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 September 30, 2014
OR
☐	Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Commission File Number: 001‑32505

TRANSMONTAIGNE PARTNERS L.P.

(Exact name of registrant as specified in its charter)

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

1670 Broadway

Suite 3100

Denver, Colorado 80202

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

(303) 626‑8200

(Telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒  No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S‑T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒  No ☐

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

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

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

As of October 31, 2014, 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 September 30, 2014 and December 31, 2013	4
	Consolidated statements of comprehensive income for the three and ninemonths ended September30, 2014 and 2013	5
	Consolidated statements of partners’ equity for the year ended December 31, 2013 and nine months ended September 30, 2014	6
	Consolidated statements of cash flows for the three and nine months ended September 30, 2014 and 2013	7
	Notes to consolidated financial statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	46
Item 4.	Controls and Procedures	47
Part II. Other Information
Item 1.	Legal Proceedings	47
Item 1A.	Risk Factors	47
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	49
Item 6.	Exhibits	51

2

CAUTIONARY STATEMENT REGARDING FORWARD‑LOOKING STATEMENTS

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

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

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

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

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

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

Part I. Financial Information

ITEM 1.  UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

The interim unaudited consolidated financial statements of TransMontaigne Partners L.P. as of and for the three and ninemonths ended September 30, 2014 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, 2013, 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 11, 2014 with the Securities and Exchange Commission (File No. 001‑32505).

TransMontaigne Partners L.P. is a holding company with the following active 100% owned operating subsidiaries during the three and ninemonths ended September 30, 2014:

· 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.

· TPME L.L.C.

The above omits non‑operating subsidiaries that, considered in the aggregate, do not constitute significant subsidiaries as of September 30, 2014. We do not have off‑balance‑sheet arrangements (other than operating leases) or special‑purpose entities.

3

TransMontaigne Partners L.P. and subsidiaries

Consolidated balance sheets (unaudited)

(Dollars in thousands)

	September 30,		December 31,
	2014		2013
ASSETS
Current assets:
Cash and cash equivalents	$	726	$	3,263
Trade accounts receivable, net		12,252		6,427
Due from affiliates		1,011		2,257
Other current assets		2,976		3,478
Total current assets		16,965		15,425
Property, plant and equipment, net		388,140		407,045
Goodwill		8,485		8,485
Investments in unconsolidated affiliates		252,679		211,605
Other assets, net		4,085		5,872
	$	670,354	$	648,432
LIABILITIES AND EQUITY
Current liabilities:
Trade accounts payable	$	4,010	$	5,717
Due to affiliates		52		—
Accrued liabilities		11,766		16,189
Total current liabilities		15,828		21,906
Other liabilities		4,247		6,059
Long-term debt		252,000		212,000
Total liabilities		272,075		239,965
Partners’ equity:
Common unitholders (16,124,566 units issued and outstanding at September 30, 2014 and December 31, 2013)		340,298		350,505
General partner interest (2% interest with 329,073 equivalent units outstanding at September 30, 2014 and December 31, 2013)		57,981		57,962
Total partners’ equity		398,279		408,467
	$	670,354	$	648,432

See accompanying notes to consolidated financial statements.

4

TransMontaigne Partners L.P. and subsidiaries

Consolidated statements of comprehensive income (unaudited)

(In thousands, except per unit amounts)

	Three months ended				Nine months ended
	September 30,				September 30,
	2014		2013		2014		2013
Revenue:
External customers	$	22,130	$	12,645	$	51,227	$	39,216
Affiliates		13,573		25,729		61,888		79,454
Total revenue		35,703		38,374		113,115		118,670
Operating costs and expenses and other:
Direct operating costs and expenses		(16,514)		(17,843)		(48,302)		(51,865)
Direct general and administrative expenses		(1,086)		(1,201)		(2,466)		(2,952)
Allocated general and administrative expenses		(2,782)		(2,741)		(8,346)		(8,222)
Allocated insurance expense		(942)		(935)		(2,769)		(2,828)
Reimbursement of bonus awards		(375)		(313)		(1,125)		(938)
Depreciation and amortization		(7,400)		(7,392)		(22,196)		(22,191)
Loss on disposition of assets		—		(1,398)		—		(1,398)
Earnings from unconsolidated affiliates		1,653		234		3,091		270
Total operating costs and expenses and other		(27,446)		(31,589)		(82,113)		(90,124)
Operating income		8,257		6,785		31,002		28,546
Other income (expenses):
Interest expense		(1,493)		(532)		(3,672)		(2,035)
Foreign currency transaction loss		—		(5)		—		(13)
Amortization of deferred financing costs		(244)		(244)		(732)		(732)
Total other expenses, net		(1,737)		(781)		(4,404)		(2,780)
Net earnings		6,520		6,004		26,598		25,766
Other comprehensive income—foreign currency translation adjustments		—		81		—		83
Comprehensive income	$	6,520	$	6,085	$	26,598	$	25,849
Net earnings	$	6,520	$	6,004	$	26,598	$	25,766
Less—earnings allocable to general partner interest including incentive distribution rights		(1,779)		(1,536)		(5,400)		(4,333)
Net earnings allocable to limited partners	$	4,741	$	4,468	$	21,198	$	21,433
Net earnings per limited partner unit—basic and diluted	$	0.29	$	0.28	$	1.31	$	1.44

See accompanying notes to consolidated financial statements.

5

TransMontaigne Partners L.P. and subsidiaries

Consolidated statements of partners’ equity (unaudited)

Year ended December 31, 2013 and nine months ended September 30, 2014

(Dollars in thousands)

					Accumulated
			General		other
	Common		partner		comprehensive
	unitholders		interest		income (loss)		Total
Balance December 31, 2012	$	292,648	$	56,564	$	(475)	$	348,737
Proceeds from offering of 1,667,500 common units, net of underwriters’ discounts and offering expenses of $3,462		68,774		—		—		68,774
Contribution of cash by TransMontaigne GP to maintain its 2% general partner interest		—		1,474		—		1,474
Distributions to unitholders		(39,466)		(6,005)		—		(45,471)
Deferred equity-based compensation related to restricted phantom units		337		—		—		337
Purchase of 13,069 common units by our long-term incentive plan and from affiliate		(585)		—		—		(585)
Issuance of 10,608 common units by our long-term incentive plan due to vesting of restricted phantom units		—		—		—		—
Net earnings for year ended December 31, 2013		28,797		5,929		—		34,726
Other comprehensive income—foreign currency translation adjustments		—		—		83		83
Foreign currency translation adjustments reclassified into loss upon the sale of the Mexico operations		—		—		392		392
Balance December 31, 2013		350,505		57,962		—		408,467
Distributions to unitholders		(31,838)		(5,381)		—		(37,219)
Deferred equity-based compensation related to restricted phantom units		698		—		—		698
Purchase of 6,003 common units by our long-term incentive plan		(265)		—		—		(265)
Issuance of 20,500 common units by our long-term incentive plan due to vesting of restricted phantom units		—		—		—		—
Net earnings for nine months ended September 30, 2014		21,198		5,400		—		26,598
Balance September 30, 2014	$	340,298	$	57,981	$	—	$	398,279

See accompanying notes to consolidated financial statements.

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TransMontaigne Partners L.P. and subsidiaries

Consolidated statements of cash flows (unaudited)

(In thousands)

	Three months ended				Nine months ended
	September 30,				September 30,
	2014		2013		2014		2013
Cash flows from operating activities:
Net earnings	$	6,520	$	6,004	$	26,598	$	25,766
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation and amortization		7,400		7,392		22,196		22,191
Loss on disposition of assets		—		1,398		—		1,398
Earnings from unconsolidated affiliates		(1,653)		(234)		(3,091)		(270)
Distributions from unconsolidated affiliates		3,259		328		5,697		877
Deferred equity-based compensation		584		81		698		285
Amortization of deferred financing costs		244		244		732		732
Utility deposits returned		—		135		—		135
Amortization of deferred revenue		(510)		(793)		(1,921)		(2,978)
Amounts due under long-term terminaling services agreements, net		306		353		919		996
Changes in operating assets and liabilities:
Trade accounts receivable, net		(3,614)		(812)		(5,733)		(1,824)
Due from affiliates		2,438		890		1,246		1,275
Other current assets		273		112		502		(157)
Trade accounts payable		(1,302)		596		(1,507)		(2,256)
Due to affiliates		52		(387)		52		(40)
Accrued liabilities		978		(1,571)		(4,423)		88
Net cash provided by operating activities		14,975		13,736		41,965		46,218
Cash flows from investing activities:
Proceeds from sale of assets		—		2,109		—		2,109
Investments in unconsolidated affiliates		(20,283)		(23,412)		(43,680)		(94,368)
Capital expenditures		(726)		(1,186)		(3,338)		(11,562)
Net cash used in investing activities		(21,009)		(22,489)		(47,018)		(103,821)
Cash flows from financing activities:
Proceeds from issuance of common units		—		69,190		—		69,190
Deferred issuance costs		—		—		—		(398)
Contribution of cash by TransMontaigne GP		—		1,474		—		1,474
Borrowings of debt under credit facility		56,000		26,500		112,000		146,000
Repayments of debt under credit facility		(38,000)		(73,500)		(72,000)		(123,000)
Distributions paid to unitholders		(12,621)		(12,133)		(37,219)		(33,334)
Purchase of common units by our long-term incentive plan and from affiliate		(88)		(335)		(265)		(501)
Net cash provided by financing activities		5,291		11,196		2,516		59,431
Increase (decrease) in cash and cash equivalents		(743)		2,443		(2,537)		1,828
Foreign currency translation effect on cash		—		3		—		49
Cash and cash equivalents at beginning of period		1,469		6,176		3,263		6,745
Cash and cash equivalents at end of period	$	726	$	8,622	$	726	$	8,622
Supplemental disclosures of cash flow information:
Cash paid for interest	$	1,473	$	579	$	3,658	$	1,933
Property, plant and equipment acquired with accounts payable	$	518	$	381	$	518	$	381

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 a wholly‑owned subsidiary of TransMontaigne Inc. At September 30, 2014, NGL Energy Partners LP (“NGL”) owned all of the issued and outstanding capital stock of TransMontaigne Inc., and, as a result, NGL is the indirect owner of our general partner. At September 30, 2014, TransMontaigne Inc. and NGL had a significant interest in our partnership through their indirect ownership of an approximate 20% 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 Inc., 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 Inc. to NGL. The sale resulted in a change in control of Partners, but did not result in a deemed termination of Partners for tax purposes.

In addition to the sale of our general partner to NGL, NGL acquired the common units owned by TransMontaigne Inc. and affiliates of Morgan Stanley, representing approximately 20% of our outstanding common units, and assumed Morgan Stanley Capital Group’s obligations under our light-oil terminaling service agreements in Florida and the Southeast regions, excluding the Collins/Purvis tankage (collectively, the “NGL Acquisition”). All other terminaling services agreements with Morgan Stanley Capital Group remained with Morgan Stanley Capital Group. The NGL Acquisition did not involve the sale or purchase of any of our common units held by the public and our common units continue to trade on the New York Stock Exchange.

(b) Basis of presentation and use of estimates

Our accounting and financial reporting policies conform to accounting principles and practices generally accepted in the United States of America. The accompanying consolidated financial statements include the accounts of TransMontaigne Partners L.P., a Delaware limited partnership, and its controlled subsidiaries. Investments where we do not have the ability to exercise control, but do have the ability to exercise significant influence, are accounted for using the equity method of accounting. All inter‑company accounts and transactions have been eliminated in the preparation of the accompanying consolidated financial statements. The accompanying consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly our financial position as of September 30, 2014 and December 31, 2013, our results of operations for the three and nine months ended September 30, 2014 and 2013 and our cash flows for the three and nine months ended September 30, 2014 and 2013.

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

8

will occur as a result of the passage of time and the occurrence of future events. Actual results could differ from these estimates.

