10-K 1 tlp-20181231x10k.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, 2018

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 LLC

(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: NONE

 

 

Title of Each Class

Name of Each Exchange on Which Registered

 

 

 

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, 2018 was $480,962,668 computed by reference to the last sale price ($36.84 per common unit) of the registrant’s common units on the New York Stock Exchange on June 30, 2018.

As of February 27, 2019, the registrant has no common units outstanding.

* The registrant is a voluntary filer of reports required to be filed by certain companies under Section 13 or 15(d) of the Securities Exchange Act of 1934 and has filed all reports that would have been required to have been filed by the registrant during the preceding 12 months had it been subject to such filing requirements during the entirety of such period.

DOCUMENTS INCORPORATED BY REFERENCE

 


 

None.

 

 

 


 

TABLE OF CONTENTS

 

 

 

 

 

 

Item

    

    

    

Page No.

 

 

 

Part I

 

 

 

1 and 2. 

 

Business and Properties

 

 

1A. 

 

Risk Factors

 

23 

 

1B. 

 

Unresolved Staff Comments

 

34 

 

3. 

 

Legal Proceedings

 

34 

 

4. 

 

Mine Safety Disclosures

 

34 

 

 

 

Part II

 

 

 

5. 

 

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

 

35 

 

6. 

 

Selected Financial Data

 

35 

 

7. 

 

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

 

36 

 

7A. 

 

Quantitative and Qualitative Disclosures About Market Risks

 

51 

 

8. 

 

Financial Statements and Supplementary Data

 

52 

 

9. 

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

86 

 

9A. 

 

Controls and Procedures

 

86 

 

9B. 

 

Other Information

 

88 

 

 

 

Part III

 

 

 

10. 

 

Directors, Executive Officers and Corporate Governance

 

88 

 

11. 

 

Executive Compensation

 

90 

 

12. 

 

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

 

93 

 

13. 

 

Certain Relationships and Related Transactions, and Director Independence

 

93 

 

14. 

 

Principal Accounting Fees and Services

 

95 

 

 

 

Part IV

 

 

 

15. 

 

Exhibits, Financial Statement Schedules

 

96 

 

16. 

 

Form 10-K Summary

 

115 

 

 

 

3


 

 

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 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;

·

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.

 

4


 

Part I

As used in this Annual Report, unless the context requires otherwise, references to “we,” “us,” “our,” “TransMontaigne Partners,” "the Partnership,” or “the Company” are intended to mean, prior to the Take-Private Transaction (defined below), TransMontaigne Partners L.P., and following the Take-Private Transaction, TransMontaigne Partners LLC, and our wholly owned and controlled operating subsidiaries. References to ‘‘TransMontaigne GP’’ or ‘‘our general partner’’ are intended, prior to the Take-Private Transaction, to mean TransMontaigne GP L.L.C., our general partner prior to the Take-Private Transaction. 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

On February 26, 2019, an affiliate of ArcLight completed its previously announced acquisition of all of the Partnership’s outstanding publicly traded common units not already held by ArcLight and its affiliates by way of our merger (the “Merger”) with a wholly owned subsidiary of TLP Finance Holdings, LLC (“TLP Finance”), an indirect controlled subsidiary of Arclight. At the effective time of the Merger, each of the Partnership’s general partner units issued and outstanding immediately prior to the acquisition effective time was converted into (i)(a) one Partnership common unit, and (i)(b) in aggregate, a non-economic general partner interest in the Partnership, (ii) each of the Partnership’s incentive distribution rights issued and outstanding immediately prior to the acquisition effective time was converted into 100 Partnership common units, (iii) our general partner distributed its common units in the Partnership (the “Transferred GP Units”) to TLP Acquisition Holdings, LLC, a Delaware limited liability company (“TLP Holdings”), and TLP Holdings contributed the Transferred GP Units to TLP Finance, (iv) the Partnership converted into the Company (a Delaware limited liability company) pursuant to Section 17-219 of the Delaware Limited Partnership Act and changed its name to “TransMontaigne Partners LLC”, and all of our common units owned by TLP Finance were converted into limited liability company interests, (v) the non-economic interest in the Company owned by our general partner was automatically cancelled and ceased to exist and our general partner merged with and into the Company with the Company surviving, and (vi) the Company became 100% owned by TLP Finance (the transactions described in the foregoing clauses (i) through (iv), collectively with the Merger, the “Take-Private Transaction”).

As a result of the Take-Private Transaction, our common units ceased to be publicly traded, and our common units are no longer listed on the New York Stock Exchange (“NYSE”).  Our currently outstanding 6.125% senior unsecured notes due in 2026 remain outstanding, and the Company is voluntarily filing with the Securities and Exchange Commission pursuant to the covenants contained in those notes.

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.

5


 

Recent Developments

Take-Private Transaction. On February 26, 2019, we completed our Take-Private Transaction.

 

Expansion of our Brownsville operations.  The Frontera joint venture waived its right of first refusal to participate in our previously announced Brownsville terminal expansion. Accordingly, our Brownsville expansion project will be 100% constructed and owned by the Company. The project, which is underpinned by new long-term agreements, includes the construction of approximately 630,000 barrels of additional liquids storage capacity and the conversion of our Diamondback Pipeline to transport diesel and gasoline to the U.S./Mexico border. The Diamondback Pipeline is comprised of an 8” pipeline that previously transported propane approximately 16 miles from our Brownsville facilities to the U.S./Mexico border, as well as a 6” pipeline, which runs parallel to the 8” pipeline, that has been idle and can be used to transport additional refined products. We expect the first tanks of the additional liquids storage capacity under construction to be placed into commercial service during the first quarter of 2019. We expect to recommission the Diamondback Pipeline and resume operations on both the 8” pipeline and the previously idle 6” pipeline by the end of 2019, with the remaining additional liquids storage capacity being placed into commercial service at the same time. The anticipated aggregate cost of the terminal expansion and pipeline recommissioning is estimated to be approximately $55 million.

