Edgar Filing: TransMontaigne Partners L.P.

tlp_Current folio_10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10‑Q


(Mark One)
☒	Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended September 30, 2015
OR
☐	Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Commission File Number: 001‑32505

TRANSMONTAIGNE PARTNERS L.P.

(Exact name of registrant as specified in its charter)


Delaware (State or other jurisdiction of incorporation or organization)	34‑2037221 (I.R.S. Employer Identification No.)

1670 Broadway

Suite 3100

Denver, Colorado 80202

(Address, including zip code, of principal executive offices)

(303) 626‑8200

(Telephone number, including area code)

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 whether the registrant is a large accelerated filer, an accelerated filer, a non‑accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b‑2 of the Exchange Act.


Large accelerated filer ☐	Accelerated filer ☒	Non‑accelerated filer ☐ (Do not check if a smaller reporting company)	Smaller reporting company ☐

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

As of October 31, 2015, there were 16,124,566 units of the registrant’s Common Limited Partner Units outstanding.

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TABLE OF CONTENTS

		Page No.
Part I. Financial Information
Item 1.	Unaudited Consolidated Financial Statements	3
	Consolidated balance sheets as of September 30, 2015 and December 31, 2014	4
	Consolidated statements of operations for the three and nine months ended September 30, 2015 and 2014	5
	Consolidated statements of partners’ equity for the year ended December 31, 2014 and nine months ended September 30, 2015	6
	Consolidated statements of cash flows for the three and nine months ended September 30, 2015 and 2014	7
	Notes to consolidated financial statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	45
Item 4.	Controls and Procedures	46
Part II. Other Information
Item 1.	Legal Proceedings	46
Item 1A.	Risk Factors	46
Item 6.	Exhibits	49

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CAUTIONARY STATEMENT REGARDING FORWARD‑LOOKING STATEMENTS

This Quarterly Report contains forward‑looking statements, including the following:

certain statements, including possible or assumed future results of operations, in “Management’s Discussion and Analysis of Financial Condition and Results of Operations;”

any statements contained herein regarding the prospects for our business or any of our services;

any statements preceded by, followed by or that include the words “may,” “seeks,” “believes,” “expects,” “anticipates,” “intends,” “continues,” “estimates,” “plans,” “targets,” “predicts,” “attempts,” “is scheduled,” or similar expressions; and

other statements contained herein regarding matters that are not historical facts.

Our business and results of operations are subject to risks and uncertainties, many of which are beyond our ability to control or predict. Because of these risks and uncertainties, actual results may differ materially from those expressed or implied by forward‑looking statements, and investors are cautioned not to place undue reliance on such statements, which speak only as of the date thereof. Important factors that could cause actual results to differ materially from our expectations and may adversely affect our business and results of operations, include, but are not limited to those risk factors set forth in this report in Part II. Other Information under the heading “Item 1A. Risk Factors.”

Part I. Financial Information

ITEM 1. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

The interim unaudited consolidated financial statements of TransMontaigne Partners L.P. as of and for the three and nine months ended September 30, 2015 are included herein beginning on the following page. The accompanying unaudited interim consolidated financial statements should be read in conjunction with our consolidated financial statements and related notes for the year ended December 31, 2014, together with our discussion and analysis of financial condition and results of operations, included in our Annual Report on Form 10‑K, filed on March 12, 2015 with the Securities and Exchange Commission (File No. 001‑32505).

TransMontaigne Partners L.P. is a holding company with the following 100% owned operating subsidiaries during the three and nine months ended September 30, 2015:

TransMontaigne Operating GP L.L.C.

TransMontaigne Operating Company L.P.

TransMontaigne Terminals L.L.C.

Razorback L.L.C. (d/b/a Diamondback Pipeline L.L.C.)

TPSI Terminals L.L.C.

TLP Finance Corp.

TLP Operating Finance Corp.

TPME L.L.C.

We do not have off‑balance‑sheet arrangements (other than operating leases) or special‑purpose entities.

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TransMontaigne Partners L.P. and subsidiaries

Consolidated balance sheets (unaudited)

(Dollars in thousands)


	September 30,		December 31,
	2015		2014
ASSETS
Current assets:
Cash and cash equivalents	$	791	$	3,304
Trade accounts receivable, net		8,166		9,359
Due from affiliates		907		1,316
Other current assets		2,109		3,065
Total current assets		11,973		17,044
Property, plant and equipment, net		387,056		385,301
Goodwill		8,485		8,485
Investments in unconsolidated affiliates		248,204		249,676
Other assets, net		3,446		3,551
	$	659,164	$	664,057
LIABILITIES AND EQUITY
Current liabilities:
Trade accounts payable	$	6,760	$	6,887
Due to affiliates		220		—
Accrued liabilities		14,364		9,835
Total current liabilities		21,344		16,722
Other liabilities		3,441		3,870
Long-term debt		249,600		252,000
Total liabilities		274,385		272,592
Commitments and contingencies (Note 16)
Partners’ equity:
Common unitholders (16,124,566 units issued and outstanding at September 30, 2015 and December 31, 2014)		327,090		333,619
General partner interest (2% interest with 329,073 equivalent units outstanding at September 30, 2015 and December 31, 2014)		57,689		57,846
Total partners’ equity		384,779		391,465
	$	659,164	$	664,057

See accompanying notes to consolidated financial statements.

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TransMontaigne Partners L.P. and subsidiaries

Consolidated statements of operations (unaudited)

(In thousands, except per unit amounts)


	Three months ended				Nine months ended
	September 30,				September 30,
	2015		2014		2015		2014
Revenue:
External customers	$	27,143	$	22,130	$	79,196	$	51,227
Affiliates		10,126		13,573		33,004		61,888
Total revenue		37,269		35,703		112,200		113,115
Operating costs and expenses and other:
Direct operating costs and expenses		(16,655)		(16,514)		(47,481)		(48,302)
Direct general and administrative expenses		(1,117)		(1,086)		(2,810)		(2,466)
Allocated general and administrative expenses		(2,835)		(2,782)		(8,440)		(8,346)
Allocated insurance expense		(944)		(942)		(2,812)		(2,769)
Reimbursement of bonus awards expense		(121)		(375)		(1,185)		(1,125)
Depreciation and amortization		(7,711)		(7,400)		(22,524)		(22,196)
Earnings from unconsolidated affiliates		2,191		1,653		9,764		3,091
Total operating costs and expenses and other		(27,192)		(27,446)		(75,488)		(82,113)
Operating income		10,077		8,257		36,712		31,002
Other expenses:
Interest expense		(2,198)		(1,493)		(6,083)		(3,672)
Amortization of deferred financing costs		(167)		(244)		(607)		(732)
Total other expenses		(2,365)		(1,737)		(6,690)		(4,404)
Net earnings		7,712		6,520		30,022		26,598
Less—earnings allocable to general partner interest including incentive distribution rights		(1,803)		(1,779)		(5,546)		(5,400)
Net earnings allocable to limited partners	$	5,909	$	4,741	$	24,476	$	21,198
Net earnings per limited partner unit—basic	$	0.37	$	0.29	$	1.52	$	1.31
Net earnings per limited partner unit—diluted	$	0.37	$	0.29	$	1.52	$	1.31

See accompanying notes to consolidated financial statements.

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TransMontaigne Partners L.P. and subsidiaries

Consolidated statements of partners’ equity (unaudited)

Year ended December 31, 2014 and nine months ended September 30, 2015

(Dollars in thousands)



			General
	Common		partner
	units		interest		Total
Balance December 31, 2013	$	350,505	$	57,962	$	408,467
Distributions to unitholders		(42,561)		(7,283)		(49,844)
Equity-based compensation		721		—		721
Purchase of 8,004 common units by our long-term incentive plan		(342)		—		(342)
Issuance of 20,500 common units due to vesting of restricted phantom units		—		—		—
Net earnings for year ended December 31, 2014		25,296		7,167		32,463
Balance December 31, 2014		333,619		57,846		391,465
Distributions to unitholders		(32,168)		(5,703)		(37,871)
Equity-based compensation		1,255		—		1,255
Purchase of 2,668 common units by our long-term incentive plan		(92)		—		(92)
Net earnings for nine months ended September 30, 2015		24,476		5,546		30,022
Balance September 30, 2015	$	327,090	$	57,689	$	384,779

See accompanying notes to consolidated financial statements.

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TransMontaigne Partners L.P. and subsidiaries

Consolidated statements of cash flows (unaudited)

(In thousands)


	Three months ended				Nine months ended
	September 30,				September 30,
	2015		2014		2015		2014
Cash flows from operating activities:
Net earnings	$	7,712	$	6,520	$	30,022	$	26,598
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation and amortization		7,711		7,400		22,524		22,196
Earnings from unconsolidated affiliates		(2,191)		(1,653)		(9,764)		(3,091)
Distributions from unconsolidated affiliates		7,510		3,259		15,462		5,697
Equity-based compensation		145		584		1,255		698
Amortization of deferred financing costs		167		244		607		732
Amortization of deferred revenue		(437)		(510)		(1,004)		(1,921)
Unrealized loss on derivative instruments		461		—		551		—
Changes in operating assets and liabilities, net of effects from acquisitions and dispositions:
Trade accounts receivable, net		1,881		(3,614)		1,193		(5,733)
Due from affiliates		(55)		2,438		409		1,246
Other current assets		270		273		956		502
Amounts due under long-term terminaling services agreements, net		388		306		727		919
Trade accounts payable		2,274		(1,302)		283		(1,507)
Due to affiliates		105		52		220		52
Accrued liabilities		2,833		978		4,529		(4,423)
Net cash provided by operating activities		28,774		14,975		67,970		41,965
Cash flows from investing activities:
Investments in unconsolidated affiliates		(4,226)		(20,283)		(4,226)		(43,680)
Capital expenditures		(8,784)		(726)		(24,538)		(3,338)
Net cash used in investing activities		(13,010)		(21,009)		(28,764)		(47,018)
Cash flows from financing activities:
Borrowings of debt under credit facility		26,000		56,000		64,000		112,000
Repayments of debt under credit facility		(33,400)		(38,000)		(66,400)		(72,000)
Deferred debt issuance costs		5		—		(1,356)		—
Distributions paid to unitholders		(12,624)		(12,621)		(37,871)		(37,219)
Purchase of common units by our long-term incentive plan		—		(88)		(92)		(265)
Net cash provided by (used in) financing activities		(20,019)		5,291		(41,719)		2,516
Decrease in cash and cash equivalents		(4,255)		(743)		(2,513)		(2,537)
Cash and cash equivalents at beginning of period		5,046		1,469		3,304		3,263
Cash and cash equivalents at end of period	$	791	$	726	$	791	$	726
Supplemental disclosures of cash flow information:
Cash paid for interest	$	1,760	$	1,473	$	5,285	$	3,658
Property, plant and equipment acquired with accounts payable	$	1,415	$	518	$	1,415	$	518

See accompanying notes to consolidated financial statements.

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TransMontaigne Partners L.P. and subsidiaries

Notes to consolidated financial statements (unaudited)

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a) Nature of business

TransMontaigne Partners L.P. (“Partners,” “we,” “us” or “our”) was formed in February 2005 as a Delaware limited partnership initially to own and operate refined petroleum products terminaling and transportation facilities. We conduct our operations in the United States along the Gulf Coast, in the Midwest, in Houston and Brownsville, Texas, along the Mississippi and Ohio rivers, and in the Southeast. We provide integrated terminaling, storage, transportation and related services for companies engaged in the trading, distribution and marketing of light refined petroleum products, heavy refined petroleum products, crude oil, chemicals, fertilizers and other liquid products.

We are controlled by our general partner, TransMontaigne GP L.L.C. (“TransMontaigne GP”), which is an indirect wholly‑owned subsidiary of TransMontaigne LLC. At September 30, 2015, NGL Energy Partners LP (“NGL”) owned all of the issued and outstanding capital stock of TransMontaigne LLC, and as a result NGL is the indirect owner of our general partner. At September 30, 2015, TransMontaigne LLC and NGL had a significant interest in our partnership through their indirect ownership of an approximate 19% limited partner interest, a 2% general partner interest and the incentive distribution rights.

Prior to July 1, 2014, Morgan Stanley Capital Group Inc. (“Morgan Stanley Capital Group”), a wholly‑owned subsidiary of Morgan Stanley and the principal commodities trading arm of Morgan Stanley, owned all of the issued and outstanding capital stock of TransMontaigne LLC, and, as a result, Morgan Stanley was the indirect owner of our general partner. Effective July 1, 2014, Morgan Stanley consummated the sale of its 100% ownership interest in TransMontaigne LLC to NGL.