The accompanying consolidated financial statements include allocated general and administrative charges from TransMontaigne Inc. for indirect corporate overhead to cover costs of functions such as legal, accounting, treasury, engineering, environmental safety, information technology, and other corporate services (see Note 2 of Notes to consolidated financial statements). The allocated general and administrative expenses were approximately $2.8 million and $2.7 million for the three months ended September 30, 2014 and 2013, respectively. The allocated general and administrative expenses were approximately $8.3 million and $8.2 million for the nine months ended September 30, 2014 and 2013, respectively. The accompanying consolidated financial statements also include allocated insurance charges from TransMontaigne Inc. for 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 charges were approximately $0.9 million and $0.9 million for the three months ended September 30, 2014 and 2013, respectively. The allocated insurance charges were approximately $2.8 million and $2.8 million for the nine months ended September 30, 2014 and 2013, respectively. The accompanying consolidated financial statements also include reimbursement of bonus awards paid to TransMontaigne Services Inc. (a wholly‑ owned subsidiary of TransMontaigne Inc.) towards bonus awards granted by TransMontaigne Services Inc. to certain key officers and employees who provide services to Partners that vest over future periods. The reimbursement of bonus awards was approximately $0.4 million and $0.3 million for the three months ended September 30, 2014 and 2013, respectively. The reimbursement of bonus awards was approximately $1.1 million and $0.9 million for the nine months ended September 30, 2014 and 2013, respectively.

(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 throughput; transportation revenue is recognized when the product has been delivered to the customer at the specified delivery location; management fee revenue and cost reimbursements are recognized as the services are performed or as the costs are incurred; ancillary service revenue is recognized as the services are performed; and gains from the sale of refined products are recognized when the title to the product is transferred.

Pursuant to terminaling services agreements with certain of our throughput customers, we are entitled to the volume of product gained resulting from differences in the measurement of product volumes received and distributed at our terminaling facilities. Consistent with recognized industry practices, measurement differentials occur as the result of the inherent variances in measurement devices and methodology. We recognize as revenue the net proceeds from the sale of the product gained. For the three months ended September 30, 2014 and 2013, we recognized revenue of approximately $3.1 million and $3.3 million, respectively, for net product gained. Within these amounts, approximately $1.2 million and $2.9 million for the three months ended September 30, 2014 and 2013, respectively, were pursuant to terminaling services agreements with affiliate customers. For the nine months ended September 30, 2014 and 2013, we recognized revenue of approximately $10.8 million and $11.0 million, respectively, for net product gained. Within these amounts, approximately $6.1 million and $9.8 million for the nine months ended September 30, 2014 and 2013, 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

9

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 Inc. 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 (see Note 2 of Notes to consolidated financial statements). TransMontaigne Inc. 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 (see Note 2 of Notes to consolidated financial statements). TransMontaigne Inc. 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 (see Note 2 of Notes to consolidated financial statements). TransMontaigne Inc. 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 (see Note 2 of Notes to consolidated financial statements).

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(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 service 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) Foreign currency translation and transactions

The functional currency of Partners and its U.S.‑based subsidiaries is the U.S. Dollar. The functional currency of our Mexico operations, which we sold effective August 8, 2013 (see Note 3 of Notes to consolidated financial statements), was the Mexican Peso. The assets and liabilities of our foreign subsidiaries were translated at period‑end rates of exchange, and revenue and expenses were translated at average exchange rates prevailing for the period. The resulting translation adjustments, net of related income taxes, were recorded as a component of other comprehensive income in the consolidated statements of comprehensive income. Gains and losses from the re‑measurement of foreign currency transactions (transactions denominated in a currency other than the entity’s functional currency) were included in other income (expenses) in the consolidated statements of comprehensive income.

(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. Certain of our Mexican subsidiaries were corporations for Mexican tax purposes and, therefore, were subject to Mexican federal and provincial income taxes. Effective August 8, 2013, we sold our Mexico operations, including the Mexican corporations (see Note 3 of Notes to consolidated financial statements).

Partners accounts for U.S. state income taxes and Mexican federal and provincial income taxes under the asset and liability method pursuant to generally accepted accounting principles. Mexican federal and provincial income taxes and 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

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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.

(2) TRANSACTIONS WITH AFFILIATES

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

Under the omnibus agreement we pay TransMontaigne Inc. an administrative fee for the provision of various general and administrative services for our benefit. For the three months ended September 30, 2014 and 2013, the administrative fee paid to TransMontaigne Inc. was approximately $2.8 million and $2.7 million, respectively. For the nine months endedSeptember 30, 2014 and 2013, the administrative fee paid to TransMontaigne Inc. was approximately $8.3 million and $8.2 million, respectively. If we acquire or construct additional facilities, TransMontaigne Inc. 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 Inc. will provide services for the additional facilities pursuant to the agreement. The administrative fee includes expenses incurred by TransMontaigne Inc. 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 Inc.

The omnibus agreement further provides that we pay TransMontaigne Inc. an insurance reimbursement for premiums on insurance policies covering our facilities and operations. For the three months ended September 30, 2014 and 2013, the insurance reimbursement paid to TransMontaigne Inc. was approximately $0.9 million and $0.9 million, respectively. For the nine months ended September 30, 2014 and 2013, the insurance reimbursement paid to TransMontaigne Inc. was approximately $2.8 million and $2.8 million, respectively. We also reimburse TransMontaigne Inc. for direct operating costs and expenses that TransMontaigne Inc. 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.

We also agreed to reimburse TransMontaigne Inc. and its affiliates for a portion of the incentive payment grants to key employees of TransMontaigne Inc. and its affiliates under the TransMontaigne Services Inc. savings and retention plan, provided the compensation committee of our general partner determines that an adequate portion of the incentive payment grants are allocated to an investment fund indexed to the performance of our common units. For the three months ended September 30, 2014 and 2013, we reimbursed TransMontaigne Inc. and its affiliates approximately

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$0.4 million and $0.3 million, respectively. For the nine months ended September 30, 2014 and 2013, we reimbursed TransMontaigne Inc. and its affiliates approximately $1.1 million and $0.9 million, respectively.

The omnibus agreement also provides TransMontaigne Inc. a right of first refusal to purchase our assets, subject to certain exceptions discussed below and provided that TransMontaigne Inc. 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 Inc. TransMontaigne Inc. will then have the sole and exclusive option, for a period of 45 days following receipt of the notice, to purchase the subject facilities for no less than 105% of the purchase price on the terms specified in the notice. Subject to certain exceptions discussed below, TransMontaigne Inc. 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 Inc. 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 Inc., or an affiliate of TransMontaigne Inc., 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 Inc. 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 Inc.’s maximum liability for this indemnification obligation is $15.0 million. TransMontaigne Inc. has no obligation to indemnify us for losses until such aggregate losses exceed $250,000. TransMontaigne Inc. 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 Inc. 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 Inc.’s maximum liability for this indemnification obligation is $15.0 million. TransMontaigne Inc. 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 Inc. 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 Inc. 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 Inc.’s maximum liability for this indemnification obligation is $15.0 million. TransMontaigne Inc. 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 Inc. 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 Inc. 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 Inc.’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 Inc. 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

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long-term terminaling services agreement with Metroplex Energy, a wholly-owned subsidiary of RaceTrac Petroleum Inc. (“Metroplex”), 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 Metroplex 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 Metroplex on September 16, 2014.  The tankage at Port Manatee is expected to become available to Metroplex by the fall 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 at our Port Everglades Northterminal.

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 lease agreement with Magellan Pipeline Company, L.P., covering 100% of the capacity of our Razorback system.

Under the Florida and Midwest terminaling services agreement, and taking into consideration the amendments to the agreement, Morgan Stanley Capital Group, and NGL as the successor to the agreement, is obligated to throughput a volume that will, at the fee and tariff schedule contained in the agreement, result in minimum throughput payments to us of approximately $21.1 million for the year ending December 31, 2014. 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—Fisher Island terminal.  We had a terminaling services agreement with TransMontaigne Inc. that expired on December 31, 2013. Under this agreement, TransMontaigne Inc. had agreed to throughput at our Fisher Island terminal in the Gulf Coast region a volume of fuel oils that, at the fee schedule contained in the agreement, resulted in revenue to us of approximately $1.8 million for the contract year ended December 31, 2013. In exchange for its minimum throughput commitment, we had agreed to provide TransMontaigne Inc. with approximately 185,000 barrels of fuel oil capacity.

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

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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, effective July 1, 2014, 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, Morgan Stanley Capital Group, and NGL as the successor to the majority of the agreement, 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 $36.8 million for the year ending December 31, 2014; 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.

On December 20, 2013, Morgan Stanley Capital Group provided us 24 months’ prior notice that it will terminate its obligations under the Southeast terminaling services agreement relating to our Collins/Purvis terminal on December 31, 2015. This termination notice does not encompass the Collins/Purvis additional light oil tankage, which is part of a separate terminaling services agreement. Our firmly committed annual revenues under the Southeast terminaling services agreement with respect to the Collins/Purvis terminal are approximately $9.2 million.

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.

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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 September 30, 2014 and 2013, we recognized revenue of approximately $1.2 million and $1.0 million, respectively, related to this operations and reimbursement agreement. For the nine months ended September 30, 2014 and 2013, we recognized revenue of approximately $3.0 million and $2.8 million, respectively, related to this operations and reimbursement agreement.

(3) TERMINAL ACQUISITIONS AND DISPOSITIONS

Investment in BOSTCO.  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, distillates and other black oils. The initial phase of BOSTCO involvedthe construction of 51 storage tanks with approximately 6.2 million barrels of storage capacity at acost of approximately $480 million. 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 that is estimated to cost approximately $55 million. The expansion is supported by a long‑term leased storage and handling services contract with Morgan Stanley Capital Group and includes six, 150,000 barrel, ultra‑low sulphur diesel tanks, additional pipeline and deepwater vessel dock access and high‑speed loading at a rate of 25,000 barrels per hour. Work on the 900,000 barrel expansion started in the second quarter of 2013, and was placed into service by 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 estimated overall construction cost of approximately $535 million. We expect our total payments for the initial and the expansion projects to be approximately $235 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.

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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.

Disposition of Mexico operations.  Effective August 8, 2013, we sold our Mexico operations to an unaffiliated third party for cash proceeds of approximately $2.1 million, net of $0.2 million in bank accounts sold related to the Mexico operations. The Mexico operations consisted of a 7,000 barrel liquefied petroleum gas storage terminal in Matamoros, Mexico and a seven mile pipeline system connecting the Matamoros terminal to our Diamondback pipeline system at the U.S. border, which connects to our Brownville, Texas terminals. The net carrying amount of the Mexico operations was approximately $3.4 million, which was in excess of the net cash proceeds, resulting in an approximate $1.3 million loss on disposition of assets. The accompanying consolidated financial statements exclude the assets, liabilities and results of the Mexico operations subsequent to August 8, 2013.

(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):

	September 30,		December 31,
	2014		2013
Trade accounts receivable	$	12,716	$	6,527
Less allowance for doubtful accounts		(464)		(100)
	$	12,252	$	6,427

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

	Three months				Nine months
	ended				ended
	September 30,				September 30,
	2014		2013		2014		2013
NGL Energy Partners LP	35	%	—	%	11	%	—	%
Morgan Stanley Capital Group	13	%	63	%	45	%	63	%

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(5) OTHER CURRENT ASSETS

Other current assets are as follows (in thousands):

	September 30,		December 31,
	2014		2013
Amounts due from insurance companies	$	1,300	$	1,722
Additive detergent		1,613		1,718
Deposits and other assets		63		38
	$	2,976	$	3,478

Amounts due from insurance companies.  We periodically file claims for recovery of environmental remediation costs with our insurance carriers under our comprehensive liability policies. We recognize our insurance recoveries in the period that we assess the likelihood of recovery as being probable (i.e., likely to occur). At September 30, 2014 and December 31, 2013, we have recognized amounts due from insurance companies of approximately $1.3 million and $1.7 million, respectively, representing our best estimate of our probable insurance recoveries. During the three and nine months ended September 30, 2014, we received reimbursements from insurance companies of approximately$0.1million and $0.4 million, respectively. During the nine months ended September 30, 2014, 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):

	September 30,		December 31,
	2014		2013
Land	$	52,519	$	52,519
Terminals, pipelines and equipment		565,065		562,077
Furniture, fixtures and equipment		2,101		1,861
Construction in progress		2,642		2,730
		622,327		619,187
Less accumulated depreciation		(234,187)		(212,142)
	$	388,140	$	407,045

(7) GOODWILL

Goodwill is as follows (in thousands):

	September 30,		December 31,
	2014		2013
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

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goodwill is performed as of December 31. The impairment test is performed at the reporting unit level. Our reporting units are our operating segments (see Note 18 of Notes to consolidated financial statements). The fair value of each reporting unit is determined on a stand‑alone basis from the perspective of a market participant and represents an estimate of the price that would be received to sell the unit as a whole in an orderly transaction between market participants at the measurement date. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered to be impaired.