 

Expansion of our Collins terminal. Our Collins, 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 continue to implement the design and construction of approximately 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 our Collins terminal, we also 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 terminal 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. We expect the first of the new tanks to come online in the first quarter of 2019 and the Colonial Pipeline Company improvements to come online in the second quarter of 2019.

Expansion of our West Coast terminals. 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 consist of 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 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, we have begun the construction of an additional 125,000 barrels of storage capacity at our Richmond West Coast terminal. The cost of constructing this new capacity is expected to be approximately $8 million. We are also pursuing other high-return investment opportunities similar to this at these terminals. The first of the new tanks began to come online in the fourth quarter of 2018.

6


 

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, 2018 are as follows: 

 

 

 

 

 

    

Active storage

 

 

 

capacity

 

 

 

(shell bbls)

 

Our Terminals by Region:

 

 

 

Gulf Coast Terminals:

 

 

 

Port Everglades North (Fort Lauderdale), FL

 

2,487,000

 

Port Everglades South  (Fort Lauderdale), FL (1)

 

376,000

 

Jacksonville, FL

 

271,000

 

Cape Canaveral, FL

 

724,000

 

Port Manatee, FL

 

1,293,000

 

Pensacola, FL

 

270,000

 

Fisher Island (Miami), FL

 

673,000

 

Tampa, FL

 

760,000

 

Gulf Coast Total

 

6,854,000

 

Midwest Terminals:

 

 

 

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

 

420,000

 

Cushing, OK

 

1,005,000

 

Oklahoma City, OK

 

158,000

 

Midwest Total

 

1,583,000

 

Brownsville Terminal

 

840,000

 

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

 

 

7


 

 

 

 

 

 

    

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 (Collins, bulk storage)

 

5,410,000

 

Collins, MS (Collins Rack)

 

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

 

11,983,000

 

West Coast Terminals:

 

 

 

Martinez, CA

 

4,754,000

 

Richmond, CA

 

561,000

 

West Coast Total

 

5,315,000

 

Our Joint Ventures Terminals:

 

 

 

Frontera Joint Venture Terminal (2)

 

1,656,000

 

    BOSTCO Joint Venture Terminal (3)

 

7,080,000

 

TOTAL CAPACITY

 

37,995,000

 

 

(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 6.9 million barrels of aggregate active storage capacity in ports including Port Everglades, 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 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.

8


 

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 Razorback terminals have 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 in 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.

Brownsville, Texas Operations.  We own and operate a refined product terminal with approximately 0.8 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 south Texas and Mexico. 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.

The Diamondback pipeline consists of an 8” pipeline that previously transported propane 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.

In 2018 and prior thereto, we also operated and maintained the United States portion of a 174-mile 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. We operated and managed the 18-mile portion of the pipeline located in the United States for a fee that was based on the average daily volume handled during the month. Additionally, we were reimbursed for non-routine maintenance expenses based on the actual costs plus a fee based on a fixed percentage of the expense. Our services for this pipeline terminated on August 23, 2018, and a third party has taken 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, 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.

9


 

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 12.0 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 bulk storage terminal. The Collins terminal, currently going through expansion, 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 5.3 million barrels of aggregate active 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 vessels, pipeline and rail facilities on behalf of our customers and distribute products primarily via vessel, 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. An affiliate of PEMEX, Mexico’s state owned petroleum company, 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 1.7 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 deep water 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.

10


 

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.    Our terminaling services agreements are structured as either throughput agreements or storage agreements. 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 a stipulated period of time. Due to this minimum payment arrangement, we recognize a fixed amount of revenue from the customer over a certain period of time, even if the customer throughputs less than the minimum volume of product during that period. In addition, if a customer throughputs a volume of product exceeding the 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 recognized revenue. We refer to the fixed amount of revenue recognized pursuant to our terminaling services agreements as being “firm commitments.” Revenue recognized in excess of firm commitments and revenue recognized based solely on the volume of product distributed or injected are referred to as “ancillary.” In addition, “ancillary” revenue also includes fees received from ancillary services including heating and mixing of stored products, product transfer, railcar handling, butane blending, proceeds from the sale of product gains, wharfage and vapor recovery.

 

·

Pipeline transportation fees. We earn pipeline transportation fees at our Diamondback pipeline either based on the volume of product transported or under capacity reservation agreements. Revenue associated with the capacity reservation is recognized ratably over the respective term, regardless of whether the capacity is actually utilized. 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.

·

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 the Frontera joint venture and receive a management fee based on our costs incurred. 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. We lease land under operating leases and thereafter receive a fee as the lessor or sublessor from third parties and, in certain cases, our affiliates. We also managed and operated for an affiliate of PEMEX, Mexico’s state-owned petroleum company, a products pipeline connected to our Brownsville terminal facility and received a management fee through August 23, 2018. 

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,

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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.

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 at our Collins terminal, we continue to implement 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 expansion.  870,000 barrels entered into service in the first quarter of 2019.  To facilitate our further expansion of tankage at Collins, we also 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. 