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

(b) Basis of presentation and use of estimates

Our accounting and financial reporting policies conform to accounting principles and practices generally accepted in the United States of America. The accompanying consolidated financial statements include the accounts of TransMontaigne Partners L.P., a Delaware limited partnership, and its controlled subsidiaries. Investments where we do not have the ability to exercise control, but do have the ability to exercise significant influence, are accounted for using the equity method of accounting. All inter‑company accounts and transactions have been eliminated in the preparation of the accompanying consolidated financial statements. The accompanying consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly our financial position as of September 30, 2015 and December 31, 2014 and our results of operations for the three and nine months ended September 30, 2015 and 2014.

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

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

Pursuant to terminaling services agreements with certain of our throughput customers, we are entitled to the volume of product gained resulting from differences in the measurement of product volumes received and distributed at our terminaling facilities. Consistent with recognized industry practices, measurement differentials occur as the result of the inherent variances in measurement devices and methodology. We recognize as revenue the net proceeds from the sale of the product gained. For the three months ended September 30, 2015 and 2014, we recognized revenue of approximately $1.9 million and $3.1 million, respectively, for net product gained. Within these amounts, approximately $0.5 million and $1.2 million for the three months ended September 30, 2015 and 2014, respectively, were pursuant to terminaling services agreements with affiliate customers. For the nine months ended September 30, 2015 and 2014, we recognized revenue of approximately $5.9 million and $10.8 million, respectively, for net product gained. Within these amounts, approximately $2.1 million and $6.1 million for the nine months ended September 30, 2015 and 2014, respectively, were pursuant to terminaling services agreements with affiliate customers.

(d) Cash and cash equivalents

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

(e) Property, plant and equipment

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

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

(f) Investments in unconsolidated affiliates

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

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(g) Environmental obligations

We accrue for environmental costs that relate to existing conditions caused by past operations when probable and reasonably estimable (see Note 10 of Notes to consolidated financial statements). Environmental costs include initial site surveys and environmental studies of potentially contaminated sites, costs for remediation and restoration of sites determined to be contaminated and ongoing monitoring costs, as well as fines, damages and other costs, including direct legal costs. Liabilities for environmental costs at a specific site are initially recorded, on an undiscounted basis, when it is probable that we will be liable for such costs, and a reasonable estimate of the associated costs can be made based on available information. Such an estimate includes our share of the liability for each specific site and the sharing of the amounts related to each site that will not be paid by other potentially responsible parties, based on enacted laws and adopted regulations and policies. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods. Estimates of our ultimate liabilities associated with environmental costs are difficult to make with certainty due to the number of variables involved, including the early stage of investigation at certain sites, the lengthy time frames required to complete remediation, technology changes, alternatives available and the evolving nature of environmental laws and regulations. We periodically file claims for insurance recoveries of certain environmental remediation costs with our insurance carriers under our comprehensive liability policies (see Note 5 of Notes to consolidated financial statements). We recognize our insurance recoveries as a credit to income in the period that we assess the likelihood of recovery as being probable (i.e., likely to occur).

TransMontaigne LLC agreed to indemnify us against certain potential environmental claims, losses and expenses that were identified on or before May 27, 2010 and that were associated with the ownership or operation of the Florida and Midwest terminal facilities prior to May 27, 2005, up to a maximum liability not to exceed $15.0 million for this indemnification obligation. TransMontaigne LLC agreed to indemnify us against certain potential environmental claims, losses and expenses that were identified on or before December 31, 2011 and that were associated with the ownership or operation of the Brownsville and River facilities prior to December 31, 2006, up to a maximum liability not to exceed $15.0 million for this indemnification obligation. TransMontaigne LLC agreed to indemnify us against certain potential environmental claims, losses and expenses that were identified on or before December 31, 2012 and that were associated with the ownership or operation of the Southeast terminals prior to December 31, 2007, up to a maximum liability not to exceed $15.0 million for this indemnification obligation. TransMontaigne LLC has agreed to indemnify us against certain potential environmental claims, losses and expenses that are identified on or before March 1, 2016 and that were associated with the ownership or operation of the Pensacola terminal prior to March 1, 2011, up to a maximum liability not to exceed $2.5 million for this indemnification obligation.

(h) Asset retirement obligations

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

(i) Equity based compensation

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

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(j) Accounting for derivative instruments

Generally accepted accounting principles require us to recognize all derivative instruments at fair value in the consolidated balance sheets as assets or liabilities (see Note 11 of Notes to consolidated financial statements). Changes in the fair value of our derivative instruments are recognized in earnings.

We did not have any derivative instruments at December 31, 2014. At September 30, 2015, our derivative instruments were limited to interest rate swap agreements with an aggregate notional amount of $75.0 million that expire March 25, 2018. Pursuant to the terms of the interest rate swap agreements, we pay a blended fixed rate of approximately 1.05% and receive interest payments based on the one-month LIBOR. The net difference to be paid or received under the interest rate swap agreements is settled monthly and is recognized as an adjustment to interest expense. The fair value of our interest rate swap agreements are determined using a pricing model based on the LIBOR swap rate and other observable market data.

(k) Income taxes

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

Partners is a taxable entity under certain U.S. state jurisdictions, primarily Texas. Partners accounts for U.S. state income taxes under the asset and liability method pursuant to generally accepted accounting principles. U.S. state income taxes are not material.

(l) Net earnings per limited partner unit

Net earnings allocable to the limited partners, for purposes of calculating net earnings per limited partner unit, are net of the earnings allocable to the general partner interest and distributions payable to any restricted phantom units granted under our equity based compensation plans that participate in Partners’ distributions (see Note 15 of Notes to consolidated financial statements). The earnings allocable to the general partner interest include the distributions of available cash (as defined by our partnership agreement) attributable to the period to the general partner interest, net of adjustments for the general partner’s share of undistributed earnings, and the incentive distribution rights. Undistributed earnings are the difference between the earnings and the distributions attributable to the period. Undistributed earnings are allocated to the limited partners and general partner interest based on their respective sharing of earnings or losses specified in the partnership agreement, which is based on their ownership percentages of 98% and 2%, respectively. The incentive distribution rights are not allocated a portion of the undistributed earnings given they are not entitled to distributions other than from available cash. Further, the incentive distribution rights do not share in losses under our partnership agreement. Basic net earnings per limited partner unit is computed by dividing net earnings allocable to limited partners by the weighted average number of limited partner units outstanding during the period. Diluted net earnings per limited partner unit is computed by dividing net earnings allocable to the limited partners by the weighted average number of limited partner units outstanding during the period and any potential dilutive securities outstanding during the period.

(m) Recent accounting pronouncements

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The objective of this update is to clarify the principles for recognizing revenue and to develop a common revenue standard. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. We are currently evaluating the potential impact that the adoption will have on our disclosures and financial statements.

(2) TRANSACTIONS WITH AFFILIATES

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

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Under the omnibus agreement we pay TransMontaigne LLC an administrative fee for the provision of various general and administrative services for our benefit. For the three months ended September 30, 2015 and 2014, the administrative fee paid to TransMontaigne LLC was approximately $2.8 million and $2.8 million, respectively. For the nine months ended September 30, 2015 and 2014, the administrative fee paid to TransMontaigne LLC was approximately $8.4 million and $8.3 million, respectively. If we acquire or construct additional facilities, TransMontaigne LLC will propose a revised administrative fee covering the provision of services for such additional facilities. If the conflicts committee of our general partner agrees to the revised administrative fee, TransMontaigne LLC will provide services for the additional facilities pursuant to the agreement. The administrative fee encompasses the reimbursement of services to perform centralized corporate functions, such as legal, accounting, treasury, insurance administration and claims processing, health, safety and environmental, information technology, human resources, credit, payroll, taxes and engineering and other corporate services, to the extent such services are not outsourced by TransMontaigne LLC.

The omnibus agreement further provides that we pay TransMontaigne LLC an insurance reimbursement for premiums on insurance policies covering our facilities and operations. For the three months ended September 30, 2015 and 2014, the insurance reimbursement paid to TransMontaigne LLC was approximately $0.9 million and $0.9 million, respectively. For the nine months ended September 30, 2015 and 2014, the insurance reimbursement paid to TransMontaigne LLC was approximately $2.8 million and $2.8 million, respectively. We also reimburse TransMontaigne LLC for direct operating costs and expenses, such as salaries of operational personnel performing services on‑site at our terminals and pipelines and the cost of their employee benefits, including 401(k) and health insurance benefits.

Under the omnibus agreement we have agreed to reimburse TransMontaigne LLC for a portion of the incentive bonus awards made to key employees under the TransMontaigne Services LLC savings and retention plan, provided the compensation committee of our general partner determines that an adequate portion of the incentive bonus awards are indexed to the performance of our common units in the form of restricted phantom units. The value of our incentive bonus award reimbursement for a single grant year may be no less than $1.5 million. Effective April 13, 2015 and beginning with the 2015 incentive bonus award, we have the option to provide the reimbursement in either a cash payment to TransMontaigne LLC or the delivery of our common units to TransMontaigne LLC or to the award recipients, with the reimbursement made in accordance with the underlying vesting and payment schedule of the TransMontaigne Services LLC savings and retention plan. Prior to the 2015 incentive bonus award, we reimbursed our portion of the incentive bonus awards by making cash payments to TransMontaigne LLC over the first year that each applicable award was granted. For the three months ended September 30, 2015 and 2014, the expense associated with the reimbursement of incentive bonus awards was approximately $0.1 million and $0.4 million, respectively. For the nine months ended September 30, 2015 and 2014, the expense associated with the reimbursement of incentive bonus awards was approximately $1.2 million and $1.1 million, respectively.

The omnibus agreement also provides TransMontaigne LLC a right of first refusal to purchase our assets, subject to certain exceptions discussed below and provided that TransMontaigne LLC agrees to pay no less than 105% of the purchase price offered by the third party bidder. Before we enter into any contract to sell such terminal or pipeline facilities, we must give written notice of all material terms of such proposed sale to TransMontaigne LLC. TransMontaigne LLC will then have the sole and exclusive option, for a period of 45 days following receipt of the notice. Subject to certain exceptions discussed below, TransMontaigne LLC also has a right of first refusal to contract for the use of any petroleum product storage capacity that (i) is put into commercial service after January 1, 2008, or (ii) was subject to a terminaling services agreement that expires or is terminated (excluding a contract renewable solely at the option of our customer), provided that TransMontaigne LLC agrees to pay no less than 105% of the fees offered by the third party customer. The above rights of first refusal do not apply to any storage capacity or terminaling assets for which TransMontaigne LLC, or an affiliate of TransMontaigne LLC, has, subsequent to July 2013, elected to terminate (or not renew upon expiration) its existing terminaling services agreement relating thereto.

Environmental indemnification. In connection with our acquisition of the Florida and Midwest terminals, TransMontaigne LLC agreed to indemnify us against certain potential environmental claims, losses and expenses that were identified on or before May 27, 2010, and that were associated with the ownership or operation of the Florida and Midwest terminals prior to May 27, 2005. TransMontaigne LLC’s maximum liability for this indemnification obligation is $15.0 million. TransMontaigne LLC has no obligation to indemnify us for losses until such aggregate losses exceed

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$250,000. TransMontaigne LLC has no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after May 27, 2005.

In connection with our acquisition of the Brownsville, Texas and River terminals, TransMontaigne LLC agreed to indemnify us against potential environmental claims, losses and expenses that were identified on or before December 31, 2011, and that were associated with the ownership or operation of the Brownsville and River facilities prior to December 31, 2006. TransMontaigne LLC’s maximum liability for this indemnification obligation is $15.0 million. TransMontaigne LLC has no obligation to indemnify us for losses until such aggregate losses exceed $250,000. The deductible amount, cap amount and limitation of time for indemnification do not apply to any environmental liabilities known to exist as of December 31, 2006. TransMontaigne LLC has no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after December 31, 2006.

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

In connection with our acquisition of the Pensacola terminal, TransMontaigne LLC has agreed to indemnify us against potential environmental claims, losses and expenses that are identified on or before March 1, 2016, and that are associated with the ownership or operation of the Pensacola terminal prior to March 1, 2011. Our environmental losses must first exceed $200,000 and TransMontaigne LLC’s indemnification obligations are capped at $2.5 million. The deductible amount, cap amount and limitation of time for indemnification do not apply to any environmental liabilities known to exist as of March 1, 2011. TransMontaigne LLC has no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after March 1, 2011.

Terminaling services agreement—Florida and Midwest terminals. In connection with the NGL Acquisition, effective July 1, 2014, Morgan Stanley Capital Group assigned to NGL its obligations under our terminaling services agreement for light oil terminaling capacity at our Florida terminals. Effective September 16, 2014, we amended our long-term terminaling services agreement with RaceTrac Petroleum Inc. to include the use of gasoline, ethanol and diesel tankage at our Cape Canaveral, Port Manatee and Port Everglades South terminals. Simultaneous with the entry into the RaceTrac Petroleum Inc. agreement, we amended the Florida and Midwest terminaling services agreement to immediately terminate NGL’s obligations at our Cape Canaveral and Port Everglades South terminals, and to terminate NGL’s obligation at our Port Manatee terminal effective March 14, 2015. The tankage at Cape Canaveral and Port Everglades South became available to RaceTrac Petroleum Inc. on September 16, 2014. The tankage at Port Manatee became available to RaceTrac Petroleum Inc. in July of 2015, upon the completion of certain enhancements at this facility.

