. In connection with the ArcLight acquisition of our general partner, effective February 1, 2016, 15,750 restricted phantom units previously granted to the independent directors vested and were satisfied via the delivery of 8,018 existing common units and issuance of 7,732 new units. On October 21, 2016 we issued an additional 3,258 common units to our independent directors for a total of 19,008 common units delivered to the independent directors for the year ended December 31, 2016. On October 20, 2017 we issued 6,498 common units to our independent directors.

(14) EQUITY-BASED COMPENSATION

TransMontaigne GP is our general partner and manages our operations and activities. Prior to February 1, 2016, TransMontaigne GP was a wholly owned subsidiary of TransMontaigne LLC, which is a wholly owned subsidiary of NGL. TransMontaigne Services LLC, which is a wholly owned subsidiary of TransMontaigne LLC, had a long‑term incentive plan and a savings and retention program to compensate through incentive bonus awards certain employees and independent directors of our general partner who provided services with respect to the business of our general partner.

Long-term incentive plan. On February 26, 2016, the board of our general partner approved, subject to the approval of our common unitholders, the TLP Management Services 2016 long-term incentive plan and the TLP Management Services savings and retention program (discussed further below) which constitutes a program under, and is subject to, the TLP Management Services long-term incentive plan, which replaced the TransMontaigne Services LLC long-term incentive plan and the TransMontaigne Services LLC savings and retention program. TLP Management Services is a wholly owned indirect subsidiary of ArcLight and employs all the officers and employees who provide services to our partnership and such entity provides payroll and maintains all employee benefits programs on behalf of our partnership. On July 12, 2016, we held a special meeting of our common unitholders at which time the TLP Management Services long-term incentive plan and savings and retention program were approved by the partnership’s unitholders.

The TLP Management Services long-term incentive plan operates in a manner similar to the TransMontaigne Services LLC long-term incentive plan used previously. The TLP Management Services long-term incentive plan reserves 750,000 common units to be granted as awards under the plan, with such amount subject to adjustment as provided for under the terms of the plan if there is a change in our common units, such as a unit split or other reorganization. The common units authorized to be granted under the TLP Management Services long-term incentive plan are registered pursuant to a registration statement on Form S-8.

The TLP Management Services long‑term incentive plan is administered by the compensation committee of the board of directors of our general partner and is used for grants of units to the independent directors of our general partner. The grants to the independent directors of our general partner under the TransMontaigne Services LLC long-term incentive plan had historically vested and were payable annually in equal tranches over a four-year period, subject to accelerated vesting upon a change in control of TransMontaigne GP. Ownership in the awards was subject to forfeiture until the vesting date, but recipients had distribution and voting rights from the date of the grant. Beginning

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TransMontaigne Partners L.P. and subsidiaries

Notes to Consolidated Financial Statements (continued)

Years ended December 31, 2017, 2016 and 2015

with the annual grant in 2016, the grants to the independent directors of our general partner under the TLP Management Services long-term incentive plan are immediately vested and not subject to forfeiture.

Activity under the long-term incentive plan is as follows:


	Restricted	NYSE
	phantom	closing
	units	price
Restricted phantom units outstanding at January 1, 2015	9,000
Vesting on September 30, 2015	(2,250)	$	27.20
Grant on October 14, 2015	9,000	$	31.11
Restricted phantom units outstanding at December 31, 2015	15,750
Vesting on February 1, 2016	(15,750)	$	30.41
Grant on October 21, 2016	3,258	$	41.45
Vesting on October 21, 2016	(3,258)	$	41.45
Restricted phantom units outstanding at December 31, 2016	—
Grant on October 20, 2017	6,498	$	41.55
Vesting on October 20, 2017	(6,498)	$	41.55
Restricted phantom units outstanding at December 31, 2017	—

Generally accepted accounting principles require us to measure the cost of board member services received in exchange for an award of equity instruments based on the grant‑date fair value of the award. That cost is recognized over the vesting period on a straight line basis during which a board member is required to provide services in exchange for the award with the costs being accelerated upon the occurrence of accelerated vesting events, such as a change in control of our general partner. In connection with the ArcLight acquisition of our general partner, effective February 1, 2016, 15,750 restricted phantom units previously granted to the independent directors vested and were satisfied via the delivery of our common units. On October 21, 2016, we granted and issued an additional 3,258 common units to our independent directors under the TLP Management Services long‑term incentive plan. On October 20, 2017 we granted and issued 6,498 common units to our independent directors under the TLP Management Services long‑term incentive plan.

For awards to the independent directors of our general partner, equity‑based compensation expense of approximately $270,000, $722,000 and $108,000 is included in general and administrative expenses for the years ended December 31, 2017, 2016 and 2015, respectively.

Savings and retention program. On February 26, 2016, the board of our general partner unanimously approved the new TLP Management Services savings and retention program, subject to the approval of our common unitholders, for employees who provide services with respect to our business. This plan is intended to constitute a program under, and be subject to, the TLP Management Services 2016 long-term incentive plan described above. The new savings and retention program was used for annual incentive bonus awards beginning in March 2016 and is intended to be used for future awards to employees of TLP Management Services who provide services to the partnership. The new savings and retention program operates in a manner substantially similar to the TransMontaigne Services LLC savings and retention plan used previously.

The restricted phantom units awarded and accrued under the savings and retention program are subject to forfeiture until the vesting date. Recipients have distribution equivalent rights from the date of grant that accrue additional restricted phantom units equivalent to the value of quarterly distributions paid by us on each of our outstanding common units. Recipients of restricted phantom units under the savings and retention program do not have voting rights.

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TransMontaigne Partners L.P. and subsidiaries

Notes to Consolidated Financial Statements (continued)

Years ended December 31, 2017, 2016 and 2015

The purpose of the savings and retention program is to provide for the reward and retention of participants by providing them with bonus awards that vest over future service periods. Awards under the program generally become vested as to 50% of a participant’s annual award as of the first day of the month that falls closest to the second anniversary of the grant date, and the remaining 50% as of the first day of the month that falls closest to the third anniversary of the grant date, subject to earlier vesting upon a participant’s attainment of the age and length of service thresholds, retirement, death or disability, involuntary termination without cause, or termination of a participant’s employment following a change in control of the partnership, our general partner or TLP Management Services, as specified in the program.

A person will satisfy the age and length of service thresholds of the program upon the attainment of the earliest of (a) age sixty, (b) age fifty five and ten years of service as an officer of TLP Management Services or any of its affiliates or predecessors, or (c) age fifty and twenty years of service as an employee of TLP Management Services or any of its affiliates or predecessors.

Effective April 13, 2015 and beginning with the 2015 incentive bonus award and continuing under the new savings and retention program, under the omnibus agreement we have the option to provide the reimbursement in either a cash payment or the delivery of our common units to the savings and retention program or alternatively directly to the award recipients, with the reimbursement made in accordance with the underlying vesting and payment schedule of the savings and retention program. Our reimbursement for the incentive bonus awards is reduced for forfeitures and is increased for the value of quarterly distributions accrued under the distribution equivalent rights. We have the intent and ability to settle our reimbursement for incentive bonus awards in our common units, and accordingly, effective April 13, 2015, we began accounting for the incentive bonus awards as an equity award. Prior to the 2015 incentive bonus award, we reimbursed our portion of the incentive bonus awards through monthly cash payments to the savings and retention program over the first year that each applicable award was granted.

For certain senior level employees, including the executive officers of our general partner, all prior grants under the TransMontaigne Services LLC savings and retention program vested upon the change in control of our general partner as a result of the ArcLight acquisition that occurred on February 1, 2016.

Given that we do not have any employees to provide corporate and support services and instead we contract for such services under the omnibus agreement, generally accepted accounting principles require us to classify the savings and retention program awards as a non-employee award and measure the cost of services received in exchange for an award of equity instruments based on the vesting‑date fair value of the award. That cost, or an estimate of that cost in the case of unvested restricted phantom units, is recognized over the period during which services are provided in exchange for the award. As of December 31, 2017, there was approximately $1.0 million of total unrecognized equity-based compensation expense related to unvested restricted phantom units, which is expected to be recognized over the remaining weighted average period of 1.23 years.

For the years ended December 31, 2017, 2016 and 2015, the expense associated with equity-based compensation was approximately $2.7 million, $2.5 million and $1.3 million respectively.

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TransMontaigne Partners L.P. and subsidiaries

Notes to Consolidated Financial Statements (continued)

Years ended December 31, 2017, 2016 and 2015

Activity related to our equity-based awards granted under the savings and retention program for services performed under the omnibus agreement is as follows:


		Weighted			Weighted
		average			average
	Vested	price		Unvested	price
Restricted phantom units outstanding at December 31, 2016	88,118	$	35.82	38,438	$	34.90
Issuance of units	(33,205)	$	44.50	—	$	—
Units withheld for settlement of withholding taxes	(15,734)	$	44.12	—	$	—
Unit accrual for distributions paid	5,973	$	43.23	3,344	$	43.19
Vesting of units	9,413	$	44.35	(9,413)	$	44.35
Grant of units	37,312	$	45.02	21,875	$	45.17
Restricted phantom units outstanding at December 31, 2017	91,877	$	38.91	54,244	$	38.81
Vested and expected to vest at December 31, 2017	146,121	$	38.87

(15) NET EARNINGS PER LIMITED PARTNER UNIT

The following table reconciles net earnings to earnings allocable to limited partners and sets forth the computation of basic and diluted net earnings per limited partner unit (in thousands):


	Year ended		Year ended		Year ended
	December 31,		December 31,		December 31,
	2017		2016		2015
Net earnings	$	48,493	$	44,106	$	41,689
Less:
Distributions payable on behalf of incentive distribution rights		(11,974)		(8,630)		(6,808)
Distributions payable on behalf of general partner interest		(986)		(916)		(877)
Earnings allocable to general partner interest less than distributions payable to general partner interest		255		206		179
Earnings allocable to general partner interest including incentive distribution rights		(12,705)		(9,340)		(7,506)
Net earnings allocable to limited partners per the consolidated statements of operations		35,788		34,766		34,183
Less distributions payable for unvested long-term incentive plan grants		—		—		(27)
Net earnings allocable to limited partners for calculating net earnings per limited partner unit	$	35,788	$	34,766	$	34,156
Basic weighted average units		16,258		16,210		16,137
Diluted weighted average units		16,284		16,229		16,146
Net earnings per limited partner unit—basic	$	2.20	$	2.14	$	2.12
Net earnings per limited partner unit—diluted	$	2.20	$	2.14	$	2.12

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TransMontaigne Partners L.P. and subsidiaries

Notes to Consolidated Financial Statements (continued)

Years ended December 31, 2017, 2016 and 2015

Pursuant to our partnership agreement we are required to distribute available cash (as defined by our partnership agreement) as of the end of the reporting period. Such distributions are declared within 45 days after the end of each quarter. The following table sets forth the distribution declared per common unit attributable to the periods indicated:


	Distribution
January 1, 2015 through March 31, 2015	$	0.665
April 1, 2015 through June 30, 2015	$	0.665
July 1, 2015 through September 30, 2015	$	0.665
October 1, 2015 through December 31, 2015	$	0.670
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

(16) COMMITMENTS AND CONTINGENCIES

Contract commitments. At December 31, 2017, we have contractual commitments of approximately $20.8 million for the supply of services, labor and materials related to capital projects that currently are under development. We expect that these contractual commitments will be paid during the year ending December 31, 2018.

Operating leases. We lease property and equipment under non‑cancelable operating leases that extend through August 2030. At December 31, 2017, future minimum lease payments under these non‑cancelable operating leases are as follows (in thousands):


Years ending December 31:
2018	$	3,160
2019		3,301
2020		1,960
2021		1,878
2022		958
Thereafter		4,259
	$	15,516

Included in the above non‑cancelable operating lease commitments are amounts for property rentals that we have sublet under non‑cancelable sublease agreements or have reimbursement agreements with affiliates, for which we expect to receive minimum rentals of approximately $4.9 million in future periods.

Rental expense under operating leases was approximately $3.3 million, $3.4 million and $3.5 million for the years ended December 31, 2017, 2016 and 2015, respectively.

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.

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TransMontaigne Partners L.P. and subsidiaries

Notes to Consolidated Financial Statements (continued)

Years ended December 31, 2017, 2016 and 2015

(17) DISCLOSURES ABOUT FAIR VALUE

“GAAP” defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. GAAP also establishes a fair value hierarchy that prioritizes the use of higher‑level inputs for valuation techniques used to measure fair value. The three levels of the fair value hierarchy are: (1) Level 1 inputs, which are quoted prices (unadjusted) in active markets for identical assets or liabilities; (2) Level 2 inputs, which are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly; and (3) Level 3 inputs, which are unobservable inputs for the asset or liability.

The fair values of the following financial instruments represent our best estimate of the amounts that would be received to sell those assets or that would be paid to transfer those liabilities in an orderly transaction between market participants at that date. Our fair value measurements maximize the use of observable inputs. However, in situations where there is little, if any, market activity for the asset or liability at the measurement date, the fair value measurement reflects our judgments about the assumptions that market participants would use in pricing the asset or liability based on the best information available in the circumstances. The following methods and assumptions were used to estimate the fair value of financial instruments at December 31, 2017 and 2016.

Cash and cash equivalents. The carrying amount approximates fair value because of the short‑term maturity of these instruments. The fair value is categorized in Level 1 of the fair value hierarchy.

Derivative instruments. The carrying amount of our interest rate swaps as of December 31, 2017 and 2016 was determined using a pricing model based on the LIBOR swap rate and other observable market data. The fair value is categorized in Level 2 of the fair value hierarchy.

Debt. The carrying amount of our revolving credit facility debt approximates fair value since borrowings under the facility bear interest at current market interest rates. The fair value is categorized in Level 2 of the fair value hierarchy.

