10-Q

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 March 31, 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 April 30, 2015, there were 16,124,566 units of the registrant’s Common Limited Partner Units outstanding.

TABLE OF CONTENTS

		Page No.
Part I. Financial Information
Item 1.	Unaudited Consolidated Financial Statements	3
	Consolidated balance sheets as of March 31, 2015 and December 31, 2014	4
	Consolidated statements of operations for the three months ended March 31, 2015 and 2014	5
	Consolidated statements of partners’ equity for the year ended December 31, 2014 and three months ended March 31, 2015	6
	Consolidated statements of cash flows for the three months ended March 31, 2015 and 2014	7
	Notes to consolidated financial statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	36
Item 4.	Controls and Procedures	37
Part II. Other Information
Item 1.	Legal Proceedings	38
Item 1A.	Risk Factors	38
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 5.	Other Information	41
Item 6.	Exhibits	41

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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 months ended March 31, 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 months ended March 31, 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)

	March 31,		December 31,
	2015		2014
ASSETS
Current assets:
Cash and cash equivalents	$	918	$	3,304
Trade accounts receivable, net		8,761		9,359
Due from affiliates		1,194		1,316
Other current assets		2,772		3,065
Total current assets		13,645		17,044
Property, plant and equipment, net		385,840		385,301
Goodwill		8,485		8,485
Investments in unconsolidated affiliates		248,090		249,676
Other assets, net		3,972		3,551
	$	660,032	$	664,057
LIABILITIES AND EQUITY
Current liabilities:
Trade accounts payable	$	6,565	$	6,887
Accrued liabilities		11,010		9,835
Total current liabilities		17,575		16,722
Other liabilities		3,541		3,870
Long-term debt		250,000		252,000
Total liabilities		271,116		272,592
Commitments and contingencies (Note 15)
Partners’ equity:
Common unitholders (16,124,566 units issued and outstanding at March 31, 2015 and December 31, 2014)		331,121		333,619
General partner interest (2% interest with 329,073 equivalent units outstanding at March 31, 2015 and December 31, 2014)		57,795		57,846
Total partners’ equity		388,916		391,465
	$	660,032	$	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		Three Months Ended
	March 31,		March 31,
	2015		2014
Revenue:
External customers	$	25,299	$	13,623
Affiliates		12,598		24,430
Total revenue		37,897		38,053
Operating costs and expenses and other:
Direct operating costs and expenses		(14,954)		(15,392)
Direct general and administrative expenses		(1,021)		(918)
Allocated general and administrative expenses		(2,803)		(2,782)
Allocated insurance expense		(934)		(914)
Reimbursement of bonus awards expense		(525)		(375)
Depreciation and amortization		(7,337)		(7,400)
Earnings from unconsolidated affiliates		2,056		163
Total operating costs and expenses and other		(25,518)		(27,618)
Operating income		12,379		10,435
Other expenses:
Interest expense		(1,942)		(953)
Amortization of deferred financing costs		(315)		(244)
Total other expenses		(2,257)		(1,197)
Net earnings		10,122		9,238
Less—earnings allocable to general partner interest including incentive distribution rights		(1,850)		(1,756)
Net earnings allocable to limited partners	$	8,272	$	7,482
Net earnings per limited partner unit—basic and diluted	$	0.51	$	0.46

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 three months ended March 31, 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)
Deferred equity-based compensation related to restricted phantom units		721		—		721
Purchase of 8,004 common units by our long-term incentive plan		(342)		—		(342)
Issuance of 20,500 common units by our long-term incentive plan 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		(10,723)		(1,901)		(12,624)
Deferred equity-based compensation related to restricted phantom units		23		—		23
Purchase of 2,001 common units by our long-term incentive plan		(70)		—		(70)
Net earnings for three months ended March 31, 2015		8,272		1,850		10,122
Balance March 31, 2015	$	331,121	$	57,795	$	388,916

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		Three Months Ended
	March 31,		March 31,
	2015		2014
Cash flows from operating activities:
Net earnings	$	10,122	$	9,238
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation and amortization		7,337		7,400
Earnings from unconsolidated affiliates		(2,056)		(163)
Distributions from unconsolidated affiliates		3,642		750
Deferred equity-based compensation		23		52
Amortization of deferred financing costs		315		244
Amortization of deferred revenue		(309)		(740)
Unrealized loss on derivative instrument		149		—
Changes in operating assets and liabilities, net of effects from acquisitions and dispositions:
Trade accounts receivable, net		598		(601)
Due from affiliates		122		(224)
Other current assets		293		191
Amounts due under long-term terminaling services agreements, net		41		277
Trade accounts payable		(1,403)		(657)
Due to affiliates		—		57
Accrued liabilities		1,175		(4,474)
Net cash provided by operating activities		20,049		11,350
Cash flows from investing activities:
Investments in unconsolidated affiliates		—		(18,017)
Capital expenditures		(6,744)		(1,723)
Net cash used in investing activities		(6,744)		(19,740)
Cash flows from financing activities:
Borrowings of debt under credit facility		20,800		39,000
Repayments of debt under credit facility		(22,800)		(17,000)
Deferred debt issuance costs		(997)		—
Distributions paid to unitholders		(12,624)		(12,136)
Purchase of common units by our long-term incentive plan		(70)		(85)
Net cash provided by (used in) financing activities		(15,691)		9,779
Increase (decrease) in cash and cash equivalents		(2,386)		1,389
Cash and cash equivalents at beginning of period		3,304		3,263
Cash and cash equivalents at end of period	$	918	$	4,652
Supplemental disclosures of cash flow information:
Cash paid for interest	$	1,615	$	945
Property, plant and equipment acquired with accounts payable	$	2,354	$	341

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 March 31, 2015,  NGL Energy Partners LP (“NGL”) owned all of the issued and outstanding capital stock of TransMontaigne LLC, and as a resultNGL is the indirect owner of our general partner. At March 31, 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 Stanleyand 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 March 31, 2015 and December 31, 2014 and our results of operations for the three months ended March 31, 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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(c) Accounting for terminal and pipeline operations

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 March 31, 2015 and 2014, we recognized revenue of approximately $1.8 million and $3.6 million, respectively, for net product gained. Within these amounts, approximately $0.9 million and $2.5 million for the three months ended March 31, 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.

(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

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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 plan

Generally accepted accounting principles require us to measure the cost of services received in exchange for an award of equity instruments based on the grant‑date fair value of the award. That cost will be recognized over the period during which a board member or employee is required to provide services in exchange for the award. We are required to estimate the number of equity instruments that are expected to vest in measuring the total compensation cost to be recognized over the related service period. Compensation cost is recognized over the service period on a straight‑line basis.

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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 March 31, 2015, our derivative instruments were limited to an interest rate swap agreement with a notional amount of $40.0 million that expires March 2018. Pursuant to the terms of the interest rate swap agreement, we pay a fixed rate of approximately 1.09% and receive an interest payment based on the one-month LIBOR. The net difference to be paid or received under the interest rate swap agreement is settled monthly and is recognized as an adjustment to interest expense. The fair value of our interest rate swap was 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 the long‑term incentive plan that participate in Partners’ distributions (see Note 16 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 partnership 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 partnership 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, 2016, including interim periods within that reporting period. We are currently evaluating the potential impact that the adoption will have on our disclosures and financial statements.

In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs.The objective of this update is to present debt issuance costs in the balance sheet as a reduction from the related debt liability rather than as an asset.  ASU 2015-03 is effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period.  Upon adoption, our unamortized debt issuance costs will be reclassified from other assets, net to long-term debt.

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(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.

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 March 31, 2015 and 2014, the administrative fee paid to TransMontaigne LLC was approximately $2.8 million and $2.8 million, respectively.If we acquire or construct additional facilities, TransMontaigne LLC will propose a revised administrative fee covering the provision of services for such additional facilities. If the conflicts committee of our general partner agrees to the revised administrative fee, TransMontaigne LLC will provide services for the additional facilities pursuant to the agreement. The administrative fee includes expenses incurred by TransMontaigne LLC to perform centralized corporate functions, such as legal, accounting, treasury, insurance administration and claims processing, health, safety and environmental, information technology, human resources, credit, payroll, taxes and engineering and other corporate services, to the extent such services are not outsourced by TransMontaigne LLC.

The omnibus agreement further provides that we pay TransMontaigne LLC an insurance reimbursement for premiums on insurance policies covering our facilities and operations. For the three months ended March 31, 2015 and 2014, the insurance reimbursement paid to TransMontaigne LLC was approximately $0.9 million and $0.9 million, respectively. We also reimburse TransMontaigne LLC for direct operating costs and expenses that TransMontaigne LLC incurs on our behalf, such as salaries of operational personnel performing services on‑site at our terminals and pipelines and the cost of their employee benefits, including 401(k) and health insurance benefits.

Under the omnibus agreement we have agreed to reimburse TransMontaigne LLCfor a portion of the incentive bonusawardsmade 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 bonusawards are allocated to an investment fund indexed to the performance of our common units. The value of ourincentive bonus awards reimbursement for a single grant year maybe no less than $1.5 million.  Effective April 14, 2015,  and beginning with our reimbursement for the 2015 incentive bonusawards, we have the option to provide the reimbursement in either cash or our common units, with the reimbursement payable by us in accordance with the underlying employee vesting and payment schedule of the TransMontaigne Services LLC savings and retention plan. Prior to the 2015 incentive bonusawards, we reimbursed our portion of the incentive bonusawards by making cash payments to TransMontaigne LLC over the first year that each applicable award was granted.  Our expenses associated with the reimbursement of incentive bonus awards were approximately $0.5 million and $0.4 million for the three months ended March 31, 2015 and 2014, 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 is expected to become available to RaceTrac Petroleum Inc. in the third quarter 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 0.5 million barrels of this capacity to World Fuel Services Corporation and RaceTrac Petroleum Inc. at similar rates charged to NGL.  The 0.5 million barrels of tankage became available to these third party customers in May of 2015.

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,

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which runs from Mount Vernon to Rogers. We refer to these terminals and the related pipeline as the Razorback system. 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 $5.7 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, Morgan Stanley Capital Group’s 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 to Morgan Stanley Capital Group, Morgan Stanley Capital Group 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 Acquisitionthe 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, Morgan Stanley Capital Group’s 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 to Morgan Stanley Capital Group, Morgan Stanley Capital Group 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, Morgan Stanley Capital Group’s obligations would be temporarily suspended. If a force majeure event continues for 120 consecutive days, Morgan Stanley Capital Group 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 March 31, 2015 and 2014, we recognized revenue of approximately $1.2 million and $0.8 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 involvedthe construction of 51 storage tanks with approximately 6.2 million barrels of storage capacity. The BOSTCO

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facility began initial commercial operation in the fourth quarter of 2013. Completion of the full 6.2 million barrels of storage capacity and related infrastructure occurred in the second quarter of 2014.

On June 5, 2013, we announced an expansion of BOSTCO 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 fully subscribed capacity of approximately 7.1 million barrels at an overall construction cost of approximately $529 million. Our total payments for the initial and for the expansion projects are estimated to be approximately $233 million, which includes our proportionate share of the BOSTCO project costs and necessary start‑up working capital, a one‑time buy‑in fee paid to Kinder Morgan to acquire our 42.5% interest and the capitalization of interest on our investment during the construction of BOSTCO. We have funded our payments for BOSTCO utilizing borrowings under our credit facility.

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

(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 and the United States government. 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):

	March 31,		December 31,
	2015		2014
Trade accounts receivable	$	9,225	$	9,823
Less allowance for doubtful accounts		(464)		(464)
	$	8,761	$	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		Three Months Ended
	March 31,		March 31,
	2015		2014
NGL Energy Partners LP	30	%	—	%
Morgan Stanley Capital Group	13	%	62	%

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(5) OTHER CURRENT ASSETS

Other current assets are as follows (in thousands):

	March 31,		December 31,
	2015		2014
Amounts due from insurance companies	$	1,094	$	1,233
Additive detergent		1,361		1,591
Deposits and other assets		317		241
	$	2,772	$	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 March 31, 2015 and December 31, 2014, we have recognized amounts due from insurance companies of approximately $1.1 million and $1.2 million, respectively, representing our best estimate of our probable insurance recoveries. During the three months ended March 31, 2015, we received reimbursements from insurance companies of approximately$0.1million. During the three months ended March 31, 2015, we did not adjust our estimate of probable insurance recoveries.

(6) PROPERTY, PLANT AND EQUIPMENT, NET

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

	March 31,		December 31,
	2015		2014
Land	$	52,519	$	52,519
Terminals, pipelines and equipment		568,495		566,677
Furniture, fixtures and equipment		2,122		2,122
Construction in progress		11,451		5,444
		634,587		626,762
Less accumulated depreciation		(248,747)		(241,461)
	$	385,840	$	385,301

(7) GOODWILL

Goodwill is as follows (in thousands):

	March 31,		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 March 31, 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 three months ended March 31, 2015 or during the year ended December 31, 2014 for this reporting unit.  However, a significant decline in the price

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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 March 31, 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 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)
	March 31,		December 31,		March 31,		December 31,
	2015		2014		2015		2014
BOSTCO	42.5	%	42.5	%	$	224,567	$	225,920
Frontera	50	%	50	%		23,523		23,756
Total investments in unconsolidated affiliates					$	248,090	$	249,676

At March 31, 2015 and December 31, 2014, our investment in BOSTCO includes approximately $7.7 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		Three Months Ended
	March 31,		March 31,
	2015		2014
BOSTCO	$	1,781	$	(80)
Frontera		275		243
Total earnings from investments in unconsolidated affiliates	$	2,056	$	163

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

	Three Months Ended		Three Months Ended
	March 31,		March 31,
	2015		2014
BOSTCO	$	—	$	17,972
Frontera		—		45
Additional capital investments in unconsolidated affiliates	$	—	$	18,017

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

	Three Months Ended		Three Months Ended
	March 31,		March 31,
	2015		2014
BOSTCO	$	3,134	$	113
Frontera		508		637
Cash distributions received from unconsolidated affiliates	$	3,642	$	750

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

Balance sheets:

	BOSTCO				Frontera
	March 31,		December 31,		March 31,		December 31,
	2015		2014		2015		2014
Current assets	$	13,710	$	19,400	$	4,588	$	4,222
Long-term assets		507,654		511,373		43,805		44,528
Current liabilities		(11,188)		(17,435)		(1,347)		(1,238)
Long-term liabilities		—		—		—		—
Net assets	$	510,176	$	513,338	$	47,046	$	47,512

Statements of operations:

	BOSTCO				Frontera
	Three Months Ended				Three Months Ended
	March 31,				March 31,
	2015		2014		2015		2014
Revenue	$	15,887	$	8,337	$	3,640	$	3,045
Expenses		(11,467)		(8,455)		(3,090)		(2,559)
Net earnings (loss)	$	4,420	$	(118)	$	550	$	486

(9) OTHER ASSETS, NET

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

	March 31,		December 31,
	2015		2014
Amounts due under long-term terminaling services agreements:
External customers	$	552	$	649
Affiliates		832		945
		1,384		1,594
Deferred financing costs, net of accumulated amortization of $3,593 and $3,278, respectively		1,820		1,138
Customer relationships, net of accumulated amortization of $1,738 and $1,687, respectively		692		743
Deposits and other assets		76		76
	$	3,972	$	3,551

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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 March 31, 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 $1.4 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):

	March 31,		December 31,
	2015		2014
Customer advances and deposits:
External customers	$	2,695	$	2,756
Affiliates		2,677		—
		5,372		2,756
Accrued property taxes		1,497		892
Accrued environmental obligations		1,376		1,524
Interest payable		193		159
Rebate due to affiliate		—		1,795
Accrued expenses and other		2,572		2,709
	$	11,010	$	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 March 31, 2015 and December 31, 2014, we have billed and collected from certain of our customers approximately $5.4 million and $2.8 million, respectively, in advance of the terminaling services being provided.