On October 31, 2014, NGL provided us the required 18 months’ prior notice that it will terminate its remaining obligations under the Florida and Midwest terminaling services agreement effective April 30, 2016, which constitutes NGL’s light oil terminaling capacity for approximately 1.1 million barrels at our Port Everglades North, Florida terminal. NGL has agreed to allow us to re-contract some of this tankage prior to its effective contract termination date. Accordingly, we have re-contracted approximately 0.9 million barrels of this capacity to third party customers at similar rates charged to NGL.

Effective May 31, 2014, the Florida tanks dedicated to bunker fuels were no longer subject to the Florida and Midwest terminaling services agreement. A large portion of this capacity has been re‑contracted to Glencore Ltd. effective June 1, 2014.

Under the Florida and Midwest terminaling services agreement, Morgan Stanley Capital Group had also contracted for our Mount Vernon, Missouri and Rogers, Arkansas terminals and the use of our Razorback Pipeline, which runs from Mount Vernon to Rogers. We refer to these terminals and the related pipeline as the Razorback system.

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This portion of the Florida and Midwest terminaling services agreement related to the Razorback system was terminated effective February 28, 2014. Effective March 1, 2014, we entered into a ten-year capacity agreement with Magellan Pipeline Company, L.P., covering 100% of the capacity of our Razorback system.

Under the Florida and Midwest terminaling services agreement, taking into consideration terminations, NGL is obligated to throughput a volume that, at the fee and tariff schedule contained in the agreement, will result in minimum throughput payments to us of approximately $5.0 million for the year ending December 31, 2015. The minimum annual throughput payment is reduced proportionately for any decrease in storage capacity due to out‑of‑service tank capacity or for capacity that has been vacated.

If a force majeure event occurs that renders us unable to perform our obligations with respect to an asset, the obligations would be temporarily suspended with respect to that asset. If a force majeure event continues for 30 consecutive days or more and results in a diminution in the storage capacity we make available, then the counterparty may terminate its obligations with respect to the asset affected by the force majeure event and their minimum revenue commitment would be reduced proportionately for the duration of the agreement.

Terminaling services agreement—Cushing terminal. In July 2011, we entered into a terminaling services agreement with Morgan Stanley Capital Group relating to our Cushing, Oklahoma facility that will expire in July 2019, subject to a five-year automatic renewal unless terminated by either party upon 180 days’ prior notice. In exchange for its minimum revenue commitment, we agreed to construct storage tanks and associated infrastructure to provide approximately 1.0 million barrels of crude oil capacity. These capital projects were completed and placed into service on August 1, 2012. Under this agreement, Morgan Stanley Capital Group agreed to throughput a volume of crude oil at our terminal that will, at the fee schedule contained in the agreement, result in minimum throughput payments to us of approximately $4.3 million for each one‑year period following the in‑service date of August 1, 2012. Subsequent to the NGL Acquisition, effective July 1, 2014, revenue associated with the Cushing tankage is recorded as revenue from external customers as opposed to revenue from affiliates.

If a force majeure event occurs that renders us unable to perform our obligations with respect to an asset, the obligations would be temporarily suspended with respect to that asset. If a force majeure event continues for 120 consecutive days or more and results in a diminution in the storage capacity we make available, the counterparty may terminate its obligations with respect to the asset affected by the force majeure event and their minimum revenue commitment would be reduced proportionately for the duration of the agreement.

Terminaling services agreement—Southeast terminals. In connection with the NGL Acquisition, effective July 1, 2014, Morgan Stanley Capital Group assigned to NGL its obligations under our terminaling services agreement relating to our Southeast terminals, excluding the Collins/Purvis tankage. The terminaling services agreement provisions pertaining to the Collins/Purvis tankage remained with Morgan Stanley Capital Group, and subsequent to the NGL Acquisition the revenue associated with the Collins/Purvis tankage is recorded as revenue from external customers as opposed to revenue from affiliates. The Southeast terminaling services agreement, excluding the Collins/Purvis tankage, will continue in effect unless and until NGL provides us at least 24 months’ prior notice of its intent to terminate the agreement. We have the right to terminate the terminaling services agreement effective at any time after July 31, 2023 by providing at least 24 months’ prior notice to NGL.

Under this agreement, NGL is obligated to throughput a volume of refined product at our Southeast terminals that will, at the fee schedule contained in the agreement, result in minimum throughput payments to us of approximately $27.0 million for the year ending December 31, 2015; with stipulated annual increases in throughput payments through July 31, 2015, and for each contract year thereafter the throughput payments will adjust based on increases in the United States Consumer Price Index. The minimum annual throughput payment is reduced proportionately for any decrease in storage capacity due to out‑of‑service tank capacity.

If a force majeure event occurs that renders us unable to perform our obligations with respect to an asset, the obligations would be temporarily suspended with respect to that asset. If a force majeure event continues for 30 consecutive days or more and results in a diminution in the storage capacity we make available, the counterparty may terminate its obligations with respect to the asset affected by the force majeure event and their minimum revenue commitment would be reduced proportionately for the duration of the agreement.

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Terminaling services agreement—Collins/Purvis additional light oil tankage. In January 2010, we entered into a terminaling services agreement with Morgan Stanley Capital Group for additional light oil tankage relating to our Collins/Purvis, Mississippi facility that will expire in July 2018, after which the terminaling services agreement will continue in effect unless and until Morgan Stanley Capital Group provides us at least 24 months’ prior notice of its intent to terminate the agreement. In exchange for its minimum revenue commitment, we agreed to undertake certain capital projects to provide approximately 700,000 barrels of additional light oil capacity and other improvements at the Collins/Purvis terminal. These capital projects were completed and placed into service in July 2011. Under this agreement, Morgan Stanley Capital Group has agreed to throughput a volume of light oil products at our terminal that will, at the fee schedule contained in the agreement, result in minimum throughput payments to us of approximately $4.1 million for the one-year period following the in‑service date of July 2011 for the aforementioned capital projects, and for each contract year thereafter, subject to increases based on increases in the United States Consumer Price Index beginning July 1, 2018. Subsequent to the NGL Acquisition, effective July 1, 2014, revenue associated with the Collins/Purvis additional light oil tankage is recorded as revenue from external customers as opposed to revenue from affiliates.

If a force majeure event occurs that renders us unable to perform our obligations with respect to an asset, the obligations would be temporarily suspended with respect to that asset. If a force majeure event continues for 30 consecutive days or more and results in a diminution in the storage capacity we make available, the counterparty may terminate its obligations with respect to the asset affected by the force majeure event and their minimum revenue commitment would be reduced proportionately for the duration of the agreement.

Barge dock services agreement—Baton Rouge dock. Effective May 2013, we entered into a barge dock services agreement with Morgan Stanley Capital Group relating to our Baton Rouge, LA dock facility that will expire in May 2023, subject to a five-year automatic renewal unless terminated by either party upon 180 days’ prior notice. Under this agreement, Morgan Stanley Capital Group agreed to throughput a volume of refined product at our Baton Rouge dock facility that will, at the fee schedule contained in the agreement, result in minimum throughput payments to us of approximately $1.2 million for each of the first three years ending May 12, 2016 and approximately $0.9 million for each of the remaining seven years ending May 12, 2023. In exchange for its minimum throughput commitment, we agreed to provide Morgan Stanley Capital Group with exclusive access to our dock facility. Effective September 1, 2014, Morgan Stanley Capital Group assigned its rights and obligations under the Baton Rouge barge dock services agreement to Colonial Pipeline Company. Subsequent to the NGL Acquisition, effective July 1, 2014, revenue associated with the Baton Rouge barge dock services agreement is recorded as revenue from external customers as opposed to revenue from affiliates.

If a force majeure event occurs that renders us unable to perform our obligations, the counterparty obligations would be temporarily suspended. If a force majeure event continues for 120 consecutive days, the counterparty may terminate its obligations under this agreement.

Operations and reimbursement agreement—Frontera. Effective as of April 1, 2011, we entered into the Frontera Brownsville LLC joint venture, or “Frontera”, in which we have a 50% ownership interest. In conjunction with us entering into the joint venture, we agreed to operate Frontera, in accordance with an operations and reimbursement agreement executed between us and Frontera, for a management fee that is based on our costs incurred. Our agreement with Frontera stipulates that we may resign as the operator at any time with the prior written consent of Frontera, or that we may be removed as the operator for good cause, which includes material noncompliance with laws and material failure to adhere to good industry practice regarding health, safety or environmental matters. For the three months ended September 30, 2015 and 2014, we recognized revenue of approximately $1.1 million and $1.2 million, respectively, related to this operations and reimbursement agreement. For the nine months ended September 30, 2015 and 2014, we recognized revenue of approximately $3.3 million and $3.0 million, respectively, related to this operations and reimbursement agreement.

(3) TERMINAL ACQUISITION

On December 20, 2012, we acquired a 42.5%, general voting, Class A Member (“ownership”) interest in BOSTCO, for approximately $79 million, from Kinder Morgan Battleground Oil, LLC, a wholly owned subsidiary of Kinder Morgan Energy Partners, L.P. (“Kinder Morgan”). BOSTCO is a new terminal facility on the Houston Ship Channel designed to handle residual fuel, feedstocks, other black oils and distillates. The initial phase of BOSTCO

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involved the construction of 51 storage tanks with approximately 6.2 million barrels of storage capacity. The BOSTCO facility began initial commercial operations in the fourth quarter of 2013. Completion of the full 6.2 million barrels of storage capacity and related infrastructure occurred in the second quarter of 2014.

On June 5, 2013, we announced an expansion of BOSTCO for an additional 900,000 barrels of distillate tankage. Work on the expansion started in the second quarter of 2013, and was placed into service at the end of the third quarter of 2014. With the addition of this expansion project, BOSTCO has capacity of approximately 7.1 million barrels at an overall construction cost of approximately $538 million. Our total payments for the initial and expansion projects are estimated to be approximately $237 million, which includes our proportionate share of the BOSTCO project costs and necessary start‑up working capital, a one‑time buy‑in fee paid to Kinder Morgan to acquire our 42.5% interest and the capitalization of interest on our investment during the construction of BOSTCO. We have funded our payments for BOSTCO utilizing borrowings under our credit facility.

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

(4) CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE

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

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


	September 30,		December 31,
	2015		2014
Trade accounts receivable	$	8,630	$	9,823
Less allowance for doubtful accounts		(464)		(464)
	$	8,166	$	9,359

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


	Three months ended				Nine months ended
	September 30,				September 30,
	2015		2014		2015		2014
NGL Energy Partners LP	24	%	35	%	26	%	11	%
Morgan Stanley Capital Group	13	%	13	%	13	%	45	%
RaceTrac Petroleum Inc.	13	%	6	%	11	%	6	%

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(5) OTHER CURRENT ASSETS

Other current assets are as follows (in thousands):


	September 30,		December 31,
	2015		2014
Amounts due from insurance companies	$	713	$	1,233
Additive detergent		1,250		1,591
Deposits and other assets		146		241
	$	2,109	$	3,065

Amounts due from insurance companies. We periodically file claims for recovery of environmental remediation costs with our insurance carriers under our comprehensive liability policies. We recognize our insurance recoveries in the period that we assess the likelihood of recovery as being probable (i.e., likely to occur). At September 30, 2015 and December 31, 2014, we have recognized amounts due from insurance companies of approximately $0.7 million and $1.2 million, respectively, representing our best estimate of our probable insurance recoveries. During the nine months ended September 30, 2015, we received reimbursements from insurance companies of approximately $0.4 million. During the nine months ended September 30, 2015, we decreased our estimate of probable future insurance recoveries by $0.1 million.

(6) PROPERTY, PLANT AND EQUIPMENT, NET

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


	September 30,		December 31,
	2015		2014
Land	$	53,076	$	52,519
Terminals, pipelines and equipment		590,613		566,677
Furniture, fixtures and equipment		2,436		2,122
Construction in progress		4,764		5,444
		650,889		626,762
Less accumulated depreciation		(263,833)		(241,461)
	$	387,056	$	385,301

(7) GOODWILL

Goodwill is as follows (in thousands):


	September 30,		December 31,
	2015		2014
Brownsville terminals	$	8,485	$	8,485

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

At September 30, 2015 and December 31, 2014, our only reporting unit that contained goodwill was our Brownsville terminals. We did not recognize any goodwill impairment charges during the nine months ended September

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30, 2015 or during the year ended December 31, 2014 for this reporting unit. However, a significant decline in the price of our common units with a resulting increase in the assumed market participants’ weighted average cost of capital, the loss of a significant customer, the disposition of significant assets, or an unforeseen increase in the costs to operate and maintain the Brownsville terminals, could result in the recognition of an impairment charge in the future.