(18) BUSINESS SEGMENTS

We provide integrated terminaling, storage, transportation and related services to companies engaged in the trading, distribution and marketing of refined petroleum products, crude oil, chemicals, fertilizers and other liquid products. Our chief operating decision maker is our general partner’s chief executive officer. Our general partner’s chief executive officer reviews the financial performance of our business segments using disaggregated financial information about “net margins” for purposes of making operating decisions and assessing financial performance. “Net margins” is composed of revenue less direct operating costs and expenses. Accordingly, we present “net margins” for each of our 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.

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TransMontaigne Partners L.P. and subsidiaries

Notes to Consolidated Financial Statements (continued)

Years ended December 31, 2017, 2016 and 2015

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


	Year ended		Year ended		Year ended
	December 31,		December 31,		December 31,
	2017		2016		2015
Gulf Coast Terminals:
Terminaling services fees	$	50,613	$	45,903	$	42,049
Other		12,328		10,807		11,659
Revenue		62,941		56,710		53,708
Direct operating costs and expenses		(22,829)		(22,952)		(19,147)
Net margins		40,112		33,758		34,561
Midwest Terminals and Pipeline System:
Terminaling services fees		8,443		8,590		8,330
Pipeline transportation fees		1,732		1,732		1,694
Other		822		879		1,398
Revenue		10,997		11,201		11,422
Direct operating costs and expenses		(2,859)		(3,220)		(3,000)
Net margins		8,138		7,981		8,422
Brownsville Terminals:
Terminaling services fees		7,591		8,234		8,037
Pipeline transportation fees		3,987		5,057		4,919
Other		9,067		12,194		12,747
Revenue		20,645		25,485		25,703
Direct operating costs and expenses		(10,447)		(11,338)		(12,152)
Net margins		10,198		14,147		13,551
River Terminals:
Terminaling services fees		10,174		9,664		9,316
Other		773		2,914		878
Revenue		10,947		12,578		10,194
Direct operating costs and expenses		(6,624)		(7,957)		(7,126)
Net margins		4,323		4,621		3,068
Southeast Terminals:
Terminaling services fees		67,323		53,699		46,503
Other		8,681		5,251		4,980
Revenue		76,004		58,950		51,483
Direct operating costs and expenses		(24,302)		(22,948)		(22,608)
Net margins		51,702		36,002		28,875
West Coast Terminals:
Terminaling services fees		1,400		—		—
Other		338		—		—
Revenue		1,738		—		—
Direct operating costs and expenses		(639)		—		—
Net margins		1,099		—		—
Total net margins		115,572		96,509		88,477
General and administrative expenses		(19,433)		(14,100)		(14,749)
Insurance expenses		(4,064)		(4,081)		(3,756)
Equity-based compensation expense		(2,999)		(3,263)		(1,411)
Depreciation and amortization		(35,960)		(32,383)		(30,650)
Earnings from unconsolidated affiliates		7,071		10,029		11,948
Operating income		60,187		52,711		49,859
Other expenses		(11,694)		(8,605)		(8,170)
Net earnings	$	48,493	$	44,106	$	41,689

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TransMontaigne Partners L.P. and subsidiaries

Notes to Consolidated Financial Statements (continued)

Years ended December 31, 2017, 2016 and 2015

Supplemental information about our business segments is summarized below (in thousands):


	Year ended December 31, 2017
			Midwest
			Terminals and
	Gulf Coast		Pipeline		Brownsville		River		Southeast		West Coast
	Terminals		System		Terminals		Terminals		Terminals		Terminals		Total
Revenue:
External customers	$	62,941	$	10,997	$	13,452	$	10,947	$	76,004	$	1,738	$	176,079
Frontera		—		—		7,193		—		—		—		7,193
Revenue	$	62,941	$	10,997	$	20,645	$	10,947	$	76,004	$	1,738	$	183,272
Capital expenditures	$	6,233	$	174	$	11,678	$	2,075	$	37,957	$	48	$	58,165
Identifiable assets	$	123,963	$	20,502	$	52,265	$	49,761	$	215,950	$	276,317	$	738,758
Cash and cash equivalents														923
Investments in unconsolidated affiliates														233,181
Deferred financing costs														6,778
Other														7,363
Total assets													$	987,003


	Year ended December 31, 2016
			Midwest
			Terminals and
	Gulf Coast		Pipeline		Brownsville		River		Southeast		West Coast
	Terminals		System		Terminals		Terminals		Terminals		Terminals		Total
Revenue:
External customers	$	56,586	$	11,201	$	20,028	$	12,578	$	56,113	$	—	$	156,506
NGL Energy Partners LP		124		—		—		—		2,837		—		2,961
Frontera		—		—		5,457		—		—		—		5,457
Revenue	$	56,710	$	11,201	$	25,485	$	12,578	$	58,950	$	—	$	164,924
Capital expenditures	$	7,675	$	871	$	1,428	$	2,788	$	42,102	$	—	$	54,864
Identifiable assets	$	126,457	$	21,919	$	43,878	$	53,005	$	195,632	$	—	$	440,891
Cash and cash equivalents														593
Investments in unconsolidated affiliates														241,093
Deferred financing costs														1,298
Other														5,819
Total assets													$	689,694

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TransMontaigne Partners L.P. and subsidiaries

Notes to Consolidated Financial Statements (continued)

Years ended December 31, 2017, 2016 and 2015


	Year ended December 31, 2015
			Midwest
			Terminals and
	Gulf Coast		Pipeline		Brownsville		River		Southeast		West Coast
	Terminals		System		Terminals		Terminals		Terminals		Terminals		Total
Revenue:
External customers	$	48,430	$	11,422	$	21,277	$	9,765	$	18,663	$	—	$	109,557
NGL Energy Partners LP		5,278		—		10		429		32,820		—		38,537
Frontera		—		—		4,416		—		—		—		4,416
Revenue	$	53,708	$	11,422	$	25,703	$	10,194	$	51,483	$	—	$	152,510
Capital expenditures	$	9,236	$	1,129	$	3,753	$	4,888	$	10,421	$	—	$	29,427
Identifiable assets	$	120,590	$	22,990	$	45,287	$	54,213	$	163,987	$	—	$	407,067

(19) FINANCIAL RESULTS BY QUARTER (UNAUDITED)


	Three months ended
									Year ended
	March 31,		June 30,		September 30,		December 31,		December 31,
	2017		2017		2017		2017		2017
	(in thousands except per unit amounts)
Revenue	$	44,850	$	45,364	$	45,449	$	47,609	$	183,272
Direct operating costs and expenses		(16,511)		(15,984)		(17,719)		(17,486)		(67,700)
General and administrative expenses		(3,971)		(4,080)		(5,247)		(6,135)		(19,433)
Insurance expenses		(1,006)		(1,002)		(999)		(1,057)		(4,064)
Equity-based compensation expense		(1,817)		(352)		(544)		(286)		(2,999)
Depreciation and amortization		(8,705)		(8,792)		(8,882)		(9,581)		(35,960)
Earnings from unconsolidated affiliates		2,560		2,120		1,884		507		7,071
Operating income		15,400		17,274		13,942		13,571		60,187
Other expenses		(2,446)		(2,796)		(2,976)		(3,476)		(11,694)
Net earnings	$	12,954	$	14,478	$	10,966	$	10,095	$	48,493
Net earnings per limited partner unit—basic and diluted	$	0.62	$	0.70	$	0.47	$	0.41	$	2.20

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TransMontaigne Partners L.P. and subsidiaries

Notes to Consolidated Financial Statements (continued)

Years ended December 31, 2017, 2016 and 2015


	Three months ended
									Year ended
	March 31,		June 30,		September 30,		December 31,		December 31,
	2016		2016		2016		2016		2016
	(in thousands except per unit amounts)
Revenue	$	40,626	$	41,136	$	40,638	$	42,524	$	164,924
Direct operating costs and expenses		(15,906)		(17,703)		(17,048)		(17,758)		(68,415)
General and administrative expenses		(3,878)		(3,446)		(3,605)		(3,171)		(14,100)
Insurance expenses		(895)		(912)		(969)		(1,305)		(4,081)
Equity-based compensation expense		(2,155)		(258)		(251)		(599)		(3,263)
Depreciation and amortization		(7,935)		(8,064)		(8,169)		(8,215)		(32,383)
Earnings from unconsolidated affiliates		1,850		2,130		2,960		3,089		10,029
Operating income		11,707		12,883		13,556		14,565		52,711
Other expenses		(2,997)		(2,573)		(1,671)		(1,364)		(8,605)
Net earnings	$	8,710	$	10,310	$	11,885	$	13,201	$	44,106
Net earnings per limited partner unit—basic and diluted	$	0.41	$	0.50	$	0.58	$	0.65	$	2.14

(20) SUBSEQUENT EVENTS

On January 16, 2018, we announced a distribution of $0.77 per unit for the period from October 1, 2017 through December 31, 2017, and we paid the distribution on February 8, 2018 to unitholders of record on January 31, 2018.

On February 12, 2018, we 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, which we refer to as our senior notes. The net proceeds were used primarily to repay indebtedness under our revolving credit facility. Our senior notes are guaranteed on a senior unsecured basis by each of our 100% owned subsidiaries that guarantee obligations under our revolving credit facility. These subsidiary guarantees are full and unconditional and joint and several, and the subsidiaries that did not guarantee our senior notes are minor. TransMontaigne Partners L.P. does not have independent assets or operations unrelated to its investments in its consolidated subsidiaries. There are no significant restrictions on our ability or the ability of any subsidiary guarantor to obtain funds from its subsidiaries by such means as a dividend or loan.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the Commission’s rules and forms, and that information is accumulated and communicated to the management of our general partner, including our general partner’s principal executive and principal financial officer (whom we refer to as the Certifying Officers), as appropriate to allow timely decisions regarding required disclosure. The management of our general partner evaluated, with the participation of the Certifying Officers, the effectiveness of our disclosure controls and procedures as of December 31, 2017, pursuant to Rule 13a‑15(b) under the Exchange Act. Based upon that evaluation, the Certifying Officers concluded that, as of December 31, 2017, our disclosure controls and procedures were effective at the reasonable assurance level. In addition, our Certifying Officers concluded that there were no changes in our internal control over financial reporting that occurred during the fiscal quarter ended December 31, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

The management of our general partner is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.

The management of our general partner has used the framework set forth in the report entitled “Internal Control—Integrated Framework (2013)” published by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) to evaluate the effectiveness of our internal control over financial reporting. Based on that evaluation, the management of our general partner has concluded that our internal control over financial reporting was effective as of December 31, 2017. The effectiveness of our internal control over financial reporting as of December 31, 2017 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which appears herein.

As stated in Note 3 - “Business Combination and Terminal Acquisition” to the Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K, we acquired the West Coast terminals on December 15, 2017. We have excluded the West Coast terminals from our assessment of the effectiveness of our internal control over financial reporting as of December 31, 2017. The West Coast terminals consolidated total assets represent approximately 28% of our consolidated total assets as of December 31, 2017, 1% of our revenue and 2% of our net earnings for the year ended December 31, 2017. We are in the process of integrating the West Coast terminals into our financial reporting processes. As a result of these integration activities, certain internal controls over financial reporting will be evaluated and may be changed. We believe, however that we will be able to maintain sufficient internal control over financial reporting throughout this integration process.

March 15, 2018

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Report of Independent Registered Public Accounting Firm

To the Board of Directors of TransMontaigne GP L.L.C. and

To the Unitholders of TransMontaigne Partners L.P.

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of TransMontaigne Partners L.P. and subsidiaries (the "Partnership") as of December 31, 2017, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2017 of the Partnership and our report dated March 15, 2018, expressed an unqualified opinion on those financial statements.

As described in Management’s Annual Report on Internal Control over Financial Reporting, management excluded from its assessment the internal control over financial reporting at the West Coast Terminal Facilities (“WCT”), which were acquired on December 15, 2017, and whose financial statements constitute 28% of total assets, 1% of net operating revenue, and 2% of net earnings of the consolidated financial statement amounts as of and for the year ended December 31, 2017. Accordingly, our audit did not include the internal control over financial reporting of WCT.

Basis for Opinion

The Partnership's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of the effectiveness to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Deloitte & Touche LLP

Denver, Colorado
March 15, 2018

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ITEM 9B. OTHER INFORMATION

On March 14, 2018, upon the recommendation of the audit committee, the board of directors of our general partner adopted an updated Code of Ethics for Senior Financial Officers. A copy of the Code of Ethics for Senior Financial Officers is available on our website at www.transmontaignepartners.com/investors/corporate-governance and additional information relating to the Code of Ethics for Senior Financial Officers can be found under Item 10. “Directors, Executive Officers of Our General Partner and Corporate Governance—Corporate Governance Guidelines; Code of Business Conduct and Ethics” of this Annual Report.

No information was required to be disclosed in a report on Form 8‑K, but not so reported, for the quarter ended December 31, 2017.

Part III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS OF OUR GENERAL PARTNER AND CORPORATE GOVERNANCE

Management of TransMontaigne Partners

TransMontaigne GP is our general partner and manages our operations and activities. Effective as of the February 1, 2016 ArcLight acquisition, TransMontaigne GP became a wholly owned subsidiary of ArcLight. Our partnership has no officers or employees and all of our management and operational activities were provided by officers and employees of NGL Energy Operating prior to the ArcLight acquisition and thereafter for an interim period. In connection with the ArcLight acquisition, NGL and ArcLight entered into a transition services agreement whereby NGL Energy Operating served as the entity that employed the officers and employees that provided services to our partnership, and NGL Energy Operating provided payroll and benefits services related thereto until June 25, 2016. From and after June 26, 2016 all employees who provide services to the partnership became employees of TLP Management Services. TLP Management Services continues to employ all the officers and employees who provide services to our partnership and such entity provides payroll and maintains all employee benefits programs on behalf of our partnership.