 

In addition our Brownsville terminal expansion project, which is underpinned by new long-term agreements, includes the construction of approximately 630,000 barrels of additional liquids storage capacity and the conversion of our Diamondback Pipeline to transport diesel and gasoline to the U.S./Mexico border. The Diamondback Pipeline is comprised of an 8” pipeline that previously transported propane approximately 16 miles from our Brownsville facilities to the U.S./Mexico border, as well as a 6” pipeline, which runs parallel to the 8” pipeline, that has been idle and can be used to transport additional refined products. We expect the first tanks of the additional liquids storage capacity under construction to be placed into commercial service during the first quarter of 2019. We expect to recommission the Diamondback Pipeline and resume operations on both the 8” pipeline and the previously idle 6” pipeline by the end of 2019, with the remaining additional liquids storage capacity being placed into commercial service at the same time. The anticipated aggregate cost of the terminal expansion and pipeline recommissioning is estimated to be approximately $55 million.

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, an affiliate of which, following the Take-Private Transaction is our sole equity-holder, 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.

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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.

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, 2018,  75% of our revenue was generated from firmly committed fee-based contracts pursuant to our terminaling service fees and the remaining 25% of our revenue was generated from ratable revenue sources.

Our Relationship with ArcLight and its Affiliates

Following the Take-Private Transaction, which closed on February 26, 2019, we are wholly owned by TLP Finance, an indirect controlled 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 sole equity-holder 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 initially 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 consisted of 100% of our general partner interest and incentive distribution rights and approximately 19.2% of our common units prior to the Take-Private Transaction.

 

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 levels of 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

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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 derive revenue from our terminal and pipeline transportation operations by charging fees for providing integrated terminaling, transportation and related services. We have several significant customer relationships that made up 86% of the total revenue for the year ended December 31, 2018. These relationships include: NGL Energy Partners LP, Castleton Commodities International LLC, RaceTrac Petroleum Inc., Glencore Ltd., Musket Corporation, BP, Associated Asphalt, 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, Shell 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.

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,

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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.

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

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stations and meter‑measurement points on the pipeline are linked by high speed communication systems for remote monitoring and control. In addition, our Collins, Mississippi facility contains full back‑up/redundant disaster recovery systems covering all of our SCADA systems.

Safety and Maintenance

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

We monitor the structural integrity of all of our Department of Transportation, or DOT, regulated pipeline systems. These pipeline systems include the 67‑mile Razorback pipeline; a 37‑mile pipeline, known as the “Pinebelt pipeline,” located in Covington County, Mississippi that transports refined petroleum liquids between our Collins and 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, until August 23, 2018, an approximately 18‑mile, refined petroleum liquids pipeline in Texas, known as the “MB pipeline,” that we operated and maintained on behalf of PMI Services North America, Inc., an affiliate of PEMEX,  which a third party has since taken operatorship. 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.

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

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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 mitigating 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. PHMSA is expected to issue revised regulations in 2019 applicable to oil and liquids pipelines, which are expected to impose, among other things, enhanced inspection requirements. While we cannot predict the final form of these regulations at this time, we do not anticipate the regulations to impact our operations materially differently from other similarly situated operators.

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

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

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

Environmental Matters

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

·

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

·

requiring capital expenditures to comply with environmental control requirements; and

·

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

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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, 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.

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, 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.

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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 Very Small Quantity Generators. Our terminals do not generate hazardous waste except in isolated and infrequent cases. At such times, only third party disposal sites which have been audited and approved by us are used. Our operations also generate solid wastes that are regulated under state law or the less stringent solid waste requirements of RCRA. We believe that we are in substantial compliance with the existing requirements of RCRA and similar state and local laws, and the cost involved in complying with these requirements is not material.

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

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In connection with our acquisition of the Florida and Midwest terminals on May 27, 2005, a subsidiary of NGL Energy Partners LP 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. The 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. There are 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, a subsidiary of NGL Energy Partners LP 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 the 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, a subsidiary of NGL Energy Partners LP 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 the 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, a subsidiary of NGL Energy Partners LP 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 the 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 a subsidiary of NGL Energy Partners LP to us remain in place and were not affected by the Take-Private Transaction.  

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

Operational Hazards and Insurance

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

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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.  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.  The current rates charged by each of our Razorback and Diamondback pipelines are negotiated rates that were established via agreement with non-affiliated shippers, and are not established via an index methodology or via a cost-of-service methodology.

 

Index-Rate Methodology. On October 20, 2016, the FERC issued an Advanced Notice of Proposed Rulemaking (ANOPR) to consider modifications to its current policies for evaluating 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 pipelines that utilize index rate changes: (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 on pipelines that utilize index rate changes, or whether the proposal will be modified or even adopted all.

 

Cost‑of‑service methodology.  Formerly, FERC policy permitted interstate pipelines, including those owned by master limited partnerships (MLPs), to 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 of ownership. 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 MLP 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 MLPs under FERC’s current ratemaking policy. Initial comments were due March 8, 2017, and reply comments were due April 7, 2017. On March 15, 2018, FERC issued a Revised Policy Statement on Treatment of Income Taxes in which FERC found that an impermissible double recovery results from granting an MLP pipeline both an income tax allowance and an ROE pursuant to FERC’s discounted cash flow methodology. FERC revised its previous policy, stating that it would no longer permit an MLP pipeline to recover an income tax allowance in its cost of service. FERC stated it will address the application of the United Airlines, Inc. v. FERC decision to non-MLP partnership forms as those issues arise in subsequent proceedings. FERC will also apply the revised Policy Statement and the Tax Cuts and Jobs Act of 2017 to initial pipeline cost-of-service rates and cost-of-service rate changes on a going-forward basis under FERC’s existing ratemaking policies, including cost-of-service rate proceedings resulting from shipper-initiated complaints. On July 18, 2018, FERC dismissed requests for rehearing and clarification of the March 15, 2018 Revised Policy Statement, but provided further guidance, clarifying that a pass-through entity will not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double recovery of investors’ income tax costs. On February 21, 2019, FERC issued its first order (Trailblazer Pipeline Company LLC) addressing how its Revised Policy Statement on Treatment of Income Taxes applies to a pipeline