At September 30, 2014 and December 31, 2013, our only reporting unit that contained goodwill was our Brownsville terminals. Our estimate of the fair value of our Brownsville terminals at December 31, 2013 exceeded its carrying amount. Accordingly, we did not recognize any goodwill impairment charges during the year ended December 31, 2013 for this reporting unit. However, a significant decline in the price of our common units with a resulting increase in the assumed market participants’ weighted average cost of capital, the loss of a significant customer, the disposition of significant assets, or an unforeseen increase in the costs to operate and maintain the Brownsville terminals, could result in the recognition of an impairment charge in the future.

(8) INVESTMENTS IN UNCONSOLIDATED AFFILIATES

At September 30, 2014 and December 31, 2013, our investments in unconsolidated affiliates include a 42.5% interest in BOSTCO and a 50% interest in Frontera. BOSTCO is a terminal facility construction project for approximately 7.1 million barrels of storage capacity at an estimated cost of approximately $535 million. BOSTCO is located on the Houston Ship Channel and began initial commercial operations in the fourth quarter of 2013 (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:

					Carrying value
	Percentageof ownership				(in thousands)
	September 30,		December 31,		September 30,		December 31,
	2014		2013		2014		2013
BOSTCO	42.5	%	42.5	%	$	228,361	$	186,181
Frontera	50	%	50	%		24,318		25,424
Total investments in unconsolidated affiliates					$	252,679	$	211,605

At September 30, 2014 and December 31, 2013, our investment in BOSTCO includes approximately $7.7 million and $6.4 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 the BOSTCO entity.

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

	Three months				Nine months
	ended				ended
	September 30,				September 30,
	2014		2013		2014		2013
BOSTCO	$	1,368	$	—	$	2,617	$	—
Frontera		285		234		474		270
Total earnings from unconsolidated affiliates	$	1,653	$	234	$	3,091	$	270

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

	Three months				Nine months
	ended				ended
	September 30,				September 30,
	2014		2013		2014		2013
BOSTCO	$	20,283	$	23,412	$	43,635	$	94,216
Frontera		—		—		45		152
Total additional capital investments in unconsolidated affiliates	$	20,283	$	23,412	$	43,680	$	94,368

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

	Three months				Nine months
	ended				ended
	September 30,				September 30,
	2014		2013		2014		2013
BOSTCO	$	2,915	$	—	$	4,072	$	—
Frontera		344		328		1,625		877
Total cash distributions received from unconsolidated affiliates	$	3,259	$	328	$	5,697	$	877

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

Balance sheets:

	BOSTCO				Frontera
	September 30,		December 31,		September 30,		December 31,
	2014		2013		2014		2013
Current assets	$	52,164	$	30,776	$	4,662	$	4,465
Long‑term assets		514,301		458,707		45,311		47,691
Current liabilities		(47,264)		(66,469)		(1,337)		(1,308)
Long‑term liabilities		—		—		—		—
Net assets	$	519,201	$	423,014	$	48,636	$	50,848

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Statements of comprehensive income (loss):

	BOSTCO				Frontera
	Three months				Three months
	ended				ended
	September 30,				September 30,
	2014		2013		2014		2013
Operating revenue	$	14,708	$	—	$	3,474	$	3,231
Operating expenses		(11,119)		—		(2,904)		(2,763)
Net earnings and comprehensive income	$	3,589	$	—	$	570	$	468
	BOSTCO				Frontera
	Nine months				Nine months
	ended				ended
	September 30,				September 30,
	2014		2013		2014		2013
Operating revenue	$	35,451	$	—	$	9,934	$	8,946
Operating expenses		(28,812)		—		(8,986)		(8,406)
Net earnings and comprehensive income	$	6,639	$	—	$	948	$	540

(9) OTHER ASSETS, NET

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

	September 30,		December 31,
	2014		2013
Amounts due under long-term terminaling services agreements:
External customers	$	760	$	592
Affiliates		1,074		2,146
		1,834		2,738
Deferred financing costs, net of accumulated amortization of $3,034 and $2,303, respectively		1,382		2,113
Customer relationships, net of accumulated amortization of $1,637 and $1,485, respectively		793		945
Deposits and other assets		76		76
	$	4,085	$	5,872

Amounts due under long‑term terminaling services agreements.  We have long‑term terminaling services agreements with certain of our customers that provide for minimum payments that increase over the terms of the respective agreements. We recognize as revenue the minimum payments under the long‑term terminaling services agreements on a straight‑line basis over the term of the respective agreements. At September 30, 2014 and December 31, 2013, 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 $1.8 million and $2.7 million, respectively.

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

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

(10) ACCRUED LIABILITIES

Accrued liabilities are as follows (in thousands):

	September 30,		December 31,
	2014		2013
Customer advances and deposits:
External customers	$	1,882	$	475
Affiliates		96		6,264
		1,978		6,739
Accrued property taxes		3,584		767
Accrued environmental obligations		1,603		1,966
Interest payable		179		163
Rebate due to customers		1,780		3,793
Accrued expenses and other		2,642		2,761
	$	11,766	$	16,189

Customer advances and deposits.  We bill certain of our customers one month in advance for terminaling services to be provided in the following month. At September 30, 2014 and December 31, 2013, we have billed and collected from certain of our customers approximately $2.0 million and $6.7 million, respectively, in advance of the terminaling services being provided.

Accrued environmental obligations.  At September 30, 2014 and December 31, 2013, we have accrued environmental obligations of approximately $1.6 million and $2.0 million, respectively, representing our best estimate of our remediation obligations. During the three and nine months ended September 30, 2014, we made payments of approximately $0.1 million and $0.5 million, respectively, towards our environmental remediation obligations. During the three and nine months ended September 30, 2014, we increased our remediation obligations by approximately $nil and $0.1 million, respectively, to reflect a change in 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 customers.  Pursuant to our terminaling services agreement related to the Southeast terminals, 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. At September 30, 2014 and December 31, 2013, we have accrued a liability due to these customers of approximately $1.8 million and $3.8 million, respectively. During the three months ended March 31, 2014, we paid approximately $3.8 million to our customers for the rebate due for the year ended December 31, 2013.

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(11) OTHER LIABILITIES

Other liabilities are as follows (in thousands):

	September 30,		December 31,
	2014		2013
Advance payments received under long-term terminaling services agreements	$	312	$	297
Deferred revenue—ethanol blending fees and other projects		3,935		5,762
	$	4,247	$	6,059

Advance payments received under long‑term terminaling services agreements.  We have long‑term terminaling services agreements with certain of our customers that provide for advance minimum payments. We recognize the advance minimum payments as revenue either on a straight‑line basis over the term of the respective agreements or when services have been provided based on volumes of product distributed. At September 30, 2014 and December 31, 2013, 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 $0.3 million, respectively.

Deferred revenue—ethanol blending fees and other projects.  Pursuant to agreements with affiliates and others, 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, affiliates and others have paid us lump‑sum amounts that will be recognized as revenue on a straight‑line basis over the remaining term of the agreements. At September 30, 2014 and December 31, 2013, we have unamortized deferred revenue of approximately $3.9 million and $5.8 million, respectively, for completed projects. During the three months ended September 30, 2014 and 2013, we recognized revenue on a straight‑line basis of approximately $0.5 million and $0.8 million, respectively, for completed projects.  During the nine months ended September 30, 2014 and 2013, we recognized revenue on a straight‑line basis of approximately $1.9 million and $3.0 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 credit facility replaced in its entirety the senior secured credit facility that was in place as of December 31, 2010. The credit facility provides for a maximum borrowing line of credit equal to the lesser of (i) $350 million and (ii) 4.75 times Consolidated EBITDA (as defined: $355.7 million at September 30, 2014). 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.

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 “permitted JV investments”. Permitted JV investments include up to $225 million of investments in BOSTCO, the “Specified BOSTCO Investment”. In addition to the Specified BOSTCO Investment, under the terms of the credit facility, we may make an additional $75 million of other permitted JV investments (including additional investments in BOSTCO). The principal balance of loans and any accrued and unpaid interest are due and payable in full on the maturity date, March 9, 2016.

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

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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 September 30, 2014.

For the three months ended September 30, 2014 and 2013, the weighted average interest rate on borrowings under the credit facility was approximately 2.7% and 2.7%, respectively.  For the nine months ended September 30, 2014 and 2013, the weighted average interest rate on borrowings under the credit facility was approximately 2.6% and 2.5%, respectively. At September 30, 2014 and December 31, 2013, our outstanding borrowings under the credit facility were $252million and $212 million, respectively. At September 30, 2014 and December 31, 2013, our outstanding letters of credit were approximately $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. 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:

	Common	General
	units	partner units
Units outstanding at September 30, 2014 and December 31, 2013	16,124,566	329,073

At September 30, 2014 and December 31, 2013, common units outstanding include 5,599 and 20,096 common units, respectively, held on behalf of TransMontaigne Services Inc.’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 Inc. TransMontaigne Services Inc. is an indirect wholly owned subsidiary of TransMontaigne Inc. TransMontaigne Services Inc. employs the personnel who provide support to TransMontaigne Inc.’s operations, as well as our operations. TransMontaigne Services Inc. 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 2,428,377 units, which amount will automatically increase on an annual basis by 2% of the total outstanding common and subordinated units, if any, at the end of the preceding fiscal year. At September 30, 2014, 2,179,457 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

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committee of the board of directors of our general partner. TransMontaigne GP purchases 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 6,003 and 5,727 common units pursuant to the program during the nine months ended September 30, 2014 and 2013, respectively.

Information about restricted phantom unit activity for the year ended December 31, 2013 and the nine months ended September 30, 2014 is as follows:

		Restricted	NYSE
	Availablefor	phantom	closing
	future grant	units	price
Units outstanding at December 31, 2013	1,871,966	14,500
Automatic increase in units available for future grant on January 1, 2014	322,491	—
Grant on March 31, 2014	(6,000)	6,000	$	43.08
Vesting on March 31, 2014	—	(5,500)	$	43.08
Vesting on July 1, 2014	—	(15,000)	$	43.80
Grant on September 30, 2014	(9,000)	9,000	$	41.24
Units outstanding at September 30, 2014	2,179,457	9,000

On March 31, 2014, TransMontaigne Services Inc. granted 6,000 restricted phantom units, respectively, to the independent directors of our general partner. We typically recognize the deferred equity‑based compensation expense associated with these annual grants 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 Inc. Accordingly, as a result of Morgan Stanley’s sale of its 100% ownership interest in TransMontaigne Inc. 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.  As of July 1, 2014, we recognized the remaining grant date fair value pertaining to these 15,000 restricted phantom units, of approximately $0.6 million, as deferred equity‑based compensation expense because the requisite service period for these restricted phantom units had been completed upon the change in control.

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 plan to 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 $584,000 and $81,000 is included in direct general and administrative expenses for the three months ended September 30, 2014 and 2013, respectively.  Deferred equity‑based compensation of approximately $698,000 and $285,000 is included in direct general and administrative expenses for the nine months ended September 30, 2014 and 2013, respectively.

(15) COMMITMENTS AND CONTINGENCIES

Contract commitments.  At September 30, 2014, we have contractual commitments of approximately $5.8 million for the supply of services, labor and materials related to capital projects that currently are under development. We expect that these contractual commitments will be paid within the next twelve months.

Operating leases.  We lease property and equipment under non‑ cancelable operating leases that extend through August 2030. At September 30, 2014, future minimum lease payments under these non‑cancelable operating leases are as follows (in thousands):

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Years ending December 31:
2014 (remainder of the year)	$	882
2015		3,841
2016		3,967
2017		2,997
2018		601
Thereafter		4,002
	$	16,290

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 $1.3million in future periods.

Rental expense under operating leases was approximately $0.9million and $0.9 million for the three months ended September 30, 2014 and 2013, respectively.  Rental expense under operating leases was approximately $2.6 million and $2.6 million for the nine months ended September 30, 2014 and 2013, respectively.