Our general partner is not elected by our unitholders and is not subject to re‑election on a regular basis in the future. Unitholders are not entitled to elect directors to the board of directors of our general partner or directly or indirectly participate in our management or operation. Under the Corporate Governance Guidelines adopted by the board of directors of our general partner, the board assesses, on an annual basis, the skills and characteristics that candidates for election to the board of directors should possess, as well as the composition of the board of directors as a whole. This assessment includes the qualifications under applicable independence standards and other standards applicable to the board of directors and its committees, as well as consideration of skills and experience in the context of the needs of the board of directors as a whole. Our general partner has no formal policy regarding the diversity of board members, but seeks to ensure that its board of directors collectively have the personal qualities to be able to make an active contribution to the board of directors’ deliberations, which qualities may include relevant industry experience, financial management, reporting and control expertise and executive and operational management experience.

Board of Directors and Officers

The board of directors of our general partner oversees our operations. As part of its oversight function, the board of directors monitors how management operates the partnership, in part via its committee structure. When granting authority to management, approving strategies and receiving management reports, the board of directors considers, among other things, the risks and vulnerabilities we face. The audit committee of the board of directors considers risk associated with our overall accounting, financial reporting and disclosure process. Except for executive sessions held with unaffiliated directors, all members of the board of directors are invited to and frequently attend the meetings of the audit committee. The conflicts committee of our general partner reviews specific matters that the board believes may involve conflicts of interests.

As of the date of this report, there are seven members of the board of directors of our general partner, three of whom, Messrs. Blank, Welch and Wiese, are independent as defined under the independence standards established by the New York Stock Exchange (the “NYSE”). The NYSE does not require a publicly traded limited partnership listed on the exchange, like TransMontaigne Partners, to have a majority of independent directors on the board of directors of its general partner or to establish a compensation committee or a nominating or governance committee. However, the Governance Guidelines of our general partner provide that at least three directors will be independent.

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Upon the closing of the ArcLight acquisition, on February 1, 2016, Atanas H. Atanasov, Benjamin Borgen, Brian Cannon and Donald M. Jensen, each employees of NGL, resigned from the board of directors of our general partner. To fill the vacancies resulting from the resignation of the NGL directors, Daniel R. Revers, Kevin M. Crosby and Lucius H. Taylor, each employees of ArcLight, were appointed to the board of directors of our general partner effective February 1, 2016. On February 22, 2016, Theodore D. Burke, an employee of ArcLight, was appointed to the board of directors of our general partner. On July 19, 2016, Robert A. Burk and Lawrence C. Ross notified the partnership of their intention to resign from the board of directors of our general partner and the audit, compensation and conflicts committees thereof, effective July 21, 2016. On July 21, 2016, the board of directors of our general partner appointed Jay A. Wiese and Barry E. Welch to serve as independent members of the board of directors of our general partner. Mr. Wiese was elected to serve as the chairman of the compensation committee of our general partner and as a member of the audit and conflicts committees. Mr. Welch was elected to serve as the chairman of the conflicts committee of our general partner and as a member of the audit and compensation committees.

Directors and Executive Officers

The following table sets forth the names, ages and titles of the directors and executive officers of TransMontaigne GP as of March 15, 2018:


Name	Age	Position
Frederick W. Boutin	62	Chief Executive Officer
James F. Dugan	60	Executive Vice President and Chief Operating Officer
Robert T. Fuller	48	Executive Vice President, Chief Financial Officer and Treasurer
Michael A. Hammell	47	Executive Vice President, General Counsel and Secretary
Mark S. Huff	58	President
Steven A. Blank	63	Independent Director, Chairman of Audit Committee
Theodore D. Burke	57	Director
Kevin M. Crosby	45	Director
Daniel R. Revers	56	Director
Lucius H. Taylor	43	Director
Barry E. Welch	60	Independent Director, Chairman of Conflicts Committee
Jay A. Wiese	61	Independent Director, Chairman of Compensation Committee

Frederick W. Boutin has served as Chief Executive Officer of our general partner and its subsidiaries since November of 2014. Prior to then he served as Executive Vice President and Chief Financial Officer beginning in January 2008. Mr. Boutin also managed business development and commercial contracting activities from December 2007 to July 2010 and from August 2013 to January 2015. Prior to February 1, 2016, Mr. Boutin also served in various other capacities at our general partner and its subsidiaries, and TransMontaigne LLC and its predecessors, since 1995. Prior to his affiliation with TransMontaigne, Mr. Boutin was a Vice President at Associated Natural Gas Corporation, and its successor Duke Energy Field Services, and a certified public accountant with Peat Marwick. Mr. Boutin holds a B.S. in Electrical Engineering and an M.S. in Accounting from Colorado State University.

James F. Dugan has served as Executive Vice President and Chief Operating Officer of our general partner and its subsidiaries since August 30, 2017. Mr. Dugan previously served as Executive Vice President, Engineering and Operations of our general partner and its subsidiaries from June 30, 2017 to August 30, 2017 and served as the Senior Vice President, Engineering and Operations of our general partner and its subsidiaries from January 2008 to June 30, 2017. Mr. Dugan joined TransMontaigne Inc. as Engineering Manager in 1998. He has over 16 years of experience in senior leadership positions overseeing domestic and international petroleum marine terminals, pipelines and engineering divisions. Mr. Dugan began his career as a Project Engineer for Gulf Interstate Energy in 1983 and in 1993 he joined Louis Dreyfus Energy as a Project Engineer. He has served on the Board of Directors for the International Liquid Terminals Association (ILTA) since 2011, and he holds certification through the American Petroleum Institute.

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Robert T. Fuller has served as Executive Vice President, Chief Financial Officer and Treasurer of our general partner and its subsidiaries since November of 2014. Prior to November of 2014, Mr. Fuller served as Vice President and Chief Accounting Officer of our general partner and its subsidiaries since January 2011 and as its Assistant Treasurer since February 2012. Prior to his affiliation with TransMontaigne, Mr. Fuller spent 13 years as a certified public accountant with KPMG LLP. Mr. Fuller has a B.A. in Political Science from Fort Lewis College and a M.S. in Accounting from the University of Colorado. Mr. Fuller is licensed as a certified public accountant in Colorado and New York.

Michael A. Hammell has served as Executive Vice President, General Counsel and Secretary of our general partner and its subsidiaries since October 2012. Mr. Hammell served as the Senior Vice President, Assistant General Counsel and Secretary of each of our general partner and the TransMontaigne LLC entities from July 2011 to October 2012; as Vice President, Assistant General Counsel and Secretary from January 2011 to July 2011; as Vice President, Assistant General Counsel and Assistant Secretary from November 2007 until January 2011 and as Assistant General Counsel from April 2007 to November 2007. Prior to joining TransMontaigne, Mr. Hammell practiced at the law firm of Hogan & Hartson LLP (now Hogan Lovells). Mr. Hammell received a B.S. in Business Administration from the University of Colorado at Boulder and a J.D. from Northwestern University School of Law.

Mark S. Huff has served as President of our general partner and its subsidiaries since August 2017. Mr. Huff served as Executive Vice President, Commercial Operations of our general partner and its subsidiaries from September 2016 to August 2017 and prior thereto as Senior Vice President, Commercial Operations since returning to the partnership in January 2015. Prior thereto he served as Director of Business Development with Colonial Pipeline from November 2012 to January 2015 and as Managing Director of Vecenergy from 2008 to 2012. Mr. Huff was previously employed with a former affiliate of the partnership from 1996 to 2007 where he was responsible at various times for the business development and product marketing activities of TransMontaigne Partners and its affiliates. Mr. Huff holds a B.S. in Nautical Science from the United States Merchant Marine Academy at Kings Point, NY.

Steven A. Blank was elected as a director of our general partner on September 24, 2014. Mr. Blank was asked to join the board of directors, in part, based on his executive management experience in the energy industry, his financial and accounting knowledge and because he qualified as an independent director. Mr. Blank served as Executive Vice President, Chief Financial Officer and Treasurer of NuStar GP, LLC and NuStar GP Holdings from February 2012 until December 2013. Mr. Blank served as Senior Vice President and Chief Financial Officer of NuStar GP, LLC from January 2002 until February 2012. Mr. Blank also served as NuStar GP, LLC’s Treasurer from July 2005 until February 2012. Mr. Blank has also served as Senior Vice President, Chief Financial Officer and Treasurer of NuStar GP Holdings from March 2006 until December 2013. From December 1999 until January 2002, Mr. Blank was Chief Accounting and Financial Officer and a director of NuStar GP, LLC. Mr. Blank served as Vice President and Treasurer of Ultramar Diamond Shamrock Corporation from December 1996 until January 2002. From February 2015 until November 2016 Mr. Blank served on the board of directors of Dakota Plains Holdings, Inc. an integrated midstream energy company that operated the Pioneer Terminal in Mountrail County, North Dakota with services that included outbound crude storage, logistics and rail transportation and inbound frac sand logistics. Mr. Blank holds a B.A. in History from the State University of New York and a Master of International Affairs, Specialization in Business from Columbia University. Mr. Blank serves as the chair of the audit committee of our general partner and as a member of the compensation and conflicts committees of our general partner.

Theodore D. Burke was elected as a director of our general partner on February 22, 2016. Mr. Burke was appointed to the board of directors of our general partner by ArcLight, in part, based on his position with ArcLight and his legal and executive management experience in the energy industry. Mr. Burke serves as a Partner and the General Counsel of ArcLight. He joined ArcLight in 2014 and has over 30 years of legal, energy finance, and private equity experience. Prior to joining ArcLight, Mr. Burke was the Chief Executive and Global Managing Partner of Freshfields, Bruckhaus Deringer LLP. Before Freshfields, he was a Partner with Milbank Tweed Hadley and McCloy. Mr. Burke earned a Bachelor of Arts in Economics from the University of Vermont and a Juris Doctor from Georgetown University.

Kevin M. Crosby was elected as a director of our general partner on February 1, 2016. Mr. Crosby was appointed to the board of directors of our general partner by ArcLight, in part, based on his position with ArcLight and his energy finance and industry experience. Mr. Crosby serves as a Partner of Arclight. He joined ArcLight in 2001 and has 21 years of energy finance and private equity experience. Prior to joining ArcLight, Mr. Crosby was an Associate in the Corporate Finance Group at John Hancock where he focused on analyzing, structuring, and closing private debt and equity investments in the energy industry. Mr. Crosby also focused on industrial sectors such as chemicals, metals, consumer products, and healthcare while at John Hancock. Mr. Crosby began his career in 1995 at John Hancock Funds, where he held various financial positions. Mr. Crosby earned a Bachelor of Science in Finance from the University of Maine.

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Daniel R. Revers was elected as a director of our general partner on February 1, 2016. Mr. Revers was appointed to the board of directors of our general partner by ArcLight, in part, based on his position with ArcLight and his energy finance and industry experience. Mr. Revers is a co-founder and the Managing Partner of ArcLight and has 27 years of energy finance and private equity experience. Mr. Revers is responsible for overall investment, asset management, strategic planning, and operations of ArcLight and its funds. Prior to forming ArcLight in 2000, Mr. Revers was a Managing Director in the Corporate Finance Group at John Hancock Financial Services, where he was responsible for the origination, execution, and management of a $6 billion portfolio consisting of debt, equity, and mezzanine investments in the energy industry. Prior to joining John Hancock in 1995, Mr. Revers held various financial positions at Wheelabrator Technologies, where he specialized in the development, acquisition, and financing of domestic and international power and energy projects. Mr. Revers serves as a director of the general partner of American Midstream Partners, LP and served as a director of the general partner of JP Energy Partners LP prior to American Midstream Partners, LP’s acquisition of JP Energy Partners LP in March 2017. Mr. Revers earned a Bachelor of Arts in Economics from Lafayette College and a Master of Business Administration from the Amos Tuck School of Business Administration at Dartmouth College.

Lucius H. Taylor was elected as a director of our general partner on February 1, 2016. Mr. Taylor was appointed to the board of directors of our general partner by ArcLight, in part, based on his position with ArcLight and his energy finance and industry experience. Mr. Taylor serves as a Principal of Arclight. He joined ArcLight in 2007 and has 17 years of experience in energy and natural resource finance and engineering. Prior to joining ArcLight, Mr. Taylor was a Vice President in the Energy and Natural Resource Group at FBR Capital Markets, where he focused on raising public and private capital for companies in the power and energy sectors. Mr. Taylor began his career as a geologist and project manager at CH2M HILL and is a licensed professional geologist. Mr. Taylor serves as a director of the general partner of American Midstream Partners, LP. Mr. Taylor earned a Bachelor of Arts in Geology from Colorado College, a Master of Science in Hydrogeology from the University of Nevada, and a Master of Business Administration from the Wharton School of Business at the University of Pennsylvania.

Barry E. Welch was elected as a director of our general partner on July 21, 2016. Mr. Welch was asked to join the board of directors, in part, based on his corporate finance and public company executive management and board experience, and because he qualifies as an independent director. Since January 2015, Mr. Welch has been an independent energy consultant, including a senior advisor role to Southwest Generation, a US independent power company. In June 2016, Mr. Welch joined the board of directors of Novatus Energy, LLC, a renewable energy independent power company. From 2004 to September 2014, Mr. Welch served as the Chief Executive Officer of Atlantic Power and also served on the board of directors of Atlantic Power from 2006 to 2014. From 2001 to 2004, Mr. Welch served as the Senior Vice President, Head of the Bond and Corporate Finance Group at John Hancock Financial Services, and from 1989 to 2001 he served in various other roles at John Hancock, including Senior Vice President, Team leader: Utilities, Infrastructure Project Finance, Oil & Gas from 1998 to 2001, Senior Managing Director, Team Leader: Utilities and Infrastructure Project Finance from 1995 to 1998, Senior Investment Officer – Project Finance 1992 to 1995 and Investment Officer – Project Finance 1989 to 1992. Mr. Welch holds a Bachelor of Science in Engineering from Princeton University and a Masters of Business Administration from Boston College.