(8) INVESTMENTS IN UNCONSOLIDATED AFFILIATES

At September 30, 2015 and December 31, 2014, our investments in unconsolidated affiliates include a 42.5% interest in BOSTCO and a 50% interest in Frontera. BOSTCO is a newly constructed terminal facility located on the Houston Ship Channel. BOSTCO began initial commercial operations in the fourth quarter of 2013; with completion of its approximately 7.1 million barrels of storage capacity and related infrastructure occurring at the end of the third quarter of 2014 (see Note 3 of Notes to consolidated financial statements). Frontera is a terminal facility located in Brownsville, Texas that encompasses approximately 1.5 million barrels of light petroleum product storage capacity, as well as related ancillary facilities.

The following table summarizes our investments in unconsolidated affiliates:


	Percentage of				Carrying value
	ownership				(in thousands)
	September 30,		December 31,		September 30,		December 31,
	2015		2014		2015		2014
BOSTCO	42.5	%	42.5	%	$	225,027	$	225,920
Frontera	50	%	50	%		23,177		23,756
Total investments in unconsolidated affiliates					$	248,204	$	249,676

At September 30, 2015 and December 31, 2014, our investment in BOSTCO includes approximately $7.5 million and $7.8 million, respectively, of excess investment related to a one time buy-in fee to acquire our 42.5% interest and capitalization of interest on our investment during the construction of BOSTCO. Excess investment is the amount by which our investment exceeds our proportionate share of the book value of the net assets of BOSTCO.

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


	Three months ended				Nine months ended
	September 30,				September 30,
	2015		2014		2015		2014
BOSTCO	$	1,670	$	1,368	$	8,244	$	2,617
Frontera		521		285		1,520		474
Total earnings from investments in unconsolidated affiliates	$	2,191	$	1,653	$	9,764	$	3,091

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


	Three months ended				Nine months ended
	September 30,				September 30,
	2015		2014		2015		2014
BOSTCO	$	4,226	$	20,283	$	4,226	$	43,635
Frontera		—		—		—		45
Additional capital investments in unconsolidated affiliates	$	4,226	$	20,283	$	4,226	$	43,680

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


	Three months ended				Nine months ended
	September 30,				September 30,
	2015		2014		2015		2014
BOSTCO	$	6,555	$	2,915	$	13,363	$	4,072
Frontera		955		344		2,099		1,625
Cash distributions received from unconsolidated affiliates	$	7,510	$	3,259	$	15,462	$	5,697

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

Balance sheets:


	BOSTCO				Frontera
	September 30,		December 31,		September 30,		December 31,
	2015		2014		2015		2014
Current assets	$	19,363	$	19,400	$	4,814	$	4,222
Long-term assets		503,276		511,373		43,626		44,528
Current liabilities		(11,522)		(17,435)		(2,086)		(1,238)
Long-term liabilities		—		—		—		—
Net assets	$	511,117	$	513,338	$	46,354	$	47,512

Statements of operations:


	BOSTCO				Frontera
	Three months ended				Three months ended
	September 30,				September 30,
	2015		2014		2015		2014
Revenue	$	15,273	$	14,708	$	4,227	$	3,474
Expenses		(11,081)		(11,119)		(3,185)		(2,904)
Net earnings	$	4,192	$	3,589	$	1,042	$	570


	BOSTCO				Frontera
	Nine months ended				Nine months ended
	September 30,				September 30,
	2015		2014		2015		2014
Revenue	$	54,127	$	35,451	$	12,118	$	9,934
Expenses		(33,705)		(28,812)		(9,078)		(8,986)
Net earnings	$	20,422	$	6,639	$	3,040	$	948

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(9) OTHER ASSETS, NET

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


	September 30,		December 31,
	2015		2014
Amounts due under long-term terminaling services agreements:
External customers	$	247	$	649
Affiliates		644		945
		891		1,594
Deferred financing costs, net of accumulated amortization of $3,779 and $3,278, respectively		1,887		1,138
Customer relationships, net of accumulated amortization of $1,839 and $1,687, respectively		591		743
Deposits and other assets		77		76
	$	3,446	$	3,551

Amounts due under long‑term terminaling services agreements. We have long‑term terminaling services agreements with certain of our customers that provide for minimum payments that increase over the terms of the respective agreements. We recognize as revenue the minimum payments under the long‑term terminaling services agreements on a straight‑line basis over the term of the respective agreements. At September 30, 2015 and December 31, 2014, we have recognized revenue in excess of the minimum payments that are due through those respective dates under the long‑term terminaling services agreements resulting in an asset of approximately $0.9 million and $1.6 million, respectively.

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

Customer relationships. Other assets, net include certain customer relationships at our River terminals. These customer relationships are being amortized on a straight‑line basis over twelve years.

(10) ACCRUED LIABILITIES

Accrued liabilities are as follows (in thousands):


	September 30,		December 31,
	2015		2014
Customer advances and deposits:
External customers	$	4,726	$	2,756
Affiliates		2,584		—
		7,310		2,756
Accrued property taxes		3,636		892
Accrued environmental obligations		975		1,524
Interest payable		131		159
Rebate due to affiliate		—		1,795
Accrued expenses and other		2,312		2,709
	$	14,364	$	9,835

Customer advances and deposits. We bill certain of our customers one month in advance for terminaling services to be provided in the following month. At September 30, 2015 and December 31, 2014, we have billed and collected from certain of our customers approximately $7.3 million and $2.8 million, respectively, in advance of the terminaling services being provided.

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Accrued environmental obligations. At September 30, 2015 and December 31, 2014, we have accrued environmental obligations of approximately $1.0 million and $1.5 million, respectively, representing our best estimate of our remediation obligations. During the nine months ended September 30, 2015, we made payments of approximately $0.4 million towards our environmental remediation obligations. During the nine months ended September 30, 2015, we decreased our estimate of our future environmental remediation costs by $0.1 million. Changes in our estimates of our future environmental remediation obligations may occur as a result of the passage of time and the occurrence of future events.

Rebate due to affiliate. Pursuant to our terminaling services agreement related to the Southeast terminals, we agreed to rebate to our affiliate customer 50% of the proceeds we receive annually in excess of $4.2 million from the sale of product gains at our Southeast terminals. At September 30, 2015 and December 31, 2014, we have accrued a liability due to affiliate of approximately $nil and $1.8 million, respectively. In January of 2015 we paid approximately $1.8 million to our affiliate customer for the rebate due for the year ended December 31, 2014.

(11) OTHER LIABILITIES

Other liabilities are as follows (in thousands):


	September 30,		December 31,
	2015		2014
Advance payments received under long-term terminaling services agreements	$	475	$	451
Deferred revenue—ethanol blending fees and other projects		2,415		3,419
Unrealized loss on derivative instruments		551		—
	$	3,441	$	3,870

Advance payments received under long‑term terminaling services agreements. We have long‑term terminaling services agreements with certain of our customers that provide for advance minimum payments. We recognize the advance minimum payments as revenue either on a straight‑line basis over the term of the respective agreements or when services have been provided based on volumes of product distributed. At September 30, 2015 and December 31, 2014, we have received advance minimum payments in excess of revenue recognized under these long‑term terminaling services agreements resulting in a liability of approximately $0.5 million and $0.5 million, respectively.

Deferred revenue—ethanol blending fees and other projects. Pursuant to agreements with our customers, we agreed to undertake certain capital projects that primarily pertain to providing ethanol blending functionality at certain of our Southeast terminals. Upon completion of the projects, our customers have paid us lump‑sum amounts that will be recognized as revenue on a straight‑line basis over the remaining term of the agreements. At September 30, 2015 and December 31, 2014, we have unamortized deferred revenue of approximately $2.4 million and $3.4 million, respectively, for completed projects. During the three months ended September 30, 2015 and 2014, we recognized revenue on a straight‑line basis of approximately $0.4 million and $0.5 million, respectively, for completed projects. During the nine months ended September 30, 2015 and 2014, we recognized revenue on a straight‑line basis of approximately $1.0 million and $1.9 million, respectively, for completed projects.

(12) LONG‑TERM DEBT

On March 9, 2011, we entered into an amended and restated senior secured credit facility, or “credit facility”, which has been subsequently amended from time to time. The most recent amendment to our credit facility was the Fifth Amendment, which was completed on February 26, 2015. This amendment extended the maturity date of the credit facility from March 9, 2016 to July 31, 2018, increased the maximum borrowing line of credit from $350 million to $400 million, and allowed for up to $125 million in additional future “permitted JV investments”, which may include additional investments in BOSTCO. In addition, the amendment allowed for, at our request, the maximum borrowing line of credit to be increased by an additional $100 million, subject to the approval of the administrative agent and the receipt of additional commitments from one or more lenders.

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At September 30, 2015, the credit facility provides for a maximum borrowing line of credit equal to the lesser of (i) $400 million and (ii) 4.75 times Consolidated EBITDA (as defined: $401.2 million at September 30, 2015). At our request, the maximum borrowing line of credit may be increased by an additional $100 million, subject to the approval of the administrative agent and the receipt of additional commitments from one or more lenders. We may elect to have loans under the credit facility bear interest either (i) at a rate of LIBOR plus a margin ranging from 2% to 3% depending on the total leverage ratio then in effect, or (ii) at the base rate plus a margin ranging from 1% to 2% depending on the total leverage ratio then in effect. We also pay a commitment fee on the unused amount of commitments, ranging from 0.375% to 0.5% per annum, depending on the total leverage ratio then in effect. Our obligations under the credit facility are secured by a first priority security interest in favor of the lenders in the majority of our assets, including our investments in unconsolidated affiliates.

The terms of the credit facility include covenants that restrict our ability to make cash distributions, acquisitions and investments, including investments in joint ventures. We may make distributions of cash to the extent of our “available cash” as defined in our partnership agreement. We may make acquisitions and investments that meet the definition of “permitted acquisitions”; “other investments” which may not exceed 5% of “consolidated net tangible assets”; and additional future “permitted JV investments” up to $125 million, which may include additional investments in BOSTCO. The principal balance of loans and any accrued and unpaid interest are due and payable in full on the maturity date, July 31, 2018.

If we were to fail any financial performance covenant, or any other covenant contained in the credit facility, we would seek a waiver from our lenders under such facility. If we were unable to obtain a waiver from our lenders and the default remained uncured after any applicable grace period, we would be in breach of the credit facility, and the lenders would be entitled to declare all outstanding borrowings immediately due and payable. We were in compliance with all of the financial covenants under the credit facility as of September 30, 2015.

For the three months ended September 30, 2015 and 2014, the weighted average interest rate on borrowings under the credit facility was approximately 2.6% and 2.7%, respectively. For the nine months ended September 30, 2015 and 2014, the weighted average interest rate on borrowings under the credit facility was approximately 2.7% and 2.6%, respectively. At September 30, 2015 and December 31, 2014, our outstanding borrowings under the credit facility were $249.6 million and $252.0 million, respectively. At September 30, 2015 and December 31, 2014, our outstanding letters of credit were $nil at both dates.

We have an effective universal shelf‑registration statement and prospectus on Form S‑3 with the Securities and Exchange Commission that expires in June 2016. TLP Finance Corp., a 100% owned subsidiary of Partners, may act as a co‑issuer of any debt securities issued pursuant to that registration statement. Partners and TLP Finance Corp. have no independent assets or operations. Our operations are conducted by subsidiaries of Partners through Partners’ 100% owned operating company subsidiary, TransMontaigne Operating Company L.P. Each of TransMontaigne Operating Company L.P.s’ and Partners’ other 100% owned subsidiaries (other than TLP Finance Corp., whose sole purpose is to act as co‑issuer of any debt securities) may guarantee the debt securities. We expect that any guarantees will be full and unconditional and joint and several, subject to certain automatic customary releases, including sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, exercise of legal defeasance option or covenant defeasance option, and designation of a subsidiary guarantor as unrestricted in accordance with the indenture. There are no significant restrictions on the ability of Partners or any guarantor to obtain funds from its subsidiaries by dividend or loan. None of the assets of Partners or a guarantor represent restricted net assets pursuant to the guidelines established by the Securities and Exchange Commission.

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(13) PARTNERS’ EQUITY

The number of units outstanding is as follows:


		General
	Common	partner
	units	equivalent units
Units outstanding at September 30, 2015 and December 31, 2014	16,124,566	329,073

At September 30, 2015 and December 31, 2014, common units outstanding include 10,268 and 7,600 common units, respectively, held on behalf of TransMontaigne LLC’s long‑term incentive plan.