Accrued environmental obligations.  At March 31, 2015 and December 31, 2014, we have accrued environmental obligations of approximately $1.4 million and $1.5 million, respectively, representing our best estimate of our remediation obligations. During the three months ended March 31, 2015, we made payments of approximately $0.1 million towards our environmental remediation obligations. During the three months ended March 31, 2015, we did not change our estimate of our future environmental remediation costs. 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 customer50% of the proceeds we receive annually in excess of $4.2 million from the sale of product gains at our Southeast terminals. At March 31, 2015 and December 31, 2014, we have accrued a liability due to affiliate of approximately $nil and $1.8 million, respectively. During the three months ended March 31, 2015, we paid approximately $1.8 million to our affiliate customerfor the rebate due for the year ended December 31, 2014.

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(11) OTHER LIABILITIES

Other liabilities are as follows (in thousands):

	March 31,		December 31,
	2015		2014
Advance payments received under long-term terminaling services agreements	$	282	$	451
Deferred revenue—ethanol blending fees and other projects		3,110		3,419
Unrealized loss on derivative instrument		149		—
	$	3,541	$	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 March 31, 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 $0.3 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 March 31, 2015 and December 31, 2014, we have unamortized deferred revenue of approximately $3.1 million and $3.4 million, respectively, for completed projects. During the three months ended March 31, 2015 and 2014, we recognized revenue on a straight‑line basis of approximately $0.3 million and $0.7 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 facilityfrom 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.

At March 31, 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: $368.7 million at March 31, 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

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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.

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).

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 March 31, 2015.

For the three months ended March 31, 2015 and 2014, the weighted average interest rate on borrowings under the credit facility was approximately 2.7% and 2.6%, respectively.  At March 31, 2015 and December 31, 2014, our outstanding borrowings under the credit facility were $250million and $252 million, respectively. At March 31, 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.

(13) PARTNERS’ EQUITY

The number of units outstanding is as follows:

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

At March 31, 2015 and December 31, 2014, common units outstanding include 9,601 and 7,600 common units, respectively, held on behalf of TransMontaigne LLC’s long‑term incentive plan.

(14) LONG‑TERM INCENTIVE PLAN

TransMontaigne GP is our general partner and manages our operations and activities. TransMontaigne GP is an indirect wholly owned subsidiary of TransMontaigne LLC. TransMontaigne Services LLC is an indirect wholly owned subsidiary of TransMontaigne LLC. TransMontaigne Services LLC employs the personnel who provide support to TransMontaigne LLC’s operations, as well as our operations. TransMontaigne Services LLC adopted a long‑term incentive plan for its employees and consultants and the independent directors of our general partner. 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

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end of the preceding fiscal year. At March 31, 2015,  2,501,948 units are available for future grant under the long‑term incentive plan. Ownership in the awards is subject to forfeiture until the vesting date, but recipients have distribution and voting rights from the date of grant. 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 to the independent directors of our general partner. TransMontaigne GP has historically purchased outstanding common units on the open market for purposes of making grants of restricted phantom units to independent directors of our general partner.

TransMontaigne GP, on behalf of the long‑term incentive plan, has purchased 2,001 and 2,001 common units pursuant to the program during the three months ended March 31, 2015 and 2014, respectively.

Information about restricted phantom unit activity for the three months ended March 31, 2015 is as follows:

		Restricted
	Available for	phantom
	future grant	units
Units outstanding at December 31, 2014	2,179,457	9,000
Automatic increase in units available for future grant on January 1, 2015	322,491	—
Units outstanding at March 31, 2015	2,501,948	9,000

We typically recognize the deferred equity‑based compensation expense associated with annual grants under the long-term incentive plan on a straight-line basis over their respective four-year vesting periods.  However, pursuant to the terms of the long‑term incentive plan, all outstanding grants of restricted phantom units vest upon a change in control of TransMontaigne LLC. Accordingly, as a result of Morgan Stanley’s sale of its 100% ownership interest in TransMontaigne LLC to NGL, effective July 1, 2014 all 15,000 of the then outstanding restricted phantom units vested, and equivalent common units were delivered to the independent directors of our general partner at that time.

In September of 2014, our general partner appointed three new independent directors to replace the independent directors that had resigned in August of 2014.  The new independent directors, in aggregate, were granted 9,000 restricted phantom units on September 30, 2014.  We will recognize the deferred equity‑based compensation expense associated with these grants on a straight-line basis over their respective four‑year vesting periods.

Deferred equity‑based compensation of approximately $23,000 and $52,000 is included in direct general and administrative expenses for the three months ended March 31, 2015 and 2014, respectively.

(15) COMMITMENTS AND CONTINGENCIES

Contract commitments.  At March 31, 2015, we have contractual commitments of approximately $10.5 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 March 31, 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)	$	2,835
2016		3,981
2017		3,003
2018		607
2019		594
Thereafter		3,414
	$	14,434

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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 $1.0  million in future periods.

Rental expense under operating leases was approximately $0.9million and $0.9 million for the three months ended March 31, 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.  In an effort to increase Nieto’s ability to transport LPG through the Diamondback pipeline during the period that the King Ranch plant was not operating and in reliance upon Nieto’s promise to reimburse us for the costs of construction, we constructed a truck unloading facility at our Brownsville terminal for Nieto’s use at a cost of approximately $0.5 million.  Nieto disputes requesting such a facility and has not reimbursed us for it.  Nieto also has claimed that the fire at the 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 and Nieto’s failure to reimburse us for the costs of the truck unloading facility that we constructed for it, on September 26, 2014, we filed a complaint for damages and declaratory relief in the Supreme Court of the State of New York, County of New York, against Nieto, by which we seek damages that have accumulated as of March 31, 2015 in the amount of at least $6.2 million and a declaratory judgment clarifying our rights to receive the deficiency fees under the terminaling services agreement.

(16) 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		Three Months Ended
	March 31,		March 31,
	2015		2014
Net earnings	$	10,122	$	9,238
Less:
Distributions payable on behalf of incentive distribution rights		(1,682)		(1,603)
Distributions payable on behalf of general partner interest		(219)		(217)
Earnings allocable to general partner interest less than distributions payable to general partner interest		51		64
Earnings allocable to general partner interest including incentive distribution rights		(1,850)		(1,756)
Net earnings allocable to limited partners per the consolidated statements of operations	$	8,272	$	7,482
Less distributions payable on behalf of unvested long-term incentive plan grants		(6)		(10)
Net earnings allocable to limited partners for calculating net earnings per limited partner unit	$	8,266	$	7,472
Basic and diluted weighted average units		16,125		16,103
Net earnings per limited partner unit—basic and diluted	$	0.51	$	0.46

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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

(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 the best information available in the circumstances. The following methods and assumptions were used to estimate the fair value of financial instruments at March 31, 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 instrument.  The carrying amount of our interest rate swap as of March 31, 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		Three Months Ended
	March 31,		March 31,
	2015		2014
Gulf Coast Terminals:
Terminaling services fees	$	10,678	$	11,768
Other		1,998		3,001
Revenue		12,676		14,769
Direct operating costs and expenses		(4,406)		(4,837)
Net margins		8,270		9,932
Midwest Terminals and Pipeline System:
Terminaling services fees		2,102		1,993
Pipeline transportation fees		414		327
Other		227		374
Revenue		2,743		2,694
Direct operating costs and expenses		(678)		(704)
Net margins		2,065		1,990
Brownsville Terminals:
Terminaling services fees		1,816		1,497
Pipeline transportation fees		1,182		366
Other		3,962		2,974
Revenue		6,960		4,837
Direct operating costs and expenses		(3,150)		(3,480)
Net margins		3,810		1,357
River Terminals:
Terminaling services fees		2,257		2,021
Other		255		214
Revenue		2,512		2,235
Direct operating costs and expenses		(1,543)		(1,782)
Net margins		969		453
Southeast Terminals:
Terminaling services fees		11,757		11,440
Other		1,249		2,078
Revenue		13,006		13,518
Direct operating costs and expenses		(5,177)		(4,589)
Net margins		7,829		8,929
Total net margins		22,943		22,661
Direct general and administrative expenses		(1,021)		(918)
Allocated general and administrative expenses		(2,803)		(2,782)
Allocated insurance expense		(934)		(914)
Reimbursement of bonus awards expense		(525)		(375)
Depreciation and amortization		(7,337)		(7,400)
Earnings from unconsolidated affiliates		2,056		163
Operating income		12,379		10,435
Other expenses		(2,257)		(1,197)
Net earnings	$	10,122	$	9,238

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

	Three Months Ended March 31, 2015
			Midwest
			Terminals and
	Gulf Coast		Pipeline		Brownsville		River		Southeast
	Terminals		System		Terminals		Terminals		Terminals		Total
Revenue:
External customers	$	9,920	$	2,743	$	5,773	$	2,395	$	4,468	$	25,299
NGL Energy Partners LP		2,756		—		10		117		8,478		11,361
Frontera		—		—		1,177		—		—		1,177
TransMontaigne LLC		—		—		—		—		60		60
Revenue	$	12,676	$	2,743	$	6,960	$	2,512	$	13,006	$	37,897
Capital expenditures	$	3,239	$	437	$	993	$	1,328	$	747	$	6,744
Identifiable assets	$	124,212	$	23,585	$	45,998	$	54,028	$	160,495	$	408,318
Cash and cash equivalents												918
Investments in unconsolidated affiliates												248,090
Deferred financing costs												1,820
Other												886
Total assets											$	660,032

	Three Months Ended March 31, 2014
			Midwest
			Terminals and
	Gulf Coast		Pipeline		Brownsville		River		Southeast
	Terminals		System		Terminals		Terminals		Terminals		Total
Revenue:
External customers	$	6,023	$	807	$	3,996	$	1,951	$	846	$	13,623
Morgan Stanley Capital Group		8,736		1,887		—		284		12,624		23,531
Frontera		—		—		841		—		—		841
TransMontaigne LLC		10		—		—		—		48		58
Revenue	$	14,769	$	2,694	$	4,837	$	2,235	$	13,518	$	38,053
Capital expenditures	$	200	$	28	$	567	$	493	$	435	$	1,723

r

(19) SUBSEQUENT EVENT

On April 13, 2015, we announced a distribution of $0.665 per unit for the period from January 1, 2015 through March 31, 2015. This distribution is payable on May 7, 2015 to unitholders of record on April 30, 2015.

On May 4, 2015, we entered into a new five year terminaling services agreement with Morgan Stanley Capital Group for approximately 2.7 million barrels of product storage capacity at our Collins/Purvis, Mississippi terminals.  The new agreement will be effective January 1, 2016 and will replace the existing agreement we have with Morgan Stanley Capital Group for this tankage.  The new agreement contains an increase to the minimum throughput payments and is anticipated to generate additional minimum throughput revenue in excess of $4.0 million annually.

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

RECENT DEVELOPMENTS

Commercial activity.On May 4, 2015, we entered into a new five year terminaling services agreement with Morgan Stanley Capital Group for approximately 2.7 million barrels of product storage capacity at our Collins/Purvis, Mississippi terminals.  The new agreement will be effective January 1, 2016 and will replace the existing agreement we have with Morgan Stanley Capital Group for this tankage.  The new agreement contains an increase to the minimum throughput payments and is anticipated to generate additional minimum throughput revenue in excess of $4.0 million annually.

We have recently contracted 110,000 barrels of available capacity at our Brownsville, Texas terminals 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.  We have also contracted 119,000 barrels of available capacity at our Louisville and Greater Cincinnati, Kentucky terminals to a different third party for a three year term commencing in May of 2015. The majority of this capacity had been unsubscribed since the beginning of 2012.  These two new agreements in combination are anticipated to generate additional minimum throughput revenue in excess of $2.5 million annually.

Effective March 1, 2015, our Frontera joint venture re-contracted a large portion of its capacity at a throughput rate that is in excess of the throughput rate contained in the previous contract.  The new agreement is anticipated to generate additional revenue at Frontera in excess of $1.5 million annually.  We have a 50% ownership interest in Frontera, and we expect to benefit from its additional revenue through increases in our proportionate share of Frontera’s earnings and cash distributions.

NGL has previously 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 0.5 million barrels of the capacity to World Fuel Services Corporation and RaceTrac Petroleum Inc. at similar rates charged to NGL. The 0.5 million barrels of tankage became available to these third party customers in May of 2015.  We expect to re-contract the remaining available space at Port Everglades North prior to April 30, 2016 and at rates that are at least similar to the current rate charged to NGL.

Quarterly distributions.On January 8, 2015, we announced a distribution of $0.665 per unit for the period from October 1, 2014 through December 31, 2014. This distribution was paid on February 6, 2015 to unitholders of record on January 30, 2015.

On April 13, 2015, we announced a distribution of $0.665 per unit for the period from January 1, 2015 through March 31, 2015. This distribution is payable on May 7, 2015 to unitholders of record on April 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 (see Note 1 of Notes to consolidated financial statements). Certain of these accounting policies require the use of estimates. The following estimates, in management’s opinion, are subjective in nature, require the exercise of judgment, and involve complex analyses: useful lives of our plant and equipment, accrued environmental obligations and 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 MARCH 31, 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 March 31,
	2015		2014
Terminaling services fees	$	28,610	$	28,719
Pipeline transportation fees		1,596		693
Management fees and reimbursed costs		1,932		1,540
Other		5,759		7,101
Revenue	$	37,897	$	38,053

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 March 31,
	2015		2014
Gulf Coast terminals	$	12,676	$	14,769
Midwest terminals and pipeline system		2,743		2,694
Brownsville terminals		6,960		4,837
River terminals		2,512		2,235
Southeast terminals		13,006		13,518
Revenue	$	37,897	$	38,053

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 March 31,
	2015		2014
Gulf Coast terminals	$	10,678	$	11,768
Midwest terminals and pipeline system		2,102		1,993
Brownsville terminals		1,816		1,497
River terminals		2,257		2,021
Southeast terminals		11,757		11,440
Terminaling services fees	$	28,610	$	28,719

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The decrease in terminaling services fees includes a decrease of approximately $0.7 million at our Gulf Coast terminals 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.

Included in terminaling services fees for the three months ended March 31, 2015 and 2014 are fees charged to affiliates of approximately $10.2 million and $19.8 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 March 31,
	2015		2014
Firm commitments:
External customers	$	16,981	$	8,043
Affiliates		9,576		19,688
Total		26,557		27,731
Variable:
External customers		1,364		866
Affiliates		689		122
Total		2,053		988
Terminaling services fees	$	28,610	$	28,719

At March 31, 2015, the remaining terms on the terminaling services agreements that generated “firm commitments” for the three months ended March 31, 2015 wereasfollows (in thousands):

	At
	March 31,
	2015
Remaining minimum terms on terminaling services agreements that generated “firm commitments:”
Less than 1 year remaining	$	4,859
1 year or more, but less than 3 years remaining		16,569
3 years or more, but less than 5 years remaining		4,112
5 years or more remaining		1,017
Total firm commitments for the three months ended March 31, 2015	$	26,557

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Pipeline transportation fees.  We earn pipeline transportation fees at our Razorback, Diamondback and Ella‑Brownsville pipelines based on the volume of product transported and the distance from the origin point to the delivery point. We own the Razorback and Diamondback pipelines, and we lease the Ella‑Brownsville pipeline from a third party. The Federal Energy Regulatory Commission regulates the tariff on our pipelines. The pipeline transportation fees by business segments were as follows (in thousands):

Pipeline Transportation Fees by Business Segment

	Three months ended March 31,
	2015		2014
Gulf Coast terminals	$	—	$	—
Midwest terminals and pipeline system		414		327
Brownsville terminals		1,182		366
River terminals		—		—
Southeast terminals		—		—
Pipeline transportation fees	$	1,596	$	693

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 at the plant.  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 “Item 1. Legal Proceedings” for a discussion of the legal damages we are seeking from Nieto.