Jay A. Wiese was elected as a director of our general partner on July 21, 2016. Mr. Wiese was asked to join the Board, in part, based on his executive management experience in the energy industry, experience as a former member of the Board and because he qualifies as an independent director. Mr. Wiese previously served as a director of our general partner and as a member of the audit, conflicts and compensation committees of our general partner from October 2010 until August 2014. From December 2006 to the present, Mr. Wiese has served as the Managing Member of Liberated Partners LLC, a global energy consulting business with a focus on client strategy, acquisitions, logistics, business development and operational analysis. From 1982 to October 2006, Mr. Wiese served in various senior management positions, including most recently Vice President, with Magellan Midstream Partners, L.P., where he had responsibility over Magellan Terminal Holdings in the areas of commercial and business development, acquisitions and operations. From March 2012 until October 2016, Mr. Wiese served on the board of directors of Associated Asphalt, Inc., a private company engaged in the storage and supply of liquid asphalt to the paving industry, where Mr. Wiese was a member of the Audit and Compensation Committees. Mr. Wiese holds a Bachelor of Science in Business from Oklahoma State University where Mr. Wiese is a member of the Foundation's Board of Trustees and Chair of its Investment Committee.

Compliance with Section 16(a) of the Securities Exchange Act of 1934

Section 16(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) requires the executive officers and directors of our general partner, and persons who own more than ten percent of a registered class of our equity securities (collectively, “Reporting Persons”) to file with the SEC and the NYSE initial reports of ownership and reports of changes in ownership of our common units and our other equity securities. Specific due dates for those reports have been

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established, and we are required to report herein any failure to file reports by those due dates. Reporting Persons are also required by SEC regulations to furnish TransMontaigne Partners with copies of all Section 16(a) reports they file.

To our knowledge, based solely on a review of the copies of such reports furnished to us and written representations that no other reports were required during the year ended December 31, 2017, all Section 16(a) filing requirements applicable to such Reporting Persons were satisfied.

Committees of the Board of Directors

The board of directors of our general partner has three standing committees: an audit committee, a conflicts committee and a compensation committee. The composition, duties and responsibilities of these committees are set forth below.

Audit Committee

The audit committee currently has three members, Steven A. Blank, Barry E. Welch and Jay A. Wiese, each of whom is able to understand fundamental financial statements and at least one of whom has past experience in accounting or related financial management. The board has determined that each member of the audit committee is independent under Section 303A.02 of the NYSE listing standards and Section 10A(m)(3) of the Exchange Act. In making the independence determination, the board considered the requirements of the NYSE and the Corporate Governance Guidelines of our general partner. Among other factors, the board considered current or previous employment with the partnership, its auditors or their affiliates by the director or his immediate family members, ownership of our voting securities, and other material relationships with the partnership.

Based upon his education and employment experience as more fully detailed in Mr. Blank’s biography set forth above, Mr. Blank has been designated by the board as the audit committee’s financial expert meeting the requirements promulgated by the SEC and set forth in Item 407(d)(5)(ii) of Regulation S‑K of the Exchange Act.

The audit committee has the authority and responsibility to review our external financial reporting, review our procedures for internal auditing and the adequacy of our internal accounting controls, consider the qualifications and independence of our independent auditor, engage and direct our independent auditor and to engage the services of any other advisors and accountants as the audit committee deems advisable. The audit committee reviews and discusses our audited financial statements with management, discusses with our independent auditor matters required to be discussed by auditing standards and makes recommendations to the board of directors of our general partner relating to our audited financial statements. The audit committee also periodically reviews the audit committee charter and recommends to the board of directors of our general partner any changes that the audit committee believes are required or desirable. On March 12, 2018, upon the recommendation of the audit committee, the board of directors of our general partner adopted our current audit committee charter.

Conflicts Committee

Messrs. Blank, Welch and Wiese currently serve on the conflicts committee of the board of directors of our general partner. The conflicts committee reviews specific matters that the board of directors of our general partner believe may involve conflicts of interest. The conflicts committee determines if the resolution of the conflict of interest is fair and reasonable to the partnership. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, and must meet the independence standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors and certain other requirements. Pursuant to our partnership agreement, any matter approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, to be approved by all of our partners and not deemed a breach by our general partner of any duties it may owe us or our unitholders.

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Compensation Committee

Although not required by the NYSE listing requirements, the board of directors of our general partner has a standing compensation committee, which (1) has overall responsibility for evaluating and recommending to the board of our general partner the director compensation plans, policies and programs, and (2) with the concurrence of the conflicts committee, reviews on an annual basis, the awards granted by TLP Management Services under the TLP Management Services long-term incentive plan, and shall approve the aggregate amount of reimbursement, if any, for such awards to be paid by the partnership to TLP Management Services, or directly to the program participants. The forgoing reimbursement may be satisfied by the partnership in either a cash payment to TLP Management Services or the delivery of our common units to the savings and retention program or alternatively directly to the award recipients, with the reimbursement made in accordance with the underlying vesting and payment schedule of the savings and retention program.

Corporate Governance Guidelines; Code of Business Conduct and Ethics

The board of directors of our general partner has adopted Corporate Governance Guidelines that outline the important policies and practices regarding our governance. The board of directors has no policy requiring that we have a chairman of the board or that the positions of the chairman of the board and the chief executive officer of our general partner be separate or that they be occupied by the same individual. The board of directors believes that this issue is properly addressed as part of the succession planning process and that a determination on this subject should be made if at some future period it elects a new chief executive officer or at such other times as when consideration of the matter is warranted by circumstances.

On March 14, 2018, upon the recommendation of the audit committee, the board of directors of our general partner adopted an updated Code of Ethics for Senior Financial Officers. The Code of Ethics for Senior Financial Officers applies to the senior financial officers of our general partner, including the chief executive officer, the chief financial officer, the chief accounting officer, the chief operating officer and the president or persons performing similar functions. In addition, we have a separate Code of Business Conduct and Ethics, which applies to all employees acting on behalf of our general partner and to the officers and directors of our general partner.

Copies of our Code of Business Conduct and Ethics, Code of Ethics for Senior Financial Officers, Corporate Governance Guidelines, Audit Committee Charter and Compensation Committee Charter are available on our website at www.transmontaignepartners.com/investors/corporate-governance. We intend to satisfy the disclosure requirements regarding certain amendments to, or waivers from, provisions of the Code of Business Conduct and Ethics and Code of Ethics for Senior Financial Officers by posting such information to our website.

Communications by Unitholders

Pursuant to our Corporate Governance Guidelines, the board of directors of our general partner meets at the conclusion of regularly‑scheduled board meetings without the presence of executive officers of or employees who provide services on behalf of our general partner, which meetings are presided over by Barry E. Welch as presiding director. In addition, the independent members of the board of directors of our general partner meet in executive sessions at the conclusion of regularly‑scheduled board meetings, pursuant to which, the board has chosen Mr. Welch to preside as chair of these executive session meetings.

Unitholders and other interested parties may communicate with (1) Barry E. Welch, in his capacity as chairman of the executive session meetings of the board of directors of our general partner, (2) the independent members of the board of directors of our general partner as a group, or (3) any and all members of the board of directors of our general partner by transmitting correspondence by mail or facsimile addressed to one or more directors by name or to the independent directors (or to the presiding director or any standing committee of the board) at the following address and fax number:

Name of the Director(s)

c/o Secretary

TransMontaigne Partners L.P.

1670 Broadway, Suite 3100

Denver, Colorado 80202

(303) 626‑8228

The Secretary of our general partner will collect and organize all such communications in accordance with procedures approved by the board of directors. The Secretary will forward all communications to the presiding director or to the identified director(s) as soon as practicable. However, we may handle differently communications that are abusive, offensive or that

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present safety or security concerns. If we receive multiple communications on a similar topic, our secretary may, in his or her discretion, forward only representative correspondence.

The presiding director will determine whether any communication addressed to the entire board should be properly addressed by the entire board or a committee thereof if a communication is sent to the board or a committee, the presiding director or the chairman of that committee, as the case may be, will determine whether the communication warrants a response. If a response to the communication is warranted, the content and method of the response will be coordinated with our general partner’s internal or external counsel.

ITEM 11. EXECUTIVE COMPENSATION

EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

We do not directly employ any of the persons responsible for managing our business. We are managed by our general partner, TransMontaigne GP. 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.

We do not incur any direct compensation charge for the executive officers of our general partner. Instead, pursuant to our omnibus agreement with ArcLight, we pay ArcLight an annual administrative fee that is intended to compensate ArcLight for providing, through TLP Management Services, certain corporate staff and support services to us, including services provided to us by the executive officers of our general partner. During the year ended December 31, 2017, we paid ArcLight an administrative fee of approximately $12.8 million. The administrative fee is a lump‑sum payment and does not reflect specific amounts attributable to the compensation of the executive officers of our general partner while acting on our behalf.

In addition, under the omnibus agreement, and prior to ArcLight acquiring our general partner on February 1, 2016, we agreed to reimburse TransMontaigne LLC for a portion of the incentive bonus awards made to key employees under the TransMontaigne Services LLC savings and retention plan, provided that the compensation committee of our general partner determines that an adequate portion of the incentive bonus awards are indexed to the performance of our common units in the form of restricted phantom units. The value of our incentive bonus award reimbursement for a single grant year may be no less than $1.5 million. Effective April 13, 2015 and beginning with the 2015 incentive bonus award, we have the option to provide the reimbursement in either a cash payment to TransMontaigne LLC (or ArcLight from and after February 1, 2016) or the delivery of our common units to TransMontaigne LLC (or ArcLight from and after February 1, 2016) or to the award recipients, with the reimbursement made in accordance with the underlying vesting and payment schedule of the savings and retention plan. Prior to the 2015 incentive bonus award, we reimbursed our portion of the incentive bonus awards by making cash payments to TransMontaigne LLC over the first year that each applicable award was granted. For the 2017 incentive bonus awards, the expense associated with the reimbursement was approximately $2.7 million.

The board of directors and the compensation committee of our general partner perform only a limited advisory role in setting the compensation of the executive officers of our general partner, which for 2017 was determined by the compensation committee of TLP Management Services. The compensation committee of our general partner, however, determines the amount, timing and terms of all equity awards granted to our independent directors. For 2015 and prior years, such awards were granted under TransMontaigne Services LLC’s long‑term incentive plan.

The primary elements of the executive compensation program for 2017 were a combination of annual cash and long‑term equity‑based compensation. During 2017, elements of compensation for our executive officers consisted of the following:

Annual base salary;

Discretionary annual cash awards;

Long‑term equity‑based compensation; and

Other compensation, including very limited perquisites.

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The elements of TLP Management Services’ compensation program for 2017, along with TransMontaigne LLC’s other rewards (for example, benefits, work environment, career development), were intended to provide a total rewards package designed to support the business strategies of TransMontaigne LLC and our partnership. During 2017, TransMontaigne LLC did not use any elements of compensation based on specific performance‑based criteria and did not have any other specific performance‑based objectives. Although the board of directors and the compensation committee of our general partner perform only a limited advisory role in setting the compensation of the executive officers of our general partner, we are not aware of any compensation elements of TransMontaigne LLC’s compensation program which are reasonably likely to have a material adverse effect on us.

TLP Management Services long‑term incentive plan and the savings and retention program was intended to align the long‑term interests of the executive officers of our general partner with those of our unitholders to the extent a portion of the bonus awards under the savings and retention program is deemed invested in our common units.

Employment and Other Agreements

We have not entered into any employment agreements with any officers of our general partner.

Compensation Committee Report

The compensation committee has reviewed and discussed the Compensation Discussion and Analysis with management. Based on such review and discussions, the compensation committee recommended to the board of directors of our general partner that the Compensation Discussion and Analysis be included in our Annual Report on Form 10‑K for filing with the Securities and Exchange Commission.


	COMPENSATION COMMITTEE Jay A. Wiese, Chair Steven A. Blank Barry E. Welch

COMPENSATION OF DIRECTORS

Employees of our general partner or its affiliates (including employees of ArcLight and its affiliates) who also serve as directors of our general partner do not receive additional compensation. Pursuant to our independent director annual compensation program, the independent directors receive annual compensation consisting of: (i) $60,000 annual cash retainer; paid quarterly in arrears, and (ii) common units valued at $90,000 and issued pursuant to the TLP Management Services long-term incentive plan, which common units are immediately vested and are not subject to forfeiture. For each annual award of common units issued to the independent directors under the TLP Management Services long-term incentive plan, the awards will be made on the third Friday of October (or the next trading day if the NYSE is closed), based on the closing sales price during normal trading hours of the common units on the NYSE. In addition, each director is reimbursed for out‑of‑pocket expenses in connection with attending meetings of the board of directors or committees. No additional consideration is paid to the independent directors for service on any committee of the board of directors of our general partner or for service as a committee chairperson unless approved by the board in advance for a specific engagement or transaction.

Each director will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law. The following table provides information concerning the compensation of our general partner’s directors for 2017.

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Director Compensation Table for 2017


	Fees earned or		Stock		All other
	paid in cash ($)		awards ($)		compensation ($)	Total ($)
Name (a)	(b)		(c)		(g)	(h)
Theodore D. Burke(1)		—		—	—		—
Kevin M. Crosby(1)		—		—	—		—
Daniel R. Revers(1)		—		—	—		—
Lucius H. Taylor(1)		—		—	—		—
Steven A. Blank	$	60,000	$	90,000	—	$	150,000
Barry E. Welch	$	60,000	$	90,000	—	$	150,000
Jay A. Wiese	$	60,000	$	90,000	—	$	150,000

(1)

Because Messrs. Burke, Crosby, Revers and Taylor are employees of an affiliate of our general partner, none of them received compensation for service as a director of our general partner. At December 31, 2017, none of Messrs. Burke, Crosby, Revers and Taylor held any restricted phantom or other limited partner interests in the Partnership (except as to those securities over which Mr. Revers may be deemed to have beneficial ownership as described under Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters).