(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				Nine months ended
	September 30,				September 30,
	2014		2013		2014		2013
Net earnings	$	6,520	$	6,004	$	26,598	$	25,766
Less:
Distributions payable on behalf of incentive distribution rights		(1,682)		(1,445)		(4,967)		(3,895)
Distributions payable on behalf of general partner interest		(219)		(214)		(655)		(595)
Earnings allocable to general partner interest less than distributions payable to general partner interest		122		123		222		157
Earnings allocable to general partner interest including incentive distribution rights		(1,779)		(1,536)		(5,400)		(4,333)
Net earnings allocable to limited partners per the consolidated statements of comprehensive income	$	4,741	$	4,468	$	21,198	$	21,433
Less distributions payable on behalf of unvested long-term incentive plan grants		(6)		(9)		(26)		(41)
Net earnings allocable to limited partners for calculating net earnings per limited partner unit	$	4,735	$	4,459	$	21,172	$	21,392
Basic and diluted weighted average units		16,120		15,676		16,110		14,857
Net earnings per limited partner unit—basic and diluted	$	0.29	$	0.28	$	1.31	$	1.44

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:

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	Distribution
January 1, 2013 through March 31, 2013	$	0.640
April 1, 2013 through June 30, 2013	$	0.650
July 1, 2013 through September 30, 2013	$	0.650
October 1, 2013 through December 31, 2013	$	0.650
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

(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 September 30, 2014 and December 31, 2013.

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.

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				Nine months
	ended				ended
	September 30,				September 30,
	2014		2013		2014		2013
Gulf Coast Terminals:
Terminaling services fees, net	$	10,215	$	11,515	$	33,290	$	35,018
Other		2,318		1,973		9,406		6,802
Revenue		12,533		13,488		42,696		41,820
Direct operating costs and expenses		(5,115)		(5,180)		(14,656)		(15,642)
Net margins		7,418		8,308		28,040		26,178
Midwest Terminals and Pipeline System:
Terminaling services fees, net		2,032		1,992		6,039		5,927
Pipeline transportation fees		414		365		1,155		1,082
Other		612		691		1,622		1,871
Revenue		3,058		3,048		8,816		8,880
Direct operating costs and expenses		(682)		(841)		(2,254)		(2,305)
Net margins		2,376		2,207		6,562		6,575
Brownsville Terminals:
Terminaling services fees, net		1,624		1,631		4,588		5,390
Pipeline transportation fees		372		1,712		1,100		5,173
Other		2,932		2,950		9,076		7,803
Revenue		4,928		6,293		14,764		18,366
Direct operating costs and expenses		(3,597)		(4,303)		(10,528)		(11,712)
Net margins		1,331		1,990		4,236		6,654
River Terminals:
Terminaling services fees, net		2,336		2,188		6,450		7,604
Other		146		112		536		599
Revenue		2,482		2,300		6,986		8,203
Direct operating costs and expenses		(1,940)		(2,121)		(5,575)		(5,931)
Net margins		542		179		1,411		2,272
Southeast Terminals:
Terminaling services fees, net		11,131		11,356		34,086		34,792
Other		1,571		1,889		5,767		6,609
Revenue		12,702		13,245		39,853		41,401
Direct operating costs and expenses		(5,180)		(5,398)		(15,289)		(16,275)
Net margins		7,522		7,847		24,564		25,126
Total net margins		19,189		20,531		64,813		66,805
Direct general and administrative expenses		(1,086)		(1,201)		(2,466)		(2,952)
Allocated general and administrative expenses		(2,782)		(2,741)		(8,346)		(8,222)
Allocated insurance expense		(942)		(935)		(2,769)		(2,828)
Reimbursement of bonus awards		(375)		(313)		(1,125)		(938)
Depreciation and amortization		(7,400)		(7,392)		(22,196)		(22,191)
Loss on disposition of assets		—		(1,398)		—		(1,398)
Earnings from unconsolidated affiliates		1,653		234		3,091		270
Operating income		8,257		6,785		31,002		28,546
Other expenses, net		(1,737)		(781)		(4,404)		(2,780)
Net earnings	$	6,520	$	6,004	$	26,598	$	25,766

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

	Three months ended  September 30, 2014
			Midwest
	Gulf Coast		Terminals and		Brownsville		River		Southeast
	Terminals		Pipeline System		Terminals		Terminals		Terminals		Total
Revenue:
External customers	$	8,373	$	3,058	$	3,777	$	2,367	$	4,555	$	22,130
NGL Energy Partners LP		4,160		—		—		115		8,082		12,357
Frontera		—		—		1,151		—		—		1,151
TransMontaigne Inc.		—		—		—		—		65		65
Total revenue	$	12,533	$	3,058	$	4,928	$	2,482	$	12,702	$	35,703
Capital expenditures	$	289	$	10	$	73	$	137	$	217	$	726
Identifiable assets	$	123,817	$	23,658	$	44,322	$	54,104	$	169,107	$	415,008
Cash and cash equivalents												726
Investments in unconsolidated affiliates												252,679
Deferred financing costs												1,382
Other												559
Total assets											$	670,354

	Three months ended  September 30, 2013
			Midwest
	Gulf Coast		Terminals and		Brownsville		River		Southeast
	Terminals		Pipeline System		Terminals		Terminals		Terminals		Total
Revenue:
External customers	$	3,872	$	472	$	5,341	$	2,023	$	937	$	12,645
Morgan Stanley Capital Group		9,166		2,576		—		277		12,259		24,278
Frontera		—		—		952		—		—		952
TransMontaigne Inc.		450		—		—		—		49		499
Total revenue	$	13,488	$	3,048	$	6,293	$	2,300	$	13,245	$	38,374
Capital expenditures	$	40	$	50	$	274	$	223	$	599	$	1,186

	Nine months ended September 30, 2014
			Midwest
	Gulf Coast		Terminals and		Brownsville		River		Southeast
	Terminals		Pipeline System		Terminals		Terminals		Terminals		Total
Revenue:
External customers	$	21,054	$	5,830	$	11,779	$	6,202	$	6,362	$	51,227
NGL Energy Partners LP		4,160		—		—		115		8,082		12,357
Morgan Stanley Capital Group		17,472		2,986		—		669		25,248		46,375
Frontera		—		—		2,985		—		—		2,985
TransMontaigne Inc.		10		—		—		—		161		171
Total revenue	$	42,696	$	8,816	$	14,764	$	6,986	$	39,853	$	113,115
Capital expenditures	$	678	$	39	$	994	$	732	$	895	$	3,338

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	Nine months ended September 30, 2013
			Midwest
	Gulf Coast		Terminals and		Brownsville		River		Southeast
	Terminals		Pipeline System		Terminals		Terminals		Terminals		Total
Revenue:
External customers	$	11,689	$	1,406	$	15,561	$	7,723	$	2,837	$	39,216
Morgan Stanley Capital Group		28,769		7,474		—		456		38,455		75,154
Frontera		—		—		2,805		—		—		2,805
TransMontaigne Inc.		1,362		—		—		24		109		1,495
Total revenue	$	41,820	$	8,880	$	18,366	$	8,203	$	41,401	$	118,670
Capital expenditures	$	1,495	$	1,446	$	1,172	$	1,175	$	6,274	$	11,562

(19) SUBSEQUENT EVENT

On October 16, 2014, Charles L. Dunlap notified Partners of his intention to retire from his position as Chief Executive Officer of our general partner and as President, Chief Executive Officer and member of the board of directors of TransMontaigne Inc., and the other subsidiaries of Partners and TransMontaigne Inc., each to be effective November 7, 2014.  As a result of Mr. Dunlap’s resignation, on October 20, 2014, the board of directors of TransMontaigne GP appointed Frederick W. Boutin to serve as Chief Executive Officer of our general partner, effective November 7, 2014. Mr. Boutin has also been appointed to serve as the President and Chief Executive Officer of TransMontaigne Inc., effective November 7, 2014.  In connection with Mr. Boutin’s appointment to Chief Executive Officer, on October 20, 2014, the board of directors of TransMontaigne GP appointed Robert T. Fuller to serve as the Executive Vice President, Chief Financial Officer, Chief Accounting Officer and Treasurer of our general partner, effective November 7, 2014. Mr. Fuller has also been appointed to serve as the Executive Vice President, Chief Financial Officer and Treasurer of TransMontaigne Inc., effective November 7, 2014.

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 at our Port Everglades, Florida North terminal.

On October 13, 2014, we announced a distribution of $0.665 per unit for the period from July 1, 2014 through September 30, 2014. This distribution is payable on November 7, 2014 to unitholders of record on October 31, 2014.

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

RECENT DEVELOPMENTS

Change in control of the ownership of our general partner.Effective July 1, 2014, Morgan Stanley consummated the sale of its 100% ownership interest in TransMontaigne Inc. to NGL Energy Partners LP (“NGL”). TransMontaigne Inc. is the indirect parent and sole member of TransMontaigne GP, which is our general partner. The sale resulted in a change in control of Partners, but did not result in a deemed termination of Partners for tax purposes.

In addition to the sale of our general partner to NGL, NGL acquired the common units owned by TransMontaigne Inc. and affiliates of Morgan Stanley, representing approximately 20% of our outstanding common units, and assumed Morgan Stanley Capital Group’s obligations under our light-oil terminaling service 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. Pursuant to the terms and conditions of the NGL Acquisition, in exchange for Partners’ consent to the assignment of terminaling services agreements to NGL, an affiliate of Morgan Stanley issued a financial guarantee to Partners on certain negotiated terms, including termination of the financial guarantee upon delivery of a letter of credit from NGL.  In addition, we amended our existing credit facility to, among other items, consent to the change of control of Partners resulting from the NGL Acquisition.  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.

Termination of discussions to exchange our common units for NGL common units.On July 10, 2014, NGL submitted a non-binding, unsolicited proposal (the “Proposal”) to the Conflicts Committee of the board of directors of TransMontaigne GP, pursuant to which each outstanding common unit of Partners would have been exchanged for one common unit of NGL.  On August 15, 2014, NGL and our Conflicts Committeejointly announced, that after several discussions, an agreement on the price to be offered to Partners’ unitholders could not be reached, and both parties had terminated discussions regarding the Proposal to acquire the outstanding common units of Partners.  We do not know whether or when NGL may make another proposal similar to, or with similar objectives as, the Proposal.

Changes in our board composition and management team.In connection with the consummation of the NGL Acquisition, on July 1, 2014, Stephen R. Munger, Goran Trapp and Martin S. Mitchell, each employees of Morgan Stanley, resigned from the board of directors of TransMontaigne GP. To fill the vacancies resulting from the resignation of the Morgan Stanley directors, Atanas H. Atanasov, Benjamin Borgen, David C. Kehoe and Donald M. Jensen, each employees of NGL, were appointed to the board of directors of TransMontaigne GP effective July 1, 2014.

On August 25, 2014, Jerry R. Masters, David A. Peters and Jay A. Wiese, who qualified as independent directors under the applicable listing standards of the New York Stock Exchange,  resigned from the board of directors of TransMontaigne GP.  Mr. Masters served as the Chairman of the Audit and Compensation Committees and as a member of the Conflicts Committee. Mr. Peters served as the Chairman of the Conflicts Committee and as a member of the Audit and Compensation Committees. Mr. Wiese served as a member of the Audit, Compensation and Conflicts Committees.

On September 4, 2014, the board of directors of TransMontaigne GPappointed Robert A. Burk to serve as a director.  Mr. Burk serves as a member of the Audit and Compensation Committees, as the chair of the Conflicts Committee, and as the presiding director over non-management and independent directors.  Mr. Burk qualifies as anindependent director under the applicable listing standards of the New York Stock Exchange.

On September 24, 2014, the board of directors of the TransMontaigne GP appointed Steven A. Blank and Lawrence C. Ross to serve as directors. Mr. Blank serves as the chair of the Audit Committee and as a member of the Compensation and Conflicts Committees. Based upon his education and employment experience, Mr. Blank qualifies as an “audit committee financial expert” as defined by the Securities and Exchange Commission.Mr. Ross serves as the chair of the Compensation Committee and as a member of the Audit and Conflicts Committees.  Mr. Blank and Mr. Ross both qualify as independent directors under the applicable listing standards of the New York Stock Exchange.