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organized as a pass-through entity that is not an MLP in a Natural Gas Act section 4 rate case proceeding.  In Trailblazer, FERC issued preliminary findings that United Airlines likely precludes an income tax allowance for owners of a pipeline that are taxed as individuals, while it may permit an income tax allowance for those owners taxed as corporations.  Although FERC’s findings are preliminary and subject to former proceedings before an administrative law judge, its Trailblazer order suggests that FERC may extend its Revised Policy Statement on Treatment of Income Taxes to other types of pass-through entities that were not addressed in United Airlines

 

Negotiated rates.  The current rates charged by  each of the Razorback and Diamondback pipelines are negotiated rates that were established via agreement with non-affiliated shippers, and are not index rates or

cost-of-service rates. Therefore, while we continue to monitor FERC’s policy changes, we do not expect such changes to have an adverse impact on the rates charged by the Razorback and Diamondback pipelines.

 

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 and require us to modify the amounts charged. 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.

 

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. We have obtained 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, we believe 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.

We believe 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, we  believe that none of these burdens should

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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 employees and our officers are employees of an ArcLight affiliate. Pursuant to our omnibus agreement with ArcLight, all of our officers and the employees who provide services to the Company are employed by TLP Management Services, a controlled subsidiary of ArcLight. TLP Management Services provides payroll and maintains all employee benefits programs on behalf of the Company.

As of March 8, 2019, approximately 563 employees of TLP Management Services provided services directly to us. As of March 8, 2019, none of TLP Management Services employees who provide services directly to us were covered by a collective bargaining agreement.

Available Information

We file annual, quarterly, and current reports, and other documents with the SEC under the Securities Exchange Act of 1934. The SEC maintains an Internet website that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The public can obtain any documents that we file at http://www.sec.gov.

In addition, our annual reports on Form 10-K, as well as our quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to all of the foregoing reports, are made available free of charge on or through the “Investor” section of our website at www.transmontaignepartners.com as soon as reasonably practicable after such reports are electronically filed with or furnished to the SEC.

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. If any of the following risks actually occurs, our business, financial condition, results of operations or cash flows could be materially adversely affected, which could result in investors in our securities losing all or part of their investment.

Risks Inherent in Our Business

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

We expect to derive a substantial majority of our revenue from a small number of significant customers for the foreseeable future.  For example, in 2018 NGL Energy Partners LP accounted for approximately 22% 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.

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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.

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, 2018, our outstanding borrowings were $306 million. At December 31, 2018, 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.

Moreover, our long term business strategies include acquiring additional energy‑related terminaling and transportation facilities and further expansion of our existing terminal capacity. We will need to raise additional funds to grow our business and implement these strategies. We anticipate that such additional funds would be raised through equity or debt financings. Any equity or debt financing, if available at all, may not be on terms that are favorable to us. Limitations on our access to capital 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, decreases in the availability of credit or the tightening of terms required by lenders. 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, 2018, we had total long-term debt of $598.6 million and we had an unused borrowing base availability of $544 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 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; 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 or delaying our business activities, acquisitions, investments or capital expenditures, selling

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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;

·

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.

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 security-holders 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, 2018, we had additional borrowing capacity of $544 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;

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·

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

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

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

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

·

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

·

the perception that another company may provide better service; and

·

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

In addition, our 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.

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

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;

·

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

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·

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

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

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 obtaining 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 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.

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;

·

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

·

acts of terrorism or vandalism.

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

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, 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.

29


 

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.

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, including as a result of attempts to seek ransom from the Company. 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.

We could also face attempts to obtain unauthorized access to our information technology systems, proprietary business information, and information about our customers by targeting acts of deception against individuals with legitimate access to physical locations or information. We regularly remind our officers and the employees providing services to the Company of these risks, and we annually update our executive team as to current and evolving risks relating to a variety of cyber-attacks; however, these efforts are not guaranteed to prevent the effectiveness of these cyber-attacks or any losses that may arise as a result thereof.

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 stricter 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

30


 

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 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 cash flows.

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 cash flows.

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.

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.

Our revolving credit facility matures in March 2022, and our senior notes mature in February 2026. At December 31, 2018, we had outstanding borrowings under our revolving credit facility of $306 million and outstanding senior notes of $300 million, 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.

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 the United States on an annual basis. 

 

31


 

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 the conduct of our business and the management of 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.

ArcLight is our controlling equity-holder and is responsible under our omnibus agreement for providing the personnel who provide support to our operations.

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 ArcLight ceases to directly or indirectly control the Company.

ArcLight is our controlling equity-holder. Therefore, conflicts of interest may arise between ArcLight and its affiliates and subsidiaries, on the one hand, and us, on the other hand. In resolving those conflicts of interest, ArcLight may favor its own interests and the interests of its affiliates over the interests of the Company.

32


 

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

·

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

·

Neither our operating agreement nor any other agreement requires ArcLight or its affiliates to pursue a business strategy that favors us. This entitles ArcLight 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 other security-holder. 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 operating agreement does not restrict ArcLight 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;

·

ArcLight 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,” ArcLight may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

·

Our officers are officers of affiliates of Arclight, and we are managed by TLP Finance Holdings, LLC, our direct parent and a controlled subsidiary of ArcLight, and also devote significant time to the business of these entities and are compensated accordingly;

·

ArcLight has limited its liability and reduced its fiduciary duties, and also has restricted the remedies available to any party for actions that, without the limitations, might constitute breaches of fiduciary duty. ArcLight will not have any liability to us for decisions made in its capacity as our controlling equity-holder so long as it acted in good faith, meaning it believed that its decision was in the best interests of our company;

·

ArcLight determines the amount and timing of acquisitions and dispositions, capital expenditures, borrowings, issuance of additional securities, and reserves, each of which can affect our cash flows;

·

ArcLight determines the amount and timing of any capital expenditures by our company 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, which can affect our cash flows;

·

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

·

ArcLight and its officers and directors will not be liable for monetary damages to us, our security-holders 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 ArcLight or those other persons acted in bad faith or engaged in fraud or willful misconduct; or

·

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

 

Upon the 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 company has no officers or employees and all of our management and operational activities are provided by officers and employees of TLP Management Services, a controlled 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.