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

During the year ended December 31, 2017, Messrs. Blank, Welch and Wiese each served on the compensation committee of our general partner. During 2017, none of the members of the compensation committee was an officer or employee of our general partner or any of our subsidiaries or served as an officer of any company with respect to which any of the executive officers of our general partner served on such company’s board of directors.

LONG‑TERM INCENTIVE PLAN

On February 26, 2016, the board of our general partner approved, subject to the approval of our unitholders, the TLP Management Services 2016 long-term incentive plan, or otherwise referred to as TLP Management Services long-term incentive plan and the TLP Management Services savings and retention program (discussed further below) which constitutes a program under, and is subject to, the TLP Management Services long-term incentive plan. On July 12, 2016, we held a special meeting of common unitholders at which time the TLP Management Services long-term incentive plan was approved by the partnership’s common unitholders.

The TLP Management Services long-term incentive plan reserves 750,000 common units to be granted as awards under the plan, with such amount subject to adjustment as provided for under the terms of the plan if there is a change in our common units, such as a unit split or other reorganization. The common units authorized to be granted under the TLP Management Services long-term incentive plan are registered pursuant to a registration statement on Form S-8.

The TLP Management Services long‑term incentive plan is administered by the compensation committee of the board of directors of our general partner and is used for grants of restricted phantom units to the independent directors of our general partner. Up to and including the 2015 award grants, all annual award grants to the independent directors of our general partner vested and were payable annually in equal tranches over a four-year period, subject to accelerated vesting upon a change in control of TransMontaigne GP. Ownership in the awards was subject to forfeiture until the vesting date, but recipients had distribution and voting rights from the date of the grant.

Effective as of October 18, 2016, the board of directors of our general partner, with the concurrence of the compensation committee, adopted a revised independent director annual compensation program, which program includes the award of our common units valued at $90,000 and issued pursuant to the TLP Management Services long-term incentive plan, as described in more detail under Item 11. Executive Compensation – Compensation of Directors above.

SAVINGS AND RETENTION PROGRAM

On February 26, 2016, the board of directors approved the savings and retention program, which constitutes a “program” under, and be subject to, the TLP Management Services long-term incentive plan described above, for employees who provide services with respect to our business. The purpose of the plan was to provide for the reward and retention of

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certain key employees of TLP Management Services or its affiliates by providing them with bonus awards that vest over future service periods. Awards under the plan generally vested as to 50% of a participant’s annual award on the first day of the month containing the second anniversary of the grant date and the remaining 50% on the first day of the month containing the third anniversary of the grant date, subject to earlier vesting upon a participant’s attainment of certain age or length of service thresholds as specified in the plan. Awards are payable as to 50% of a participant’s annual award in the month containing the second anniversary of the grant date, and the remaining 50% in the month containing the third anniversary of the grant date, subject to earlier payment upon the participant’s retirement after achieving the age or service thresholds, death or disability, involuntary termination without cause or termination of a participant’s employment following a change in control, each as specified in the plan.

Pursuant to the provisions of the plan, once participating employees of TLP Management Services reach the age and length of service thresholds set forth below, awards are immediately vested and become payable as set forth above, and such vested awards remain subject to forfeiture as specified in the plan. A person will satisfy the age and length of service thresholds of the plan upon the attainment of the earliest of (a) age sixty, (b) age fifty-five and ten years of service as an officer of TLP Management Services or its affiliates, or (c) age fifty and twenty years of service as an employee of TLP Management Services or its affiliates. Each of Messrs. Boutin, Huff and Dugan have satisfied the age and length of service thresholds of the plan. Generally, only senior level management of TLP Management Services receive awards under the savings and retention program. Although no assets are segregated or otherwise set aside with respect to a participant’s account, the amount ultimately payable to a participant shall be the amount credited to such participant’s account as if such account had been invested in some or all of the investment funds selected by the plan administrator.

Under the second amended and restated omnibus agreement entered into on March 1, 2016, we have agreed to satisfy the incentive bonus awards made to key employees under the savings and retention program in either cash or in common units; provided the compensation committee and conflicts committee of our general partner approves the annual awards granted under the plan. The plan administrator allocated 100% of all 2016, 2017 and 2018 awards to the partnership’s common units fund. For the 2017 incentive bonus awards, the expense associated with the reimbursement was approximately $2.7 million.

ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

The following table sets forth certain information regarding the beneficial ownership of our common units as of March 9, 2018 by each director of our general partner, by each individual serving as an executive officer of our general partner as of March 9, 2018, by each person known by us to own more than 5% of the outstanding common units, and by all directors, director nominees and the named executive officers as of March 9, 2018 as a group. The information set forth below is based solely upon information furnished by such individuals or contained in filings made by such beneficial owners with the SEC.

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The calculation of the percentage of beneficial ownership is based on an aggregate of 16,200,485 common units outstanding as of March 9, 2018. Beneficial ownership is determined in accordance with the rules of the SEC and includes voting and investment power with respect to the common units. To our knowledge, except under applicable community property laws or as otherwise indicated, the persons named in the table have sole voting and sole investment power with respect to all common units beneficially owned. Common units underlying outstanding phantom units, warrants or options that are currently exercisable or exercisable within 60 days of March 9, 2018 are deemed outstanding for the purpose of computing the percentage of beneficial ownership of the person holding those options or warrants, but are not deemed outstanding for computing the percentage of beneficial ownership of any other person. The address for each named executive officer, director and director nominee is care of TransMontaigne Partners L.P., 1670 Broadway, Suite 3100, Denver, Colorado 80202.


	Common units	Percentage of
	beneficially	common units
Name of beneficial owner	owned	beneficially owned
TLP Equity Holdings, LLC(1)	2,366,704	14.6	%
Gulf TLP Holdings, LLC(1)	800,000	4.9	%
Oppenheimer Funds, Inc.(2)	2,282,721	14.1	%
Named Executive Officers
Frederick W. Boutin(3)(4)	78,347		*
Robert T. Fuller(5)(6)	6,997		*
Michael A. Hammell(7)(6)	5,627		*
Mark Huff(8)(4)	36,720		*
James F. Dugan(9)(4)	26,607		*
Directors
Steven A. Blank(10)	11,338		*
Theodore D. Burke	—		*
Kevin M. Crosby	—		*
Daniel R. Revers(1)	3,166,704	19.5	%
Lucius H. Taylor	—		*
Jay A. Wiese(10)	2,709		*
Barry E. Welch(10)	2,709		*
All directors, director nominees and executive officers as a group (12 persons)	3,337,758	20.6	%

*Less than 1%.

(1)Based on the Schedule 13D filed with the Securities and Exchange Commission on April 11, 2016 by each of Daniel R. Revers, TLP Equity Holdings, LLC, a Delaware limited liability company (“TLPEH”); and Gulf TLP Holdings, LLC, a Delaware limited liability company (“Gulf”). TLPEH is indirectly owned by ArcLight Energy Partners Fund VI, L.P., which is indirectly owned by ArcLight Capital Holdings, LLC. Gulf is indirectly owned by ArcLight Energy Partners Fund VI, L.P., which is indirectly owned by ArcLight Capital Holdings, LLC. Mr. Revers is the manager of the general partner of the limited partnership that manages ArcLight Capital Holdings, LLC. Mr. Revers reports shared voting and shared dispositive power over the 3,166,704 common units reported above. TLPEH reports shared voting and shared dispositive power over the 2,366,704 common units reported above. Gulf reports shared voting and shared dispositive power over the 800,000 common units reported above. The principal business address of each reporting person/entity is c/o ArcLight Capital Holdings, LLC, 200 Clarendon Street, 55th Floor, Boston, Massachusetts 02117.

(2)Based on the Schedule 13G (Amendment No. 7) filed with the Securities and Exchange Commission on February 5, 2018 by OppenheimerFunds, Inc. The address of OppenheimerFunds, Inc. is Two World Financial Center, 225 Liberty Street, New York, New York 10281.

(3)Includes 5,843 phantom units awarded to Mr. Boutin in March 2016, 13,283 phantom units awarded to Mr. Boutin in February 2017 and 17,542 phantom units awarded to Mr. Boutin in February 2018 pursuant to the TLP Management Services savings and retention program, as well as the additional phantom units Mr. Boutin has received from quarterly in-kind distributions in respect of Mr. Boutin’s phantom units.

(4)Each of Messrs. Boutin, Huff and Dugan have satisfied the age and length of service thresholds under the prior and the current savings and retention plans, therefore, the common units beneficially owned and reported in the table above include phantom units that were immediately vested upon grant and will become payable as to 50% of a participant’s award in the month containing the second anniversary of the grant date, and the remaining 50% in the month containing the third

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anniversary of the grant date. The phantom units are subject to earlier payment as described under “—Savings and Retention Program” above. At the time of payment, phantom units will be paid out, in the sole discretion of the plan administrator, in cash, in common units or a combination thereof.

(5)Includes 1,826 phantom units that will vest within 60 days of March 9, 2018, which represents the first 50% of the phantom units awarded to Mr. Fuller in March 2016, as well as the additional phantom units Mr. Fuller has received from quarterly in-kind distributions in respect to such 1,826 phantom units. Excludes the remaining 50% of the phantom units awarded to Mr. Fuller in March 2016, 5,535 phantom units awarded to Mr. Fuller in February 2017 and 7,309 phantom units awarded to Mr. Fuller in February 2018 under the TLP Management Services savings and retention program, as well as the additional phantom units Mr. Fuller has received from quarterly in-kind distributions in respect of Mr. Fuller’s phantom units.

(6)The phantom units vest 50% in the month containing the second anniversary of the grant date, and the remaining 50% in the month containing the third anniversary of the grant date. Phantom units are subject to earlier vesting as described under “—Savings and Retention Program” above. At the time of payment, phantom units will be paid out, in the sole discretion of the plan administrator, in cash, in common units or a combination thereof.

(7) Includes 2,191 phantom units that will vest within 60 days of March 9, 2018, which represents the first 50% of the phantom units awarded to Mr. Hammell in March 2016, as well as the additional phantom units Mr. Hammell has received from quarterly in-kind distributions in respect to such 2,191 phantom units. Excludes the remaining 50% of the phantom units awarded to Mr. Hammell in March 2016, 3,874 phantom units awarded to Mr. Hammell in February 2017 and 5,677 phantom units awarded to Mr. Hammell in February 2018 under the TLP Management Services savings and retention program, as well as the additional phantom units Mr. Hammell has received from quarterly in-kind distributions in respect of Mr. Hammell’s phantom units.

(8)Includes 7,974 phantom units awarded to Mr. Huff in March 2016, 7,416 phantom units awarded to Mr. Huff in February 2017 and 12,347 phantom units awarded to Mr. Huff in February 2018 pursuant to the TLP Management Services savings and retention program, as well as the additional phantom units Mr. Huff has received from quarterly in-kind distributions in respect of Mr. Huff’s phantom units.

(9)Includes 5,112 phantom units awarded to Mr. Dugan in March 2016, 4,428 phantom units awarded to Mr. Dugan in February 2017 and 7,096 phantom units awarded to Mr. Dugan in February 2018 pursuant to the TLP Management Services savings and retention program, as well as the additional phantom units Mr. Dugan has received from quarterly in-kind distributions in respect of Mr. Dugan’s phantom units.

(10)Includes the October 2017 award of common units under the TLP Management Services long-term incentive plan, pursuant to which the independent directors receive common units valued at $90,000 (prorated based on length of service on the board of our general partner) that are immediately vested.

EQUITY COMPENSATION PLAN INFORMATION

The following table summarizes information about our equity compensation plans as of December 31, 2017.


			Number of securities
			remaining available for
			future issuance under
	Number of securities to be	Weighted average	equity compensation
	issued upon exercise of	exercise price of	plans (excluding
	outstanding options,	outstanding options,	securities reflected
	warrants and rights(1)	warrants and rights	in column (a))(1)
	(a)	(b)	(c)
Equity compensation plans approved by security holders	146,121	—	603,879
Equity compensation plans not approved by security holders	—	—	—
Total	146,121	—	603,879

(1)

Includes: (i) a total of 31,113 phantom unit awards outstanding that were granted in 2015 under the TransMontaigne Services LLC savings and retention plan, which awards were later assumed under the current savings and retention

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program, which constitutes a “program” under, and is subject to, the TLP Management Services long-term incentive plan (ii) a total of 59,825 phantom unit awards outstanding that were granted in 2016 under the savings and retention program, which constitutes a “program” under, and is subject to, the TLP Management Services long-term incentive plan; and (iii) a total of 55,183 phantom unit awards outstanding that were granted in 2017 under the savings and retention program. The TLP Management Services long-term incentive plan reserves 750,000 common units to be granted as awards under the plan, including the savings and retention program, with such amount subject to adjustment as provided for under the terms of the plan.

ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

REVIEW, APPROVAL OR RATIFICATION OF TRANSACTIONS WITH RELATED PERSONS

Our general partner’s conflicts committee reviews specific matters that the board of directors of our general partner believes may involve conflicts of interest and other transactions with related persons in accordance with the procedures set forth in our amended and restated limited partnership agreement. Due to the conflicts of interest inherent in our operating structure, our general partner may, but is not required to, seek the approval of any conflict of interest transaction from the conflicts committee. Generally, such approval is requested for material transactions, including the purchase of a material amount of assets from TransMontaigne LLC or NGL prior to the ArcLight acquisition, and from ArcLight and its affiliates thereafter, or the modification of a material agreement with the foregoing parties. Under our partnership agreement, any matter approved by the conflicts committee will be conclusively deemed fair and reasonable to the partnership, to be approved by all of our partners, and not to be a breach by our general partner of its fiduciary duties. The conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict, including taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us. In addition, the conflicts committee has been granted authority to engage outside advisors to assist it in making its determinations.