On October 16, 2014, Charles L. Dunlap notified Partners of his intention to retire from his position as Chief Executive Officer of our general partner and as President, Chief Executive Officer and member of the board of directors of TransMontaigne Inc., and the other subsidiaries of Partners and TransMontaigne Inc., each to be effective November 7, 2014.  As a result of Mr. Dunlap’s resignation, on October 20, 2014, the board of directors of TransMontaigne GP appointed Frederick W. Boutin to serve as Chief Executive Officer of our general partner, effective November 7, 2014. Mr. Boutin has also been appointed to serve as the President and Chief Executive Officer of TransMontaigne Inc.,

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effective November 7, 2014.  In connection with Mr. Boutin’s appointment to Chief Executive Officer, on October 20, 2014, the board of directors of TransMontaigne GP appointed Robert T. Fuller to serve as the Executive Vice President, Chief Financial Officer, Chief Accounting Officer and Treasurer of our general partner, effective November 7, 2014. Mr. Fuller has also been appointed to serve as the Executive Vice President, Chief Financial Officer and Treasurer of TransMontaigne Inc., effective November 7, 2014.

Commercial activity.Effective September 16, 2014, we amended our long-term terminaling services agreement with Metroplex Energy, a wholly-owned subsidiary of RaceTrac Petroleum Inc. (“Metroplex”), to include the use of gasoline, ethanol and diesel tankage at our Cape Canaveral, Port Manatee and Port Everglades Southterminals located in Florida.  The tankage at Cape Canaveral and Port Everglades South became immediately available to Metroplex on September 16, 2014.  The tankage at Port Manatee is expected to become available to Metroplex by the fall of 2015, upon the completion of certain enhancements at this facility. Wehad previously entered into an agreement with Metroplex that was effective in September of 2013 relating to the use of storage capacity at our Tampa, Florida terminal.  The amended agreement brings the aggregate capacity of our tankage under contract with Metroplex in Florida to approximately 2.17 million barrels.

The tankage related to this new amendment with Metroplex was previously used by NGL under our Florida and Midwest Terminaling Services Agreement. Simultaneous with the entry into the Metroplex agreement, we amended the Florida and Midwest Terminaling Services Agreement to immediately terminate NGL’s obligations relating to the tank capacityat our Cape Canaveral and Port Everglades Southterminals, and to terminate NGL’s obligation at our Port Manatee terminal effective March 14, 2015.  We expect that the amendments to the Metroplex agreement will generate approximately the same annual revenue as the NGL agreement generated with respect to those tanks.

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 at our Port Everglades, Florida North terminal.

As of September 30, 2014, the second phase of the BOSTCO construction project, encompassing 900,000 barrels of diesel storage,has been placed into service.  With the addition of thissecond phase, combined with the initial phase becoming fully operational in the second quarter of 2014, BOSTCO has 57 storage tanks that are operational, with a  fully subscribed capacity of approximately 7.1 million barrels.

Quarterly distributions.On July 16, 2014, we announced a distribution of $0.665 per unit for the period from April 1, 2014 through June 30, 2014, representing a $0.005 increase over the previous quarter. This distribution was paid on August 7, 2014 to unitholders of record on July 31, 2014.

On October 13, 2014, we announced a distribution of $0.665 per unit for the period from July 1, 2014 through September 30, 2014. This distribution is payable on November 7, 2014 to unitholders of record on October 31, 2014.

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, 2013, included in our Annual Report on Form 10‑K, filed on March 11, 2014 (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 SEPTEMBER 30, 2014 AND 2013

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

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ANALYSIS OF REVENUE

Total Revenue.  We derive revenue from our terminal and pipeline transportation operations by charging fees for providing integrated terminaling, transportation and related services. Our total revenue by category was as follows (in thousands):

Total Revenue by Category

	Three months ended
	September 30,
	2014		2013
Terminaling services fees, net	$	27,338	$	28,682
Pipeline transportation fees		786		2,077
Management fees and reimbursed costs		1,892		1,506
Other		5,687		6,109
Revenue	$	35,703	$	38,374

See discussion below for a detailed analysis of terminaling services fees, net, pipeline transportation fees, management fees and reimbursed costs, and other revenue included in the table above.

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

Total Revenue by Business Segment

	Three months ended
	September 30,
	2014		2013
Gulf Coast terminals	$	12,533	$	13,488
Midwest terminals and pipeline system		3,058		3,048
Brownsville terminals		4,928		6,293
River terminals		2,482		2,300
Southeast terminals		12,702		13,245
Revenue	$	35,703	$	38,374

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

Terminaling Services Fees, Net.  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, net 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, net by business segments were as follows (in thousands):

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Terminaling Services Fees, Net, by Business Segment

	Three months ended
	September 30,
	2014		2013
Gulf Coast terminals	$	10,215	$	11,515
Midwest terminals and pipeline system		2,032		1,992
Brownsville terminals		1,624		1,631
River terminals		2,336		2,188
Southeast terminals		11,131		11,356
Terminaling services fees, net	$	27,338	$	28,682

The decrease in terminaling services fees, net includes a decrease of approximately $1.0 million at our Gulf Coast terminals resulting from Morgan Stanley Capital Group terminating its bunker fuels agreement at our Port Manatee, Florida and Cape Canaveral, Florida terminals 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, net for the three months ended September 30, 2014 and 2013 are fees charged to affiliates of approximately $11.1 million and $20.7 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, net were as follows (in thousands):

Firm Commitments and Variable Revenue

	Three months ended
	September 30,
	2014		2013
Firm commitments:
External customers	$	15,211	$	7,142
Affiliates		10,930		20,709
Total		26,141		27,851
Variable:
External customers		990		803
Affiliates		207		28
Total		1,197		831
Terminaling services fees, net	$	27,338	$	28,682

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At September 30, 2014, the remaining terms on the terminaling services agreements that generated “firm commitments” for the three months ended September 30, 2014 wereasfollows (in thousands):

	At
	September 30,
	2014
Remaining terms on terminaling services agreements that generated “firm commitments”:
Less than 1 year remaining	$	2,046
1 year or more, but less than 3 years remaining		19,522
3 years or more, but less than 5 years remaining		3,412
5 years or more remaining		1,161
Total firm commitments for the three months ended September 30, 2014	$	26,141

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 began leasing the Ella‑Brownsville pipeline from a third party in January 2013. 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
	September 30,
	2014		2013
Gulf Coast terminals	$	—	$	—
Midwest terminals and pipeline system		414		365
Brownsville terminals		372		1,712
River terminals		—		—
Southeast terminals		—		—
Pipeline transportation fees	$	786	$	2,077

The decrease in pipeline transportation fees includes a decrease of approximately $1.3 million resulting from a November 2013 fire that has shutdown Exxon’s King Ranch natural gas processing plant in Kleberg County, Texas. This 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 anticipate that Exxon’s King Ranch plant will not be able to supply LPG to our customer until possibly sometime in the fourth quarter of 2014. We anticipate pipeline transportation fees to decline at our Brownsville terminals while Exxon’s King Ranch plant is out of commission.  See “Item 1. Legal Proceedings” for a discussion of the legal damages we are seeking from Nieto related to them not paying certain minimum fees required under their terminaling services agreement and the reimbursement of other costs we incurred on their behalf pertaining to the shutdown of Exxon’s King Ranch plant.

Included in pipeline transportation fees for the three months ended September 30, 2014 and 2013 are fees charged to affiliates of $nil and approximately $0.4 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

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reimbursement of costs. We manage and operate the Frontera terminal facility located in Brownsville, Texas for a management fee based on our costs incurred. Frontera is an unconsolidated affiliate for which we have a 50% ownership interest. The management fees and reimbursed costs by business segments were as follows (in thousands):

Management Fees and Reimbursed Costs by Business Segment

	Three months
	ended
	September 30,
	2014		2013
Gulf Coast terminals	$	257	$	64
Midwest terminals and pipeline system		—		—
Brownsville terminals		1,635		1,442
River terminals		—		—
Southeast terminals		—		—
Management fees and reimbursed costs	$	1,892	$	1,506

Included in management fees and reimbursed costs for the three months ended September 30, 2014 and 2013 are fees charged to affiliates of approximately $1.2 million and $1.0 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 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
	September 30,
	2014		2013
Product gains	$	3,062	$	3,328
Steam heating fees		593		719
Product transfer services		611		491
Railcar handling		154		213
Other		1,267		1,358
Other revenue	$	5,687	$	6,109

For the three months ended September 30, 2014 and 2013, we sold approximately 29,000 and 32,600 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 $112 and $120 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 September 30, 2014 and 2013, we have accrued a liability due toour customers under the Southeast terminaling services agreement of approximately $0.2 million and $0.6 million, respectively.

Included in other revenue for the three months ended September 30, 2014 and 2013 are amounts charged to affiliates of approximately $1.3 million and $3.6 million, respectively.

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

Other Revenue by Business Segment

	Three months
	ended
	September 30,
	2014		2013
Gulf Coast terminals	$	2,061	$	1,909
Midwest terminals and pipeline system		612		691
Brownsville terminals		1,297		1,508
River terminals		146		112
Southeast terminals		1,571		1,889
Other revenue	$	5,687	$	6,109

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
	September 30,
	2014		2013
Wages and employee benefits	$	5,889	$	5,770
Utilities and communication charges		1,738		1,838
Repairs and maintenance		4,366		5,425
Rentals, property taxes and office supplies		2,281		2,237
Vehicles and fuel costs		273		329
Environmental compliance costs		708		882
Other		1,259		1,362
Direct operating costs and expenses	$	16,514	$	17,843

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

Direct Operating Costs and Expenses by Business Segment

	Three months
	ended
	September 30,
	2014		2013
Gulf Coast terminals	$	5,115	$	5,180
Midwest terminals and pipeline system		682		841
Brownsville terminals		3,597		4,303
River terminals		1,940		2,121
Southeast terminals		5,180		5,398
Direct operating costs and expenses	$	16,514	$	17,843

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. The direct general and administrative expenses were approximately $1.1 million and $1.2 million for the three months ended September 30, 2014 and 2013, respectively.

Allocated general and administrative expenses include charges from TransMontaigne Inc. 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 $2.7 million for the three months ended September 30, 2014 and 2013, respectively.

Allocated insurance expenses include charges from TransMontaigne Inc. for allocations of insurance premiums to cover costs of insuring activities such as property, casualty, pollution, automobile, directors’ and officers’ liability, and other insurable risks. The allocated insurance expenses were approximately $0.9 million and $0.9 million for the three months ended September 30, 2014 and 2013, respectively.

The accompanying consolidated financial statements also include amounts paid to TransMontaigne Services Inc. as a partial reimbursement of bonus awards granted by TransMontaigne Services Inc. to certain key officers and employees that vest over future service periods. The reimbursements were approximately $0.4 million and $0.3 million for the three months ended September 30, 2014 and 2013, respectively.

For the three months ended September 30, 2014 and 2013, depreciation and amortization expense was approximately $7.4 million and $7.4 million, respectively.

For the three months ended September 30, 2014 and 2013, interest expense was approximately $1.5 million and $0.5 million, respectively.  The increase in interest expense is primarily attributable to us ceasing the capitalization of interest on our investment in BOSTCO as it was being placed into service throughout the first three quarters of 2014.