Included in pipeline transportation fees for the three months ended March 31, 2015 and 2014are fees charged to affiliates of $nil and approximately $0.1 million, respectively.

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 March 31,
	2015		2014
Gulf Coast terminals	$	191	$	244
Midwest terminals and pipeline system		—		—
Brownsville terminals		1,741		1,296
River terminals		—		—
Southeast terminals		—		—
Management fees and reimbursed costs	$	1,932	$	1,540

Included in management fees and reimbursed costs for the three months ended March 31, 2015 and 2014 are fees charged to affiliates of approximately $1.2 million and $1.1 million, respectively.

Other revenue.  We provide ancillary services including heating and mixing of stored products, product transfer services, railcar handling, wharfage fees and vapor recovery fees. Pursuant to 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

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industry practices, measurement differentials occur as the result of the inherent variances in measurement devices and methodology. We recognize as revenue the net proceeds from the sale of the product gained. Other revenue is composed of the following (in thousands):

Principal Components of Other Revenue

	Three months ended March 31,
	2015		2014
Product gains	$	1,825	$	3,617
Steam heating fees		1,682		1,581
Product transfer services		355		329
Railcar handling		199		230
Other		1,698		1,344
Other revenue	$	5,759	$	7,101

For the three months ended March 31, 2015 and 2014, we sold approximately 27,260 and 38,350 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 $67 and $116 per barrel, respectively. Pursuant to our Southeast terminaling services agreement, we agreed to rebate to our customers 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 March 31, 2015 and 2014, we have accrued a liability due toour customers under the Southeast terminaling services agreement of approximately $nil and $0.8 million, respectively.

Included in other revenue for the three months ended March 31, 2015 and 2014 are amounts charged to affiliates of approximately $1.2 million and  $3.4 million, respectively.

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

Other Revenue by Business Segment

	Three months ended March 31,
	2015		2014
Gulf Coast terminals	$	1,807	$	2,757
Midwest terminals and pipeline system		227		374
Brownsville terminals		2,221		1,678
River terminals		255		214
Southeast terminals		1,249		2,078
Other revenue	$	5,759	$	7,101

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ANALYSIS OF COSTS AND EXPENSES

The direct operating costs and expenses of our operations include the directly related wages and employee benefits, utilities, communications, maintenance and repairs, property taxes, rent, vehicle expenses, environmental compliance costs, materials and supplies. Consistent with historical trends, across our terminaling and transportation facilities we anticipate an increase in repairs and maintenance expenses in the later months of the year as the weather becomes more conducive to these types of projects. The direct operating costs and expenses of our operations were as follows (in thousands):

Direct Operating Costs and Expenses

	Three months ended March 31,
	2015		2014
Wages and employee benefits	$	5,217	$	5,666
Utilities and communication charges		2,069		2,412
Repairs and maintenance		3,095		2,758
Office, rentals and property taxes		2,313		2,298
Vehicles and fuel costs		269		364
Environmental compliance costs		554		661
Other		1,437		1,233
Direct operating costs and expenses	$	14,954	$	15,392

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 March 31,
	2015		2014
Gulf Coast terminals	$	4,406	$	4,837
Midwest terminals and pipeline system		678		704
Brownsville terminals		3,150		3,480
River terminals		1,543		1,782
Southeast terminals		5,177		4,589
Direct operating costs and expenses	$	14,954	$	15,392

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 deferred equity‑based compensation under the long-term incentive plan. The direct general and administrative expenses were approximately $1.0 million and $0.9 million for the three months ended March 31, 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 March 31, 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 March 31, 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 $0.5 million and $0.4 million for the three months ended March 31, 2015 and 2014, respectively.

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For the three months ended March 31, 2015 and 2014, depreciation and amortization expense was approximately $7.3 million and $7.4 million, respectively.

For the three months ended March 31, 2015 and 2014, interest expense was approximately $1.9 million and $1.0 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.

ANALYSIS OF INVESTMENTS IN UNCONSOLIDATED AFFILIATES

At March 31, 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 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 thatencompasses 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)
	March 31,		December 31,		March 31,		December 31,
	2015		2014		2015		2014
BOSTCO	42.5	%	42.5	%	$	224,567	$	225,920
Frontera	50	%	50	%		23,523		23,756
Total investments in unconsolidated affiliates					$	248,090	$	249,676

At March 31, 2015 and December 31, 2014, our investment in BOSTCO includes approximately $7.7 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		Three Months Ended
	March 31,		March 31,
	2015		2014
BOSTCO	$	1,781	$	(80)
Frontera		275		243
Total earnings from investments in unconsolidated affiliates	$	2,056	$	163

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

	Three Months Ended		Three Months Ended
	March 31,		March 31,
	2015		2014
BOSTCO	$	—	$	17,972
Frontera		—		45
Additional capital investments in unconsolidated affiliates	$	—	$	18,017

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

	Three Months Ended		Three Months Ended
	March 31,		March 31,
	2015		2014
BOSTCO	$	3,134	$	113
Frontera		508		637
Cash distributions received from unconsolidated affiliates	$	3,642	$	750

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 three months ended March 31, 2015 were approximately $6.7 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 expansion capital projects at our existing terminals that currently are, or will be, under construction with estimated completion dates that extend throughout 2015. At March 31, 2015, the remaining expenditures to complete the approved additional expansion capital projects are estimated to be approximately $15 million. We expect to fund our future expansion capital 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: $368.7  million at March 31, 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 March 31, 2015, our outstanding borrowings under the credit facility were $250 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

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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):

									Twelve months
	Three months ended								ended
	June 30,		September 30,		December 31,		March 31,		March 31,
	2014		2014		2014		2015		2015
Financial performance debt covenant test:
Consolidated EBITDA for the total leverage ratio, as stipulated in the credit facility	$	20,181	$	17,847	$	18,278	$	21,325	$	77,631
Consolidated funded indebtedness									$	250,000
Total leverage ratio										3.22	x
Consolidated EBITDA for the interest coverage ratio	$	20,181	$	17,847	$	18,278	$	21,325	$	77,631
Consolidated interest expense, as stipulated in the credit facility (1)	$	1,226	$	1,493	$	1,817	$	1,793	$	6,329
Interest coverage ratio										12.27	x
Reconciliation of consolidated EBITDA to cash flows provided by operating activities:
Consolidated EBITDA	$	20,181	$	17,847	$	18,278	$	21,325	$	77,631
Consolidated interest expense		(1,226)		(1,493)		(1,817)		(1,942)		(6,478)
Unrealized loss on derivative instrument		—		—		—		149		149
Amortization of deferred revenue		(671)		(510)		(516)		(309)		(2,006)
Change in operating assets and liabilities		(2,644)		(869)		3,019		826		332
Cash flows provided by operating activities	$	15,640	$	14,975	$	18,964	$	20,049	$	69,628

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

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 an interest rate swap, which reduces our exposure to changes in interest rates by converting variable interest rates to fixed interest rates. At March 31, 2015, we are party to an interest rate swap agreement with a notional amount of $40.0 million that expires March 2018. Pursuant to the terms of the interest rate swap agreement, we

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pay a fixed rate of approximately 1.09% and receive an interest payment based on the one-month LIBOR. The net difference to be paid or received under the interest rate swap agreement is settled monthly and is recognized as an adjustment to interest expense.  At March 31, 2015, we had outstanding borrowings of $250 million under our credit facility. Based on the outstanding balance of our variable‑interest‑rate debt at March 31, 2015, the terms of our interest rate swap agreement and assuming market interest rates increase or decrease by 100 basis points, the potential annual increase or decrease in interest expense is approximately $2.1 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 customers 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 three months ended March 31, 2015 and 2014, we sold approximately 27,260 and 38,350barrels, 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 $67 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 March 31, 2015, pursuant to Rule 13a‑15(b) under the Exchange Act. Based upon that evaluation, the Certifying Officers concluded that, as of March 31, 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.

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Part II. Other Information

ITEM 1.  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.  In an effort to increase Nieto’s ability to transport LPG through the Diamondback pipeline during the period that the King Ranch plant was not operating and in reliance upon Nieto’s promise to reimburse us for the costs of construction, we constructed a truck unloading facility at our Brownsville terminal for Nieto’s use at a cost of approximately $0.5 million.  Nieto disputes requesting such a facility and has not reimbursed us for it.  Nieto also has claimed that the fire at the 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 and Nieto’s failure to reimburse us for the costs of the truck unloading facility that we constructed for it, on September 26, 2014, we filed a complaint for damages and declaratory relief in the Supreme Court of the State of New York, County of New York, against Nieto, by which we seek damages that have accumulated as of March 31, 2015 in the amount of at least $6.2 million and a declaratory judgment clarifying our rights to receive the deficiency fees under the terminaling services agreement.

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;

· 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;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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· 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.

ITEM 2.  UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Purchases of securities.  The following table covers the purchases of our common units by, or on behalf of, Partners during the three months ended March 31, 2015 covered by this report.

				Total number of	Maximum number
				common units	of common units
				purchased as	that may yet be
	Total number of	Average price		part of publicly	purchased under
	common units	paid per		announced	the plans or
Period	purchased	common unit		plans or programs	programs
January	667	$	32.04	667	2,001
February	667	$	37.06	667	1,334
March	667	$	35.64	667	667
	2,001	$	34.91	2,001

During the three months ended March 31, 2015, we purchased 2,001 common units, with approximately $70,000 of aggregate market value, in the open market pursuant to a purchase program announced on March 31, 2013. The purchase program establishes the purchase, from time to time, of our outstanding common units for purposes of making subsequent grants of restricted phantom units under the TransMontaigne Services LLC Long‑Term Incentive Plan to independent directors of our general partner. 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.

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ITEM 5.  OTHER INFORMATION

Amendment to the First Amended and Restated Agreement of Limited Partnership.  On May 5, 2015, our General Partner adopted the Third Amendment to First Amended and Restated Agreement of Limited Partnership of TransMontaigne Partners L.P., effective as May 5, 2015 (the “Third Amendment”) to the First Amended and Restated Agreement of Limited Partnership of the Partnership dated as of May 27, 2005, as previously amended by the First Amendment to Partnership Agreement dated as of January 23, 2006, and by the Second Amendment to Partnership Agreement dated as of April 7, 2008 (collectively referred to as the Amended Partnership Agreement).  The Third Amendment adopted a forum selection clause selecting the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction) as the exclusive forum for suits: (a) arising under the Amended Partnership Agreement; (b) brought in a derivative manner on behalf of the Partnership; (c) asserting a breach of fiduciary or other duty owed by any director, officer, or other employee of the Partnership or the General Partner, or owed by the General Partner, to the Partners or the limited partners; (d) asserting a claim under the Delaware Revised Uniform Limited Partnership Act (or other applicable governing statute); or (e) asserting a claim governed by the internal affairs doctrine.

The foregoing description of the Third Amendment does not purport to be complete and is qualified in its entirety by reference to the Amendment, a copy of which is attached as Exhibit 3.1 to this Quarterly Report on Form 10-Q, which is incorporated into this Item 5 by reference.

ITEM 6.  EXHIBITS

Exhibits:

3.1	Third Amendment to the First Amended and Restated Agreement of Limited Partnership of TransMontaigne Partners L.P. dated May 5, 2015.
10.1	Second Amendment to Amended and Restated Omnibus Agreement, dated as of April 14, 2015, by and among TransMontaigne LLC (formerly known as TransMontaigne Inc.),  TransMontaigne Partners L.P., TransMontaigne GP L.L.C., TransMontaigne Operating GP L.L.C., and TransMontaigne Operating Company L.P.
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 March 31, 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: May  7, 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

42

EXHIBIT INDEX

Exhibit number	Description of exhibits
3.1	Third Amendment to the First Amended and Restated Agreement of Limited Partnership of TransMontaigne Partners L.P. dated May 5, 2015.
10.1	Second Amendment to Amended and Restated Omnibus Agreement, dated as of April 14, 2015, by and among TransMontaigne LLC (formerly known as TransMontaigne Inc.), TransMontaigne Partners L.P., TransMontaigne GP L.L.C., TransMontaigne Operating GP L.L.C., and TransMontaigne Operating Company L.P.
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 March 31, 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.

43

EX-3.1

Exhibit 3.1

THIRD AMENDMENTTO

FIRST AMENDED AND RESTATED AGREEMENT

OF LIMITED PARTNERSHIPOF

TRANSMONTAIGNE PARTNERS L.P.

This Third Amendment (the “Third Amendment”) to the First Amended and RestatedAgreement of Limited Partnership of TransMontaigne Partners L.P. (the “Partnership”) isentered into this 5th day of May, 2015 by TransMontaigne GP L.L.C., a Delaware limited liability company (the "General Partner"), asthe general partner of the Partnership. Capitalized terms used but not defined herein are used as defined in the Partnership Agreement.

RECITALS:

A. The General Partner, the Organizational Limited Partner and the Limited Partners of the Partnership entered into that certain FirstAmended and Restated Agreement of Limited Partnership of the Partnership dated as of May 27, 2005 (the “Partnership Agreement”); and

B. The Partnership Agreement was amended by that certain First Amendment to Amended and Restated Agreement of Limited Partnershipof TransMontaigne Partners L.P. dated as of January 23, 2006 (the “First Amendment”);  

C.  The Partnership Agreement was further amended by that certain Second Amendment to Amended and Restated Agreement of Limited Partnership of TransMontaigne Partners L.P. dated as of April 7, 2008 (the “Second Amendment”, the Partnership Agreement, as amended by the First Amendment and the Second Amendment, the “Amended Partnership Agreement”); and

D.  Acting pursuant to the power and authority granted to it under Section 13.1(d)(i) of the Amended Partnership Agreement, the General Partner hasdetermined that the following amendment to the Amended Partnership Agreement does not require the approval of any Limited Partner.

NOW THEREFORE, the General Partner does hereby further amend the Amended Partnership Agreement as follows:

Section 1. Amendment.

(a) Section 16.8 of the Amended Partnership Agreement is hereby amended in its entirety to read as follows:

Applicable Law; Forum; Venue and Jurisdiction Waiver of Trial by Jury. 

(a) This Agreement shall be construed in accordance with and governed by the laws of the State of Delaware, without regard to the principles of conflicts of law.

Exhibit 3.1

(b) Each of the Partners and each Person holding any beneficial interest in the Partnership (whether through a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing or otherwise):

(i) irrevocably agrees that any claims, suits, actions or proceedings (A) arising out of or relating in any way to this Agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of this Agreement or the duties, obligations or liabilities among Partners or of Partners to the Partnership, or the rights or powers of, or restrictions on, the Partners or the Partnership), (B) brought in a derivative manner on behalf of the Partnership, (C) asserting a claim of breach of a fiduciary duty owed by any director, officer, or other employee of the Partnership or the General Partner, or owed by the General Partner, to the Partnership or the Partners, (D) asserting a claim arising pursuant to any provision of the Delaware Act or (E) asserting a claim governed by the internal affairs doctrine shall be exclusively brought in the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction), in each case regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims;

(ii) irrevocably submits to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction) in connection with any such claim, suit, action or proceeding;

(iii) agrees not to, and waives any right to, assert in any such claim, suit, action or proceeding that (A) it is not personally subject to the jurisdiction (x) of the Court of Chancery of the State of Delaware or of any other court to which proceedings in the Court of Chancery of the State of Delaware may be appealed or, (y) if the Court of Chancery of the State of Delaware does not have subject matter jurisdiction thereof, of any other court located in the State of Delaware with subject matter jurisdiction or of any other court to which proceedings in such lower court may be appealed, (B) such claim, suit, action or proceeding is brought in an inconvenient forum, or (C) the venue of such claim, suit, action or proceeding is improper;

(iv) expressly waives any requirement for the posting of a bond by a party bringing such claim, suit, action or proceeding; and

(v) consents to process being served in any such claim, suit, action or proceeding by mailing, certified mail, return receipt requested, a copy thereof to such party at the address in effect for notices hereunder,

Exhibit 3.1

and agrees that such services shall constitute good and sufficient service of process and notice thereof; provided, nothing in clause (v) hereof shall affect or limit any right to serve process in any other manner permitted by law.