(14) EQUITY BASED COMPENSATION

TransMontaigne GP is our general partner and manages our operations and activities. TransMontaigne GP is a wholly owned subsidiary of TransMontaigne LLC, which is a wholly owned subsidiary of NGL. Prior to January 1, 2015, TransMontaigne Services LLC, a wholly owned subsidiary of TransMontaigne LLC, employed the personnel who provide corporate and support services to TransMontaigne LLC’s operations, as well as our operations. Effective January 1, 2015, all the employees of TransMontaigne Services LLC became employees of NGL Energy Operating, LLC, which is a wholly owned subsidiary of NGL. TransMontaigne Services LLC has adopted a long‑term incentive plan and a savings and retention plan to compensate certain employees who provide corporate and support services to Partners and to the independent directors of our general partner.

Long-term incentive plan. The long‑term incentive plan currently permits the grant of awards covering an aggregate of 2,750,868 units, which amount will automatically increase on an annual basis by 2% of the total outstanding common and subordinated units, if any, at the end of the preceding fiscal year. At September 30, 2015, 2,501,948 units are available for future grant under the long‑term incentive plan. The long‑term incentive plan is administered by the compensation committee of the board of directors of our general partner and is currently used for grants of restricted phantom units to the independent directors of our general partner. The grants to the independent directors of our general partner generally vest and are payable annually in equal tranches over a four-year period. Ownership in the awards is subject to forfeiture until the vesting date, but recipients have distribution and voting rights from the date of the grant.

TransMontaigne GP has historically acquired outstanding common units on the open market under a purchase program for purposes of delivering vested units to the independent directors of our general partner. The purchase program concluded with its final purchase of 667 units on the program’s scheduled termination date of April 1, 2015. Future grants of restricted phantom units under the TransMontaigne Services LLC long‑term incentive plan are expected to be settled by us through the issuance of common units pursuant to our existing Form S-8 Registration Statements. TransMontaigne GP, on behalf of the long‑term incentive plan, has purchased 2,668 and 6,003 common units pursuant to the program during the nine months ended September 30, 2015 and 2014, respectively.

Activity under the long-term incentive plan for the nine months ended September 30, 2015 is as follows:


		Restricted	NYSE
	Available for	phantom	closing
	future grant	units	price
Units available at December 31, 2014	2,179,457	9,000
Automatic increase in units available for future grant on January 1, 2015	322,491	—
Vesting on September 30, 2015	—	(2,250)	$	27.20
Units available at September 30, 2015	2,501,948	6,750

Generally accepted accounting principles require us to measure the cost of board member services received in exchange for an award of equity instruments based on the grant‑date fair value of the award. That cost is recognized over the vesting period on a straight line basis during which a board member is required to provide services in exchange for the award. For awards to the independent directors of our general partner, equity‑based compensation expense of approximately $24,000 and $584,000 is included in direct general and administrative expenses for the three months

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ended September 30, 2015 and 2014, respectively. Equity‑based compensation expense of approximately $70,000 and $698,000 is included in direct general and administrative expenses for the nine months ended September 30, 2015 and 2014, respectively.

Savings and retention plan. Under the omnibus agreement we have agreed to reimburse TransMontaigne LLC for a portion of the incentive bonus awards made by TransMontaigne Services LLC under the TransMontaigne Services LLC savings and retention plan to key employees that provide corporate and support services to Partners, provided the compensation committee of our general partner determines that an adequate portion of the incentive bonus awards are indexed to the performance of our common units in the form of restricted phantom units. In accordance with the omnibus agreement, the value of our incentive bonus award reimbursement for a single grant year may be no less than $1.5 million. Ownership in the restricted phantom units under the savings and retention plan is subject to forfeiture until the vesting date, but recipients have distribution equivalent rights from the date of grant that accrue additional restricted phantom units equivalent to the value of quarterly distributions paid by us on each of our outstanding common units. Recipients of restricted phantom units under the savings and retention plan do not have voting rights.

The purpose of the savings and retention plan is to provide for the reward and retention of participants by providing them with bonus awards that vest over future service periods. Awards under the plan generally become vested as to 50% of a participant’s annual award as of the January 1 that falls closest to the second anniversary of the grant date, and the remaining 50% as of the January 1 that falls closest to the third anniversary of the grant date, subject to earlier vesting upon a participant’s age and length of service thresholds, retirement, death or disability, involuntary termination without cause, or termination of a participant’s employment following a change of control of TransMontaigne LLC, or its affiliates, as specified in the plan. Awards are payable as to 50% of a participant’s annual award in the month containing the second anniversary of the grant date, and the remaining 50% in the month containing the third anniversary of the grant date, subject to earlier vesting and payment, as applicable, upon the participant’s attainment of retirement, death or disability, involuntary termination without cause, or a participant’s termination of employment following a change of control of TransMontaigne LLC, or its affiliates, as specified in the plan. Pursuant to the provisions of the plan, once participants reach the age and length of service thresholds set forth below, awards become vested and are payable as set forth above. A person will satisfy the age and length of service thresholds of the plan upon the attainment of the earliest of (a) age sixty, (b) age fifty‑five and ten years of service as an officer of TransMontaigne LLC or any of its affiliates, or (c) age fifty and twenty years of service as an employee of TransMontaigne LLC or any of its affiliates.

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

Given that Partners does not have any employees to provide corporate and support services and instead contracts for such services under its omnibus agreement with TransMontaigne LLC, generally accepted accounting principles require us to classify the 2015 incentive bonus award as a non-employee award and measure the cost of services received in exchange for an award of equity instruments based on the vesting‑date fair value of the award. That cost, or an estimate of that cost in the case of unvested restricted phantom units, is recognized over the period during which services are provided in exchange for the award. For the three months ended September 30, 2015 and 2014, the expenses associated with the reimbursement of incentive bonus awards were approximately $0.1 million and $0.4 million respectively. For the nine months ended September 30, 2015 and 2014, the expenses associated with the reimbursement of incentive bonus awards were approximately $1.2 million and $1.1 million respectively.

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Activity related to our equity based award granted to TransMontaigne LLC for services performed under the omnibus agreement for the nine months ended September 30, 2015 is as follows:


			NYSE
			closing
	Vested	Unvested	price
Restricted phantom units outstanding at December 31, 2014	—	—
Grant on April 13, 2015	28,399	29,644	$	34.02
Unit accrual for distributions paid on May 7, 2015	540	564	$	34.95
Unit accrual for distributions paid on August 7, 2015	606	633	$	31.74
Forfeitures	—	(892)
Restricted phantom units outstanding at September 30, 2015	29,545	29,949

(15) NET EARNINGS PER LIMITED PARTNER UNIT

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


	Three months ended				Nine months ended
	September 30,				September 30,
	2015		2014		2015		2014
Net earnings	$	7,712	$	6,520	$	30,022	$	26,598
Less:
Distributions payable on behalf of incentive distribution rights		(1,682)		(1,682)		(5,046)		(4,967)
Distributions payable on behalf of general partner interest		(219)		(219)		(657)		(655)
Earnings allocable to general partner interest less than distributions payable to general partner interest		98		122		157		222
Earnings allocable to general partner interest including incentive distribution rights		(1,803)		(1,779)		(5,546)		(5,400)
Net earnings allocable to limited partners per the consolidated statements of operations		5,909		4,741		24,476		21,198
Less distributions payable for unvested long-term incentive plan grants		(4)		(6)		(16)		(26)
Net earnings allocable to limited partners for calculating net earnings per limited partner unit	$	5,905	$	4,735	$	24,460	$	21,172
Basic weighted average units		16,144		16,120		16,134		16,110
Diluted weighted average units		16,150		16,120		16,140		16,110
Net earnings per limited partner unit—basic	$	0.37	$	0.29	$	1.52	$	1.31
Net earnings per limited partner unit—diluted	$	0.37	$	0.29	$	1.52	$	1.31

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


	Distribution
January 1, 2014 through March 31, 2014	$	0.660
April 1, 2014 through June 30, 2014	$	0.665
July 1, 2014 through September 30, 2014	$	0.665
October 1, 2014 through December 31, 2014	$	0.665
January 1, 2015 through March 31, 2015	$	0.665
April 1, 2015 through June 30, 2015	$	0.665
July 1, 2015 through September 30, 2015	$	0.665

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(16) COMMITMENTS AND CONTINGENCIES

Contract commitments. At September 30, 2015, we have contractual commitments of approximately $8.1 million for the supply of services, labor and materials related to capital projects that currently are under development. We expect that these contractual commitments will be paid within the next twelve months.

Operating leases. We lease property and equipment under non‑cancelable operating leases that extend through August 2030. At September 30, 2015, future minimum lease payments under these non‑cancelable operating leases are as follows (in thousands):


Years ending December 31:
2015 (remainder of the year)	$	923
2016		4,009
2017		3,024
2018		632
2019		618
Thereafter		4,398
	$	13,604

Included in the above non‑cancelable operating lease commitments are amounts for property rentals that we have sublet under non‑cancelable sublease agreements, for which we expect to receive minimum rentals of approximately $0.7 million in future periods.

Rental expense under operating leases was approximately $0.9 million and $0.9 million for the three months ended September 30, 2015 and 2014, respectively. Rental expense under operating leases was approximately $2.7 million and $2.6 million for the nine months ended September 30, 2015 and 2014, respectively.

Legal proceedings. The King Ranch natural-gas-processing plant in Kleberg County, Texas, was shut down as a result of a fire at the plant beginning in November 2013. This plant supplies a significant amount of liquefied petroleum gas, or “LPG,” to our third-party customer, Nieto Trading, B.V. (“Nieto”), which transports LPG through our Ella-Brownsville and Diamondback pipelines, and has contracted for the LPG storage capacity at our Brownsville terminals. The King Ranch plant became operational again in late November 2014. Nieto has claimed that the fire at the King Ranch plant constitutes a force majeure event that relieves Nieto of its obligation to pay certain fees required under the related terminaling services agreement for failure to throughput a minimum number of barrels of LPG (“deficiency fees”). We do not believe that the King Ranch fire qualified as a force majeure event under the terminaling services agreement, or that, even if it did, it relieved Nieto of its obligation to pay the deficiency fees. As a result of Nieto’s failure to pay the deficiency fees due to us, on September 26, 2014, we filed a complaint for damages and declaratory relief in the Supreme Court of the State of New York, County of New York, against Nieto, by which we seek damages that have accumulated as of September 30, 2015 in an amount in excess of $5.7 million and a declaratory judgment clarifying our rights to receive the deficiency fees under the terminaling services agreement.

(17) DISCLOSURES ABOUT FAIR VALUE

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

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

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the best information available in the circumstances. The following methods and assumptions were used to estimate the fair value of financial instruments at September 30, 2015 and December 31, 2014.

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

Derivative instruments. The carrying amount of our interest rate swaps as of September 30, 2015 was determined using a pricing model based on the LIBOR swap rate and other observable market data. The fair value is categorized in Level 2 of the fair value hierarchy. We did not have an interest rate swap as of December 31, 2014.

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

(18) BUSINESS SEGMENTS

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

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


	Three months ended				Nine months ended
	September 30,				September 30,
	2015		2014		2015		2014
Gulf Coast Terminals:
Terminaling services fees	$	10,844	$	10,215	$	31,305	$	33,290
Other		2,202		2,318		6,459		9,406
Revenue		13,046		12,533		37,764		42,696
Direct operating costs and expenses		(4,920)		(5,115)		(13,815)		(14,656)
Net margins		8,126		7,418		23,949		28,040
Midwest Terminals and Pipeline System:
Terminaling services fees		2,206		2,032		6,299		6,039
Pipeline transportation fees		433		414		1,261		1,155
Other		585		612		1,098		1,622
Revenue		3,224		3,058		8,658		8,816
Direct operating costs and expenses		(871)		(682)		(2,351)		(2,254)
Net margins		2,353		2,376		6,307		6,562
Brownsville Terminals:
Terminaling services fees		2,096		1,624		5,979		4,588
Pipeline transportation fees		1,183		372		3,687		1,100
Other		2,827		2,932		10,043		9,076
Revenue		6,106		4,928		19,709		14,764
Direct operating costs and expenses		(3,269)		(3,597)		(9,479)		(10,528)
Net margins		2,837		1,331		10,230		4,236
River Terminals:
Terminaling services fees		2,346		2,336		6,899		6,450
Other		114		146		547		536
Revenue		2,460		2,482		7,446		6,986
Direct operating costs and expenses		(1,898)		(1,940)		(5,255)		(5,575)
Net margins		562		542		2,191		1,411
Southeast Terminals:
Terminaling services fees		11,521		11,131		34,789		34,086
Other		912		1,571		3,834		5,767
Revenue		12,433		12,702		38,623		39,853
Direct operating costs and expenses		(5,697)		(5,180)		(16,581)		(15,289)
Net margins		6,736		7,522		22,042		24,564
Total net margins		20,614		19,189		64,719		64,813
Direct general and administrative expenses		(1,117)		(1,086)		(2,810)		(2,466)
Allocated general and administrative expenses		(2,835)		(2,782)		(8,440)		(8,346)
Allocated insurance expense		(944)		(942)		(2,812)		(2,769)
Reimbursement of bonus awards expense		(121)		(375)		(1,185)		(1,125)
Depreciation and amortization		(7,711)		(7,400)		(22,524)		(22,196)
Earnings from unconsolidated affiliates		2,191		1,653		9,764		3,091
Operating income		10,077		8,257		36,712		31,002
Other expenses		(2,365)		(1,737)		(6,690)		(4,404)
Net earnings	$	7,712	$	6,520	$	30,022	$	26,598