RESULTS OF OPERATIONS—NINE MONTHS ENDED SEPTEMBER 30, 2014 AND 2013

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

ANALYSIS OF REVENUE

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):

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Total Revenue by Category

	Nine months ended
	September 30,
	2014		2013
Terminaling services fees, net	$	84,453	$	88,731
Pipeline transportation fees		2,255		6,255
Management fees and reimbursed costs		5,203		4,732
Other		21,204		18,952
Revenue	$	113,115	$	118,670

See discussion below for a detailed analysis of terminaling services fees, net, 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

	Nine months ended
	September 30,
	2014		2013
Gulf Coast terminals	$	42,696	$	41,820
Midwest terminals and pipeline system		8,816		8,880
Brownsville terminals		14,764		18,366
River terminals		6,986		8,203
Southeast terminals		39,853		41,401
Revenue	$	113,115	$	118,670

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

Terminaling Services Fees, Net.  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, net 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, net by business segments were as follows (in thousands):

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Terminaling Services Fees, Net, by Business Segment

	Nine months ended
	September 30,
	2014		2013
Gulf Coast terminals	$	33,290	$	35,018
Midwest terminals and pipeline system		6,039		5,927
Brownsville terminals		4,588		5,390
River terminals		6,450		7,604
Southeast terminals		34,086		34,792
Terminaling services fees, net	$	84,453	$	88,731

The decrease in terminaling services fees, net includes a decrease of approximately $1.6 million at our Gulf Coast terminals resulting from Morgan Stanley Capital Group terminating its bunker fuels agreement at our Port Manatee, Florida and Cape Canaveral, Florida terminals effective May 31, 2014. The decrease also includes a decrease of approximately $1.4 million at our River terminals resulting from a new terminaling services agreement with a third‑party customer that was effective April 1, 2013. This new terminaling services agreement reduced the third‑party customer’s minimum monthly throughput commitments from approximately 1.1 million barrels to approximately 0.6 million barrels of light refined product storage capacity at certain of our River terminals.We are currently in the process of identifying other potential parties to re‑contract the unused capacity at these Gulf Coast and River terminals.

Included in terminaling services fees, net for the nine months ended September 30, 2014 and 2013 are fees charged to affiliates of approximately $49.4 million and $63.3 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, net were as follows (in thousands):

Firm Commitments and Variable Revenue

	Nine months ended
	September 30,
	2014		2013
Firm commitments:
External customers	$	32,433	$	23,117
Affiliates		48,825		63,317
Total		81,258		86,434
Variable:
External customers		2,641		2,304
Affiliates		554		(7)
Total		3,195		2,297
Terminaling services fees, net	$	84,453	$	88,731

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At September 30, 2014, the remaining terms on the terminaling services agreements that generated “firm commitments” for the nine months ended September 30, 2014 were as follows (in thousands):

	At
	September 30,
	2014
Remaining terms on terminaling services agreements that generated “firm commitments”:
Less than 1 year remaining	$	10,921
1 year or more, but less than 3 years remaining		57,572
3 years or more, but less than 5 years remaining		10,136
5 years or more remaining		2,629
Total firm commitments for the nine months ended September 30, 2014	$	81,258

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 began leasing the Ella‑Brownsville pipeline from a third party in January 2013. 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

	Nine months
	ended
	September 30,
	2014		2013
Gulf Coast terminals	$	—	$	—
Midwest terminals and pipeline system		1,155		1,082
Brownsville terminals		1,100		5,173
River terminals		—		—
Southeast terminals		—		—
Pipeline transportation fees	$	2,255	$	6,255

The decrease in pipeline transportation fees includes a decrease of approximately $3.6 million resulting from a November 2013 fire that has shutdown Exxon’s King Ranch natural gas processing plant in Kleberg County, Texas. This 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 anticipate that Exxon’s King Ranch plant will not be able to supply LPG to our customer until possibly sometime in the fourth quarter of 2014. We anticipate pipeline transportation fees to decline at our Brownsville terminals while Exxon’s King Ranch plant is out of commission.  See “Item 1. Legal Proceedings” for a discussion of the legal damages we are seeking from Nieto related to them not paying certain minimum fees required under their terminaling services agreement and the reimbursement of other costs we incurred on their behalf pertaining to the shutdown of Exxon’s King Ranch plant.

Included in pipeline transportation fees for the nine months ended September 30, 2014 and 2013 are fees charged to affiliates of approximately $0.2 million and $1.1 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

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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

	Nine months
	ended
	September 30,
	2014		2013
Gulf Coast terminals	$	752	$	221
Midwest terminals and pipeline system		—		—
Brownsville terminals		4,451		4,511
River terminals		—		—
Southeast terminals		—		—
Management fees and reimbursed costs	$	5,203	$	4,732

Included in management fees and reimbursed costs for the nine months ended September 30, 2014 and 2013 are fees charged to affiliates of approximately $3.4 million and $2.8 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 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

	Nine months
	ended
	September 30,
	2014		2013
Product gains	$	10,753	$	11,031
Steam heating fees		2,937		2,797
Product transfer services		1,323		1,037
Railcar handling		513		471
Other		5,678		3,616
Other revenue	$	21,204	$	18,952

For the nine months ended September 30, 2014 and 2013, we sold approximately 108,150 and 114,600 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 $116 and $120 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 nine months ended September 30, 2014 and 2013, we have accrued a liability due to our customers under the Southeast terminaling services agreement of approximately $1.8 million and $2.7 million, respectively.

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Included in other revenue for the nine months ended September 30, 2014 and 2013 are amounts charged to affiliates of approximately $8.9 million and $12.3 million, respectively.

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

Other Revenue by Business Segment

	Nine months
	ended
	September 30,
	2014		2013
Gulf Coast terminals	$	8,654	$	6,581
Midwest terminals and pipeline system		1,622		1,871
Brownsville terminals		4,625		3,292
River terminals		536		599
Southeast terminals		5,767		6,609
Other revenue	$	21,204	$	18,952

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

	Nine months
	ended
	September 30,
	2014		2013
Wages and employee benefits	$	17,229	$	18,362
Utilities and communication charges		6,170		5,758
Repairs and maintenance		11,270		14,713
Rentals, property taxes and office supplies		6,957		6,889
Vehicles and fuel costs		915		1,013
Environmental compliance costs		2,062		2,018
Other		3,699		3,112
Direct operating costs and expenses	$	48,302	$	51,865

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

Direct Operating Costs and Expenses by Business Segment

	Nine months
	ended
	September 30,
	2014		2013
Gulf Coast terminals	$	14,656	$	15,642
Midwest terminals and pipeline system		2,254		2,305
Brownsville terminals		10,528		11,712
River terminals		5,575		5,931
Southeast terminals		15,289		16,275
Direct operating costs and expenses	$	48,302	$	51,865

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. The direct general and administrative expenses were approximately $2.5 million and $3.0 million for the nine months ended September 30, 2014 and 2013, respectively.

Allocated general and administrative expenses include charges from TransMontaigne Inc. for indirect corporate overhead to cover costs of centralized corporate functions such as legal, accounting, treasury, insurance administration and claims processing, health, safety and environmental, information technology, human resources, credit, payroll, taxes, engineering and other corporate services. The allocated general and administrative expenses were approximately $8.3 million and $8.2 million for the nine months ended September 30, 2014 and 2013, respectively.

Allocated insurance expenses include charges from TransMontaigne Inc. for allocations of insurance premiums to cover costs of insuring activities such as property, casualty, pollution, automobile, directors’ and officers’ liability, and other insurable risks. The allocated insurance expenses were approximately $2.8 million and $2.8 million for the nine months ended September 30, 2014 and 2013, respectively.

The accompanying consolidated financial statements also include amounts paid to TransMontaigne Services Inc. as a partial reimbursement of bonus awards granted by TransMontaigne Services Inc. to certain key officers and employees that vest over future service periods. The reimbursements were approximately $1.1 million and $0.9 million for the nine months ended September 30, 2014 and 2013, respectively.

For the nine months ended September 30, 2014 and 2013, depreciation and amortization expense was approximately $22.2 million and $22.2 million, respectively.

For the nine months ended September 30, 2014 and 2013, interest expense was approximately $3.7 million and $2.0 million, respectively.  The increase in interest expense is primarily attributable to us ceasing the capitalization of interest on our investment in BOSTCO as it was being placed into service throughout the first three quarters of 2014.

LIQUIDITY AND CAPITAL RESOURCES

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

Our capital expenditures for the nine months ended September30, 2014 were approximately $3.3 million for terminal and pipeline facilities and assets to support these facilities. In addition, we made cash investments during the

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nine months ended September 30, 2014 of approximately $43.7 million in unconsolidated affiliates. Management and the board of directors of our general partner have approved additional investments in BOSTCO and expansion capital projects at our existing terminals that currently are, or will be, under construction with estimated completion dates that extend into the third quarter of 2015. At September 30, 2014, the remaining expenditures to complete the approved additional investments and expansion capital projects are estimated to be approximately $15 million. We expect to fund our future investments and 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. The credit facility provides for a maximum borrowing line of credit equal to the lesser of (i) $350 million and (ii) 4.75 times Consolidated EBITDA (as defined: $355.7million at September 30, 2014). 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 “permitted JV investments”. Permitted JV investments include up to $225 million of investments in BOSTCO (the “Specified BOSTCO Investment”). In addition to the Specified BOSTCO Investment, under the terms of the credit facility, we may make an additional $75 million of other permitted JV investments (including additional investments in BOSTCO). The principal balance of loans and any accrued and unpaid interest are due and payable in full on the maturity date, March 9, 2016.

We may elect to have loans under the credit facility bear interest either (i) at a rate of LIBOR plus a margin ranging from 2% to 3% depending on the total leverage ratio then in effect, or (ii) at the base rate plus a margin ranging from 1% to 2% depending on the total leverage ratio then in effect. We also pay a commitment fee on the unused amount of commitments, ranging from 0.375% to 0.5% per annum, depending on the total leverage ratio then in effect. Our obligations under the credit facility are secured by a first priority security interest in favor of the lenders in the majority of our assets, including our investments in unconsolidated affiliates. At September 30, 2014, our outstanding borrowings under the credit facility were $252 million.

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

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									Twelve
	Three months ended								months ended
	December 31,		March 31,		June 30,		September 30,		September 30,
	2013		2014		2014		2014		2014
Financial performance debt covenant test:
Consolidated EBITDA for the total leverage ratio, as stipulated in the credit facility	$	18,386	$	18,474	$	20,181	$	17,847	$	74,888
Consolidated funded indebtedness									$	252,000
Total leverage ratio										3.37x
Consolidated EBITDA for the interest coverage ratio	$	18,386	$	18,474	$	20,181	$	17,847	$	74,888
Consolidated interest expense, as stipulated in the credit facility	$	677	$	953	$	1,226	$	1,493	$	4,349
Interest coverage ratio										17.22x
Reconciliation of consolidated EBITDA to cash flows provided by operating activities:
Consolidated EBITDA	$	18,386	$	18,474	$	20,181	$	17,847	$	74,888
Consolidated interest expense		(677)		(953)		(1,226)		(1,493)		(4,349)
Amortization of deferred revenue		(694)		(740)		(671)		(510)		(2,615)
Amounts due under long‑term terminaling services agreements, net		(204)		277		336		306		715
Change in operating assets and liabilities		1,206		(5,708)		(2,980)		(1,175)		(8,657)
Cash flows provided by operating activities	$	18,017	$	11,350	$	15,640	$	14,975	$	59,982

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 11, 2014, 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, 2013.

Market risk is the risk of loss arising from adverse changes in market rates and prices. The 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. At September 30, 2014, we had outstanding borrowings of $252 million under our credit facility. Based on the outstanding balance of our variable‑interest‑rate debt at September 30, 2014 and assuming market interest rates increase or decrease by 100 basis points, the potential annual increase or decrease in interest expense is $2.5 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

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product gains at our Southeast terminals. We do not use derivative commodity instruments to manage the commodity risk associated with the product we may own at any given time. Generally, to the extent we are entitled to retain product pursuant to terminaling services agreements with our customers, we sell the product to our customers on a contractually established periodic basis; the sales price is based on industry indices. For the nine months ended September 30, 2014 and 2013, we sold approximately 108,150 and 114,600 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 $116 and $120 per barrel, respectively.

ITEM 4.  CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the Commission’s rules and forms, and that information is accumulated and communicated to the management of our general partner, including our general partner’s principal executive and principal financial officer (whom we refer to as the Certifying Officers), as appropriate to allow timely decisions regarding required disclosure. The management of our general partner evaluated, with the participation of the Certifying Officers, the effectiveness of our disclosure controls and procedures as of September 30, 2014, pursuant to Rule 13a‑15(b) under the Exchange Act. Based upon that evaluation, the Certifying Officers concluded that, as of September 30, 2014, our disclosure controls and procedures were effective. There were no changes in our internal control over financial reporting that occurred during our most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Part II. Other Information

ITEM 1.  LEGAL PROCEEDINGS

Exxon’s 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”), who transports LPG on our Ella Brownsville and Diamondback pipelines and has contracted for the LPG storage capacity at our Brownsville terminals.  We anticipate that Exxon’s King Ranch plant will not be able to supply LPG to our customer until possibly sometime in the fourth quarter of 2014. In an effort to increase Nieto’s ability to transport LPG through the Diamondback pipeline during the period that Exxon’s King Ranch plant is 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.  Nieto has claimed that the fire at the Exxon King Ranch plant constitutes a force majeure that relieves Nieto of its obligation to pay certain minimum fees required under the related terminaling services agreement and has refused to reimburse us for the costs of the truck unloading facility.  As a result of Nieto’s failure to pay the minimum terminaling fees due to us and Nieto’s failure to reimburse us for the costs of the truck unloading facility we constructed for them, 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 seeking damages in the amount of $4.2 million and a declaratory judgment clarifying our rights to receive the minimum fees under the terminaling services agreement.  The $4.2 million in damages sought by us is comprised of approximately $3.7 million due as minimum fees under the terminaling services agreement as of the date of the complaint and approximately $0.5 million that we incurred in constructing the truck unloading facility.