33


 

We cannot predict whether ArcLight will seek to terminate, amend or modify the terms of the omnibus agreement. Following any termination of the omnibus agreement, the Company will be required to assume directly or indirectly through one or more service providers, the scope of the services provided to the Company 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.

ArcLight and its affiliates may compete with us and do not have any obligation to present business opportunities to us.

Neither our operating agreement nor any other agreement will prohibit ArcLight or its affiliates 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 a 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 its affiliates 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 ArcLight and its affiliates could materially adversely impact our results of operations and distributable cash flow.

Fees due to ArcLight and its affiliates for services provided under the omnibus agreement are and will continue to be substantial and will reduce our cash flow.

Payments to ArcLight are and will continue to be substantial and will reduce the amount of cash flows. For the year ended December 31, 2018, we paid affiliates of ArcLight an administrative fee of approximately $10.3 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. ArcLight 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. ArcLight will determine the amount of these expenses.  ArcLight and its affiliates also may provide us other services for which we will be charged fees as determined by ArcLight.

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.

34


 

Part II

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

MARKET FOR COMMON UNITS

As a result of the Take-Private Transaction, the Partnership’s common units ceased to be publicly traded, and the Partnership’s common units are no longer listed on the NYSE.

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, 2018, 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,

 

 

2018 (1)

 

2017 (1)

 

2016

 

2015

 

2014

 

 

(dollars in thousands except per unit amounts)

 

Operations Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenue

$

228,093

    

$

183,272

    

$

164,924

    

$

152,510

    

$

150,062

 

Direct operating costs and expenses

 

(82,028)

 

 

(67,700)

 

 

(68,415)

 

 

(64,033)

 

 

(66,183)

 

General and administrative expenses

 

(21,615)

 

 

(19,433)

 

 

(14,100)

 

 

(14,749)

 

 

(13,941)

 

Insurance expenses

 

(4,976)

 

 

(4,064)

 

 

(4,081)

 

 

(3,756)

 

 

(3,711)

 

Equity-based compensation expense

 

(3,478)

 

 

(2,999)

 

 

(3,263)

 

 

(1,411)

 

 

(2,221)

 

Depreciation and amortization

 

(49,535)

 

 

(35,960)

 

 

(32,383)

 

 

(30,650)

 

 

(29,522)

 

Loss on disposition of assets

 

(901)

 

 

             —

 

 

             —

 

 

              —

 

 

            —

 

Earnings from unconsolidated affiliates

 

8,852

 

 

7,071

 

 

10,029

 

 

11,948

 

 

4,443

 

Operating income

 

74,412

 

 

60,187

 

 

52,711

 

 

49,859

 

 

38,927

 

Other expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

(31,900)

 

 

(10,473)

 

 

(7,787)

 

 

(7,396)

 

 

(5,489)

 

Amortization of deferred financing costs

 

(3,037)

 

 

(1,221)

 

 

(818)

 

 

(774)

 

 

(975)

 

Net earnings

 

39,475

 

 

48,493

 

 

44,106

 

 

41,689

 

 

32,463

 

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

 

(15,675)

 

 

(12,705)

 

 

(9,340)

 

 

(7,506)

 

 

(7,167)

 

Net earnings allocable to limited partners

$

23,800

 

$

35,788

 

$

34,766

 

$

34,183

 

$

25,296

 

Net earnings per limited partner unit—basic

$

1.46

 

$

2.20

 

$

2.14

 

$

2.12

 

$

1.57

 

Net earnings per limited partner unit—diluted

$

1.45

 

$

2.20

 

$

2.14

 

$

2.12

 

$

1.57

 

Other Financial Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

$

118,583

 

$

103,704

 

$

79,107

 

$

87,480

 

$

60,929

 

Net cash used in investing activities

$

(56,660)

 

$

(337,070)

 

$

(69,089)

 

$

(34,153)

 

$

(50,702)

 

Net cash provided by (used in) financing activities

$

(62,514)

 

$

233,696

 

$

(10,106)

 

$

(55,950)

 

$

(10,186)

 

Cash distributions declared per common unit attributable to the period

$

3.190

 

$

2.990

 

$

2.780

 

$

2.665

 

$

2.655

 

Balance Sheet Data (at period end):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property, plant and equipment, net

$

688,179

 

$

655,053

 

$

416,748

 

$

388,423

 

$

385,301

 

Investments in unconsolidated affiliates

$

227,031

 

$

233,181

 

$

241,093

 

$

246,700

 

$

249,676

 

Total assets

$

999,376

 

$

987,003

 

$

689,694

 

$

656,687

 

$

664,057

 

Long-term debt

$

598,622

 

$

593,200

 

$

291,800

 

$

248,000

 

$

252,000

 

Equity

$

339,727

 

$

364,217

 

$

372,734

 

$

383,971

 

$

391,465

 


35


 

(1)

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. Following the consummation of our Take-Private Transaction, we are wholly owned by TLP Finance Holdings, LLC, an indirect controlled subsidiary of ArcLight, and we have converted into a Delaware limited liability company pursuant to Section 17-219 of the Delaware Limited Partnership Act. Prior to the consummation of our Take-Private Transaction, we were controlled by our general partner, which was controlled by ArcLight.