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


	Three months ended September 30, 2015
			Midwest
			Terminals and
	Gulf Coast		Pipeline		Brownsville		River		Southeast
	Terminals		System		Terminals		Terminals		Terminals		Total
Revenue:
External customers	$	11,980	$	3,224	$	4,995	$	2,343	$	4,601	$	27,143
NGL Energy Partners LP		1,066		—		—		117		7,832		9,015
Frontera		—		—		1,111		—		—		1,111
Revenue	$	13,046	$	3,224	$	6,106	$	2,460	$	12,433	$	37,269
Capital expenditures	$	1,519	$	78	$	1,188	$	832	$	5,167	$	8,784
Identifiable assets	$	123,424	$	22,902	$	46,652	$	54,358	$	160,387	$	407,723
Cash and cash equivalents												791
Investments in unconsolidated affiliates												248,204
Deferred financing costs												1,887
Other												559
Total assets											$	659,164


	Three months ended September 30, 2014
			Midwest
			Terminals and
	Gulf Coast		Pipeline		Brownsville		River		Southeast
	Terminals		System		Terminals		Terminals		Terminals		Total
Revenue:
External customers	$	8,373	$	3,058	$	3,777	$	2,367	$	4,555	$	22,130
NGL Energy Partners LP		4,160		—		—		115		8,147		12,422
Frontera		—		—		1,151		—		—		1,151
Revenue	$	12,533	$	3,058	$	4,928	$	2,482	$	12,702	$	35,703
Capital expenditures	$	289	$	10	$	73	$	137	$	217	$	726


	Nine months ended September 30, 2015
			Midwest
			Terminals and
	Gulf Coast		Pipeline		Brownsville		River		Southeast
	Terminals		System		Terminals		Terminals		Terminals		Total
Revenue:
External customers	$	32,859	$	8,658	$	16,401	$	7,095	$	14,183	$	79,196
NGL Energy Partners LP		4,905		—		10		351		24,440		29,706
Frontera		—		—		3,298		—		—		3,298
Revenue	$	37,764	$	8,658	$	19,709	$	7,446	$	38,623	$	112,200
Capital expenditures	$	8,503	$	775	$	3,455	$	3,875	$	7,930	$	24,538

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	Nine months ended September 30, 2014
			Midwest
			Terminals and
	Gulf Coast		Pipeline		Brownsville		River		Southeast
	Terminals		System		Terminals		Terminals		Terminals		Total
Revenue:
External customers	$	21,054	$	5,830	$	11,779	$	6,202	$	6,362	$	51,227
NGL Energy Partners LP		4,160		—		—		115		8,147		12,422
Morgan Stanley Capital Group		17,482		2,986		—		669		25,344		46,481
Frontera		—		—		2,985		—		—		2,985
Revenue	$	42,696	$	8,816	$	14,764	$	6,986	$	39,853	$	113,115
Capital expenditures	$	678	$	39	$	994	$	732	$	895	$	3,338

(19) SUBSEQUENT EVENT

On October 12, 2015, we announced a distribution of $0.665 per unit for the period from July 1, 2015 through September 30, 2015. This distribution is payable on November 6, 2015 to unitholders of record on October 30, 2015.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

RECENT DEVELOPMENTS

Commercial activity. On October 30, 2015, we entered into a new six-year terminaling services agreement with a subsidiary of NGL Energy Partners LP (“NGL”) for approximately 1.2 million barrels of new product storage capacity to be constructed at our Collins, Mississippi terminal and approximately 0.1 million barrels of existing storage capacity at this same terminal. The terminaling services agreement with NGL will be effective January 1, 2016 with the majority of the contract revenue coming on-line upon completion of the construction of the new tank capacity, which is expected to occur during the fourth quarter of 2016 and the first quarter of 2017. This first phase of our expansion at Collins is expected to cost approximately $43 million. We are currently negotiating agreements with other potential customers that could support the construction of another 0.8 million barrels of product storage capacity at our Collins terminal. Our Collins terminal is the only independent terminal capable of receiving from, delivering to, and transferring between the Colonial and Plantation pipeline systems.

On October 26, 2015, we finalized the negotiation of the start of a five-and-half-year terminaling services agreement with a new third party customer for approximately 700,000 barrels of existing asphalt storage capacity at our Port Everglades North, Cape Canaveral, Jacksonville, and Port Manatee, Florida terminals. The new agreement contains an increase to the minimum throughput fee per barrel and commenced November 1, 2015, upon the departure of the previous third party asphalt customer at these terminals. The new agreement re-contracts all but approximately 270,000 barrels of our asphalt storage capacity in Florida, which was under contract through October 31, 2015. We are in the process of identifying other potential parties to re‑contract this capacity, however, at this time we cannot be certain whether we will be successful in our re‑contracting efforts.

Quarterly distributions. On October 12, 2015, we announced a distribution of $0.665 per unit for the period from July 1, 2015 through September 30, 2015. This distribution is payable on November 6, 2015 to unitholders of record on October 30, 2015.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

A summary of the significant accounting policies that we have adopted and followed in the preparation of our consolidated financial statements is detailed in our consolidated financial statements for the year ended December 31, 2014, included in our Annual Report on Form 10‑K, filed on March 12, 2015. 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 determining the fair value of our reporting units when analyzing goodwill. 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.

RESULTS OF OPERATIONS—THREE MONTHS ENDED SEPTEMBER 30, 2015 AND 2014

The following discussion and analysis of the results of operations and financial condition should be read in conjunction with the accompanying unaudited consolidated financial statements.

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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


	Three months ended September 30,
	2015		2014
Terminaling services fees	$	29,013	$	27,338
Pipeline transportation fees		1,616		786
Management fees and reimbursed costs		1,966		1,892
Other		4,674		5,687
Revenue	$	37,269	$	35,703

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 five principal business segments: (i) Gulf Coast terminals, (ii) Midwest terminals and pipeline system, (iii) Brownsville terminals, (iv) River terminals and (v) Southeast terminals. The aggregate revenue of each of our business segments was as follows (in thousands):

Total Revenue by Business Segment


	Three months ended September 30,
	2015		2014
Gulf Coast terminals	$	13,046	$	12,533
Midwest terminals and pipeline system		3,224		3,058
Brownsville terminals		6,106		4,928
River terminals		2,460		2,482
Southeast terminals		12,433		12,702
Revenue	$	37,269	$	35,703

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

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

Terminaling Services Fees by Business Segment


	Three months ended September 30,
	2015		2014
Gulf Coast terminals	$	10,844	$	10,215
Midwest terminals and pipeline system		2,206		2,032
Brownsville terminals		2,096		1,624
River terminals		2,346		2,336
Southeast terminals		11,521		11,131
Terminaling services fees	$	29,013	$	27,338

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The increase in terminaling services fees at our Brownsville terminals includes an increase of approximately $0.3 million due to additional LPG throughput resulting from the King Ranch gas plant becoming operational again in late November 2014. The plant had been shut down since November 2013 due to a fire. The impact of the King Ranch gas plant fire is further discussed below in pipeline transportation fees. The increase in terminaling services fees at our Brownsville terminals also includes an increase of approximately $0.3 million resulting from us contracting 110,000 barrels of available capacity to a third party for a three year term commencing in May of 2015. The majority of this capacity had been unsubscribed since the first quarter of 2014.

Included in terminaling services fees for the three months ended September 30, 2015 and 2014 are fees charged to affiliates of approximately $8.3 million and $11.1 million, respectively.

Our terminaling services agreements are structured as either throughput agreements or storage agreements. Most of our throughput agreements contain provisions that require our customers to throughput a minimum volume of product at our facilities over a stipulated period of time, which results in a fixed amount of revenue to be recognized by us. Our storage agreements require our customers to make minimum payments based on the volume of storage capacity available to the customer under the agreement, which results in a fixed amount of revenue to be recognized by us. We refer to the fixed amount of revenue recognized pursuant to our terminaling services agreements as being “firm commitments.” Revenue recognized in excess of firm commitments and revenue recognized based solely on the volume of product distributed or injected are referred to as “variable.” The “firm commitments” and “variable” revenue included in terminaling services fees were as follows (in thousands):

Firm Commitments and Variable Revenue


	Three months ended September 30,
	2015		2014
Firm commitments:
External customers	$	19,953	$	15,211
Affiliates		7,565		10,930
Total		27,518		26,141
Variable:
External customers		753		990
Affiliates		742		207
Total		1,495		1,197
Terminaling services fees	$	29,013	$	27,338

The remaining terms on the terminaling services agreements that generated “firm commitments” for the three months ended September 30, 2015 are as follows (in thousands):


Less than 1 year remaining	$	7,228
1 year or more, but less than 3 years remaining		12,569
3 years or more, but less than 5 years remaining		3,071
5 years or more remaining		4,650
Total firm commitments for the three months ended September 30, 2015	$	27,518

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

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

Pipeline Transportation Fees by Business Segment


	Three months ended September 30,
	2015		2014
Gulf Coast terminals	$	—	$	—
Midwest terminals and pipeline system		433		414
Brownsville terminals		1,183		372
River terminals		—		—
Southeast terminals		—		—
Pipeline transportation fees	$	1,616	$	786

The increase in pipeline transportation fees includes an increase of approximately $0.8 million resulting from the King Ranch natural gas processing plant in Kleberg County, Texas becoming operational again in late November 2014. The plant had been previously shutdown since November 2013 due to a fire. The plant supplies a significant amount of liquefied petroleum gas, or “LPG”, to our third party customer, Nieto Trading, B.V. (“Nieto”), who transports LPG on our Ella‑Brownsville and Diamondback pipelines and has contracted for the LPG storage capacity at our Brownsville terminals. We are currently in a dispute with Nieto regarding the fees that were due from them during the period the King Ranch plant was not operational. See “Legal proceedings” in Note 16 of Notes to consolidated financial statements for a discussion of pending legal proceedings.

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

Management Fees and Reimbursed Costs by Business Segment


	Three months ended September 30,
	2015		2014
Gulf Coast terminals	$	262	$	257
Midwest terminals and pipeline system		—		—
Brownsville terminals		1,704		1,635
River terminals		—		—
Southeast terminals		—		—
Management fees and reimbursed costs	$	1,966	$	1,892

Included in management fees and reimbursed costs for the three months ended September 30, 2015 and 2014 are fees charged to affiliates of approximately $1.1 million and $1.2 million, respectively.

Other revenue. We provide ancillary services including heating and mixing of stored products, product transfer, railcar handling, butane blending, wharfage and vapor recovery. Pursuant to terminaling services agreements with certain throughput customers, we are entitled to the volume of product gained resulting from differences in the measurement of product volumes received and distributed at our terminaling facilities. Consistent with recognized industry practices, measurement differentials occur as the result of the inherent variances in measurement devices and

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methodology. We recognize as revenue the net proceeds from the sale of the product gained. Other revenue is composed of the following (in thousands):

Principal Components of Other Revenue


	Three months ended September 30,
	2015		2014
Product gains	$	1,875	$	3,062
Steam heating fees		629		593
Product transfer services		340		611
Railcar handling		106		154
Other		1,724		1,267
Other revenue	$	4,674	$	5,687

For the three months ended September 30, 2015 and 2014, we sold approximately 30,750 and 29,000 barrels, respectively, of product gained resulting from differences in the measurement of product volumes received and distributed at our terminaling facilities at average prices of approximately $61 and $112 per barrel, respectively. Pursuant to our Southeast terminaling services agreement, we agreed to rebate to our affiliate customer 50% of the proceeds we receive annually in excess of $4.2 million from the sale of product gains at our Southeast terminals. For the three months ended September 30, 2015 and 2014, we have accrued a liability due to our affiliate customer under the Southeast terminaling services agreement of approximately $nil and $0.2 million, respectively.

Included in other revenue for the three months ended September 30, 2015 and 2014 are amounts charged to affiliates of approximately $0.7 million and $1.3 million, respectively.