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 11, 2014, and our quarterly report on Form 10-Q for the second quarter ended June 30, 2014, filed on August 7, 2014, 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:

· 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 attract and retain qualified personnel to operate our 47

business, secure new customers or increase or extend agreements with existing customers, or enter into or retain business relationships that are important to our operations;

· 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;

· TransMontaigne Inc. controls our general partner, which has sole responsibility for conducting our business and managing our operations. TransMontaigne Inc. and NGL have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to our detriment;

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

· 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;

· 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;

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

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

· 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;

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

· 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;

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

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

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

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

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

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

· conflicts of interest and the limited fiduciary duties of our general partner;

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

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

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

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

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

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

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

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

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

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

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

There have been no material changes from risk factors as previously disclosed in our annual report on Form 10‑K for the year ended December 31, 2013, filed on March 11, 2014, or our quarterly report on Form 10-Q for the second quarter ended June 30, 2014, filed on August 7, 2014.

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 September 30, 2014 covered by this report.

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				Total number of	Maximum number of
	Total			common units	common units that
	number of	Average price		purchased as part of	may yet be purchased
	common units	paid per		publicly announced	under the plans or
Period	purchased	common unit		plans or programs	programs
July	667	$	44.10	667	5,336
August	667	$	43.72	667	4,669
September	667	$	44.13	667	4,002
	2,001	$	43.98	2,001

During the three months ended September 30, 2014, we purchased 2,001 common units, with approximately $88,000 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 Inc. Long‑Term Incentive Plan to independent directors of our general partner. There is no guarantee as to the exact number of common units that will be purchased under the purchase program, and the purchase program may be discontinued at any time. The purchase program allows us to purchase in future periods up to 4,002 common units, in the aggregate, through the purchase program’s scheduled termination date of April 1, 2015.

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ITEM 6.  EXHIBITS

Exhibits:

31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes‑Oxley Act of 2002.
31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes‑Oxley Act of 2002.
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002.
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002.
101	The following financial information from the Quarterly Report on Form 10‑Q of TransMontaigne Partners L.P. and subsidiaries for the quarter ended September 30, 2014, formatted in XBRL (eXtensible Business Reporting Language): (i) consolidated balance sheets, (ii) consolidated statements of comprehensive income, (iii) consolidated statements of partners’ equity, (iv) consolidated statements of cash flows and (v) notes to the consolidated financial statements.

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SIGNATURES

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

		Chief Executive Officer
Date: November 7, 2014	TransMontaigne Partners L.P. (Registrant)
	TransMontaigne GP L.L.C., its General Partner
	By:	/s/ Frederick W. Boutin Frederick W. Boutin Chief Executive Officer
	By:	/s/ Robert T. Fuller Robert T. Fuller Chief Financial Officer

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EXHIBIT INDEX

Exhibit number	Description of exhibits
31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes‑Oxley Act of 2002.
31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes‑Oxley Act of 2002.
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002.
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002.
101	The following financial information from the Quarterly Report on Form 10‑Q of TransMontaigne Partners L.P. and subsidiaries for the quarter ended September 30, 2014, formatted in XBRL (eXtensible Business Reporting Language): (i) consolidated balance sheets, (ii) consolidated statements of comprehensive income, (iii) consolidated statements of partners’ equity, (iv) consolidated statements of cash flows and (v) notes to the consolidated financial statements.

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EX-31.1

Exhibit 31.1

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 September 30, 2014;

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: November  7, 2014

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 September 30, 2014;

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: November  7, 2014

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 September 30, 2014, 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
November  7, 2014

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 September 30, 2014, 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
November  7, 2014

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NET EARNINGS PER LIMITED PARTNER UNIT (Tables)

9 Months Ended

Sep. 30, 2014

NET EARNINGS PER LIMITED PARTNER UNIT

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

	Three months ended				Nine months ended
	September 30,				September 30,
	2014		2013		2014		2013
Net earnings	$	6,520	$	6,004	$	26,598	$	25,766
Less:
Distributions payable on behalf of incentive distribution rights		(1,682)		(1,445)		(4,967)		(3,895)
Distributions payable on behalf of general partner interest		(219)		(214)		(655)		(595)
Earnings allocable to general partner interest less than distributions payable to general partner interest		122		123		222		157
Earnings allocable to general partner interest including incentive distribution rights		(1,779)		(1,536)		(5,400)		(4,333)
Net earnings allocable to limited partners per the consolidated statements of comprehensive income	$	4,741	$	4,468	$	21,198	$	21,433
Less distributions payable on behalf of unvested long-term incentive plan grants		(6)		(9)		(26)		(41)
Net earnings allocable to limited partners for calculating net earnings per limited partner unit	$	4,735	$	4,459	$	21,172	$	21,392
Basic and diluted weighted average units		16,120		15,676		16,110		14,857
Net earnings per limited partner unit—basic and diluted	$	0.29	$	0.28	$	1.31	$	1.44

Schedule of distribution declared per common unit attributable to the periods

	Distribution
January 1, 2013 through March 31, 2013	$	0.640
April 1, 2013 through June 30, 2013	$	0.650
July 1, 2013 through September 30, 2013	$	0.650
October 1, 2013 through December 31, 2013	$	0.650
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

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OTHER LIABILITIES (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
OTHER LIABILITIES
Advance payments received under long-term terminaling services agreements	$ 312,000		$ 312,000		$ 297,000
Deferred revenue-ethanol blending fees and other projects	3,935,000		3,935,000		5,762,000
Other liabilities	4,247,000		4,247,000		6,059,000
Recognized revenue on a straight line basis for completed projects	$ 500,000	$ 800,000	$ 1,900,000	$ 3,000,000

XML

OTHER CURRENT ASSETS (Details) (USD $)	3 Months Ended	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2014	Dec. 31, 2013
OTHER CURRENT ASSETS
Amounts due from insurance companies	$ 1,300,000	$ 1,300,000	$ 1,722,000
Additive detergent	1,613,000	1,613,000	1,718,000
Deposits and other assets	63,000	63,000	38,000
Other current assets	2,976,000	2,976,000	3,478,000
Reimbursements from insurance companies	$ 100,000	$ 400,000

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LONG-TERM DEBT (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014 item	Sep. 30, 2013	Dec. 31, 2013
Long-term debt
Restricted net assets	$ 0		$ 0
TLP Finance Corp
Long-term debt
Ownership interest in subsidiary (as a percent)			100.00%
Amount of independent assets	0		0
Amount of independent operations			0
Credit Facility
Long-term debt
Maximum borrowing capacity	350,000,000		350,000,000
Consolidated EBITDA multiplier			4.75
Maximum borrowing capacity based on 4.75 times Consolidated EBITDA	355,700,000		355,700,000
Other permitted JV investments subject to liquidity			75,000,000
Weighted average interest rate on borrowings (as a percent)	2.70%	2.70%	2.60%	2.50%
Outstanding borrowings under credit facility	252,000,000		252,000,000		212,000,000
Credit Facility | LIBOR
Long-term debt
Reference rate			LIBOR
Credit Facility | Base Rate
Long-term debt
Reference rate			base rate
Credit Facility | Minimum
Long-term debt
Commitment fee on unused amount of commitments (as a percent)			0.375%
Interest coverage ratio	3.0		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			$ 225,000,000
Leverage ratio	4.75		4.75
Senior secured leverage ratio	3.75		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

TERMINAL ACQUISITIONS AND DISPOSITIONS (Details) (USD $)	3 Months Ended	9 Months Ended	0 Months Ended	3 Months Ended	9 Months Ended				0 Months Ended
	Sep. 30, 2013	Sep. 30, 2013	Jun. 05, 2013 BOSTCO item bbl	Sep. 30, 2013 BOSTCO bbl	Sep. 30, 2014 BOSTCO bbl item	Jun. 05, 2013 BOSTCO	Dec. 20, 2012 BOSTCO Kinder Morgan	Dec. 20, 2012 BOSTCO Kinder Morgan Class A Members	Aug. 08, 2013 Mexico Operations mi bbl	Aug. 08, 2013 Mexico Operations bbl
ACQUISITIONS
Ownership interest acquired (as a percent)								42.50%
Cost of voting interest acquired							$ 79,000,000
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
Estimated construction cost of storage tanks, the construction of which is involved in the initial phase of acquisition					480,000,000
Cost of project expansion						55,000,000
Number of ultra low sulphur diesel tanks involved in the expansion phase of acquisition			6
Number of barrels in each ultra low sulphur diesel tank			150,000
High-speed loading rate of barrels per hour involved in the expansion phase of acquisition (in barrels)			25,000
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
Estimated overall construction cost of storage tanks including initial phase and expansion projects			535,000,000
Expected total payments for the initial and expansion projects			235,000,000
Cash proceeds from sale of operations									2,100,000
Amount in bank accounts related sale of operations									200,000
Number of barrels of active storage capacity sold										7,000
Length of pipelines connecting the terminal to the entity's pipelines sold under disposition of operations									7
Carrying amount of disposed operations									3,400,000
Loss on disposition of assets	$ 1,398,000	$ 1,398,000							$ 1,300,000

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OTHER ASSETS, NET (Tables)

9 Months Ended

Sep. 30, 2014

OTHER ASSETS, NET

Schedule of other assets, net (in thousands)

	September 30,		December 31,
	2014		2013
Amounts due under long-term terminaling services agreements:
External customers	$	760	$	592
Affiliates		1,074		2,146
		1,834		2,738
Deferred financing costs, net of accumulated amortization of $3,034 and $2,303, respectively		1,382		2,113
Customer relationships, net of accumulated amortization of $1,637 and $1,485, respectively		793		945
Deposits and other assets		76		76
	$	4,085	$	5,872

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LONG-TERM INCENTIVE PLAN (Details) (USD $) In Thousands, except Share data, unless otherwise specified	0 Months Ended				1 Months Ended	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Jul. 01, 2014	Mar. 31, 2014	Jan. 01, 2014	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
TransMontaigne GP
Additional disclosures
Number of independent directors appointed					3
TransMontaigne, Inc. | Morgan Stanley [Member]
Additional disclosures
Ownership interest sold (as a percent)		100.00%
Long-term incentive plan
Long-term incentive plan
Authorized units	2,428,377				2,428,377	2,428,377		2,428,377
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 beginning of the period	2,179,457			1,871,966				1,871,966
Automatic increase in units available for future grant				322,491
Grant (in units)			(6,000)		(9,000)
Units outstanding at the end of the period	2,179,457				2,179,457	2,179,457		2,179,457
Restricted phantom units
Grant (in units)			6,000		9,000
NYSE closing price
Grant (in dollars per unit)	$ 41.24		$ 43.08
Vesting (in dollars per unit)		$ 43.80	$ 43.08
Additional disclosures
Deferred equity-based compensation included in direct general and administrative expenses						$ 584	$ 81	$ 698	$ 285
Long-term incentive plan | TransMontaigne Services Inc.
Additional disclosures
Vesting period								4 years
Long-term incentive plan | Common unitholders | TransMontaigne GP
Long-term incentive plan
Number of common units purchased						6,003	5,727
Long-term incentive plan | Restricted phantom units
Available for future grant
Grant (in units)			(6,000)					(9,000)
Vesting (in units)		(15,000)	(5,500)
Restricted phantom units
Units outstanding at the beginning of the period				14,500				14,500
Grant (in units)			6,000					9,000
Vesting (in units)		(15,000)	(5,500)
Units outstanding at the end of the period	9,000				9,000	9,000		9,000
Additional disclosures
Deferred equity-based compensation included in direct general and administrative expenses		$ 600
Long-term incentive plan | Restricted phantom units | TransMontaigne Services Inc.
Available for future grant
Grant (in units)			(6,000)
Restricted phantom units
Grant (in units)			6,000