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. 

NATURE OF ASSETS 

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 6.9 million barrels of aggregate active storage capacity in ports including Port Everglades, 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.

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 razorback terminals have approximately

36


 

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 in 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.

Brownsville, Texas Operations.  We own and operate a refined product terminal with approximately 0.8 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 south Texas and Mexico. 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.

The Diamondback pipeline consists of an 8” pipeline that previously transported propane approximately 16 miles from our Brownsville facilities to the United States/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 fourth quarter of 2017; however, we expect to recommission the Diamondback pipeline and resume operations by the end of 2019.

In 2018 and prior thereto, we also operated and maintained the United States portion of a 174-mile 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. Our services for this pipeline terminated on August 23, 2018, and a third party has taken 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, customers engaged in the distribution and marketing of refined products and industrial and commercial end-users.

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 12.0 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 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 5.3 million barrels of aggregate active 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. We acquired the West Coast terminals in December 2017.

37


 

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. An affiliate of PEMEX, Mexico’s state owned petroleum company, 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 1.7 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. BOSTCO has approximately 7.1 million barrels of aggregate active storage capacity. 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.

NATURE OF REVENUE AND EXPENSES

We derive revenue from our terminal and pipeline transportation operations by charging fees for providing integrated terminaling, transportation and related services. We have several significant customer relationships that made up 85% of the total revenue for the year ended December 31, 2018. These relationships include: NGL Energy Partners LP, Castleton Commodities International LLC, RaceTrac Petroleum Inc., Glencore Ltd., Tesoro, Musket Corporation, BP, Associated Asphalt, 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, Shell and Andeavor.

The fees we charge, our other sources of revenue and our direct costs and expenses are described below.

Terminaling services fees.    Our terminaling services agreements are structured as either throughput agreements or storage agreements. 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 a stipulated period of time. Due to this minimum payment arrangement, we recognize a fixed amount of revenue from the customer over a certain period of time, even if the customer throughputs less than the minimum volume of product during that period. In addition, if a customer throughputs a volume of product exceeding the 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 recognized revenue. We refer to the fixed amount of revenue recognized pursuant to our terminaling services agreements as being “firm commitments.” Revenue recognized in excess of firm commitments and revenue recognized based solely on the volume of product distributed or injected are referred to as “ancillary.” In addition, “ancillary” revenue also includes fees received from ancillary services including heating and mixing of stored products, product transfer, railcar handling, butane blending, proceeds from the sale of product gains, wharfage and vapor recovery.

Pipeline transportation fees. We earn pipeline transportation fees at our Diamondback pipeline either based on the volume of product transported or under capacity reservation agreements. Revenue associated with the capacity reservation is recognized ratably over the respective term, regardless of whether the capacity is actually utilized. 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.

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 the Frontera joint venture and receive a management fee based on our costs

38


 

incurred. 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 We lease land under operating leases and thereafter receive a fee as the lessor or sublessor from third parties and, in certain cases, our affiliates. We also managed and operated for an affiliate of PEMEX, Mexico’s state-owned petroleum company, a products pipeline connected to our Brownsville terminal facility and received a management fee through August 23, 2018. 

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. General and administrative expenses include direct general and administrative expenses for costs and expenses of employees performing engineering, health, safety and environmental services, third party accounting costs associated with annual and quarterly reports and tax return and Schedule K‑1 preparation and distribution, legal fees and independent director fees. General and administrative expenses also include fees paid to ArcLight under the omnibus agreement to cover the costs of centralized corporate functions such as legal, accounting, treasury, insurance administration and claims processing, information technology, human resources, credit, payroll, taxes and other corporate services.

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.

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

TAKE-PRIVATE TRANSACTION 

On February 26, 2019, an affiliate of ArcLight completed its previously announced acquisition of all of the Partnership’s outstanding publicly traded common units not already held by ArcLight and its affiliates by way of our merger (the “Merger”) with a wholly owned subsidiary of TLP Finance Holdings, LLC (“TLP Finance”), an indirect controlled subsidiary of Arclight. At the effective time of the Merger, each of the Partnership’s general partner units issued and outstanding immediately prior to the acquisition effective time was converted into (i)(a) one Partnership common unit, and (i)(b) in aggregate, a non-economic general partner interest in the Partnership, (ii) each of the Partnership’s incentive distribution rights issued and outstanding immediately prior to the acquisition effective time was converted into 100 Partnership common units, (iii) our general partner distributed its common units in the Partnership (the “Transferred GP Units”) to TLP Acquisition Holdings, LLC, a Delaware limited liability company (“TLP Holdings”), and TLP Holdings contributed the Transferred GP Units to TLP Finance, (iv) the Partnership converted into the Company (a Delaware limited liability company) pursuant to Section 17-219 of the Delaware Limited Partnership Act and changed its name to “TransMontaigne Partners LLC”, and all of our common units owned by TLP Finance were converted into limited liability company interests, (v) the non-economic interest in the Company owned by our general partner was automatically cancelled and ceased to exist and our general partner merged with and into the Company with the Company surviving, and (vi) the Company became 100% owned by TLP Finance (the transactions described in the foregoing clauses (i) through (iv), collectively with the Merger, the “Take-Private Transaction”).

As a result of the Take-Private Transaction, our common units ceased to be publicly traded, and our common units are no longer listed on the New York Stock Exchange (“NYSE”). Our currently outstanding 6.125% senior unsecured notes due in 2026 remain outstanding, and the Company is voluntarily filing with the Securities and Exchange Commission pursuant to the covenants contained in those notes.