Section 2. Ratification of Amended Partnership Agreement.  Except as expressly modified and amended herein, all of the terms and conditions of the Amended Partnership Agreement shall remain in full force and effect.

Section 3. Governing Law. This Third Amendment will be governed by and construed in accordance with the laws of the State of Delaware.

IN WITNESS WHEREOF, the General Partner has executed this Third Amendment as of the date first set forth above.

GENERAL PARTNER:

TRANSMONTAIGNE GP L.L.C.

By:  /s/ Frederick W. Boutin

Name: Frederick W. Boutin

Title: Chief Executive Officer

EX-10.1

Exhibit 10.1

SECOND AMENDMENT

TO

AMENDED AND RESTATED OMNIBUS AGREEMENT

THIS SECOND AMENDMENT TO AMENDED AND RESTATED OMNIBUS AGREEMENT (“Second Amendment”), dated as of April 14, 2015 (the “Effective Date”) is entered into by and among TransMontaigne LLC., a Delaware limited liability company and formerly known as TransMontaigne Inc. (“TMG”), TransMontaigne GP L.L.C., a Delaware limited liability company (the “General Partner”), TransMontaigne Partners L.P., a Delaware limited partnership (the “Partnership”), TransMontaigne Operating GP L.L.C., a Delaware limited liability company (the “OLP GP”), and TransMontaigne Operating Company L.P., a Delaware limited partnership (the “Operating Partnership”).  The above-named entities are sometimes referred to in this Second Amendment each as a “Party” and collectively as the “Parties.”

R E C I T A L S:

A.The Parties previously entered into the Amended and Restated Omnibus Agreement dated as of December 31, 2007, but effective for all purposes as of January 1, 2008, as amended by theFirst Amendment to Amended and Restated Omnibus Agreement as of July l6, 2013 (collectively, the “Original Agreement”).

B.The Parties desire to amend the Original Agreement in certain respects.

NOW, THEREFORE, in consideration of the premises and the covenants, conditions, and agreements contained herein, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereby agree as follows:

ARTICLE 1
DEFINITIONS AND CONSTRUCTION

1.1Defined Terms.  Capitalized terms and references used but not otherwise defined in this Second Amendment have the respective meanings given to such terms in the Original Agreement. 

1.2Headings.  All headings herein are intended solely for convenience of reference and shall not affect the meaning or interpretation of the provisions of this Second Amendment. 

1.3References.  Each reference in the Original Agreement to “this Restated Agreement”, “herein” or words of like import referring to such Original Agreement shall mean and be a reference to the Original Agreement, as amended by this Second Amendment, and “thereunder”, “thereof” or words of like import shall mean and be a reference to the Original Agreement, as amended by this Second Amendment.  Any notices, requests, certificates and other documents executed and delivered on or after the date hereof may refer to the Original Agreement without making specific reference to this Second Amendment, but nevertheless all such references shall mean the Original Agreement as amended by this Second Amendment.  

ARTICLE  2

AMENDMENT TO AGREEMENT

Section 2.1(b) of the Original Agreement is hereby amended and replaced, in its entirety, to read as follows:

“(b)  Effective as of the date of the Second Amendment, during the Applicable Period, the Compensation Committee and Conflicts Committee of the Partnership’s General Partner shall approve the annual awards granted under the TransMontaigne Services LLC Savings and Retention Plan or any similar successor plan (the “Plan”) to employees performing services to or for the benefit of the Partnership Group.  The aggregate amount of such awards shall be no less than $1.5 million per year.  As awards are payable in accordance with the vesting and payment schedule provided in the Plan, the Partnership shall have the option of paying the awards either in cash or in the Partnership’s common units.  Payments in cash or in the Partnership’s common units may be made to TransMontaigne Services LLC, as the Plan administrator, for the benefit of the plan participants or, alternatively, directly to the plan participants.”

ARTICLE 3

MISCELLANEOUS

3.1Effective Date.  This Second Amendment shall be effective as of Effective Date.

3.2Scope of Second Amendment.  The Original Agreement is amended only as expressly modified by this Second Amendment.  Except as expressly modified by this Second Amendment, the terms of the Original Agreement remain unchanged, and the Original Agreement is hereby ratified and confirmed by the Parties in all respects.  In the event of any inconsistency between the terms of the Original Agreement and this Second Amendment, this Second Amendment shall prevail to the extent of such inconsistency.

3.3Representations and Warranties.  Each Party represents and warrants that this Second Amendment has been duly authorized, executed and delivered by it and that each of this Second Amendment and the Original Agreement constitutes its legal, valid, binding and enforceable obligation, enforceable against it in accordance with its terms, except to the extent such enforceability may be limited by the effect of any applicable bankruptcy, insolvency, reorganization, moratorium or similar laws affecting creditors’ rights generally and by general principles of equity.  

3.4No Waiver.  Except as expressly provided herein, the execution and delivery of this Second Amendment shall not be deemed or construed to (i) constitute an extension, modification or waiver of any term or condition of the Original Agreement, (ii) give rise to any obligation on the part of any Party to extend, modify or waive any term or condition of the Original Agreement, or (iii) be a waiver by any Party of any of its rights under the Original Agreement, at law or in equity.

3.5Reaffirmation.  Each Party hereby reaffirms each and every representation, warranty, covenant, condition, obligation and provision set forth in the Original Agreement, as modified hereby. 

3.6Choice of Law.  This Second Amendment shall be subject to and governed by the laws of the State of Colorado, excluding any conflicts of law, rule or principle that might refer to the construction or interpretation of this Second Amendment to the laws of another state. 

3.7Jurisdiction.  Each Party hereby submits to the jurisdiction of any state or federal court in the State of Colorado and venue in Denver, Colorado (without recourse to arbitration unless both Parties agree in writing), and to service of process by certified mail, delivered to the Party at the most recent designated address.  Each Party hereby irrevocably waives to the fullest extent permitted by applicable law, any objection to personal jurisdiction, whether on grounds of venue, residence or domicile.

3.8Waiver by Jury Trial.  Each Party further waives, to the fullest extent permitted by Applicable Law, any right it may have to a trial by jury in respect of any proceedings relating to this Second Amendment.

3.9Severability.  If any Article, Section or provision of this Second Amendment shall be determined to be null and void, voidable or invalid by a court of competent jurisdiction, then for such period that the same is void or invalid, it shall be deemed to be deleted from this Second Amendment and the remaining portions of this Second Amendment shall remain in full force and effect.

3.10Counterparts; Facsimile Signatures.  This Second Amendment may be executed by the Parties in separate counterparts and delivered by electronic or facsimile transmission or otherwise and all such counterparts shall together constitute one and the same instrument.

[SIGNATURE PAGE FOLLOWS]

IN WITNESS WHEREOF, the Parties have executed this Second Amendment as of the Effective Date.

TRANSMONTAIGNE LLC

By:/s/ Frederick W. Boutin

Name:  Frederick W. Boutin

Title:  Chief Executive Officer

TRANSMONTAIGNE GP L.L.C.

By:/s/ Frederick W. Boutin

Name:  Frederick W. Boutin

Title:  Chief Executive Officer

TRANSMONTAIGNE PARTNERS L.P.

By TransMontaigne GP L.L.C.

Its General Partner

By:/s/ Frederick W. Boutin

Name:  Frederick W. Boutin

Title:  Chief Executive Officer

TRANSMONTAIGNE OPERATING GP L.L.C.

By:/s/ Frederick W. Boutin

Name:  Frederick W. Boutin

Title:  Chief Executive Officer

TRANSMONTAIGNE OPERATING COMPANY L.P.

By TransMontaigne Operating GP L.L.C.

Its General Partner

By:/s/ Frederick W. Boutin

Name:  Frederick W. Boutin

Title:  Chief Executive Officer

EX-31.1

Exhibit 31.1

Certification Pursuant to

Section 302 of the Sarbanes‑Oxley Act of 2002

I, Frederick W. Boutin, Chief Executive Officer of TransMontaigne GP L.L.C., a Delaware limited liability company and general partner of TransMontaigne Partners L.P. (the “Company”), certify that:

1. I have reviewed this Quarterly Report on Form 10‑Q of TransMontaigne Partners L.P. for the fiscal quarter ended March 31, 2015;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a‑15(e) and 15d‑15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a‑15(f) and 15d‑15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May  7, 2015

Chief Executive Officer

/s/ Frederick W. Boutin

Frederick W. Boutin
Chief Executive Officer

EX-31.2

Exhibit 31.2

Certification Pursuant to

Section 302 of the Sarbanes‑Oxley Act of 2002

I, Robert T. Fuller, Chief Financial Officer of TransMontaigne GP L.L.C., a Delaware limited liability company and general partner of TransMontaigne Partners L.P. (the “Company”), certify that:

1. I have reviewed this Quarterly Report on Form 10‑Q of TransMontaigne Partners L.P. for the fiscal quarter ended March 31, 2015;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a‑15(e) and 15d‑15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a‑15(f) and 15d‑15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May  7, 2015

Chief Financial Officer

/s/ Robert T. Fuller

Robert T. Fuller
Chief Financial Officer

EX-32.1

Exhibit 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

(18 U.S.C. Section 1350)

The undersigned, the Chief Executive Officer of TransMontaigne GP L.L.C., a Delaware limited liability company and general partner of TransMontaigne Partners L.P. (the “Company”), hereby certifies that, to his knowledge on the date hereof:

(a) the Quarterly Report on Form 10‑Q of the Company for the fiscal quarter ended March 31, 2015, filed on the date hereof with the Securities and Exchange Commission (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(b) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Chief Executive Officer
May 6, 2014

/s/ Frederick W. Boutin

Frederick W. Boutin
Chief Executive Officer
May  7, 2015

EX-32.2

Exhibit 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

(18 U.S.C. Section 1350)

The undersigned, the Chief Financial Officer of TransMontaigne GP L.L.C., a Delaware limited liability company and general partner of TransMontaigne Partners L.P. (the “Company”), hereby certifies that, to his knowledge on the date hereof:

(a) the Quarterly Report on Form 10‑Q of the Company for the fiscal quarter ended March 31, 2015, filed on the date hereof with the Securities and Exchange Commission (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(b) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Chief Financial Officer
May 6, 2014

/s/ Robert T. Fuller

Robert T. Fuller
Chief Financial Officer
May  7, 2015

XML

BUSINESS SEGMENTS (Tables)

3 Months Ended

Mar. 31, 2015

BUSINESS SEGMENTS

Schedule of information related to financial performance of business segments (in thousands)

	Three Months Ended		Three Months Ended
	March 31,		March 31,
	2015		2014
Gulf Coast Terminals:
Terminaling services fees	$	10,678	$	11,768
Other		1,998		3,001
Revenue		12,676		14,769
Direct operating costs and expenses		(4,406)		(4,837)
Net margins		8,270		9,932
Midwest Terminals and Pipeline System:
Terminaling services fees		2,102		1,993
Pipeline transportation fees		414		327
Other		227		374
Revenue		2,743		2,694
Direct operating costs and expenses		(678)		(704)
Net margins		2,065		1,990
Brownsville Terminals:
Terminaling services fees		1,816		1,497
Pipeline transportation fees		1,182		366
Other		3,962		2,974
Revenue		6,960		4,837
Direct operating costs and expenses		(3,150)		(3,480)
Net margins		3,810		1,357
River Terminals:
Terminaling services fees		2,257		2,021
Other		255		214
Revenue		2,512		2,235
Direct operating costs and expenses		(1,543)		(1,782)
Net margins		969		453
Southeast Terminals:
Terminaling services fees		11,757		11,440
Other		1,249		2,078
Revenue		13,006		13,518
Direct operating costs and expenses		(5,177)		(4,589)
Net margins		7,829		8,929
Total net margins		22,943		22,661
Direct general and administrative expenses		(1,021)		(918)
Allocated general and administrative expenses		(2,803)		(2,782)
Allocated insurance expense		(934)		(914)
Reimbursement of bonus awards expense		(525)		(375)
Depreciation and amortization		(7,337)		(7,400)
Earnings from unconsolidated affiliates		2,056		163
Operating income		12,379		10,435
Other expenses		(2,257)		(1,197)
Net earnings	$	10,122	$	9,238

Schedule of supplemental information about consolidated business segments (in thousands)

	Three Months Ended March 31, 2015
			Midwest
			Terminals and
	Gulf Coast		Pipeline		Brownsville		River		Southeast
	Terminals		System		Terminals		Terminals		Terminals		Total
Revenue:
External customers	$	9,920	$	2,743	$	5,773	$	2,395	$	4,468	$	25,299
NGL Energy Partners LP		2,756		—		10		117		8,478		11,361
Frontera		—		—		1,177		—		—		1,177
TransMontaigne LLC		—		—		—		—		60		60
Revenue	$	12,676	$	2,743	$	6,960	$	2,512	$	13,006	$	37,897
Capital expenditures	$	3,239	$	437	$	993	$	1,328	$	747	$	6,744
Identifiable assets	$	124,212	$	23,585	$	45,998	$	54,028	$	160,495	$	408,318
Cash and cash equivalents												918
Investments in unconsolidated affiliates												248,090
Deferred financing costs												1,820
Other												886
Total assets											$	660,032

	Three Months Ended March 31, 2014
			Midwest
			Terminals and
	Gulf Coast		Pipeline		Brownsville		River		Southeast
	Terminals		System		Terminals		Terminals		Terminals		Total
Revenue:
External customers	$	6,023	$	807	$	3,996	$	1,951	$	846	$	13,623
Morgan Stanley Capital Group		8,736		1,887		—		284		12,624		23,531
Frontera		—		—		841		—		—		841
TransMontaigne LLC		10		—		—		—		48		58
Revenue	$	14,769	$	2,694	$	4,837	$	2,235	$	13,518	$	38,053
Capital expenditures	$	200	$	28	$	567	$	493	$	435	$	1,723

r

XML

LONG-TERM DEBT (Details) (USD $)	3 Months Ended
	Mar. 31, 2015 item	Mar. 31, 2014	Dec. 31, 2014
Long-term debt
Restricted net assets	$ 0
TLP Finance Corp
Long-term debt
Ownership interest in subsidiary (as a percent)	100.00%
Amount of independent assets	0
Amount of independent operations	0
Credit Facility
Long-term debt
Maximum borrowing capacity	400,000,000		350,000,000
Optional increase to maximum borrowing capacity	100,000,000
Consolidated EBITDA multiplier	4.75
Maximum borrowing capacity based on 4.75 times Consolidated EBITDA	368,700,000
Weighted average interest rate on borrowings (as a percent)	2.70%	2.60%
Outstanding borrowings under credit facility	250,000,000		252,000,000
Outstanding borrowings under letters of credit	0		0
Credit Facility | Minimum
Long-term debt
Commitment fee on unused amount of commitments (as a percent)	0.375%
Interest coverage ratio	3.0
Credit Facility | Minimum | LIBOR
Long-term debt
Margin interest above reference rate (as a percent)	2.00%
Credit Facility | Minimum | Base Rate
Long-term debt
Margin interest above reference rate (as a percent)	1.00%
Credit Facility | Maximum
Long-term debt
Commitment fee on unused amount of commitments (as a percent)	0.50%
Other investments as a percentage of consolidated net tangible assets	5.00%
Permitted JV investments subject to liquidity	$ 125,000,000
Leverage ratio	4.75
Senior secured leverage ratio	3.75
Credit Facility | Maximum | LIBOR
Long-term debt
Margin interest above reference rate (as a percent)	3.00%
Credit Facility | Maximum | Base Rate
Long-term debt
Margin interest above reference rate (as a percent)	2.00%