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

Other Revenue by Business Segment


	Three months ended September 30,
	2015		2014
Gulf Coast terminals	$	1,940	$	2,061
Midwest terminals and pipeline system		585		612
Brownsville terminals		1,123		1,297
River terminals		114		146
Southeast terminals		912		1,571
Other revenue	$	4,674	$	5,687

ANALYSIS OF COSTS AND EXPENSES

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compliance costs, materials and supplies. The direct operating costs and expenses of our operations were as follows (in thousands):

Direct Operating Costs and Expenses


	Three months ended September 30,
	2015		2014
Wages and employee benefits	$	5,394	$	5,889
Utilities and communication charges		1,927		1,738
Repairs and maintenance		4,133		4,366
Office, rentals and property taxes		2,307		2,281
Vehicles and fuel costs		208		273
Environmental compliance costs		671		708
Other		2,015		1,259
Direct operating costs and expenses	$	16,655	$	16,514

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

Direct Operating Costs and Expenses by Business Segment


	Three months ended September 30,
	2015		2014
Gulf Coast terminals	$	4,920	$	5,115
Midwest terminals and pipeline system		871		682
Brownsville terminals		3,269		3,597
River terminals		1,898		1,940
Southeast terminals		5,697		5,180
Direct operating costs and expenses	$	16,655	$	16,514

Direct general and administrative expenses of our operations primarily include accounting and legal costs associated with annual and quarterly reports and tax return and Schedule K‑1 preparation and distribution, independent director fees and equity‑based compensation expense under the long-term incentive plan. The direct general and administrative expenses were approximately $1.1 million and $1.1 million for the three months ended September 30, 2015 and 2014, respectively.

Allocated general and administrative expenses include charges from TransMontaigne LLC for indirect corporate overhead to cover costs of centralized corporate functions such as legal, accounting, treasury, insurance administration and claims processing, health, safety and environmental, information technology, human resources, credit, payroll, taxes, engineering and other corporate services. The allocated general and administrative expenses were approximately $2.8 million and $2.8 million for the three months ended September 30, 2015 and 2014, respectively.

Allocated insurance expenses include charges from TransMontaigne LLC for allocations of insurance premiums to cover costs of insuring activities such as property, casualty, pollution, automobile, directors’ and officers’ liability, and other insurable risks. The allocated insurance expenses were approximately $0.9 million and $0.9 million for the three months ended September 30, 2015 and 2014, respectively.

Reimbursement of bonus awards include expenses associated with us reimbursing TransMontaigne LLC for awards granted by them to certain key officers and employees that vest over future service periods. The expenses associated with these reimbursements were approximately $0.1 million and $0.4 million for the three months ended September 30, 2015 and 2014, respectively.

For the three months ended September 30, 2015 and 2014, depreciation and amortization expense was approximately $7.7 million and $7.4 million, respectively.

For the three months ended September 30, 2015 and 2014, interest expense was approximately $2.2 million and $1.5 million, respectively. The increase in interest expense is primarily attributable to us no longer capitalizing interest

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on our investment in BOSTCO, as it was placed into service throughout the first three quarters of 2014, and the recognition of unrealized losses in determining the fair value of our interest rate swap agreements. We did not have interest rate swap agreements during the year ended December 31, 2014.

ANALYSIS OF INVESTMENTS IN UNCONSOLIDATED AFFILIATES

Our investments in unconsolidated affiliates include a 42.5% interest in BOSTCO and a 50% interest in Frontera. BOSTCO is a newly constructed terminal facility located on the Houston Ship Channel. BOSTCO began initial commercial operations in the fourth quarter of 2013; with completion of its approximately 7.1 million barrels of storage capacity and related infrastructure occurring at the end of the third quarter of 2014 (see Note 3 of Notes to consolidated financial statements). Frontera is a terminal facility located in Brownsville, Texas that encompasses approximately 1.5 million barrels of light petroleum product storage capacity, as well as related ancillary facilities.

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


	Three months ended September 30,
	2015		2014
BOSTCO	$	1,670	$	1,368
Frontera		521		285
Total earnings from investments in unconsolidated affiliates	$	2,191	$	1,653

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


	Three months ended September 30,
	2015		2014
BOSTCO	$	4,226	$	20,283
Frontera		—		—
Additional capital investments in unconsolidated affiliates	$	4,226	$	20,283

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


	Three months ended September 30,
	2015		2014
BOSTCO	$	6,555	$	2,915
Frontera		955		344
Cash distributions received from unconsolidated affiliates	$	7,510	$	3,259

The increase in distributions received from our investment in BOSTCO is primarily attributable to a one-time gain resulting from a contract buy-out by one of its customers in April of 2015. Our share of the gain was approximately $3.4 million, which we received in cash as a component of our third quarter 2015 distribution from BOSTCO.

RESULTS OF OPERATIONS—NINE MONTHS ENDED SEPTEMBER 30, 2015 AND 2014

The following discussion and analysis of the results of operations and financial condition should be read in conjunction with the accompanying unaudited consolidated financial statements.

ANALYSIS OF REVENUE

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Total Revenue by Category


	Nine months ended September 30,
	2015		2014
Terminaling services fees	$	85,271	$	84,453
Pipeline transportation fees		4,948		2,255
Management fees and reimbursed costs		5,720		5,203
Other		16,261		21,204
Revenue	$	112,200	$	113,115

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.

Total Revenue by Business Segment


	Nine months ended September 30,
	2015		2014
Gulf Coast terminals	$	37,764	$	42,696
Midwest terminals and pipeline system		8,658		8,816
Brownsville terminals		19,709		14,764
River terminals		7,446		6,986
Southeast terminals		38,623		39,853
Revenue	$	112,200	$	113,115

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

Terminaling Services Fees by Business Segment


	Nine months ended September 30,
	2015		2014
Gulf Coast terminals	$	31,305	$	33,290
Midwest terminals and pipeline system		6,299		6,039
Brownsville terminals		5,979		4,588
River terminals		6,899		6,450
Southeast terminals		34,789		34,086
Terminaling services fees	$	85,271	$	84,453

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The decrease in terminaling services fees at our Gulf Coast terminals includes a decrease of approximately $1.1 million resulting from the majority of the light oil tankage at our Port Manatee, Florida terminal being offline for approximately four months during the nine months ended September 30, 2015 in order to complete enhancements for a new customer at this facility, RaceTrac Petroleum Inc. The enhanced tankage at Port Manatee became available to RaceTrac Petroleum Inc. in July of 2015. The decrease in terminaling services fees at our Gulf Coast terminals also includes a decrease of approximately $1.1 million resulting from Morgan Stanley Capital Group terminating its bunker fuels agreement at our Port Manatee, Florida terminal effective May 31, 2014. We are currently in the process of identifying other potential parties to re‑contract this capacity.

The increase in terminaling services fees at our Brownsville terminals includes an increase of approximately $0.9 million due to additional LPG throughput resulting from the King Ranch gas plant becoming operational again in late November 2014. The plant had been shut down since November 2013 due to a fire. The impact of the King Ranch gas plant fire is further discussed below in pipeline transportation fees. The increase in terminaling services fees at our Brownsville terminals also includes an increase of approximately $0.5 million resulting from us contracting 110,000 barrels of available capacity to a third party for a three year term commencing in May of 2015. The majority of this capacity had been unsubscribed since the first quarter of 2014.

Included in terminaling services fees for the nine months ended September 30, 2015 and 2014 are fees charged to affiliates of approximately $27.0 million and $49.4 million, respectively.

Firm Commitments and Variable Revenue


	Nine months ended September 30,
	2015		2014
Firm commitments:
External customers	$	55,043	$	32,433
Affiliates		24,741		48,825
Total		79,784		81,258
Variable:
External customers		3,250		2,641
Affiliates		2,237		554
Total		5,487		3,195
Terminaling services fees	$	85,271	$	84,453

The remaining terms on the terminaling services agreements that generated “firm commitments” for the nine months ended September 30, 2015 were as follows (in thousands):


Less than 1 year remaining	$	21,547
1 year or more, but less than 3 years remaining		36,381
3 years or more, but less than 5 years remaining		7,875
5 years or more remaining		13,981
Total firm commitments for the nine months ended September 30, 2015	$	79,784

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Pipeline Transportation Fees by Business Segment


	Nine months ended September 30,
	2015		2014
Gulf Coast terminals	$	—	$	—
Midwest terminals and pipeline system		1,261		1,155
Brownsville terminals		3,687		1,100
River terminals		—		—
Southeast terminals		—		—
Pipeline transportation fees	$	4,948	$	2,255

The increase in pipeline transportation fees includes an increase of approximately $2.6 million resulting from the King Ranch natural gas processing plant in Kleberg County, Texas becoming operational again in late November 2014. The plant had been previously shutdown since November 2013 due to a fire. The plant supplies a significant amount of liquefied petroleum gas, or “LPG”, to our third party customer, Nieto Trading, B.V. (“Nieto”), who transports LPG on our Ella‑Brownsville and Diamondback pipelines and has contracted for the LPG storage capacity at our Brownsville terminals. We are currently in a dispute with Nieto regarding the fees that were due from them during the period the King Ranch plant was not operational. See “Legal proceedings” in Note 16 of Notes to consolidated financial statements for a discussion of pending legal proceedings.

Included in pipeline transportation fees for the nine months ended September 30, 2015 and 2014 are fees charged to affiliates of $nil and approximately $0.2 million, respectively.

Management Fees and Reimbursed Costs by Business Segment


	Nine months ended September 30,
	2015		2014
Gulf Coast terminals	$	661	$	752
Midwest terminals and pipeline system		—		—
Brownsville terminals		5,059		4,451
River terminals		—		—
Southeast terminals		—		—
Management fees and reimbursed costs	$	5,720	$	5,203

Included in management fees and reimbursed costs for the nine months ended September 30, 2015 and 2014 are fees charged to affiliates of approximately $3.3 million and $3.4 million, respectively.

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Principal Components of Other Revenue


	Nine months ended September 30,
	2015		2014
Product gains	$	5,853	$	10,753
Steam heating fees		3,289		2,937
Product transfer services		1,082		1,323
Railcar handling		455		513
Other		5,582		5,678
Other revenue	$	16,261	$	21,204

For the nine months ended September 30, 2015 and 2014, we sold approximately 86,000 and 108,150 barrels, respectively, of product gained resulting from differences in the measurement of product volumes received and distributed at our terminaling facilities at average prices of approximately $68 and $116 per barrel, respectively. Pursuant to our Southeast terminaling services agreement, we agreed to rebate to our affiliate customer 50% of the proceeds we receive annually in excess of $4.2 million from the sale of product gains at our Southeast terminals. For the nine months ended September 30, 2015 and 2014, we have accrued a liability due to our affiliate customer under the Southeast terminaling services agreement of approximately $nil and $1.8 million, respectively.

Included in other revenue for the nine months ended September 30, 2015 and 2014 are amounts charged to affiliates of approximately $2.7 million and $8.9 million, respectively.

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

Other Revenue by Business Segment


	Nine months ended September 30,
	2015		2014
Gulf Coast terminals	$	5,798	$	8,654
Midwest terminals and pipeline system		1,098		1,622
Brownsville terminals		4,984		4,625
River terminals		547		536
Southeast terminals		3,834		5,767
Other revenue	$	16,261	$	21,204

ANALYSIS OF 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. The direct operating costs and expenses of our operations were as follows (in thousands):

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Direct Operating Costs and Expenses


	Nine months ended September 30,
	2015		2014
Wages and employee benefits	$	16,681	$	17,229
Utilities and communication charges		5,852		6,170
Repairs and maintenance		10,176		11,270
Office, rentals and property taxes		7,006		6,957
Vehicles and fuel costs		724		915
Environmental compliance costs		1,854		2,062
Other		5,188		3,699
Direct operating costs and expenses	$	47,481	$	48,302

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

Direct Operating Costs and Expenses by Business Segment


	Nine months ended September 30,
	2015		2014
Gulf Coast terminals	$	13,815	$	14,656
Midwest terminals and pipeline system		2,351		2,254
Brownsville terminals		9,479		10,528
River terminals		5,255		5,575
Southeast terminals		16,581		15,289
Direct operating costs and expenses	$	47,481	$	48,302

Direct general and administrative expenses of our operations primarily include accounting and legal costs associated with annual and quarterly reports and tax return and Schedule K‑1 preparation and distribution, independent director fees and equity‑based compensation expense under the long-term incentive plan. The direct general and administrative expenses were approximately $2.8 million and $2.5 million for the nine months ended September 30, 2015 and 2014, respectively.

Allocated general and administrative expenses include charges from TransMontaigne LLC for indirect corporate overhead to cover costs of centralized corporate functions such as legal, accounting, treasury, insurance administration and claims processing, health, safety and environmental, information technology, human resources, credit, payroll, taxes, engineering and other corporate services. The allocated general and administrative expenses were approximately $8.4 million and $8.3 million for the nine months ended September 30, 2015 and 2014, respectively.

Allocated insurance expenses include charges from TransMontaigne LLC for allocations of insurance premiums to cover costs of insuring activities such as property, casualty, pollution, automobile, directors’ and officers’ liability, and other insurable risks. The allocated insurance expenses were approximately $2.8 million and $2.8 million for the nine months ended September 30, 2015 and 2014, respectively.