EXPANSION OF ASSETS

 

Expansion of our Brownsville operations.  The Frontera joint venture has waived its right of first refusal to participate in our previously announced Brownsville terminal expansion. Accordingly, our Brownsville expansion project will be 100% constructed and owned by the Company. The project, which is underpinned by new long-term agreements, includes the construction of approximately 630,000 barrels of additional liquids storage capacity and the conversion of our Diamondback Pipeline to transport diesel and gasoline to the U.S./Mexico border. The Diamondback

39


 

Pipeline is comprised of an 8” pipeline that previously transported propane approximately 16 miles from our Brownsville facilities to the U.S./Mexico border, as well as a 6” pipeline, which runs parallel to the 8” pipeline, that has been idle and can be used to transport additional refined products. We expect the first tanks of the additional liquids storage capacity under construction to be placed into commercial service during the first quarter of 2019. We expect to recommission the Diamondback Pipeline and resume operations on both the 8” pipeline and the previously idle 6” pipeline by the end of 2019, with the remaining additional liquids storage capacity being placed into commercial service at the same time. The anticipated aggregate cost of the terminal expansion and pipeline recommissioning is estimated to be approximately $55 million.

 

Expansion of our Collins terminal. Our Collins, 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 continue to implement the design and construction of approximately 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 our Collins terminal, we also 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 terminal 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. We expect the first of the new tanks to come online in the first quarter of 2019 and the Colonial Pipeline Company improvements to come online in the second quarter of 2019.

Expansion of our West Coast terminals. 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 consist of 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 5.3 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, we have begun the construction of an additional 125,000 barrels of storage capacity at our Richmond West Coast terminal. The cost of constructing this new capacity is expected to be approximately $8 million. We are also pursuing other high-return investment opportunities similar to this at these terminals. The first of the new tanks began to come online in the fourth quarter of 2018.

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, accrued environmental obligations and business combination estimates and assumptions. 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

40


 

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, 2018, we have an accrued liability of approximately $1.6 million representing our best estimate of the undiscounted future payments we expect to pay for environmental costs to remediate existing conditions. Estimates of our environmental obligations are subject to change due to a number of factors and judgments involved in the estimation process, including the early stage of investigation at certain sites, the lengthy time frames required to complete remediation, technology changes affecting remediation methods, alternative remediation methods and strategies and changes in environmental laws and regulations. Changes in our estimates and assumptions may occur as a result of the passage of time and the occurrence of future events.

Costs incurred to remediate existing contamination at the terminals have been, and are expected in the future to be, insignificant. Pursuant to agreements, an affiliate of NGL Energy Partners LP retained certain 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, 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 indemnifications to us remain in place and were not affected by the Take-Private Transaction.  

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 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.

41


 

RESULTS OF OPERATIONS—YEARS ENDED DECEMBER 31, 2018, 2017 AND 2016

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,

 

 

    

2018

    

2017

    

2016

 

Terminaling services fees

 

$

216,231

 

$

168,083

 

$

144,568

 

Pipeline transportation fees

 

 

3,295

 

 

5,719

 

 

6,789

 

Management fees and reimbursed costs

 

 

8,567

 

 

9,470

 

 

9,035

 

Other

 

 

 —

 

 

 —

 

 

4,532

 

Revenue

 

$

228,093

 

$

183,272

 

$

164,924

 

 

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):

 

 

 

 

 

 

 

 

 

 

 

    

 

 

 

 

 

 

 

 

 

 

Total Revenue by Business Segment

 

 

Year ended

 

Year ended

 

Year ended

 

 

December 31,

 

December 31,

 

December 31,

 

    

2018

    

2017

    

2016

Gulf Coast terminals

 

$

64,622

 

$

62,941

 

$

56,710

Midwest terminals and pipeline system

 

 

11,899

 

 

10,997

 

 

11,201

Brownsville terminals

 

 

17,246

 

 

20,645

 

 

25,485

River terminals

 

 

10,654

 

 

10,947

 

 

12,578

Southeast terminals

 

 

83,712

 

 

76,004

 

 

58,950

West Coast terminals

 

 

39,960

 

 

1,738

 

 

 —

Revenue

 

$

228,093

 

$

183,272

 

$

164,924

 

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

Terminaling services fees.    Our terminaling services agreements are structured as either throughput agreements or storage agreements. 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 a stipulated period of time. Due to this minimum payment arrangement, we recognize a fixed amount of revenue from the customer over a certain period of time, even if the customer throughputs less than the minimum volume of product during that period. In addition, if a customer throughputs a volume of product exceeding the 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 recognized revenue.

 

We refer to the fixed amount of revenue recognized pursuant to our terminaling services agreements as being “firm commitments.” Revenue recognized in excess of firm commitments and revenue recognized based solely on the volume of product distributed or injected are referred to as “ancillary.” In addition “ancillary” revenue also includes fees

42


 

received from ancillary services including heating and mixing of stored products, product transfer, railcar handling, butane blending, proceeds from the sale of product gains, wharfage and vapor recovery.

 

 

 

 

 

 

 

 

 

 

 

 

Terminaling Services Fees

 

 

by Business Segment

 

 

Year ended

 

Year ended

 

Year ended

 

 

December 31,

 

December 31,

 

December 31,

 

    

2018

    

2017

    

2016

Gulf Coast terminals

 

$

64,338

 

$

61,889

 

$

54,619

Midwest terminals and pipeline system

 

 

10,127

 

 

9,265

 

 

9,469

Brownsville terminals

 

 

8,339

 

 

9,186

 

 

11,202

River terminals

 

 

10,654

 

 

10,883

 

 

10,868

Southeast terminals

 

 

82,821

 

 

75,122

 

 

58,410

West Coast terminals

 

 

39,952

 

 

1,738

 

 

 —

Terminaling services fees

 

$

216,231

 

$

168,083

 

$

144,568

The increase in terminaling services fees at our Gulf Coast terminals for the year ended December 31, 2018 results from an increase in ancillary revenue. 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, 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 Southeast terminals for the year ended December 31, 2018 includes an increase of approximately $3.0 million resulting from placing into service approximately 2.0 million barrels of new tank capacity at our Collins terminal in various stages beginning in the fourth quarter of 2016 through the second quarter of 2017, and an increase in ancillary revenue.