XML

PROPERTY, PLANT AND EQUIPMENT, NET (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Property, plant and equipment, net
Property, plant and equipment, gross	$ 634,587	$ 626,762
Less accumulated depreciation	(248,747)	(241,461)
Property, plant and equipment, net	385,840	385,301
Land
Property, plant and equipment, net
Property, plant and equipment, gross	52,519	52,519
Terminals, pipelines and equipment
Property, plant and equipment, net
Property, plant and equipment, gross	568,495	566,677
Furniture, fixtures and equipment
Property, plant and equipment, net
Property, plant and equipment, gross	2,122	2,122
Construction in progress
Property, plant and equipment, net
Property, plant and equipment, gross	$ 11,451	$ 5,444

XML

PARTNERS' EQUITY (Details)	Mar. 31, 2015	Dec. 31, 2014
Common unitholders
Changes in number of units outstanding
Units outstanding at the beginning of the period	16,124,566
Units outstanding at the end of the period	16,124,566
General partner equivalent units
Changes in number of units outstanding
Units outstanding at the beginning of the period	329,073
Units outstanding at the end of the period	329,073
Long-term incentive plan
Information related to public offering
Common units held on behalf of TransMontaigne Services Inc.'s long-term incentive plan	2,750,868
Long-term incentive plan | Common unitholders
Information related to public offering
Common units held on behalf of TransMontaigne Services Inc.'s long-term incentive plan	9,601	7,600

XML

CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Concentration of credit risk and trade accounts receivable
Trade accounts receivable	9,225		$ 9,823
Less allowance for doubtful accounts	(464)		(464)
Trade accounts receivable, net	8,761		$ 9,359
NGL Energy Partners LP
Concentration of credit risk and trade accounts receivable
Percentage of total revenue generated by major customer	30.00%
Morgan Stanley Capital Group
Concentration of credit risk and trade accounts receivable
Percentage of total revenue generated by major customer	13.00%	62.00%

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ACCRUED LIABILITIES (Tables)

3 Months Ended

Mar. 31, 2015

ACCRUED LIABILITIES

Schedule of accrued liabilities (in thousands)

	March 31,		December 31,
	2015		2014
Customer advances and deposits:
External customers	$	2,695	$	2,756
Affiliates		2,677		—
		5,372		2,756
Accrued property taxes		1,497		892
Accrued environmental obligations		1,376		1,524
Interest payable		193		159
Rebate due to affiliate		—		1,795
Accrued expenses and other		2,572		2,709
	$	11,010	$	9,835

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COMMITMENTS AND CONTINGENCIES (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Nov. 30, 2014
Contractual commitments for supply of services, labor and materials	$ 10,500,000
Future minimum lease payments under non-cancelable operating leases
2015 (remainder of the year)	2,835,000
2016	3,981,000
2017	3,003,000
2018	607,000
2019	594,000
Thereafter	3,414,000
Total	14,434,000
Expected minimum sublease rentals to be received	1,000,000
Rental expense under operating leases	900,000	900,000
Brownsville terminals | Litigation | Nieto
Legal proceedings
Cost of truck uploading facility			500,000
Damages sought	$ 6,200,000

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SUBSEQUENT EVENTS

3 Months Ended

Mar. 31, 2015

SUBSEQUENT EVENT.

SUBSEQUENT EVENT

(19) SUBSEQUENT EVENT

On April 13, 2015, we announced a distribution of $0.665 per unit for the period from January 1, 2015 through March 31, 2015. This distribution is payable on May 7, 2015 to unitholders of record on April 30, 2015.

On May 4, 2015, we entered into a new five year terminaling services agreement with Morgan Stanley Capital Group for approximately 2.7 million barrels of product storage capacity at our Collins/Purvis, Mississippi terminals.  The new agreement will be effective January 1, 2016 and will replace the existing agreement we have with Morgan Stanley Capital Group for this tankage.  The new agreement contains an increase to the minimum throughput payments and is anticipated to generate additional minimum throughput revenue in excess of $4.0 million annually.

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INVESTMENTS IN UNCONSOLIDATED AFFILIATES (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Sep. 30, 2014 bbl	Mar. 31, 2014	Dec. 31, 2014
INVESTMENTS IN UNCONSOLIDATED AFFILIATES
Carrying value of investments in unconsolidated affiliates	$ 248,090,000			$ 249,676,000
Total earnings (loss) from investments in unconsolidated affiliates	2,056,000		163,000
Additional capital investments in unconsolidated affiliates			18,017,000
Cash distributions from unconsolidated affiliates	3,642,000		750,000
BOSTCO
INVESTMENTS IN UNCONSOLIDATED AFFILIATES
Storage capacity		7,100,000
Percentage of ownership	42.50%			42.50%
Carrying value of investments in unconsolidated affiliates	224,567,000			225,920,000
Excess investment	7,700,000			7,800,000
Total earnings (loss) from investments in unconsolidated affiliates	1,781,000		(80,000)
Additional capital investments in unconsolidated affiliates			17,972,000
Cash distributions from unconsolidated affiliates	3,134,000		113,000
Balance sheets:
Current assets	13,710,000			19,400,000
Long-term assets	507,654,000			511,373,000
Current liabilities	(11,188,000)			(17,435,000)
Net assets	510,176,000			513,338,000
Statements of comprehensive income (loss):
Revenue	15,887,000		8,337,000
Expenses	(11,467,000)		(8,455,000)
Net earnings and comprehensive income (loss)	4,420,000		(118,000)
Frontera
INVESTMENTS IN UNCONSOLIDATED AFFILIATES
Storage capacity	1,500,000
Percentage of ownership	50.00%			50.00%
Carrying value of investments in unconsolidated affiliates	23,523,000			23,756,000
Total earnings (loss) from investments in unconsolidated affiliates	275,000		243,000
Additional capital investments in unconsolidated affiliates			45,000
Cash distributions from unconsolidated affiliates	508,000		637,000
Balance sheets:
Current assets	4,588,000			4,222,000
Long-term assets	43,805,000			44,528,000
Current liabilities	(1,347,000)			(1,238,000)
Net assets	47,046,000			47,512,000
Statements of comprehensive income (loss):
Revenue	3,640,000		3,045,000
Expenses	(3,090,000)		(2,559,000)
Net earnings and comprehensive income (loss)	$ 550,000		$ 486,000

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Taxes, Derivatives (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Net earnings per limited partner unit
Limited partner interest (as a percent)	98.00%
General partner interest (as a percent)	2.00%	2.00%
Interest Rate Swap
Net earnings per limited partner unit
Notional amount	40.0
Fixed interest rate paid (as a percent)	1.09%

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COMMITMENTS AND CONTINGENCIES (Tables)

3 Months Ended

Mar. 31, 2015

COMMITMENTS AND CONTINGENCIES

Schedule of future minimum lease payments under non-cancelable operating leases (in thousands)

Years ending December 31:
2015 (remainder of the year)	$	2,835
2016		3,981
2017		3,003
2018		607
2019		594
Thereafter		3,414
	$	14,434

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ACCRUED LIABILITIES (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Customer advances and deposits:
External customers	$ 2,695,000	$ 2,756,000
Affiliates	2,677,000
Customer advances and deposits	5,372,000	2,756,000
Accrued property taxes	1,497,000	892,000
Accrued environmental obligations	1,376,000	1,524,000
Interest payable	193,000	159,000
Rebate due to affiliates		1,795,000
Accrued expenses and other	2,572,000	2,709,000
Accrued liabilities	11,010,000	9,835,000
Period for billing of customers in advance for terminaling services	1 month
Accrued environmental obligations
Payments	(100,000)
Agreed rebate as a percentage of proceeds in excess of threshold sales	50.00%
Threshold sales to provide rebate	4,200,000
Payment of rebate to related party	$ 1,800,000

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OTHER CURRENT ASSETS (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
OTHER CURRENT ASSETS.
Amounts due from insurance companies	$ 1,094,000	$ 1,233,000
Additive detergent	1,361,000	1,591,000
Deposits and other assets	317,000	241,000
Other current assets	2,772,000	3,065,000
Reimbursements from insurance companies	$ 100,000

XML

TRANSACTIONS WITH AFFILIATES

3 Months Ended

Mar. 31, 2015

TRANSACTIONS WITH AFFILIATES

TRANSACTIONS WITH AFFILIATES

(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.

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 March 31, 2015 and 2014, the administrative fee paid to TransMontaigne LLC was approximately $2.8 million and $2.8 million, respectively. If we acquire or construct additional facilities, TransMontaigne LLC will propose a revised administrative fee covering the provision of services for such additional facilities. If the conflicts committee of our general partner agrees to the revised administrative fee, TransMontaigne LLC will provide services for the additional facilities pursuant to the agreement. The administrative fee includes expenses incurred by TransMontaigne LLC to perform centralized corporate functions, such as legal, accounting, treasury, insurance administration and claims processing, health, safety and environmental, information technology, human resources, credit, payroll, taxes and engineering and other corporate services, to the extent such services are not outsourced by TransMontaigne LLC.

The omnibus agreement further provides that we pay TransMontaigne LLC an insurance reimbursement for premiums on insurance policies covering our facilities and operations. For the three months ended March 31, 2015 and 2014, the insurance reimbursement paid to TransMontaigne LLC was approximately $0.9 million and $0.9 million, respectively. We also reimburse TransMontaigne LLC for direct operating costs and expenses that TransMontaigne LLC incurs on our behalf, such as salaries of operational personnel performing services on‑site at our terminals and pipelines and the cost of 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 allocated to an investment fund indexed to the performance of our common units. The value of our incentive bonus awards reimbursement for a single grant year may be no less than $1.5 million.  Effective April 14, 2015, and beginning with our reimbursement for the 2015 incentive bonus awards, we have the option to provide the reimbursement in either cash or our common units, with the reimbursement payable by us in accordance with the underlying employee vesting and payment schedule of the TransMontaigne Services LLC savings and retention plan. Prior to the 2015 incentive bonus awards, 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. Our expenses associated with the reimbursement of incentive bonus awards were approximately $0.5 million and $0.4 million for the three months ended March 31, 2015 and 2014, 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 $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 is expected to become available to RaceTrac Petroleum Inc. in the third quarter 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 0.5 million barrels of this capacity to World Fuel Services Corporation and RaceTrac Petroleum Inc. at similar rates charged to NGL.  The 0.5 million barrels of tankage became available to these third party customers in May of 2015.

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. 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 $5.7 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, Morgan Stanley Capital Group’s 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 to Morgan Stanley Capital Group, Morgan Stanley Capital Group 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.

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, Morgan Stanley Capital Group’s 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 to Morgan Stanley Capital Group, Morgan Stanley Capital Group 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, Morgan Stanley Capital Group’s obligations would be temporarily suspended. If a force majeure event continues for 120 consecutive days, Morgan Stanley Capital Group 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 March 31, 2015 and 2014, we recognized revenue of approximately $1.2 million and $0.8 million, respectively, related to this operations and reimbursement agreement.

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TRANSACTIONS WITH AFFILIATES (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Transactions with affiliates
Annual administrative fee paid	$ 2,803	$ 2,782
Annual insurance reimbursement paid	934	914
Reimbursement of bonus awards	525	375
TransMontaigne LLC-related party | Omnibus agreement
Transactions with affiliates
Notice period for termination of service agreement	24 months
Annual administrative fee paid	2,800	2,800
Annual insurance reimbursement paid	900	900
Reimbursement of bonus awards	500	400
Period, following receipt of the notice, to purchase the subject facilities by related party	45 days
TransMontaigne LLC-related party | Minimum | Omnibus agreement
Transactions with affiliates
Reimbursement of bonus awards	$ 1,500
Percentage of purchase price offered by third party bidder agreed to be paid for right of refusal to purchase the entity's assets	105.00%
Percentage of fees offered by third party agreed to be paid for right of refusal to contract	105.00%

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PROPERTY, PLANT AND EQUIPMENT, NET (Tables)

3 Months Ended

Mar. 31, 2015

PROPERTY, PLANT AND EQUIPMENT, NET

Schedule of property, plant and equipment, net (in thousands)

	March 31,		December 31,
	2015		2014
Land	$	52,519	$	52,519
Terminals, pipelines and equipment		568,495		566,677
Furniture, fixtures and equipment		2,122		2,122
Construction in progress		11,451		5,444
		634,587		626,762
Less accumulated depreciation		(248,747)		(241,461)
	$	385,840	$	385,301

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OTHER CURRENT ASSETS (Tables)

3 Months Ended

Mar. 31, 2015

OTHER CURRENT ASSETS.

Schedule of other current assets (in thousands)

	March 31,		December 31,
	2015		2014
Amounts due from insurance companies	$	1,094	$	1,233
Additive detergent		1,361		1,591
Deposits and other assets		317		241
	$	2,772	$	3,065

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LONG-TERM INCENTIVE PLAN (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended	1 Months Ended	3 Months Ended	0 Months Ended
	Mar. 31, 2015	Sep. 30, 2014 item	Mar. 31, 2014	Jul. 01, 2014	Dec. 31, 2014
Available for future grant
Units outstanding at the beginning of the period	2,179,457
Automatic increase in units available for future grant	322,491
Units outstanding at the end of the period	2,501,948
TransMontaigne GP
Additional disclosures
Number of independent directors appointed		3
TransMontaigne LLC-related party | Morgan Stanley
Additional disclosures
Ownership interest sold (as a percent)				100.00%
Restricted phantom units
Available for future grant
Units outstanding at the beginning of the period					9,000
Units outstanding at the end of the period	9,000				9,000
Long-term incentive plan
Long-term incentive plan
Authorized units	2,750,868
Percentage of total outstanding common and subordinated units authorized for automatic increase in grant awards authorized on an annual basis	2.00%
Available for future grant
Units outstanding at the end of the period	2,501,948
Additional disclosures
Vesting period	4 years
Deferred equity-based compensation included in direct general and administrative expenses	23		$ 52
Long-term incentive plan | Common unitholders | TransMontaigne GP
Long-term incentive plan
Number of common units purchased	2,001		2,001
Long-term incentive plan | Restricted phantom units
Available for future grant
Grant (in units)		(9,000)
Vesting (in units)				(15,000)
Restricted phantom units
Grant (in units)		9,000
Vesting (in units)				(15,000)