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RELATIONSHIP AND AGREEMENTS WITH OUR AFFILIATES

As a result of the ArcLight acquisition, ArcLight acquired an ownership interest in, and control of, our general partner. Consequently, the transaction resulted in a change in control of TLP. The ArcLight acquisition did not involve any of the limited partnership units in TLP held by the public, and our limited partnership units continue to trade on the NYSE. In addition, on April 1, 2016, affiliates of ArcLight acquired approximately 3.2 million of our common limited partnership units from NGL. With the purchase of the common units, ArcLight has a significant interest in our partnership through their ownership of the general partner interest, the incentive distribution rights and approximately 19.2% of the limited partner interests.

The following table summarizes the distributions and payments to be made by us to our general partner and its other affiliates in connection with our ongoing operations.

Operational stage


Distributions of available cash to our general partner and its affiliates	We will generally make cash distributions 98% to the unitholders and 2% to our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target levels, our general partner will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target level.
	During the year ended December 31, 2017, we distributed approximately $22.4 million to our general partner and its affiliates. Assuming we have sufficient available cash to pay the minimum quarterly distribution on all of our outstanding units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $0.5 million on the 2% general partner interest and approximately $5.1 million on their common units.
Payments to our general partner and its affiliates	For the year ended December 31, 2017, we paid our general partner and its affiliates an administrative fee of approximately $12.8 million for the provision of various general and administrative services for our benefit. We also agreed to reimburse our general partner for a portion of the incentive bonus awards made to key employees under the TLP Management Services savings and retention program (and the predecessor TransMontaigne Services LLC savings and retention plan) and beginning with the 2015 incentive bonus award, we have the option to provide the reimbursement in either a cash payment to TLP Management Services or the delivery of our common units to TLP Management Services or to the award recipients, with the reimbursement made in accordance with the underlying vesting and payment schedule of the savings and retention program. For further information regarding these fees, please see “Omnibus Agreement” below.

Omnibus agreement

On May 27, 2005 we entered into an omnibus agreement with TransMontaigne LLC and our general partner, which agreement has been subsequently amended from time to time. In connection with the ArcLight acquisition of our general partner, effective February 1, 2016, we entered into the second amended and restated omnibus agreement to consent to the assignment of the omnibus agreement from TransMontaigne LLC to an ArcLight subsidiary, to waive the automatic termination that would have occurred at such time as TransMontaigne LLC ceased to control our general partner and to remove certain legacy provisions that were no longer applicable to the partnership. The omnibus agreement will continue in effect until the earlier to occur of (i) ArcLight ceasing to control our general partner or (ii) the election of either us or the owner, following

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at least 24 months’ prior written notice to the other parties. Any or all of the provisions of the omnibus agreement, are terminable by ArcLight at its option if our general partner is removed without cause and units held by our general partner and its affiliates are not voted in favor of that removal.

Under the omnibus agreement we pay ArcLight, the owner of TransMontaigne GP, an administrative fee for the provision of various general and administrative services for our benefit. For the years ended December 31, 2017, 2016 and 2015, the annual administrative fee paid to the owner of our general partner was approximately $12.8 million, $11.4 million and $11.3 million, respectively. If we acquire or construct additional facilities, the owner of TransMontaigne GP may propose a revised administrative fee covering the provision of services for such additional facilities, subject to approval by the conflicts committee of our general partner. For example, effective May 3, 2017 the board of TransMontaigne GP, with the concurrence of the conflicts committee, approved a $1.8 million annual increase (or $150,000 monthly) to the administrative fee related to the construction of approximately 2.0 million barrels of new tank capacity at our Collins, Mississippi bulk storage terminal. The increase was ratably applied monthly beginning May 3, 2017 based on the percentage of the approximately 2.0 million barrels of new tank capacity placed into service. The administrative fee encompasses services to perform centralized corporate functions, such as legal, accounting, treasury, insurance administration and claims processing, health, safety and environmental, information technology, human resources, credit, payroll, taxes, engineering and other corporate services.

The omnibus agreement further provides that we pay the owner of TransMontaigne GP an insurance reimbursement for insurance policies purchased on our behalf to cover our facilities and operations. For the years ended December 31, 2017, 2016 and 2015, the insurance reimbursement paid was approximately $nil, $3.1 million and $3.8 million, respectively. On October 31, 2016, we contracted directly with insurance carriers for the majority of the partnership’s insurance requirements. For the years ended December 31, 2017, 2016 and 2015, the expense associated with insurance contracted directly by us was $4.1 million, $1.0 million and $nil, respectively.

We also reimburse the owner of TransMontaigne GP for direct operating costs and expenses, such as salaries of operational personnel performing services on‑site at our terminals and pipelines and the cost of their employee benefits, including 401(k) and health insurance benefits.

Prior to March 1, 2016, under the omnibus agreement we agreed to reimburse the owner of TransMontaigne GP for a portion of the incentive bonus awards made to key employees under the owner’s savings and retention plan, provided the compensation committee of our general partner determined that an adequate portion of the incentive bonus awards were indexed to the performance of our common units in the form of restricted phantom units. The value of our incentive bonus award reimbursement for a single grant year could be no less than $1.5 million. Effective April 13, 2015 and beginning with the 2015 incentive bonus award, we have the option to provide the reimbursement in either a cash payment or the delivery of our common units to the owner of TransMontaigne GP or directly to the award recipients, with the reimbursement made in accordance with the underlying vesting and payment schedule of the savings and retention program. Prior to the 2015 incentive bonus award, we reimbursed our portion of the incentive bonus awards by making cash payments to the owner of TransMontaigne GP over the first year that each applicable award was granted.

Under the second amended and restated omnibus agreement entered into on March 1, 2016, we agreed to satisfy the incentive bonus awards made to key employees under the savings and retention program, including awards granted in 2015 and 2016, in either cash or in common units; provided the compensation committee and conflicts committee of our general partner approves the annual awards granted under the plan. For the years ended December 31, 2017, 2016 and 2015, the expense associated with the reimbursement of incentive bonus awards was approximately $2.7 million, $2.5 million and $1.3 million, respectively.

Indemnification

We have entered into various indemnification agreements with TransMontaigne LLC, which are discussed under Item 1. “Business and Properties—Environmental Matters—Site Remediation” of this Annual Report. These indemnification obligations of TransMontaigne LLC to us remain in place and were not affected by the ArcLight acquisition.

DIRECTOR INDEPENDENCE

A description of the independence of the board of directors of our general partner may be found under Item 10. “Directors, Executive Officers of our General Partner and Corporate Governance” of this Annual Report.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Deloitte & Touche LLP is our independent auditor. Deloitte & Touche LLP’s accounting fees and services were as follows:


	2017		2016
Audit fees(1)	$	688,000	$	673,000
Comfort letter and consents		150,000		148,000
Audit-related fees		—		—
Tax fees		—		—
All other fees		—		—
Total accounting fees and services	$	838,000	$	821,000

(1)

Represents an estimate of fees for professional services provided in connection with the annual audit of our financial statements and internal control over financial reporting, including Sarbanes‑Oxley 404 attestation, the reviews of our quarterly financial statements, and other services provided by the auditor in connection with statutory and regulatory filings.

The audit committee of our general partner’s board of directors has adopted an audit committee charter, which is available on our website at www.transmontaignepartners.com. The charter requires the audit committee to approve in advance all audit and non‑audit services to be provided by our independent registered public accounting firm. All services reported in the audit, comfort letter and consents, audit‑related, tax and all other fees categories above were approved by the audit committee in advance.

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Part IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(A)

1—The following documents are filed as a part of this Annual Report.

Consolidated Financial Statements and Schedules. See the index to the consolidated financial statements of TransMontaigne Partners L.P. and its subsidiaries that appears under Item 8. “Financial Statements and Supplementary Data” of this Annual Report.

Financial Statement Schedules. Financial statement schedules included in this Item 15 are the financial statements of Battleground Oil Specialty Terminal Company LLC. Other schedules are omitted because they are not required, are inapplicable or the required information is included in the financial statements or notes thereto.

Exhibits. A list of exhibits required by Item 601 of Regulation S‑K to be filed as part of this Annual Report.

(A)

2— Battleground Oil Specialty Terminal Company LLC Financial Statements, with a Report of Independent Auditors, as of December 31, 2017 and 2016 and for the Years Ended December 31, 2017, 2016 and 2015.

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Report of Independent Registered Public Accounting Firm

To the Board of Directors of

Battleground Oil Specialty Terminal Company LLC:

We have audited the accompanying financial statements of Battleground Oil Specialty Terminal Company LLC, which comprise the balance sheets as of December 31, 2017 and 2016, and the related statements of income, of members’ equity, and of cash flows for each of the three years in the period ended December 31, 2017.

Management's Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on the financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the Company's preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Battleground Oil Specialty Terminal Company LLC as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in accordance with accounting principles generally accepted in the United States of America.

Emphasis of Matter

As discussed in Note 4 to the financial statements, the Company has extensive operations and relationships with its member, Kinder Morgan Battleground Oil, LLC and other affiliated companies.

/s/PricewaterhouseCoopers LLP

Houston, Texas

February 26, 2018

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BATTLEGROUND OIL SPECIALTY TERMINAL COMPANY LLC

STATEMENTS OF INCOME

(In Thousands)


	Year Ended December 31,
	2017		2016		2015
Revenues	$	66,235	$	66,863	$	70,710

Operating Costs and Expenses
Operations and maintenance	28,052		20,105		18,898
Depreciation and amortization	18,543		18,401		18,092
General and administrative	3,134		3,694		2,673
Taxes other than income taxes	5,622		5,776		5,947
Total Operating Costs and Expenses	55,351		47,976		45,610

Operating Income	10,884		18,887		25,100

Other Income	—		1		—

Income Before Taxes	10,884		18,888		25,100

Income Tax Expense	336		174		177

Net Income	$	10,548	$	18,714	$	24,923

The accompanying notes are an integral part of these financial statements.

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BATTLEGROUND OIL SPECIALTY TERMINAL COMPANY LLC

BALANCE SHEETS

(In Thousands)


	December 31,
	2017		2016
ASSETS
Current assets
Cash and cash equivalents	$	18,716	$	21,068
Accounts receivable, net	672		1,240
Inventories	1,663		677
Other current assets	3,925		252
Total current assets	24,976		23,237

Property, plant and equipment, net	468,727		484,677
Deferred charges and other assets	621		654
Total Assets	$	494,324	$	508,568

LIABILITIES AND MEMBERS' EQUITY
Current liabilities
Accounts payable	$	6,871	$	4,589
Accrued taxes, other than income taxes	5,669		5,818
Other current liabilities	5,010		2,392
Total current liabilities	17,550		12,799

Commitments and contingencies (Notes 2 and 5)
Members' Equity	476,774		495,769
Total Liabilities and Members' Equity	$	494,324	$	508,568

The accompanying notes are an integral part of these financial statements.

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BATTLEGROUND OIL SPECIALTY TERMINAL COMPANY LLC

STATEMENTS OF CASH FLOWS

(In Thousands)


	Year Ended December 31,
	2017			2016			2015
Cash Flows From Operating Activities
Net income	$	10,548		$	18,714		$	24,923
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	18,543			18,401			18,092
Other non-cash items	190			50			391
Changes in components of working capital:
Accounts receivable	322			138			678
Inventories	(986		)	23			115
Accounts payables	2,522			(430		)	1,656
Other current assets and liabilities	(1,105		)	(242		)	1,479
Other long-term assets and liabilities	(65		)	197			(345		)
Net Cash Provided by Operating Activities	29,969			36,851			46,989

Cash Flows From Investing Activities
Capital expenditures	(3,028		)	(4,633		)	(13,362		)
Other	250			—			90
Net Cash Used in Investing Activities	(2,778		)	(4,633		)	(13,272		)

Cash Flows From Financing Activities
Contributions from Members	342			5,000			9,943
Distributions to Members	(29,885		)	(34,942		)	(41,207		)
Net Cash Used in Financing Activities	(29,543		)	(29,942		)	(31,264		)

Net (Decrease) Increase in Cash and Cash Equivalents	(2,352		)	2,276			2,453
Cash and Cash Equivalents, beginning of period	21,068			18,792			16,339
Cash and Cash Equivalents, end of period	$	18,716		$	21,068		$	18,792

The accompanying notes are an integral part of these financial statements.

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BATTLEGROUND OIL SPECIALTY TERMINAL COMPANY LLC

STATEMENTS OF MEMBERS' EQUITY

(In Thousands)


	Class A unitholders			Class B unitholders			Total unitholders
Balance at December 31, 2014	$	513,338		$	—		$	513,338
Net income	23,481			1,442			24,923
Contributions	9,943			—			9,943
Distributions	(39,765		)	(1,442		)	(41,207		)
Balance at December 31, 2015	506,997			—			506,997
Net income	17,491			1,223			18,714
Contributions	5,000			—			5,000
Distributions	(33,719		)	(1,223		)	(34,942		)
Balance at December 31, 2016	495,769			—			495,769
Net income	9,502			1,046			10,548
Contributions	342			—			342
Distributions	(28,839		)	(1,046		)	(29,885		)
Balance at December 31, 2017	$	476,774		$	—		$	476,774

The accompanying notes are an integral part of these financial statements.