The increase in terminaling services fees at our West Coast terminals for the year ended December 31, 2018 is a result of the West Coast terminals acquisition on December 15, 2017.

 Included in terminaling services fees for the years ended December 31, 2018, 2017 and 2016 are fees charged to affiliates of approximately $11.0 million, $1.9 million and $3.4 million, respectively.

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,

 

 

 

2018

 

2017

 

2016

 

Firm commitments

 

$

171,774

 

$

135,197

 

$

116,341

 

Ancillary

 

 

44,457

 

 

32,886

 

 

28,227

 

Terminaling services fees

 

$

216,231

 

$

168,083

 

$

144,568

 

 

The remaining terms on the terminaling services agreements that generated “firm commitments” for the year ended December 31, 2018 were as follows (in thousands): 

 

 

 

 

 

 

Less than 1 year remaining

    

$

36,454

    

21%

1 year or more, but less than 3 years remaining

 

 

56,237

 

33%

3 years or more, but less than 5 years remaining

 

 

43,408

 

25%

5 years or more remaining (1)

 

 

35,675

 

21%

Total firm commitments for the year ended December 31, 2018

 

$

171,774

 

 

_____________________________

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(1) We have a terminaling services agreement with a third party relating to our Southeast terminals that will continue in effect through February 1, 2023, after which it shall automatically continue unless and until the third party provides at least 24 months’ prior notice of its intent to terminate the agreement. Effective at any time from and after July 31, 2040, we have the right to terminate the agreement by providing at least 24 months’ prior notice of our intent to terminate the agreement. We do not believe the third party will terminate the agreement prior to July 31, 2040; therefore we have presented the firm commitments related to this terminaling services agreement in the 5 years or more remaining category in the table above.

Pipeline transportation fees.    We earned pipeline transportation fees at our Diamondback pipeline either based on the volume of product transported or under capacity reservation agreements. Revenue associated with the capacity reservation is recognized ratably over the respective term, regardless of whether the capacity is actually utilized. 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 through December 31, 2017. 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,

 

 

    

 

2018

    

2017

    

2016

 

Gulf Coast terminals

 

 

$

 —

 

$

            —

 

$

 —

 

Midwest terminals and pipeline system

 

 

 

1,772

 

 

1,732

 

 

1,732

 

Brownsville terminals

 

 

 

1,523

 

 

3,987

 

 

5,057

 

River terminals

 

 

 

 —

 

 

            —

 

 

 —

 

Southeast terminals

 

 

 

 —

 

 

            —

 

 

 —

 

West Coast terminals

 

 

 

 —

 

 

            —

 

 

 —

 

Pipeline transportation fees

 

 

$

3,295

 

$

5,719

 

$

6,789

 

The decrease in pipeline transportation fees at our Brownsville terminals for the year ended December 31, 2018   is attributable to suspending operations on the Ella-Brownsville and Diamondback pipelines at the end of 2017 in connection with the expansion of our Brownville operations. The Diamondback Pipeline consists of an 8” pipeline that previously transported propane 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 has been idle and can be used to transport additional refined products. We expect to recommission and resume operations on both the 8” pipeline and the previously idle 6” pipeline by the end of 2019.

Included in pipeline transportation fees for each of the years ended December 31, 2018, 2017 and 2016 are fees charged to affiliates of approximately $nil.

44


 

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 the Frontera joint venture and receive a management fee based on our costs incurred. 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. We lease land under operating leases and thereafter receive a fee as the lessor or sublessor from third parties and, in certain cases, our affiliates. We also managed and operated for an affiliate of PEMEX, Mexico’s state-owned petroleum company, a products pipeline connected to our Brownsville terminal facility and received a management fee through August 23, 2018. 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,

 

    

    

2018

 

2017

 

2016

Gulf Coast terminals

 

 

$

284

 

$

1,052

 

$

1,159

Midwest terminals and pipeline system

 

 

 

 —

 

 

 —

 

 

                 —

Brownsville terminals

 

 

 

7,384

 

 

7,472

 

 

7,326

River terminals

 

 

 

 —

 

 

64

 

 

10

Southeast terminals

 

 

 

891

 

 

882

 

 

540

West Coast terminals

 

 

 

 8

 

 

 —

 

 

 —

Management fees and reimbursed costs

 

 

$

8,567

 

$

9,470

 

$

9,035

 

Included in management fees and reimbursed costs for the years ended December 31, 2018, 2017 and 2016 are fees charged to affiliates of approximately $5.8 million, $5.3 million and $5.0 million, respectively.

Other revenue.  Other revenue includes payments to us for settlement of litigation and reimbursements for property damage caused by customers. 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,

 

 

 

 

2018

 

2017

 

2016

 

Gulf Coast terminals

    

 

$

 —

 

$

 —

 

$

932

 

Midwest terminals and pipeline system

 

 

 

 —

 

 

 —

 

 

 —

 

Brownsville terminals

 

 

 

 —

 

 

 —

 

 

1,900

 

River terminals

 

 

 

 —

 

 

 —

 

 

1,700

 

Southeast terminals

 

 

 

 —

 

 

 —

 

 

 —

 

West Coast terminals

 

 

 

 —

 

 

 —

 

 

 —

 

Other revenue

 

 

$

 —