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TRANSACTIONS WITH AFFILIATES - Agreements (Details) (USD $)	3 Months Ended		0 Months Ended				1 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Mar. 01, 2014	Oct. 31, 2014 bbl	Jul. 01, 2014	Jul. 11, 2011 bbl	Jan. 31, 2010 bbl	May 31, 2013	Apr. 01, 2011
Transactions with affiliates
Throughput revenue	$ 12,598,000	$ 24,430,000
TransMontaigne LLC-related party
Transactions with affiliates
Throughput revenue	60,000	58,000
TransMontaigne LLC-related party | Florida and Midwest terminals | Maximum
Transactions with affiliates
Maximum liability for indemnification obligation	15,000,000
TransMontaigne LLC-related party | Brownsville and River terminals | Maximum
Transactions with affiliates
Maximum liability for indemnification obligation	15,000,000
TransMontaigne LLC-related party | Southeast Terminals | Maximum
Transactions with affiliates
Maximum liability for indemnification obligation	15,000,000
TransMontaigne LLC-related party | Pensacola terminal | Maximum
Transactions with affiliates
Maximum liability for indemnification obligation	2,500,000
Frontera
Transactions with affiliates
Throughput revenue	1,177,000	841,000
Environmental indemnification | TransMontaigne LLC-related party | Florida and Midwest terminals
Transactions with affiliates
Liability for indemnification obligation, if aggregate losses do not exceed specified amount	0
Liability for indemnification obligation related to environmental claims made as a result of additions to or modifications of environmental laws	0
Environmental indemnification | TransMontaigne LLC-related party | Florida and Midwest terminals | Minimum
Transactions with affiliates
Aggregate losses for indemnification obligation	250,000
Environmental indemnification | TransMontaigne LLC-related party | Florida and Midwest terminals | Maximum
Transactions with affiliates
Maximum liability for indemnification obligation	15,000,000
Environmental indemnification | TransMontaigne LLC-related party | Brownsville and River terminals
Transactions with affiliates
Liability for indemnification obligation, if aggregate losses do not exceed specified amount	0
Liability for indemnification obligation related to environmental claims made as a result of additions to or modifications of environmental laws	0
Environmental indemnification | TransMontaigne LLC-related party | Brownsville and River terminals | Minimum
Transactions with affiliates
Aggregate losses for indemnification obligation	250,000
Environmental indemnification | TransMontaigne LLC-related party | Brownsville and River terminals | Maximum
Transactions with affiliates
Maximum liability for indemnification obligation	15,000,000
Environmental indemnification | TransMontaigne LLC-related party | Southeast Terminals
Transactions with affiliates
Liability for indemnification obligation, if aggregate losses do not exceed specified amount	0
Liability for indemnification obligation related to environmental claims made as a result of additions to or modifications of environmental laws	0
Environmental indemnification | TransMontaigne LLC-related party | Southeast Terminals | Minimum
Transactions with affiliates
Aggregate losses for indemnification obligation	250,000
Environmental indemnification | TransMontaigne LLC-related party | Southeast Terminals | Maximum
Transactions with affiliates
Maximum liability for indemnification obligation	15,000,000
Environmental indemnification | TransMontaigne LLC-related party | Pensacola terminal
Transactions with affiliates
Liability for indemnification obligation related to environmental claims made as a result of additions to or modifications of environmental laws	0
Environmental indemnification | TransMontaigne LLC-related party | Pensacola terminal | Minimum
Transactions with affiliates
Aggregate losses for indemnification obligation	200,000
Environmental indemnification | TransMontaigne LLC-related party | Pensacola terminal | Maximum
Transactions with affiliates
Maximum liability for indemnification obligation	2,500,000
Terminaling services agreement-Florida and Midwest terminals
Transactions with affiliates
Term of lease agreement			10 years
Percentage of capacity of Razorback terminals and the Razorback pipeline covered under the agreement			100.00%
Terminaling services agreement-Florida and Midwest terminals | NGL
Transactions with affiliates
Notice period for termination of service agreement				18 months
Storage capacity agreed to be provided (in barrels)				1,100,000
Storage capacity under commitment re-contracted (in barrels)				500,000
Terminaling services agreement-Florida and Midwest terminals | NGL | Minimum
Transactions with affiliates
Number of consecutive days for which diminution in the storage capacity the entity makes available to related party due to force majeure event as a result of which related party's minimum revenue commitment would be reduced proportionately					30 days
Terminaling services agreement-Cushing terminal | Morgan Stanley Capital Group
Transactions with affiliates
Notice period for termination of service agreement						180 days
Storage capacity agreed to be provided (in barrels)						1,000,000
Term of lease agreement						1 year
Automatic renewal period of service agreement						5 years
Terminaling services agreement-Cushing terminal | Morgan Stanley Capital Group | Minimum
Transactions with affiliates
Number of consecutive days for which diminution in the storage capacity the entity makes available to related party due to force majeure event as a result of which related party's minimum revenue commitment would be reduced proportionately						120 days
Terminaling services agreement-Southeast terminals | Minimum
Transactions with affiliates
Notice period for termination of service agreement					24 months
Terminaling services agreement-Southeast terminals | NGL | Minimum
Transactions with affiliates
Notice period for termination of service agreement					24 months
Number of consecutive days for which diminution in the storage capacity the entity makes available to related party due to force majeure event as a result of which related party's minimum revenue commitment would be reduced proportionately					30 days
Terminaling services agreement-Collins/Purvis | Morgan Stanley Capital Group
Transactions with affiliates
Storage capacity agreed to be provided (in barrels)							700,000
Term of lease agreement							1 year
Terminaling services agreement-Collins/Purvis | Morgan Stanley Capital Group | Minimum
Transactions with affiliates
Notice period for termination of service agreement							24 months
Number of consecutive days for which diminution in the storage capacity the entity makes available to related party due to force majeure event as a result of which related party's minimum revenue commitment would be reduced proportionately							30 days
Barge dock services agreement-Baton Rouge dock | Morgan Stanley Capital Group
Transactions with affiliates
Notice period for termination of service agreement								180 days
Number of consecutive days for which diminution in the storage capacity the entity makes available to related party due to force majeure event as a result of which related party's minimum revenue commitment would be reduced proportionately								120 days
Automatic renewal period of service agreement								5 years
Remaining period, following the first three year period after the in-service date, over which minimum throughput payments are received								7 years
Operations and reimbursement agreement-Frontera | Frontera
Transactions with affiliates
Ownership interest in joint venture (as a percent)									50.00%
Revenue recognized	1,200,000	800,000
Forecast | Terminaling services agreement-Florida and Midwest terminals | NGL | Minimum
Transactions with affiliates
Throughput revenue				5,700,000
Forecast | Terminaling services agreement-Cushing terminal | Morgan Stanley Capital Group | Minimum
Transactions with affiliates
Throughput revenue						4,300,000
Forecast | Terminaling services agreement-Southeast terminals | NGL | Minimum
Transactions with affiliates
Throughput revenue					27,000,000
Forecast | Terminaling services agreement-Collins/Purvis | Morgan Stanley Capital Group | Minimum
Transactions with affiliates
Throughput revenue							4,100,000
Forecast | Barge dock services agreement-Baton Rouge dock | Morgan Stanley Capital Group
Transactions with affiliates
Minimum throughput payments for the first three years								1,200,000
First period, following the in-service date, over which minimum throughput payments are received								3 years
Minimum throughput payments for the remaining seven years								900,000

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GOODWILL (Tables)

3 Months Ended

Mar. 31, 2015

GOODWILL.

Schedule of goodwill (in thousands)

	March 31,		December 31,
	2015		2014
Brownsville terminals	$	8,485	$	8,485

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INVESTMENTS IN UNCONSOLIDATED AFFILIATES (Tables)

3 Months Ended

Mar. 31, 2015

INVESTMENTS IN UNCONSOLIDATED AFFILIATES

Summary of investments in unconsolidated affiliates

	Percentage of				Carrying value
	ownership				(in thousands)
	March 31,		December 31,		March 31,		December 31,
	2015		2014		2015		2014
BOSTCO	42.5	%	42.5	%	$	224,567	$	225,920
Frontera	50	%	50	%		23,523		23,756
Total investments in unconsolidated affiliates					$	248,090	$	249,676

Schedule of earnings (losses) from investments in unconsolidated affiliates (in thousands)

	Three Months Ended		Three Months Ended
	March 31,		March 31,
	2015		2014
BOSTCO	$	1,781	$	(80)
Frontera		275		243
Total earnings from investments in unconsolidated affiliates	$	2,056	$	163

Schedule of additional capital investments in unconsolidated affiliates (in thousands)

	Three Months Ended		Three Months Ended
	March 31,		March 31,
	2015		2014
BOSTCO	$	—	$	17,972
Frontera		—		45
Additional capital investments in unconsolidated affiliates	$	—	$	18,017

Schedule of cash distributions received from unconsolidated affiliates (in thousands)

	Three Months Ended		Three Months Ended
	March 31,		March 31,
	2015		2014
BOSTCO	$	3,134	$	113
Frontera		508		637
Cash distributions received from unconsolidated affiliates	$	3,642	$	750

Summary of financial information of unconsolidated affiliates

Balance sheets:

	BOSTCO				Frontera
	March 31,		December 31,		March 31,		December 31,
	2015		2014		2015		2014
Current assets	$	13,710	$	19,400	$	4,588	$	4,222
Long-term assets		507,654		511,373		43,805		44,528
Current liabilities		(11,188)		(17,435)		(1,347)		(1,238)
Long-term liabilities		—		—		—		—
Net assets	$	510,176	$	513,338	$	47,046	$	47,512

Statements of operations:

	BOSTCO				Frontera
	Three Months Ended				Three Months Ended
	March 31,				March 31,
	2015		2014		2015		2014
Revenue	$	15,887	$	8,337	$	3,640	$	3,045
Expenses		(11,467)		(8,455)		(3,090)		(2,559)
Net earnings (loss)	$	4,420	$	(118)	$	550	$	486

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

3 Months Ended

Mar. 31, 2015

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(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 March 31, 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 March 31, 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 March 31, 2015 and December 31, 2014 and our results of operations for the three months ended March 31, 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.

(c) Accounting for terminal and pipeline operations

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 March 31, 2015 and 2014, we recognized revenue of approximately $1.8 million and $3.6 million, respectively, for net product gained. Within these amounts, approximately $0.9 million and $2.5 million for the three months ended March 31, 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.

(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 plan

Generally accepted accounting principles require us to measure the cost of services received in exchange for an award of equity instruments based on the grant‑date fair value of the award. That cost will be recognized over the period during which a board member or employee is required to provide services in exchange for the award. We are required to estimate the number of equity instruments that are expected to vest in measuring the total compensation cost to be recognized over the related service period. Compensation cost is recognized over the service period on a straight‑line basis.

(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 March 31, 2015, our derivative instruments were limited to an interest rate swap agreement with a notional amount of $40.0 million that expires March 2018. Pursuant to the terms of the interest rate swap agreement, we pay a fixed rate of approximately 1.09% and receive an interest payment based on the one-month LIBOR. The net difference to be paid or received under the interest rate swap agreement is settled monthly and is recognized as an adjustment to interest expense. The fair value of our interest rate swap was 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 the long‑term incentive plan that participate in Partners’ distributions (see Note 16 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 partnership 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 partnership 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, 2016, including interim periods within that reporting period. We are currently evaluating the potential impact that the adoption will have on our disclosures and financial statements.

In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs.The objective of this update is to present debt issuance costs in the balance sheet as a reduction from the related debt liability rather than as an asset.  ASU 2015-03 is effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period.  Upon adoption, our unamortized debt issuance costs will be reclassified from other assets, net to long-term debt.

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OTHER ASSETS, NET (Tables)

3 Months Ended

Mar. 31, 2015

OTHER ASSETS, NET

Schedule of other assets, net (in thousands)

	March 31,		December 31,
	2015		2014
Amounts due under long-term terminaling services agreements:
External customers	$	552	$	649
Affiliates		832		945
		1,384		1,594
Deferred financing costs, net of accumulated amortization of $3,593 and $3,278, respectively		1,820		1,138
Customer relationships, net of accumulated amortization of $1,738 and $1,687, respectively		692		743
Deposits and other assets		76		76
	$	3,972	$	3,551

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $)	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Jul. 01, 2014
Nature of business
Limited partner interest (as a percent)	98.00%
General partner interest (as a percent)	2.00%		2.00%
Basis of presentation and use of estimates
Allocated general and administrative expenses	$ 2,803,000	$ 2,782,000
Allocated insurance charges	934,000	914,000
Reimbursement of bonus awards	525,000	375,000
Accounting for terminal and pipeline operations
Revenue recognized from proceeds of sale of product gained	1,800,000	3,600,000
Recognized revenue pursuant to terminaling services agreements with affiliate customers	$ 900,000	$ 2,500,000
TransMontaigne Inc. and Morgan Stanley
Nature of business
Limited partner interest (as a percent)	19.00%
General partner interest (as a percent)	2.00%
Morgan Stanley | TransMontaigne LLC-related party
Nature of business
Ownership interest sold (as a percent)				100.00%

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OTHER LIABILITIES (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
OTHER LIABILITIES
Advance payments received under long-term terminaling services agreements	$ 282,000		$ 451,000
Deferred revenue-ethanol blending fees and other projects	3,110,000		3,419,000
Unrealized loss on derivative instrument	149,000
Other liabilities	3,541,000		3,870,000
Recognized revenue on a straight line basis for completed projects	$ 300,000	$ 700,000

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Consolidated balance sheets (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 918	$ 3,304
Trade accounts receivable, net	8,761	9,359
Due from affiliates	1,194	1,316
Other current assets	2,772	3,065
Total current assets	13,645	17,044
Property, plant and equipment, net	385,840	385,301
Goodwill	8,485	8,485
Investments in unconsolidated affiliates	248,090	249,676
Other assets, net	3,972	3,551
TOTAL ASSETS	660,032	664,057
Current liabilities:
Trade accounts payable	6,565	6,887
Accrued liabilities	11,010	9,835
Total current liabilities	17,575	16,722
Other liabilities	3,541	3,870
Long-term debt	250,000	252,000
Total liabilities	271,116	272,592
Commitments and contingencies (Note 15)
Partners' equity:
Common unitholders (16,124,566 units issued and outstanding at March 31, 2015 and December 31, 2014)	331,121	333,619
General partner interest (2% interest with 329,073 equivalent units outstanding at March 31, 2015 and December 31, 2014)	57,795	57,846
Total partners' equity	388,916	391,465
TOTAL LIABILITIES AND EQUITY	$ 660,032	$ 664,057

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TERMINAL ACQUISITION (Details) (BOSTCO, USD $) In Millions, unless otherwise specified	0 Months Ended	3 Months Ended
	Jun. 05, 2013 bbl	Dec. 31, 2013 bbl item	Dec. 20, 2012
ACQUISITIONS
Number of storage tanks, the construction of which is involved in the initial phase of acquisition		51
Storage capacity of storage tanks, the construction of which is involved in the initial phase of acquisition (in barrels)		6,200,000
Number of barrels involved in the expansion phase of acquisition	900,000
Fully subscribed storage capacity of storage tanks after initial phase and expansion projects	7,100,000
Storage tanks, cost of construction	$ 529
Estimated overall construction cost of storage tanks including initial phase and expansion projects	233
Class A Members | Kinder Morgan
ACQUISITIONS
Percentage of ownership			42.50%
Cost of voting interest acquired			$ 79

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Consolidated statements of partners' equity (Parenthetical)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Consolidated statements of partners' equity
Purchase of common units by our long-term incentive plan and from affiliate (in units)	2,001	8,004
Issuance of common units by our long-term incentive plan due to vesting of restricted phantom units (in units)		20,500