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BATTLEGROUND OIL SPECIALTY TERMINAL COMPANY LLC

NOTES TO FINANCIAL STATEMENTS

1. General

We are a Delaware limited liability company, formed on May 26, 2011. When we refer to “us,” “we,” “our,” “ours,” “the Company”, or “BOSTCO,” we are describing Battleground Oil Specialty Terminal Company LLC.

The member interests in us (collectively referred to as the Class A Members) are as follows:

∠

55.0% - Kinder Morgan Battleground Oil, LLC (KM Battleground Oil), a subsidiary of Kinder Morgan, Inc. (KMI);

∠

42.5% - TransMontaigne Operating Company L.P. (TransMontaigne), a wholly owned subsidiary of TransMontaigne Partners L.P.; and

∠

2.5% - Tauber Terminals, L.P. (Tauber), a Texas limited partnership.

In addition, we have Class B member interests further described in Note 4.

We own and operate a terminal facility that has 7.1 million barrels of distillate, residual fuel and other black oil product storage at a Houston Ship Channel site. The facility also has deep draft docks and high speed pumps.

2. Summary of Significant Accounting Policies

Basis of Presentation

We have prepared our accompanying financial statements in accordance with the accounting principles contained in the Financial Accounting Standards Board's (FASB) Accounting Standards Codification, the single source of United States Generally Accepted Accounting Principles (GAAP) and referred to in this report as the Codification.

Management has evaluated subsequent events through February 26, 2018, the date the financial statements were available to be issued.

Out of Period of Adjustment

A $1,435,000 out of period correction was recorded in 2016 resulting in a decrease in operations and maintenance expense and increase in net income. This adjustment relates to the over accrual of certain dredging service costs in 2014 and 2015. Management evaluated this error taking into account both qualitative and quantitative factors and considered the impact in relation to each period in which they originated. The impact of recognizing this adjustment in prior years was not significant to any individual period. Management believes this adjustment is immaterial to the financial statements presented herein and the previously issued financial statements.

Use of Estimates

Certain amounts included in or affecting our financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities, our revenues and expenses during the reporting period, and our disclosures, including as it relates to contingent assets and liabilities at the date of our financial statements. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ

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significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

In addition, we believe that certain accounting policies are of more significance in our financial statement preparation process than others, and set out below are the principal accounting policies we apply in the preparation of our financial statements.

Cash Equivalents

We define cash equivalents as all highly liquid short-term investments with original maturities of three months or less.

Accounts Receivable, net

We establish provisions for losses on accounts receivable due from customers if we determine that we will not collect all or part of the outstanding balance. We regularly review collectability and establish or adjust our allowance as necessary using the specific identification method. As of December 31, 2017, our allowance for doubtful accounts was $246,000. We had no allowance for doubtful accounts as of December 31, 2016.

Inventories

Our inventories, which consist of consumable spare parts used in the operations of the facilities, are valued at weighted-average cost, and we periodically review for physical deterioration and obsolescence.

Property, Plant and Equipment, net

Our property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at the fair value of the assets acquired. For constructed assets, we capitalize all construction-related direct labor and material costs, as well as indirect construction costs. The indirect capitalized labor and related costs are based upon estimates of time spent supporting construction projects.

We use the straight-line method to depreciate property, plant and equipment over the estimated useful life for each asset. The cost of property, plant and equipment sold or retired and the related depreciation are removed from the balance sheet in the period of sale or disposition. Gains or losses resulting from property sales or dispositions are recognized in the period incurred. We generally include gains or losses in “Operations and maintenance” on our accompanying Statements of Income.

Asset Retirement Obligations (ARO)

We record liabilities for obligations related to the retirement and removal of long-lived assets used in our businesses. We record, as liabilities, the fair value of ARO on a discounted basis when they are incurred and can be reasonably estimated, which is typically at the time the assets are installed or acquired. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities increase due to the change in their present value, and the initial capitalized costs are depreciated over the useful lives of the related assets. The liabilities are eventually extinguished when the asset is taken out of service.

We are required to operate and maintain our assets, and intend to do so as long as supply and demand for such services exists, which we expect for the foreseeable future. Therefore, we believe that we cannot reasonably estimate the ARO for the substantial majority of assets because these assets have indeterminate lives. We continue to evaluate our ARO and future developments could impact the amounts we record. We had no recorded ARO as of December 31, 2017 and 2016.

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Asset Impairments

We evaluate our assets for impairment when events or circumstances indicate that their carrying values may not be recovered. These events include changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset and adverse changes in market conditions or in the legal or business environment such as adverse actions by regulators. If an event occurs, which is a determination that involves judgment, we evaluate the recoverability of the carrying value of our long-lived asset based on the long-lived asset's ability to generate future cash flows on an undiscounted basis. If an impairment is indicated, or if we decide to sell a long-lived asset or group of assets, we adjust the carrying value of the asset downward, if necessary, to its estimated fair value.

Our fair value estimates are generally based on assumptions market participants would use, including market data obtained through the sales process or an analysis of expected discounted future cash flows. There were no impairments for the years ended December 31, 2017, 2016 and 2015.

Revenue Recognition

Our revenue is generated from storage services under long-term storage contracts. We recognize storage revenues on firm contracted capacity ratably over the contract period regardless of the volume of petroleum products stored. We may also generate revenues from throughput movements and ancillary services. We record revenues for these additional services when performed and earned, subject to possible contractual minimums and maximums.

For the year ended December 31, 2017, revenues from our five largest non-affiliate customers were approximately $11,671,000, $11,230,000, $9,648,000, $8,886,000 and $6,994,000, respectively, each of which exceeded 10% of our operating revenues. For the year ended December 31, 2016, revenues from our three largest non-affiliate customers were approximately $12,519,000, $11,003,000 and $9,380,000, respectively, each of which exceeded 10% of our operating revenues. For the year ended December 31, 2015, revenues from our three largest non-affiliate customers were approximately $12,424,000, $10,739,000 and $8,702,000, respectively, and revenues from our largest affiliate customer was approximately $7,480,000, each of which exceeded 10% of our operating revenues.

During 2015, we recognized $8,219,000 of revenue associated with amounts collected on the early termination of a storage contract.

Operations and Maintenance

Operations and maintenance includes $3,787,000, $(370,000) and $862,000 of dredging service costs for the years ended December 31, 2017, 2016 and 2015, respectively, see “Out of period adjustment” above. Actual dredging services costs are capitalized and included in “Other current assets” and “Deferred charges and other assets” on our accompanying Balance Sheets. The capitalized dredging costs are amortized until the next dredging operation (an approximate 12 to 24 month period). We use the straight-line method to amortize dredging service costs.

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Environmental Matters

We capitalize or expense, as appropriate, environmental expenditures. We capitalize certain environmental expenditures required in obtaining rights-of-way, regulatory approvals or permitting as part of the construction. We accrue and expense environmental costs that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation. We generally do not discount environmental liabilities to a net present value, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable.

We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. We also routinely adjust our environmental liabilities to reflect changes in previous estimates. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us, and potential third-party liability claims. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are reasonably determinable.

We are subject to environmental cleanup and enforcement actions from time to time. In particular, Comprehensive Environmental Response, Compensation and Liability Act generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs. Our operations are also subject to federal, state and local laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental law and regulations, risks of additional costs and liabilities are inherent in our operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies under the terms of authority of those laws, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us.

Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters, and other matters to which we are a party, will not have a material adverse effect on our business, financial position, results of operations or cash flows. We had no accruals for any outstanding environmental matters as of December 31, 2017 and 2016.

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 the Company. Although no assurance can be given, we believe, based on our experiences to date and taking into account established reserves, that the ultimate resolution of such items will not have a material adverse impact on our business, financial position, results of operations or cash flows. We believe we have meritorious defenses to the matters to which we are a party and intend to vigorously defend the Company. When we determine a loss is probable of occurring and is reasonably estimable, we accrue an undiscounted liability for such contingencies based on our best estimate using information available at that time. If the estimated loss is a range of potential outcomes and there is no better estimate within the range, we accrue the amount at the low end of the range. We disclose contingencies where an adverse outcome may be material, or in the judgment of management, we conclude the matter should otherwise be disclosed.

As of December 31, 2017 and 2016, we had $1,642,000 accrued for a dispute with a customer related to the commencement of our operations. The dispute was settled in January 2018 and the parties entered into a services agreement with a five-year term over which period we intend to amortize the accrued amount. The settlement and resulting amortization will not have a material

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adverse effect on our financial position or results of operations.

Other Contingencies

We recognize liabilities for other contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue an undiscounted liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the low end of the range is accrued.

Income Taxes

We are a limited liability company that is treated as a partnership for income tax purposes and are not subject to federal or state income taxes. Accordingly, no provision for federal or state income taxes has been recorded in our financial statements. The tax effects of our activities accrue to our Members who report on their individual federal income tax returns their share of revenues and expenses. However, we are subject to Texas margin tax (a revenue based calculation), which is presented as “Income Tax Expense” on our accompanying Statements of Income.

3. Property, Plant and Equipment, net

Our property, plant and equipment, net consisted of the following (in thousands):


		December 31,
	Useful Life in Years	2017			2016
Terminal and storage facilities	10 - 40	$	437,977		$	435,730
Buildings	5 - 30	12,955			12,955
Other support equipment	5 - 30	76,846			76,606
Accumulated depreciation and amortization		(73,395		)	(54,868		)
		454,383			470,423
Land		13,168			13,168
Construction work in process		1,176			1,086
Property, plant and equipment, net		$	468,727		$	484,677

4. Related Party Transactions

Limited Liability Company Agreement (LLC Agreement)

Our profits and losses, and cash distributions are allocated, and made within 45 days after the end of each quarter, on a pro-rata basis to our Members in accordance with their equity percentage interests and profit interests, subject to other conditions as defined in the LLC Agreement. The Class A and Class B Members share in our profits and losses on a 96.5% and 3.5% pro-rata basis, respectively. Class B Member interests are not required to make capital contributions in order to maintain their profit interests. Class A units outstanding as of December 31, 2017 and 2016 were 14,914,900. Class B units outstanding as of December 31, 2017 and 2016 were 700.

Changes and amendments to the terms of the LLC Agreement, including its provisions regarding the approval of additional capital contributions, require both KM Battleground Oil and TransMontaigne approvals pursuant to the LLC Agreement. Class A and Class B Members have other rights, preferences, restrictions, obligations, and limitations, including limitations as to the transfer of ownership interests.

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Affiliate Agreement

Pursuant to the operations and reimbursement agreement, KM Battleground Oil operates our terminal facility and we pay them a service fee. The service fee for the years ended December 31, 2017, 2016 and 2015 was approximately $1,609,000, $1,574,000 and $1,544,000, respectively, and is reflected in “Operations and maintenance” on our accompanying Statements of Income.

Other Affiliate Balances and Activities

We enter into transactions with our affiliates within the ordinary course of business and the services are based on the same terms as non-affiliates.

We do not have employees. Employees of KMI provide services to us. In accordance with our governance documents,we reimburse KMI at cost.

The following table summarizes our balance sheet affiliate balances (in thousands):


	December 31,
	2017		2016
Accounts receivable, net	$	443	$	182
Prepayments(a)	102		239
Accounts payable	1,830		1,452

____________

(a)

Included in “Other current assets” and “Deferred charges and other assets” on our accompanying Balance Sheets.

The following table shows revenues and costs from our affiliates (in thousands):


	Year Ended December 31,
	2017		2016		2015
Revenues	$	665	$	4,751	$	7,480
Operations and maintenance	10,645		9,774		9,486
General and administrative	3,134		2,963		2,673

Subsequent Event

In February 2018, we made cash distributions to our Class A and B Members totaling $5,106,000.

5. Commitments

We lease property and equipment under various operating leases. Future minimum annual rental commitments under our

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operating leases as of December 31, 2017, are as follows (in thousands):

Year	Total
2018	$	419
2019	422
2020	378
2021	389
2022	400
Thereafter	7,046
Total	$	9,054

Rent expense on our lease obligations for the years ended December 31, 2017, 2016 and 2015 was approximately $429,000, $464,000 and $471,000, respectively, and is reflected in “Operations and maintenance” on our accompanying Statements of Income.

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6. Recent Accounting Pronouncements

Accounting Standards Updates

Topic 606

On May 28, 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers” followed by a series of related accounting standard updates (collectively referred to as “Topic 606”). Topic 606 is designed to create greater revenue recognition and disclosure comparability in financial statements. The provisions of Topic 606 include a five-step process by which an entity will determine revenue recognition, depicting the transfer of goods or services to customers in amounts reflecting the payment to which an entity expects to be entitled in exchange for those goods or services. Topic 606 requires certain disclosures about contracts with customers and provides more comprehensive guidance for transactions such as service revenue, contract modifications, and multiple-element arrangements.

Topic 606 will require that our revenue recognition policy disclosure include further detail regarding our performance obligations as to the nature, amount, timing, and estimates of revenue and cash flows generated from our contracts with customers. Topic 606 will also require disclosure of significant changes in contract asset and contract liability balances period to period and the amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) as of the end of the reporting period, as applicable. We utilized the modified retrospective method to adopt the provisions of this standard effective January 1, 2018, which required us to apply the new revenue standard to (i) all new revenue contracts entered into after January 1, 2018 and (ii) all existing revenue contracts as of January 1, 2018 through a cumulative adjustment to equity. In accordance with this approach, our consolidated revenues for periods prior to January 1, 2018 will not be revised. The cumulative effect of the adoption of this standard as of January 1, 2018 was not material.

ASU No. 2016-02

On February 25, 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842).” This ASU requires that lessees recognize assets and liabilities on the balance sheet for the present value of the rights and obligations created by all leases with terms of more than 12 months. The ASU also will require disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. ASU No. 2016-02 will be effective for us as of January 1, 2019. We are currently reviewing the effect of ASU No. 2016-02.