Reimbursement of bonus awards include expenses associated with us reimbursing TransMontaigne LLC for awards granted by them to certain key officers and employees that vest over future service periods. The expenses associated with these reimbursements were approximately $1.2 million and $1.1 million for the nine months ended September 30, 2015 and 2014, respectively.

For the nine months ended September 30, 2015 and 2014, depreciation and amortization expense was approximately $22.5 million and $22.2 million, respectively.

For the nine months ended September 30, 2015 and 2014, interest expense was approximately $6.1 million and $3.7 million, respectively. The increase in interest expense is primarily attributable to us no longer capitalizing interest on our investment in BOSTCO, as it was placed into service throughout the first three quarters of 2014, and the

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recognition of unrealized losses in determining the fair value of our interest rate swap agreements. We did not have interest rate swap agreements during the year ended December 31, 2014.

ANALYSIS OF INVESTMENTS IN UNCONSOLIDATED AFFILIATES

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


	Nine months ended September 30,
	2015		2014
BOSTCO	$	8,244	$	2,617
Frontera		1,520		474
Total earnings from investments in unconsolidated affiliates	$	9,764	$	3,091

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


	Nine months ended September 30,
	2015		2014
BOSTCO	$	4,226	$	43,635
Frontera		—		45
Additional capital investments in unconsolidated affiliates	$	4,226	$	43,680

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


	Nine months ended September 30,
	2015		2014
BOSTCO	$	13,363	$	4,072
Frontera		2,099		1,625
Cash distributions received from unconsolidated affiliates	$	15,462	$	5,697

The increase in earnings and distributions received from our investment in BOSTCO is attributable to the BOSTCO terminal being placed into service throughout the first three quarters of 2014 and a one-time gain resulting from a contract buy-out by one of its customers in April of 2015. Our share of the gain was approximately $3.4 million, which we received in cash as a component of our third quarter 2015 distribution from BOSTCO.

LIQUIDITY AND CAPITAL RESOURCES

Our primary liquidity needs are to fund our working capital requirements, distributions to unitholders, approved investments, approved capital projects and approved future expansion, development and acquisition opportunities. We expect to initially fund any investments, capital projects and future expansion, development and acquisition opportunities, with additional borrowings under our credit facility (see Note 12 of Notes to consolidated financial statements). After initially funding these expenditures with borrowings under our credit facility, we may raise funds through additional equity offerings and debt financings. The proceeds of such equity offerings and debt financings may then be used to reduce our outstanding borrowings under our credit facility.

Our capital expenditures for the nine months ended September 30, 2015 were approximately $24.5 million for terminal and pipeline facilities and assets to support these facilities. Management and the board of directors of our general partner have approved additional investments and expansion projects at our terminals that currently are, or will

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be, under construction with estimated completion dates that extend through the first quarter of 2017. The remaining expenditures to complete the approved projects are estimated to be approximately $50 million, which includes the construction costs associated with the first phase of our tank expansion at our Collins, Mississippi terminal. We expect to fund our future investment and expansion expenditures with additional borrowings under our credit facility.

Amended and restated senior secured credit facility. On March 9, 2011, we entered into an amended and restated senior secured credit facility, or “credit facility”, which has been subsequently amended from time to time. Concurrent with the Fifth Amendment to the credit facility, which was effective as of February 26, 2015 (see Note 12 of Notes to consolidated financial statements), the credit facility provides for a maximum borrowing line of credit equal to the lesser of (i) $400 million and (ii) 4.75 times Consolidated EBITDA (as defined: $401.2 million at September 30, 2015). At our request, the maximum borrowing line of credit may be increased by an additional $100 million, subject to the approval of the administrative agent and the receipt of additional commitments from one or more lenders. The terms of the credit facility include covenants that restrict our ability to make cash distributions, acquisitions and investments, including investments in joint ventures. We may make distributions of cash to the extent of our “available cash” as defined in our partnership agreement. We may make acquisitions and investments that meet the definition of “permitted acquisitions”; “other investments” which may not exceed 5% of “consolidated net tangible assets”; and additional future “permitted JV investments” up to $125 million, which may include additional investments in BOSTCO. The principal balance of loans and any accrued and unpaid interest are due and payable in full on the maturity date, July 31, 2018.

We may elect to have loans under the credit facility bear interest either (i) at a rate of LIBOR plus a margin ranging from 2% to 3% depending on the total leverage ratio then in effect, or (ii) at the base rate plus a margin ranging from 1% to 2% depending on the total leverage ratio then in effect. We also pay a commitment fee on the unused amount of commitments, ranging from 0.375% to 0.5% per annum, depending on the total leverage ratio then in effect. Our obligations under the credit facility are secured by a first priority security interest in favor of the lenders in the majority of our assets, including our investments in unconsolidated affiliates. At September 30, 2015, our outstanding borrowings under the credit facility were $249.6 million.

The credit facility also contains customary representations and warranties (including those relating to organization and authorization, compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults, covenant defaults, cross defaults and bankruptcy events). The primary financial covenants contained in the credit facility are (i) a total leverage ratio test (not to exceed 4.75 times), (ii) a senior secured leverage ratio test (not to exceed 3.75 times) in the event we issue senior unsecured notes, and (iii) a minimum interest coverage ratio test (not less than 3.0 times). These financial covenants are based on a defined financial performance measure within the credit facility known as “Consolidated EBITDA.” The calculation of the “total leverage ratio” and “interest coverage ratio” contained in the credit facility is as follows (in thousands, except ratios):

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									Twelve months
	Three months ended								ended
	December 31,		March 31,		June 30,		September 30,		September 30,
	2014		2015		2015		2015		2015
Financial performance debt covenant test:
Consolidated EBITDA for the total leverage ratio, as stipulated in the credit facility	$	18,278	$	21,325	$	21,612	$	23,252	$	84,467
Consolidated funded indebtedness									$	249,600
Total leverage ratio										2.96	x
Consolidated EBITDA for the interest coverage ratio	$	18,278	$	21,325	$	21,612	$	23,252	$	84,467
Consolidated interest expense, as stipulated in the credit facility (1)	$	1,817	$	1,793	$	2,002	$	1,737	$	7,349
Interest coverage ratio										11.49	x
Reconciliation of consolidated EBITDA to cash flows provided by operating activities:
Consolidated EBITDA	$	18,278	$	21,325	$	21,612	$	23,252	$	84,467
Consolidated interest expense		(1,817)		(1,942)		(1,943)		(2,198)		(7,900)
Unrealized loss (gain) on derivative instruments		—		149		(59)		461		551
Amortization of deferred revenue		(516)		(309)		(258)		(437)		(1,520)
Change in operating assets and liabilities		3,019		826		(205)		7,696		11,336
Cash flows provided by operating activities	$	18,964	$	20,049	$	19,147	$	28,774	$	86,934

(1)Consolidated interest expense, used in the calculation of the interest coverage ratio, excludes unrealized gains and losses recognized on our derivative instruments.

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

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information contained in this Item 3 updates, and should be read in conjunction with, information set forth in Part II, Item 7A of our Annual Report on Form 10‑K, filed on March 12, 2015, in addition to the interim unaudited consolidated financial statements, accompanying notes and Management’s Discussion and Analysis of Financial Condition and Results of Operations presented in Part 1, Items 1 and 2 of this Quarterly Report on Form 10‑Q. There are no material changes in the market risks faced by us from those reported in our Annual Report on Form 10‑K for the year ended December 31, 2014.

Market risk is the risk of loss arising from adverse changes in market rates and prices. A principal market risk to which we are exposed is interest rate risk associated with borrowings under our credit facility. Borrowings under our credit facility bear interest at a variable rate based on LIBOR or the lender’s base rate. We manage a portion of our interest rate risk with interest rate swaps, which reduce our exposure to changes in interest rates by converting variable interest rates to fixed interest rates. At September 30, 2015, we are party to interest rate swap agreements with an aggregate notional amount of $75.0 million that expire March 25, 2018. Pursuant to the terms of the interest rate swap agreements, we pay a blended fixed rate of approximately 1.05% and receive interest payments based on the one-month LIBOR. The net difference to be paid or received under the interest rate swap agreements is settled monthly and is recognized as an adjustment to interest expense. At September 30, 2015, we had outstanding borrowings of $249.6 million under our credit facility. Based on the outstanding balance of our variable‑interest‑rate debt at September

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30, 2015, the terms of our interest rate swap agreements and assuming market interest rates increase or decrease by 100 basis points, the potential annual increase or decrease in interest expense is approximately $1.7 million.

We do not purchase or market products that we handle or transport and, therefore, we do not have material direct exposure to changes in commodity prices, except for the value of product gains arising from certain of our terminaling services agreements with our customers. Pursuant to our Southeast terminaling services agreement, we agreed to rebate to our affiliate customer 50% of the proceeds we receive annually in excess of $4.2 million from the sale of product gains at our Southeast terminals. We do not use derivative commodity instruments to manage the commodity risk associated with the product we may own at any given time. Generally, to the extent we are entitled to retain product pursuant to terminaling services agreements with our customers, we sell the product to our customers on a contractually established periodic basis; the sales price is based on industry indices. For the nine months ended September 30, 2015 and 2014, we sold approximately 86,000 and 108,150 barrels, respectively, of product gained resulting from differences in the measurement of product volumes received and distributed at our terminaling facilities at average prices of approximately $68 and $116 per barrel, respectively.

ITEM 4. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the Commission’s rules and forms, and that information is accumulated and communicated to the management of our general partner, including our general partner’s principal executive and principal financial officer (whom we refer to as the Certifying Officers), as appropriate to allow timely decisions regarding required disclosure. The management of our general partner evaluated, with the participation of the Certifying Officers, the effectiveness of our disclosure controls and procedures as of September 30, 2015, pursuant to Rule 13a‑15(b) under the Exchange Act. Based upon that evaluation, the Certifying Officers concluded that, as of September 30, 2015, our disclosure controls and procedures were effective. There were no changes in our internal control over financial reporting that occurred during our most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Part II. Other Information

ITEM 1. LEGAL PROCEEDINGS

See the information under “Legal Proceedings” in Note 16, “Commitments and Contingencies”, of the Notes to consolidated financial statements in Part I, Item 1 of this Form 10-Q, which information is incorporated by reference to this item.

ITEM 1A. RISK FACTORS

The following risk factors, discussed in more detail below and in “Item 1A. Risk Factors,” in our Annual Report on Form 10‑K, filed on March 12, 2015, are expressly incorporated into this report by reference, are important factors that could cause actual results to differ materially from our expectations and may adversely affect our business and results of operations, include, but are not limited to:

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

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

failure by any of our significant customers to continue to engage us to provide services after the expiration of existing terminaling services agreements or our failure to secure comparable alternative arrangements;

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

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

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

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

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

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

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

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

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

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

the ability of our significant customers to secure financing arrangements adequate to purchase their desired volume of product;

the impact on our facilities or operations of extreme weather conditions, such as hurricanes, and other events, such as terrorist attacks or war and costs associated with environmental compliance and remediation;

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

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

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

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

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

timing, cost and other economic uncertainties related to the construction of new tank capacity or facilities;

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the impact of current and future laws and governmental regulations, general economic, market or business conditions;

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

cost reimbursements, which are determined by our general partner, and fees paid to our general partner and its affiliates for services will continue to be substantial;

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

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

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

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

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

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

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

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

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

the sale or exchange of 50% or more of our capital and profits interests within a 12‑month period would result in a deemed technical termination of our partnership for income tax purposes.

There have been no material changes from risk factors as previously disclosed in our annual report on Form 10‑K for the year ended December 31, 2014, filed on March 12, 2015.

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ITEM 6. EXHIBITS


31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes‑Oxley Act of 2002.
31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes‑Oxley Act of 2002.
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002.
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002.
101	The following financial information from the Quarterly Report on Form 10‑Q of TransMontaigne Partners L.P. and subsidiaries for the quarter ended September 30, 2015, formatted in XBRL (eXtensible Business Reporting Language): (i) consolidated balance sheets, (ii) consolidated statements of operations, (iii) consolidated statements of partners’ equity, (iv) consolidated statements of cash flows and (v) notes to the consolidated financial statements.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		Chief Executive Officer
Date: November 5, 2015	TransMontaigne Partners L.P. (Registrant)

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


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


	By:	/s/ Robert T. Fuller Robert T. Fuller Chief Financial Officer

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EXHIBIT INDEX


Exhibit number		Description of exhibits
31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes‑Oxley Act of 2002.
31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes‑Oxley Act of 2002.
32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002.
32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002.
101		The following financial information from the Quarterly Report on Form 10‑Q of TransMontaigne Partners L.P. and subsidiaries for the quarter ended September 30, 2015, formatted in XBRL (eXtensible Business Reporting Language): (i) consolidated balance sheets, (ii) consolidated statements of operations, (iii) consolidated statements of partners’ equity, (iv) consolidated statements of cash flows and (v) notes to the consolidated financial statements.