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BUSINESS SEGMENTS (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013
Segments of business
Total revenue	$ 37,897	$ 38,053
Direct operating costs and expenses	(14,954)	(15,392)
Net margins	22,943	22,661
Direct general and administrative expenses	(1,021)	(918)
Allocated general and administrative expenses	(2,803)	(2,782)
Allocated insurance expense	(934)	(914)
Reimbursement of bonus awards expense	(525)	(375)
Depreciation and amortization	(7,337)	(7,400)
Earnings from unconsolidated affiliates	2,056	163
Operating income	12,379	10,435
Other expenses	(2,257)	(1,197)
Net earnings	10,122	9,238	32,463
External customers	25,299	13,623
Revenue from affiliates	12,598	24,430
Capital expenditures	6,744	1,723
Identifiable assets	408,318
Cash and cash equivalents	918	4,652	3,304	3,263
Investments in unconsolidated affiliates	248,090		249,676
Deferred financing costs	1,820		1,138
Other	886
TOTAL ASSETS	660,032		664,057
NGL Energy Partners LP
Segments of business
Revenue from affiliates	11,361
Morgan Stanley Capital Group
Segments of business
Revenue from affiliates		23,531
Frontera
Segments of business
Revenue from affiliates	1,177	841
TransMontaigne LLC-related party
Segments of business
Revenue from affiliates	60	58
Gulf Coast Terminals
Segments of business
Terminaling services fees, net	10,678	11,768
Other	1,998	3,001
Total revenue	12,676	14,769
Direct operating costs and expenses	(4,406)	(4,837)
Net margins	8,270	9,932
External customers	9,920	6,023
Capital expenditures	3,239	200
Identifiable assets	124,212
Gulf Coast Terminals | NGL Energy Partners LP
Segments of business
Revenue from affiliates	2,756
Gulf Coast Terminals | Morgan Stanley Capital Group
Segments of business
Revenue from affiliates		8,736
Gulf Coast Terminals | TransMontaigne LLC-related party
Segments of business
Revenue from affiliates		10
Midwest Terminals and Pipeline System
Segments of business
Terminaling services fees, net	2,102	1,993
Pipeline transportation fees	414	327
Other	227	374
Total revenue	2,743	2,694
Direct operating costs and expenses	(678)	(704)
Net margins	2,065	1,990
External customers	2,743	807
Capital expenditures	437	28
Identifiable assets	23,585
Midwest Terminals and Pipeline System | Morgan Stanley Capital Group
Segments of business
Revenue from affiliates		1,887
Brownsville terminals
Segments of business
Terminaling services fees, net	1,816	1,497
Pipeline transportation fees	1,182	366
Other	3,962	2,974
Total revenue	6,960	4,837
Direct operating costs and expenses	(3,150)	(3,480)
Net margins	3,810	1,357
External customers	5,773	3,996
Capital expenditures	993	567
Identifiable assets	45,998
Brownsville terminals | NGL Energy Partners LP
Segments of business
Revenue from affiliates	10
Brownsville terminals | Frontera
Segments of business
Revenue from affiliates	1,177	841
River terminals
Segments of business
Terminaling services fees, net	2,257	2,021
Other	255	214
Total revenue	2,512	2,235
Direct operating costs and expenses	(1,543)	(1,782)
Net margins	969	453
External customers	2,395	1,951
Capital expenditures	1,328	493
Identifiable assets	54,028
River terminals | NGL Energy Partners LP
Segments of business
Revenue from affiliates	117
River terminals | Morgan Stanley Capital Group
Segments of business
Revenue from affiliates		284
Southeast Terminals
Segments of business
Terminaling services fees, net	11,757	11,440
Other	1,249	2,078
Total revenue	13,006	13,518
Direct operating costs and expenses	(5,177)	(4,589)
Net margins	7,829	8,929
External customers	4,468	846
Capital expenditures	747	435
Identifiable assets	160,495
Southeast Terminals | NGL Energy Partners LP
Segments of business
Revenue from affiliates	8,478
Southeast Terminals | Morgan Stanley Capital Group
Segments of business
Revenue from affiliates		12,624
Southeast Terminals | TransMontaigne LLC-related party
Segments of business
Revenue from affiliates	$ 60	$ 48

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PARTNERS' EQUITY (Tables)

3 Months Ended

Mar. 31, 2015

PARTNERS' EQUITY

Schedule of number of units outstanding

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

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NET EARNINGS PER LIMITED PARTNER UNIT

3 Months Ended

Mar. 31, 2015

NET EARNINGS PER LIMITED PARTNER UNIT

NET EARNINGS PER LIMITED PARTNER UNIT

(16) 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		Three Months Ended
	March 31,		March 31,
	2015		2014
Net earnings	$	10,122	$	9,238
Less:
Distributions payable on behalf of incentive distribution rights		(1,682)		(1,603)
Distributions payable on behalf of general partner interest		(219)		(217)
Earnings allocable to general partner interest less than distributions payable to general partner interest		51		64
Earnings allocable to general partner interest including incentive distribution rights		(1,850)		(1,756)
Net earnings allocable to limited partners per the consolidated statements of operations	$	8,272	$	7,482
Less distributions payable on behalf of unvested long-term incentive plan grants		(6)		(10)
Net earnings allocable to limited partners for calculating net earnings per limited partner unit	$	8,266	$	7,472
Basic and diluted weighted average units		16,125		16,103
Net earnings per limited partner unit—basic and diluted	$	0.51	$	0.46

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

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LONG-TERM INCENTIVE PLAN (Tables)

3 Months Ended

Mar. 31, 2015

LONG-TERM INCENTIVE PLAN

Schedule of restricted phantom unit activity

		Restricted
	Available for	phantom
	future grant	units
Units outstanding at December 31, 2014	2,179,457	9,000
Automatic increase in units available for future grant on January 1, 2015	322,491	—
Units outstanding at March 31, 2015	2,501,948	9,000

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BUSINESS SEGMENTS

3 Months Ended

Mar. 31, 2015

BUSINESS SEGMENTS

BUSINESS SEGMENTS

(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.

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

	Three Months Ended		Three Months Ended
	March 31,		March 31,
	2015		2014
Gulf Coast Terminals:
Terminaling services fees	$	10,678	$	11,768
Other		1,998		3,001
Revenue		12,676		14,769
Direct operating costs and expenses		(4,406)		(4,837)
Net margins		8,270		9,932
Midwest Terminals and Pipeline System:
Terminaling services fees		2,102		1,993
Pipeline transportation fees		414		327
Other		227		374
Revenue		2,743		2,694
Direct operating costs and expenses		(678)		(704)
Net margins		2,065		1,990
Brownsville Terminals:
Terminaling services fees		1,816		1,497
Pipeline transportation fees		1,182		366
Other		3,962		2,974
Revenue		6,960		4,837
Direct operating costs and expenses		(3,150)		(3,480)
Net margins		3,810		1,357
River Terminals:
Terminaling services fees		2,257		2,021
Other		255		214
Revenue		2,512		2,235
Direct operating costs and expenses		(1,543)		(1,782)
Net margins		969		453
Southeast Terminals:
Terminaling services fees		11,757		11,440
Other		1,249		2,078
Revenue		13,006		13,518
Direct operating costs and expenses		(5,177)		(4,589)
Net margins		7,829		8,929
Total net margins		22,943		22,661
Direct general and administrative expenses		(1,021)		(918)
Allocated general and administrative expenses		(2,803)		(2,782)
Allocated insurance expense		(934)		(914)
Reimbursement of bonus awards expense		(525)		(375)
Depreciation and amortization		(7,337)		(7,400)
Earnings from unconsolidated affiliates		2,056		163
Operating income		12,379		10,435
Other expenses		(2,257)		(1,197)
Net earnings	$	10,122	$	9,238

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

	Three Months Ended March 31, 2015
			Midwest
			Terminals and
	Gulf Coast		Pipeline		Brownsville		River		Southeast
	Terminals		System		Terminals		Terminals		Terminals		Total
Revenue:
External customers	$	9,920	$	2,743	$	5,773	$	2,395	$	4,468	$	25,299
NGL Energy Partners LP		2,756		—		10		117		8,478		11,361
Frontera		—		—		1,177		—		—		1,177
TransMontaigne LLC		—		—		—		—		60		60
Revenue	$	12,676	$	2,743	$	6,960	$	2,512	$	13,006	$	37,897
Capital expenditures	$	3,239	$	437	$	993	$	1,328	$	747	$	6,744
Identifiable assets	$	124,212	$	23,585	$	45,998	$	54,028	$	160,495	$	408,318
Cash and cash equivalents												918
Investments in unconsolidated affiliates												248,090
Deferred financing costs												1,820
Other												886
Total assets											$	660,032

	Three Months Ended March 31, 2014
			Midwest
			Terminals and
	Gulf Coast		Pipeline		Brownsville		River		Southeast
	Terminals		System		Terminals		Terminals		Terminals		Total
Revenue:
External customers	$	6,023	$	807	$	3,996	$	1,951	$	846	$	13,623
Morgan Stanley Capital Group		8,736		1,887		—		284		12,624		23,531
Frontera		—		—		841		—		—		841
TransMontaigne LLC		10		—		—		—		48		58
Revenue	$	14,769	$	2,694	$	4,837	$	2,235	$	13,518	$	38,053
Capital expenditures	$	200	$	28	$	567	$	493	$	435	$	1,723

r

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Consolidated statements of cash flows (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Cash flows from operating activities:
Net earnings	$ 10,122	$ 9,238
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation and amortization	7,337	7,400
Earnings from unconsolidated affiliates	(2,056)	(163)
Distributions from unconsolidated affiliates	3,642	750
Deferred equity-based compensation	23	52
Amortization of deferred financing costs	315	244
Amortization of deferred revenue	(309)	(740)
Unrealized loss on derivative instrument	149
Changes in operating assets and liabilities:
Trade accounts receivable, net	598	(601)
Due from affiliates	122	(224)
Other current assets	293	191
Amounts due under long-term terminaling services agreements, net	41	277
Trade accounts payable	(1,403)	(657)
Due to affiliates		57
Accrued liabilities	1,175	(4,474)
Net cash provided by operating activities	20,049	11,350
Cash flows from investing activities:
Investments in unconsolidated affiliates		(18,017)
Capital expenditures	(6,744)	(1,723)
Net cash used in investing activities	(6,744)	(19,740)
Cash flows from financing activities:
Borrowings of debt under credit facility	20,800	39,000
Repayments of debt under credit facility	(22,800)	(17,000)
Deferred debt issuance costs	(997)
Distributions paid to unitholders	(12,624)	(12,136)
Purchase of common units by our long-term incentive plan	(70)	(85)
Net cash provided by (used in) financing activities	(15,691)	9,779
Increase (decrease) in cash and cash equivalents	(2,386)	1,389
Cash and cash equivalents at beginning of period	3,304	3,263
Cash and cash equivalents at end of period	918	4,652
Supplemental disclosures of cash flow information:
Cash paid for interest	1,615	945
Property, plant and equipment acquired with accounts payable	$ 2,354	$ 341

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Consolidated balance sheets (Parenthetical)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Consolidated balance sheets
Common unitholders, units issued	16,124,566	16,124,566
Common unitholders, units outstanding	16,124,566	16,124,566
General partner interest (as a percent)	2.00%	2.00%
General partner interest, equivalent units outstanding	329,073	329,073

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OTHER LIABILITIES

3 Months Ended

Mar. 31, 2015

OTHER LIABILITIES

OTHER LIABILITIES

(11) OTHER LIABILITIES

Other liabilities are as follows (in thousands):

	March 31,		December 31,
	2015		2014
Advance payments received under long-term terminaling services agreements	$	282	$	451
Deferred revenue—ethanol blending fees and other projects		3,110		3,419
Unrealized loss on derivative instrument		149		—
	$	3,541	$	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 March 31, 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 $0.3 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 March 31, 2015 and December 31, 2014, we have unamortized deferred revenue of approximately $3.1 million and $3.4 million, respectively, for completed projects. During the three months ended March 31, 2015 and 2014, we recognized revenue on a straight‑line basis of approximately $0.3 million and $0.7 million, respectively, for completed projects.

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Document and Entity Information	3 Months Ended
	Mar. 31, 2015	Apr. 30, 2015
Document and Entity Information
Entity Registrant Name	TransMontaigne Partners L.P.
Entity Central Index Key	0001319229
Document Type	10-Q
Document Period End Date	Mar. 31, 2015
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		16,124,566
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1

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LONG-TERM DEBT

3 Months Ended

Mar. 31, 2015

LONG-TERM DEBT

LONG-TERM DEBT

(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.

At March 31, 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: $368.7 million at March 31, 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.

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).

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 March 31, 2015.

For the three months ended March 31, 2015 and 2014, the weighted average interest rate on borrowings under the credit facility was approximately 2.7% and 2.6%, respectively.  At March 31, 2015 and December 31, 2014, our outstanding borrowings under the credit facility were $250million and $252 million, respectively. At March 31, 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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Consolidated statements of operations (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Revenue:
External customers	$ 25,299	$ 13,623
Affiliates	12,598	24,430
Total revenue	37,897	38,053
Operating costs and expenses and other:
Direct operating costs and expenses	(14,954)	(15,392)
Direct general and administrative expenses	(1,021)	(918)
Allocated general and administrative expenses	(2,803)	(2,782)
Allocated insurance expense	(934)	(914)
Reimbursement of bonus awards expense	(525)	(375)
Depreciation and amortization	(7,337)	(7,400)
Earnings from unconsolidated affiliates	2,056	163
Total operating costs and expenses and other	(25,518)	(27,618)
Operating income	12,379	10,435
Other expenses:
Interest expense	(1,942)	(953)
Amortization of deferred financing costs	(315)	(244)
Total other expenses	(2,257)	(1,197)
Net earnings	10,122	9,238
Less-earnings allocable to general partner interest including incentive distribution rights	(1,850)	(1,756)
Net earnings allocable to limited partners	$ 8,272	$ 7,482
Net earnings per limited partner unit-basic and diluted (in dollars per unit)	$ 0.51	$ 0.46

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OTHER CURRENT ASSETS

3 Months Ended

Mar. 31, 2015

OTHER CURRENT ASSETS.

OTHER CURRENT ASSETS

(5) OTHER CURRENT ASSETS

Other current assets are as follows (in thousands):

	March 31,		December 31,
	2015		2014
Amounts due from insurance companies	$	1,094	$	1,233
Additive detergent		1,361		1,591
Deposits and other assets		317		241
	$	2,772	$	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 March 31, 2015 and December 31, 2014, we have recognized amounts due from insurance companies of approximately $1.1 million and $1.2 million, respectively, representing our best estimate of our probable insurance recoveries. During the three months ended March 31, 2015, we received reimbursements from insurance companies of approximately $0.1 million. During the three months ended March 31, 2015, we did not adjust our estimate of probable insurance recoveries.

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CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE

3 Months Ended

Mar. 31, 2015

CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE

CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE

(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 and the United States government. 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):

	March 31,		December 31,
	2015		2014
Trade accounts receivable	$	9,225	$	9,823
Less allowance for doubtful accounts		(464)		(464)
	$	8,761	$	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		Three Months Ended
	March 31,		March 31,
	2015		2014
NGL Energy Partners LP	30	%	—	%
Morgan Stanley Capital Group	13	%	62	%

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DISCLOSURES ABOUT FAIR VALUE

3 Months Ended

Mar. 31, 2015

DISCLOSURES ABOUT FAIR VALUE

DISCLOSURES ABOUT FAIR VALUE

(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 the best information available in the circumstances. The following methods and assumptions were used to estimate the fair value of financial instruments at March 31, 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 instrument.  The carrying amount of our interest rate swap as of March 31, 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.

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PARTNERS' EQUITY

3 Months Ended

Mar. 31, 2015

PARTNERS' EQUITY

PARTNERS' EQUITY

(13) PARTNERS’ EQUITY

The number of units outstanding is as follows:

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

At March 31, 2015 and December 31, 2014, common units outstanding include 9,601 and 7,600 common units, respectively, held on behalf of TransMontaigne LLC’s long‑term incentive plan.