ASU No. 2018-01

On January 25, 2018, the FASB issued ASU No. 2018-01, “Land Easement Practical Expedient for Transition to Topic 842.” This ASU provides an optional transition practical expedient that, if elected, would not require companies to reconsider its accounting for existing or expired land easements before the adoption of Topic 842 and that were not previously accounted for as leases under Topic 840. ASU No. 2018-01 will be effective for us as of January 1, 2019, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.

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(A)

3—EXHIBITS:


Exhibit Number		Description
2.1		Facilities Sale Agreement, dated as of December 29, 2006, by and between TransMontaigne Product Services LLC (formerly known as TransMontaigne Product Services Inc.) and TransMontaigne Partners L.P. (incorporated by reference to Exhibit 2.1 of the Current Report on Form 8‑K filed by TransMontaigne Partners L.P. with the SEC on January 5, 2007).
2.2		Facilities Sale Agreement, dated as of December 28, 2007, by and between TransMontaigne Product Services LLC and TransMontaigne Partners L.P. (incorporated by reference to Exhibit 2.1 of the Current Report on Form 8‑K filed by TransMontaigne Partners L.P. with the SEC on January 3, 2008).
3.1		Certificate of Limited Partnership of TransMontaigne Partners L.P., dated February 23, 2005 (incorporated by reference to Exhibit 3.1 of TransMontaigne Partners L.P.’s Registration Statement on Form S‑1 (Registration No. 333‑123219) filed on March 9, 2005).
3.2		First Amended and Restated Agreement of Limited Partnership of TransMontaigne Partners L.P., dated May 27, 2005 (incorporated by reference to Exhibit 3.1 of the Annual Report on Form 10‑K filed by TransMontaigne Partners L.P. with the SEC on September 13, 2005).
3.3		First Amendment to the First Amended and Restated Agreement of Limited Partnership of TransMontaigne Partners L.P. dated January 23, 2006 (incorporated by reference to Exhibit 3.3 of TransMontaigne Partners L.P.’s Annual Report on Form 10‑K filed by TransMontaigne Partners with the SEC on March 8, 2010).
3.4		Second Amendment to the First Amended and Restated Agreement of Limited Partnership of TransMontaigne Partners L.P. (incorporated by reference to Exhibit 3.1 of the Current Report on Form 8‑K filed by TransMontaigne Partners L.P. with the SEC on April 8, 2008).
3.5		Third Amendment to the First Amended and Restated Agreement of Limited Partnership of TransMontaigne Partners L.P. dated May 5, 2015 (incorporated by reference to Exhibit 3.1 of the Quarterly Report on Form 10-Q filed by TransMontaigne Partners L.P. with the SEC on May 7, 2015).
4.1		Indenture, dated February 12, 2018, among TransMontaigne Partners L.P., TLP Finance Corp. and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 of the Current Report on Form 8-K filed by TransMontaigne Partners L.P. with the SEC on February 12, 2018).
4.2		First Supplemental Indenture, dated as of February 12, 2018, among TransMontaigne Partners L.P., TLP Finance Corp., the guarantors named therein and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 of the Current Report on Form 8-K filed by TransMontaigne Partners L.P. with the SEC on February 12, 2018).
10.1		Third Amended and Restated Senior Secured Credit Facility, dated March 13, 2017, among TransMontaigne Operating Company L.P., as borrower, Wells Fargo Bank, National Association, as Administrative Agent, US Bank, National Association, as Syndication Agent, Joint Lead Arranger and Joint Book Runner, Bank of America, N.A., Citibank, N.A., MUFG Union Bank N.A. and Royal Bank of Canada, each as Documentation Agents, Wells Fargo Securities, LLC, as Joint Lead Arranger and Joint Lead Book Runner, and the other financial institutions a party thereto (incorporated by reference to Exhibit 10.1 of the Annual Report on Form 10-K filed by TransMontaigne Partners L.P. with the SEC on March 14, 2017).
10.2		Contribution, Conveyance and Assumption Agreement, dated May 27, 2005, by and among TransMontaigne LLC, TransMontaigne Partners L.P., TransMontaigne GP L.L.C., TransMontaigne Operating GP L.L.C., TransMontaigne Operating Company L.P., TransMontaigne Product Services LLC and Coastal Fuels Marketing, Inc., Coastal Terminals L.L.C., Razorback L.L.C., TPSI Terminals L.L.C. and TransMontaigne Services LLC. (incorporated by reference to Exhibit 10.2 of the Annual Report on Form 10‑K filed by TransMontaigne Partners L.P. with the SEC on September 13, 2005).

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Exhibit Number		Description
10.3		Second Amended and Restated Omnibus Agreement, dated March 1, 2016, by and among Gulf TLP Holdings, LLC, TLP Management Services LLC, TransMontaigne Partners L.P., TransMontaigne GP L.L.C., TransMontaigne Operating GP L.L.C. and TransMontaigne Operating Company L.P. (incorporated by reference to Exhibit 10.2 of the Quarterly Report on Form 8‑K filed by TransMontaigne Partners L.P. with the SEC on March 3, 2016).
10.4+		2016 Long‑Term Incentive Plan (incorporated by reference to Exhibit 10.3 of the Quarterly Report on Form 8‑K filed by TransMontaigne Partners L.P. with the SEC on March 3, 2016).
10.5+		Form of 2016 Long‑Term Incentive Plan Non‑Employee Director Award Agreement (incorporated by reference to Exhibit 10.12 of the Annual Report on Form 10‑K filed by TransMontaigne Partners L.P. with the SEC on March 10, 2016).
10.6+		TLP Management Services LLC Savings and Retention Program (incorporated by reference to Exhibit 10.4 of the Quarterly Report on Form 8‑K filed by TransMontaigne Partners L.P. with the SEC on March 3, 2016).
10.7		Registration Rights Agreement, dated May 27, 2005, by and between TransMontaigne Partners L.P. and MSDW Morgan Stanley Strategic Investments, Inc. (formerly MSDW Bondbook Ventures Inc.) (incorporated by reference to Exhibit 10.7 of the Annual Report on Form 10‑K filed by TransMontaigne Partners L.P. with the SEC on September 13, 2005).
10.8		Terminaling Services Agreement—Southeast and Collins/Purvis, dated January 1, 2008, between TransMontaigne Partners L.P. and Morgan Stanley Capital Group Inc., as amended (assigned in part to NGL Energy Partners LP on July 1, 2014) (incorporated by reference to Exhibit 10.16 of the Annual Report on Form 10 K filed by TransMontaigne Partners L.P. with the SEC on March 10, 2008). Certain portions of this exhibit have been omitted and filed separately with the Commission pursuant to a request for confidential treatment under Rule 24b 2 as promulgated under the Securities Exchange Act of 1934.
10.9		Sixth Amendment to Terminaling Services Agreement—Southeast and Collins/Purvis, dated July 16, 2013, between TransMontaigne Partners L.P. and Morgan Stanley Capital Group Inc. (assigned in part to NGL Energy Partners LP on July 1, 2014) (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8 K filed by TransMontaigne Partners L.P. with the SEC on July 17, 2013).
10.10		Seventh Amendment to Terminaling Services Agreement—Southeast and Collins/Purvis, dated December 20, 2013, between TransMontaigne Partners L.P. and Morgan Stanley Capital Group Inc. (assigned in part to NGL Energy Partners LP on July 1, 2014) (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8 K filed by TransMontaigne Partners L.P. with the SEC on December 23, 2013).
10.11		Eighth Amendment to Terminaling Services Agreement—Southeast and Collins/Purvis, dated November 4, 2014, between TransMontaigne Partners L.P. and NGL Energy Partners LP. (incorporated by reference to Exhibit 10.19 of the Annual Report on Form 10‑K filed by TransMontaigne Partners L.P. with the SEC on March 10, 2016).
10.12		Amendment No. 9 to Terminaling Services Agreement—Southeast and Collins/Purvis, dated March 1, 2016, between TransMontaigne Partners L.P. and NGL Energy Partners LP (incorporated by reference to Exhibit 10.1 of the Quarterly Report on Form 8‑K filed by TransMontaigne Partners L.P. with the SEC on March 3, 2016).
10.13		Indemnification Agreement, dated December 31, 2007, among TransMontaigne LLC, TransMontaigne Partners L.P., TransMontaigne GP L.L.C., TransMontaigne Operating GP L.L.C. and TransMontaigne Operating Company L.P. (incorporated by reference to Exhibit 10.17 of the Annual Report on Form 10‑K filed by TransMontaigne Partners L.P. with the SEC on March 10, 2008).

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Exhibit Number		Description
10.14		Amended and Restated Limited Liability Company Agreement of Battleground Oil Specialty Terminal Company LLC Company, dated October 18, 2011, by and among TransMontaigne Operating Company L.P., Kinder Morgan Battleground Oil LLC and Tauber Terminals, LP (incorporated by reference to Exhibit 10.16 of the Annual Report on Form 10‑K filed by TransMontaigne Partners L.P. with the SEC on March 12, 2013). Certain portions of this exhibit have been omitted and filed separately with the Commission pursuant to a request for confidential treatment under Rule 24b‑2 as promulgated under the Securities Exchange Act of 1934.
10.15		First Amendment to the Amended and Restated Limited Liability Company Agreement of Battleground Oil Specialty Terminal Company LLC, dated December 20, 2012, by and among TransMontaigne Operating Company L.P., Kinder Morgan Battleground Oil LLC and Tauber Terminals, LP (incorporated by reference to Exhibit 10.17 of the Annual Report on Form 10‑K filed by TransMontaigne Partners L.P. with the SEC on March 12, 2013). Certain portions of this exhibit have been omitted and filed separately with the Commission pursuant to a request for confidential treatment under Rule 24b‑2 as promulgated under the Securities Exchange Act of 1934
10.16		Purchase Agreement, dated December 20, 2012, by and among TransMontaigne Operating Company L.P., and Kinder Morgan Battleground Oil LLC (incorporated by reference to Exhibit 2.1 of the Current Report on Form 8‑K filed by TransMontaigne Partners L.P. with the SEC on December 20, 2012).
10.17		Asset Purchase Agreement, dated November 2, 2017, by and between Plains Products Terminals LLC and TransMontaigne Operating Company L.P. (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8‑K filed by TransMontaigne Partners L.P. with the SEC on November 8, 2017)
10.17		First Amendment to Third Amended and Restated Senior Secured Credit Facility, dated as of December 14, 2017, by and among TransMontaigne Operating Company L.P., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8 K filed by TransMontaigne Partners L.P. with the SEC on December 18, 2017).
10.18		Right of First Offer Agreement dated as of September 12, 2017, by and between Pike West Coast Holdings, LLC and TransMontaigne Partners L.P. (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8‑K filed by TransMontaigne Partners L.P. with the SEC on September 15, 2017).
10.19		Right of First Offer Agreement dated as of August 4, 2017, by and between Pike West Coast Holdings, LLC and TransMontaigne Partners L.P. (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8‑K filed by TransMontaigne Partners L.P. with the SEC on August 9, 2017)
12.1*		Computation of Ratio of Earnings to Fixed Charges
21.1*		List of Subsidiaries of TransMontaigne Partners L.P.
23.1*		Consent of Independent Registered Public Accounting Firm—consent of Deloitte & Touche LLP on the consolidated financial statements of TransMontaigne Partners, L.P. and the effectiveness of TransMontaigne Partners, L.P.’s internal control over financial reporting.
23.2*		Consent of Independent Registered Public Accounting Firm—consent of PricewaterhouseCoopers LLP on the financial statements of Battleground Oil Specialty Terminal Company LLC.
31.1*		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes‑Oxley Act of 2002.
31.2*		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes‑Oxley Act of 2002.
32.1*		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002.

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Exhibit Number		Description
32.2*		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002.
101*		The following financial information from the Annual Report on Form 10‑K of TransMontaigne Partners L.P. and subsidiaries for the year ended December 31, 2017, formatted in XBRL (eXtensible Business Reporting Language): (i) consolidated balance sheets, (ii) consolidated statements of income, (iii) consolidated statements of partners’ equity, (iv) consolidated statements of cash flows and (v) notes to consolidated financial statements.

*Filed with this Annual Report.

+Identifies each management compensation plan or arrangement.

ITEM 16. FORM 10-K SUMMARY

None.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	TransMontaigne Partners L.P.

	By:	TransMontaigne GP L.L.C., its General Partner

	By:	/s/ Frederick W. Boutin
		Frederick W. Boutin Chief Executive Officer

Date: March 15, 2018

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities with TransMontaigne GP L.L.C., the general partner of the registrant, on the date indicated.

Name and Signature	Title	Date

/s/ Frederick W. Boutin	Chief Executive Officer	March 15, 2018
Frederick W. Boutin	Chief Executive Officer	March 15, 2018

/s/ Robert T. Fuller	Executive Vice President, Chief Financial Officer and Treasurer	March 15, 2018
Robert T. Fuller		March 15, 2018

/s/ Lisa M. Kearney	Vice President, Chief Accounting Officer	March 15, 2018
Lisa M. Kearney	Vice President, Chief Accounting Officer	March 15, 2018

/s/ Steven A. Blank	Director	March 15, 2018
Steven A. Blank	Director	March 15, 2018

/s/ Theodore D. Burke	Director	March 15, 2018
Theodore D. Burke	Director	March 15, 2018

/s/ Kevin M. Crosby	Director	March 15, 2018
Kevin M. Crosby	Director	March 15, 2018

/s/ Daniel R. Revers	Director	March 15, 2018
Daniel R. Revers	Director	March 15, 2018

/s/ Lucius H. Taylor	Director	March 15, 2018
Lucius H. Taylor	Director	March 15, 2018

/s/ Barry E. Welch	Director	March 15, 2018
Barry E. Welch	Director	March 15, 2018

/s/ Jay A. Wiese	Director	March 15, 2018
Jay A. Wiese	Director	March 15, 2018

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