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OTHER ASSETS, NET

3 Months Ended

Mar. 31, 2015

OTHER ASSETS, NET

OTHER ASSETS, NET

(9) OTHER ASSETS, NET

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

	March 31,		December 31,
	2015		2014
Amounts due under long-term terminaling services agreements:
External customers	$	552	$	649
Affiliates		832		945
		1,384		1,594
Deferred financing costs, net of accumulated amortization of $3,593 and $3,278, respectively		1,820		1,138
Customer relationships, net of accumulated amortization of $1,738 and $1,687, respectively		692		743
Deposits and other assets		76		76
	$	3,972	$	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 March 31, 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 $1.4 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.

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SUBSEQUENT EVENTS (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended					0 Months Ended
	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Apr. 13, 2015	May 04, 2015 bbl
Subsequent Event
Distribution announced per unit (in dollars per unit)	$ 0.665	$ 0.665	$ 0.665	$ 0.665	$ 0.660
Subsequent Event
Subsequent Event
Distribution announced per unit (in dollars per unit)						$ 0.665
Subsequent Event | Terminaling services agreement-Collins/Purvis | Morgan Stanley Capital Group
Subsequent Event
Term of lease agreement							5 years
Storage capacity agreed to be provided (in barrels)							2,700,000
Throughput revenue							$ 4,000

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PROPERTY, PLANT AND EQUIPMENT, NET

3 Months Ended

Mar. 31, 2015

PROPERTY, PLANT AND EQUIPMENT, NET

PROPERTY, PLANT AND EQUIPMENT, NET

(6) PROPERTY, PLANT AND EQUIPMENT, NET

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

	March 31,		December 31,
	2015		2014
Land	$	52,519	$	52,519
Terminals, pipelines and equipment		568,495		566,677
Furniture, fixtures and equipment		2,122		2,122
Construction in progress		11,451		5,444
		634,587		626,762
Less accumulated depreciation		(248,747)		(241,461)
	$	385,840	$	385,301

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GOODWILL

3 Months Ended

Mar. 31, 2015

GOODWILL.

GOODWILL

(7) GOODWILL

Goodwill is as follows (in thousands):

	March 31,		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 March 31, 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 three months ended March 31, 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.

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ACCRUED LIABILITIES

3 Months Ended

Mar. 31, 2015

ACCRUED LIABILITIES

ACCRUED LIABILITIES

(10) ACCRUED LIABILITIES

Accrued liabilities are as follows (in thousands):

	March 31,		December 31,
	2015		2014
Customer advances and deposits:
External customers	$	2,695	$	2,756
Affiliates		2,677		—
		5,372		2,756
Accrued property taxes		1,497		892
Accrued environmental obligations		1,376		1,524
Interest payable		193		159
Rebate due to affiliate		—		1,795
Accrued expenses and other		2,572		2,709
	$	11,010	$	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 March 31, 2015 and December 31, 2014, we have billed and collected from certain of our customers approximately $5.4 million and $2.8 million, respectively, in advance of the terminaling services being provided.

Accrued environmental obligations.  At March 31, 2015 and December 31, 2014, we have accrued environmental obligations of approximately $1.4 million and $1.5 million, respectively, representing our best estimate of our remediation obligations. During the three months ended March 31, 2015, we made payments of approximately $0.1 million towards our environmental remediation obligations. During the three months ended March 31, 2015, we did not change our estimate of our future environmental remediation costs. 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 March 31, 2015 and December 31, 2014, we have accrued a liability due to affiliate of approximately $nil and $1.8 million, respectively. During the three months ended March 31, 2015, we paid approximately $1.8 million to our affiliate customer for the rebate due for the year ended December 31, 2014.

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OTHER LIABILITIES (Tables)

3 Months Ended

Mar. 31, 2015

OTHER LIABILITIES

Schedule of other liabilities (in thousands)

	March 31,		December 31,
	2015		2014
Advance payments received under long-term terminaling services agreements	$	282	$	451
Deferred revenue—ethanol blending fees and other projects		3,110		3,419
Unrealized loss on derivative instrument		149		—
	$	3,541	$	3,870

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OTHER ASSETS, NET (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Amounts due under long-term terminaling services agreements:
External customers	$ 552	$ 649
Affiliates	832	945
Amounts due under long-term terminaling services agreements	1,384	1,594
Deferred financing costs, net of accumulated amortization	1,820	1,138
Customer relationships, net of accumulated amortization	692	743
Deposits and other assets	76	76
Other assets, net	3,972	3,551
Accumulated amortization of deferred financing costs	3,593	3,278
Accumulated amortization of customer relationships	$ 1,738	$ 1,687
Amortization period of customer relationships	12 years

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COMMITMENTS AND CONTINGENCIES

3 Months Ended

Mar. 31, 2015

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

(15) COMMITMENTS AND CONTINGENCIES

Contract commitments.  At March 31, 2015, we have contractual commitments of approximately $10.5 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 March 31, 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)	$	2,835
2016		3,981
2017		3,003
2018		607
2019		594
Thereafter		3,414
	$	14,434

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 $1.0 million in future periods.

Rental expense under operating leases was approximately $0.9 million and $0.9 million for the three months ended March 31, 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.  In an effort to increase Nieto’s ability to transport LPG through the Diamondback pipeline during the period that the King Ranch plant was not operating and in reliance upon Nieto’s promise to reimburse us for the costs of construction, we constructed a truck unloading facility at our Brownsville terminal for Nieto’s use at a cost of approximately $0.5 million.  Nieto disputes requesting such a facility and has not reimbursed us for it.  Nieto also has claimed that the fire at the 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 and Nieto’s failure to reimburse us for the costs of the truck unloading facility that we constructed for it, on September 26, 2014, we filed a complaint for damages and declaratory relief in the Supreme Court of the State of New York, County of New York, against Nieto, by which we seek damages that have accumulated as of March 31, 2015 in the amount of at least $6.2 million and a declaratory judgment clarifying our rights to receive the deficiency fees under the terminaling services agreement.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

3 Months Ended

Mar. 31, 2015

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of business

(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 March 31, 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 March 31, 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.

Basis of presentation and use of estimates

(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 March 31, 2015 and December 31, 2014 and our results of operations for the three months ended March 31, 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.

Accounting for terminal and pipeline operations

(c) Accounting for terminal and pipeline operations

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 March 31, 2015 and 2014, we recognized revenue of approximately $1.8 million and $3.6 million, respectively, for net product gained. Within these amounts, approximately $0.9 million and $2.5 million for the three months ended March 31, 2015 and 2014, respectively, were pursuant to terminaling services agreements with affiliate customers.

Cash and cash equivalents

(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.

Property, plant and equipment

(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.

Investments in unconsolidated affiliates

(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.

Environmental obligations

(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.

Asset retirement obligations

(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.

Equity-based compensation plan

(i) Equity‑based compensation plan

Generally accepted accounting principles require us to measure the cost of services received in exchange for an award of equity instruments based on the grant‑date fair value of the award. That cost will be recognized over the period during which a board member or employee is required to provide services in exchange for the award. We are required to estimate the number of equity instruments that are expected to vest in measuring the total compensation cost to be recognized over the related service period. Compensation cost is recognized over the service period on a straight‑line basis.

Accounting for derivative instruments

(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 March 31, 2015, our derivative instruments were limited to an interest rate swap agreement with a notional amount of $40.0 million that expires March 2018. Pursuant to the terms of the interest rate swap agreement, we pay a fixed rate of approximately 1.09% and receive an interest payment based on the one-month LIBOR. The net difference to be paid or received under the interest rate swap agreement is settled monthly and is recognized as an adjustment to interest expense. The fair value of our interest rate swap was determined using a pricing model based on the LIBOR swap rate and other observable market data.

Income taxes

(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.

Net earnings per limited partner unit

(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 the long‑term incentive plan that participate in Partners’ distributions (see Note 16 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 partnership 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 partnership units outstanding during the period and any potential dilutive securities outstanding during the period.

Recent Accounting Pronouncements

(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, 2016, including interim periods within that reporting period. We are currently evaluating the potential impact that the adoption will have on our disclosures and financial statements.

In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs.The objective of this update is to present debt issuance costs in the balance sheet as a reduction from the related debt liability rather than as an asset.  ASU 2015-03 is effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period.  Upon adoption, our unamortized debt issuance costs will be reclassified from other assets, net to long-term debt.

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GOODWILL (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Goodwill
Goodwill	$ 8,485	$ 8,485
Brownsville terminals
Goodwill
Goodwill	$ 8,485	$ 8,485

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Property (Details)	3 Months Ended
	Mar. 31, 2015
Terminals and pipelines | Minimum
Property, plant and equipment
Estimated useful lives	15 years
Terminals and pipelines | Maximum
Property, plant and equipment
Estimated useful lives	25 years
Furniture, fixtures and equipment | Minimum
Property, plant and equipment
Estimated useful lives	3 years
Furniture, fixtures and equipment | Maximum
Property, plant and equipment
Estimated useful lives	25 years

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Consolidated statements of partners' equity (USD $) In Thousands, unless otherwise specified	Common unitholders	General partner equivalent units	Total
Balance at Dec. 31, 2013	$ 350,505	$ 57,962	$ 408,467
Increase (Decrease) in Partners' Capital
Distributions to unitholders	(42,561)	(7,283)	(49,844)
Deferred equity-based compensation related to restricted phantom units	721		721
Purchase of common units by our long-term incentive plan and from affiliate	(342)		(342)
Net earnings	25,296	7,167	32,463
Balance at Dec. 31, 2014	333,619	57,846	391,465
Increase (Decrease) in Partners' Capital
Distributions to unitholders	(10,723)	(1,901)	(12,624)
Deferred equity-based compensation related to restricted phantom units	23		23
Purchase of common units by our long-term incentive plan and from affiliate	(70)		(70)
Net earnings	8,272	1,850	10,122
Balance at Mar. 31, 2015	$ 331,121	$ 57,795	$ 388,916

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TERMINAL ACQUISITION

3 Months Ended

Mar. 31, 2015

TERMINAL ACQUISITION

TERMINAL ACQUISITION

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

On June 5, 2013, we announced an expansion of BOSTCO 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 fully subscribed capacity of approximately 7.1 million barrels at an overall construction cost of approximately $529 million. Our total payments for the initial and for the expansion projects are estimated to be approximately $233 million, which includes our proportionate share of the BOSTCO project costs and necessary start‑up working capital, a one‑time buy‑in fee paid to Kinder Morgan to acquire our 42.5% interest and the capitalization of interest on our investment during the construction of BOSTCO. We have funded our payments for BOSTCO utilizing borrowings under our credit facility.

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

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NET EARNINGS PER LIMITED PARTNER UNIT (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended					12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2014
NET EARNINGS PER LIMITED PARTNER UNIT
Net earnings	$ 10,122				$ 9,238	$ 32,463
Less:
Distributions payable on behalf of incentive distribution rights	(1,682)				(1,603)
Distributions payable on behalf of general partner interest	(219)				(217)
Earnings allocable to general partner interest less than distributions payable to general partner interest	51				64
Earnings allocable to general partner interest including incentive distribution rights	(1,850)				(1,756)
Net earnings allocable to limited partners	8,272				7,482
Less distribution payable on behalf of unvested long-term incentive plan grants	(6)				(10)
Net earnings allocable to limited partners for calculating net earnings per limited partner unit	$ 8,266				$ 7,472
Basic and diluted weighted average units	16,125				16,103
Net earnings per limited partner unit-basic and diluted (in dollars per unit)	$ 0.51				$ 0.46
Period for declaration of distribution, maximum	45 days
Distribution declared per common unit (in dollars per unit)	$ 0.665	$ 0.665	$ 0.665	$ 0.665	$ 0.660

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CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE (Tables)

3 Months Ended

Mar. 31, 2015

CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE

Schedule of trade accounts receivable, net (in thousands)

	March 31,		December 31,
	2015		2014
Trade accounts receivable	$	9,225	$	9,823
Less allowance for doubtful accounts		(464)		(464)
	$	8,761	$	9,359

Schedule of customer who accounted for at least 10% of consolidated revenue

	Three Months Ended		Three Months Ended
	March 31,		March 31,
	2015		2014
NGL Energy Partners LP	30	%	—	%
Morgan Stanley Capital Group	13	%	62	%

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NET EARNINGS PER LIMITED PARTNER UNIT (Tables)

3 Months Ended

Mar. 31, 2015

NET EARNINGS PER LIMITED PARTNER UNIT

Schedule of reconciliation of net earnings to net earnings allocable to limited partners (in thousands)

	Three Months Ended		Three Months Ended
	March 31,		March 31,
	2015		2014
Net earnings	$	10,122	$	9,238
Less:
Distributions payable on behalf of incentive distribution rights		(1,682)		(1,603)
Distributions payable on behalf of general partner interest		(219)		(217)
Earnings allocable to general partner interest less than distributions payable to general partner interest		51		64
Earnings allocable to general partner interest including incentive distribution rights		(1,850)		(1,756)
Net earnings allocable to limited partners per the consolidated statements of operations	$	8,272	$	7,482
Less distributions payable on behalf of unvested long-term incentive plan grants		(6)		(10)
Net earnings allocable to limited partners for calculating net earnings per limited partner unit	$	8,266	$	7,472
Basic and diluted weighted average units		16,125		16,103
Net earnings per limited partner unit—basic and diluted	$	0.51	$	0.46

Schedule of distribution declared per common unit attributable to the periods

	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

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LONG-TERM INCENTIVE PLAN

3 Months Ended

Mar. 31, 2015

LONG-TERM INCENTIVE PLAN

LONG-TERM INCENTIVE PLAN

(14) LONG‑TERM INCENTIVE PLAN

TransMontaigne GP is our general partner and manages our operations and activities. TransMontaigne GP is an indirect wholly owned subsidiary of TransMontaigne LLC. TransMontaigne Services LLC is an indirect wholly owned subsidiary of TransMontaigne LLC. TransMontaigne Services LLC employs the personnel who provide support to TransMontaigne LLC’s operations, as well as our operations. TransMontaigne Services LLC adopted a long‑term incentive plan for its employees and consultants and the independent directors of our general partner. 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 March 31, 2015, 2,501,948 units are available for future grant under the long‑term incentive plan. Ownership in the awards is subject to forfeiture until the vesting date, but recipients have distribution and voting rights from the date of grant. 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 to the independent directors of our general partner. TransMontaigne GP has historically purchased outstanding common units on the open market for purposes of making grants of restricted phantom units to independent directors of our general partner.

TransMontaigne GP, on behalf of the long‑term incentive plan, has purchased 2,001 and 2,001 common units pursuant to the program during the three months ended March 31, 2015 and 2014, respectively.

Information about restricted phantom unit activity for the three months ended March 31, 2015 is as follows:

		Restricted
	Available for	phantom
	future grant	units
Units outstanding at December 31, 2014	2,179,457	9,000
Automatic increase in units available for future grant on January 1, 2015	322,491	—
Units outstanding at March 31, 2015	2,501,948	9,000

We typically recognize the deferred equity‑based compensation expense associated with annual grants under the long-term incentive plan on a straight-line basis over their respective four-year vesting periods.  However, pursuant to the terms of the long‑term incentive plan, all outstanding grants of restricted phantom units vest upon a change in control of TransMontaigne LLC. Accordingly, as a result of Morgan Stanley’s sale of its 100% ownership interest in TransMontaigne LLC to NGL, effective July 1, 2014 all 15,000 of the then outstanding restricted phantom units vested, and equivalent common units were delivered to the independent directors of our general partner at that time.

In September of 2014, our general partner appointed three new independent directors to replace the independent directors that had resigned in August of 2014.  The new independent directors, in aggregate, were granted 9,000 restricted phantom units on September 30, 2014.  We will recognize the deferred equity‑based compensation expense associated with these grants on a straight-line basis over their respective four‑year vesting periods.

Deferred equity‑based compensation of approximately $23,000 and $52,000 is included in direct general and administrative expenses for the three months ended March 31, 2015 and 2014, respectively.