XML

BUSINESS SEGMENTS

9 Months Ended

Sep. 30, 2014

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				Nine months
	ended				ended
	September 30,				September 30,
	2014		2013		2014		2013
Gulf Coast Terminals:
Terminaling services fees, net	$	10,215	$	11,515	$	33,290	$	35,018
Other		2,318		1,973		9,406		6,802
Revenue		12,533		13,488		42,696		41,820
Direct operating costs and expenses		(5,115)		(5,180)		(14,656)		(15,642)
Net margins		7,418		8,308		28,040		26,178
Midwest Terminals and Pipeline System:
Terminaling services fees, net		2,032		1,992		6,039		5,927
Pipeline transportation fees		414		365		1,155		1,082
Other		612		691		1,622		1,871
Revenue		3,058		3,048		8,816		8,880
Direct operating costs and expenses		(682)		(841)		(2,254)		(2,305)
Net margins		2,376		2,207		6,562		6,575
Brownsville Terminals:
Terminaling services fees, net		1,624		1,631		4,588		5,390
Pipeline transportation fees		372		1,712		1,100		5,173
Other		2,932		2,950		9,076		7,803
Revenue		4,928		6,293		14,764		18,366
Direct operating costs and expenses		(3,597)		(4,303)		(10,528)		(11,712)
Net margins		1,331		1,990		4,236		6,654
River Terminals:
Terminaling services fees, net		2,336		2,188		6,450		7,604
Other		146		112		536		599
Revenue		2,482		2,300		6,986		8,203
Direct operating costs and expenses		(1,940)		(2,121)		(5,575)		(5,931)
Net margins		542		179		1,411		2,272
Southeast Terminals:
Terminaling services fees, net		11,131		11,356		34,086		34,792
Other		1,571		1,889		5,767		6,609
Revenue		12,702		13,245		39,853		41,401
Direct operating costs and expenses		(5,180)		(5,398)		(15,289)		(16,275)
Net margins		7,522		7,847		24,564		25,126
Total net margins		19,189		20,531		64,813		66,805
Direct general and administrative expenses		(1,086)		(1,201)		(2,466)		(2,952)
Allocated general and administrative expenses		(2,782)		(2,741)		(8,346)		(8,222)
Allocated insurance expense		(942)		(935)		(2,769)		(2,828)
Reimbursement of bonus awards		(375)		(313)		(1,125)		(938)
Depreciation and amortization		(7,400)		(7,392)		(22,196)		(22,191)
Loss on disposition of assets		—		(1,398)		—		(1,398)
Earnings from unconsolidated affiliates		1,653		234		3,091		270
Operating income		8,257		6,785		31,002		28,546
Other expenses, net		(1,737)		(781)		(4,404)		(2,780)
Net earnings	$	6,520	$	6,004	$	26,598	$	25,766

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

	Three months ended  September 30, 2014
			Midwest
	Gulf Coast		Terminals and		Brownsville		River		Southeast
	Terminals		Pipeline System		Terminals		Terminals		Terminals		Total
Revenue:
External customers	$	8,373	$	3,058	$	3,777	$	2,367	$	4,555	$	22,130
NGL Energy Partners LP		4,160		—		—		115		8,082		12,357
Frontera		—		—		1,151		—		—		1,151
TransMontaigne Inc.		—		—		—		—		65		65
Total revenue	$	12,533	$	3,058	$	4,928	$	2,482	$	12,702	$	35,703
Capital expenditures	$	289	$	10	$	73	$	137	$	217	$	726
Identifiable assets	$	123,817	$	23,658	$	44,322	$	54,104	$	169,107	$	415,008
Cash and cash equivalents												726
Investments in unconsolidated affiliates												252,679
Deferred financing costs												1,382
Other												559
Total assets											$	670,354

	Three months ended  September 30, 2013
			Midwest
	Gulf Coast		Terminals and		Brownsville		River		Southeast
	Terminals		Pipeline System		Terminals		Terminals		Terminals		Total
Revenue:
External customers	$	3,872	$	472	$	5,341	$	2,023	$	937	$	12,645
Morgan Stanley Capital Group		9,166		2,576		—		277		12,259		24,278
Frontera		—		—		952		—		—		952
TransMontaigne Inc.		450		—		—		—		49		499
Total revenue	$	13,488	$	3,048	$	6,293	$	2,300	$	13,245	$	38,374
Capital expenditures	$	40	$	50	$	274	$	223	$	599	$	1,186

	Nine months ended September 30, 2014
			Midwest
	Gulf Coast		Terminals and		Brownsville		River		Southeast
	Terminals		Pipeline System		Terminals		Terminals		Terminals		Total
Revenue:
External customers	$	21,054	$	5,830	$	11,779	$	6,202	$	6,362	$	51,227
NGL Energy Partners LP		4,160		—		—		115		8,082		12,357
Morgan Stanley Capital Group		17,472		2,986		—		669		25,248		46,375
Frontera		—		—		2,985		—		—		2,985
TransMontaigne Inc.		10		—		—		—		161		171
Total revenue	$	42,696	$	8,816	$	14,764	$	6,986	$	39,853	$	113,115
Capital expenditures	$	678	$	39	$	994	$	732	$	895	$	3,338

	Nine months ended September 30, 2013
			Midwest
	Gulf Coast		Terminals and		Brownsville		River		Southeast
	Terminals		Pipeline System		Terminals		Terminals		Terminals		Total
Revenue:
External customers	$	11,689	$	1,406	$	15,561	$	7,723	$	2,837	$	39,216
Morgan Stanley Capital Group		28,769		7,474		—		456		38,455		75,154
Frontera		—		—		2,805		—		—		2,805
TransMontaigne Inc.		1,362		—		—		24		109		1,495
Total revenue	$	41,820	$	8,880	$	18,366	$	8,203	$	41,401	$	118,670
Capital expenditures	$	1,495	$	1,446	$	1,172	$	1,175	$	6,274	$	11,562

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GOODWILL (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Goodwill
Goodwill	$ 8,485	$ 8,485
Brownsville terminals
Goodwill
Goodwill	$ 8,485	$ 8,485

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details 2)	9 Months Ended
	Sep. 30, 2014
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

XML

LONG-TERM INCENTIVE PLAN (Tables)

9 Months Ended

Sep. 30, 2014

LONG-TERM INCENTIVE PLAN

Schedule of restricted phantom unit activity

		Restricted	NYSE
	Availablefor	phantom	closing
	future grant	units	price
Units outstanding at December 31, 2013	1,871,966	14,500
Automatic increase in units available for future grant on January 1, 2014	322,491	—
Grant on March 31, 2014	(6,000)	6,000	$	43.08
Vesting on March 31, 2014	—	(5,500)	$	43.08
Vesting on July 1, 2014	—	(15,000)	$	43.80
Grant on September 30, 2014	(9,000)	9,000	$	41.24
Units outstanding at September 30, 2014	2,179,457	9,000

XML

OTHER ASSETS, NET (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Amounts due under long-term terminaling services agreements:
External customers	$ 760	$ 592
Affiliates	1,074	2,146
Amounts due under long-term terminaling services agreements	1,834	2,738
Deferred financing costs, net of accumulated amortization of $2,791 and $2,303, respectively	1,382	2,113
Customer relationships, net of accumulated amortization of $1,586 and $1,485, respectively	793	945
Deposits and other assets	76	76
Other assets, net	4,085	5,872
Accumulated amortization of deferred financing costs	3,034	2,303
Accumulated amortization of customer relationships	$ 1,637	$ 1,485
Amortization period of customer relationships	12 years

XML

SUBSEQUENT EVENT (Details) (USD $)	3 Months Ended						0 Months Ended
	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Mar. 31, 2013	Oct. 13, 2014 Subsequent Event	Oct. 31, 2014 Subsequent Event Terminaling services agreement-Florida and Midwest terminals
Subsequent Event
Notification period, in months								18 months
Distribution announced per unit (in dollars per unit)	$ 0.665	$ 0.665	$ 0.660	$ 0.650	$ 0.650	$ 0.640	$ 0.665

XML

CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE (Details) (USD $) In Thousands, unless otherwise specified			3 Months Ended	9 Months Ended	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014 NGL Energy Partners LP	Sep. 30, 2014 NGL Energy Partners LP	Sep. 30, 2014 Morgan Stanley Capital Group	Sep. 30, 2013 Morgan Stanley Capital Group	Sep. 30, 2014 Morgan Stanley Capital Group	Sep. 30, 2013 Morgan Stanley Capital Group
CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE
Trade accounts receivable	$ 12,716	$ 6,527
Less allowance for doubtful accounts	(464)	(100)
Trade accounts receivable, net	$ 12,252	$ 6,427
Customer who accounted for at least 10% of consolidated revenue
Percentage of total revenue generated by major customer			35.00%	11.00%	13.00%	63.00%	45.00%	63.00%

XML

TRANSACTIONS WITH AFFILIATES

9 Months Ended

Sep. 30, 2014

TRANSACTIONS WITH AFFILIATES

TRANSACTIONS WITH AFFILIATES

(2) TRANSACTIONS WITH AFFILIATES

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

Under the omnibus agreement we pay TransMontaigne Inc. an administrative fee for the provision of various general and administrative services for our benefit. For the three months ended September 30, 2014 and 2013, the administrative fee paid to TransMontaigne Inc. was approximately $2.8 million and $2.7 million, respectively. For the nine months endedSeptember 30, 2014 and 2013, the administrative fee paid to TransMontaigne Inc. was approximately $8.3 million and $8.2 million, respectively. If we acquire or construct additional facilities, TransMontaigne Inc. 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 Inc. will provide services for the additional facilities pursuant to the agreement. The administrative fee includes expenses incurred by TransMontaigne Inc. 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 Inc.

The omnibus agreement further provides that we pay TransMontaigne Inc. an insurance reimbursement for premiums on insurance policies covering our facilities and operations. For the three months ended September 30, 2014 and 2013, the insurance reimbursement paid to TransMontaigne Inc. was approximately $0.9 million and $0.9 million, respectively. For the nine months ended September 30, 2014 and 2013, the insurance reimbursement paid to TransMontaigne Inc. was approximately $2.8 million and $2.8 million, respectively. We also reimburse TransMontaigne Inc. for direct operating costs and expenses that TransMontaigne Inc. 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.

We also agreed to reimburse TransMontaigne Inc. and its affiliates for a portion of the incentive payment grants to key employees of TransMontaigne Inc. and its affiliates under the TransMontaigne Services Inc. savings and retention plan, provided the compensation committee of our general partner determines that an adequate portion of the incentive payment grants are allocated to an investment fund indexed to the performance of our common units. For the three months ended September 30, 2014 and 2013, we reimbursed TransMontaigne Inc. and its affiliates approximately $0.4 million and $0.3 million, respectively. For the nine months ended September 30, 2014 and 2013, we reimbursed TransMontaigne Inc. and its affiliates approximately $1.1 million and $0.9 million, respectively.

The omnibus agreement also provides TransMontaigne Inc. a right of first refusal to purchase our assets, subject to certain exceptions discussed below and provided that TransMontaigne Inc. 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 Inc. TransMontaigne Inc. will then have the sole and exclusive option, for a period of 45 days following receipt of the notice, to purchase the subject facilities for no less than 105% of the purchase price on the terms specified in the notice. Subject to certain exceptions discussed below, TransMontaigne Inc. 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 Inc. 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 Inc., or an affiliate of TransMontaigne Inc., 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 Inc. 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 Inc.’s maximum liability for this indemnification obligation is $15.0 million. TransMontaigne Inc. has no obligation to indemnify us for losses until such aggregate losses exceed $250,000. TransMontaigne Inc. 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 Inc. 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 Inc.’s maximum liability for this indemnification obligation is $15.0 million. TransMontaigne Inc. 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 Inc. 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 Inc. 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 Inc.’s maximum liability for this indemnification obligation is $15.0 million. TransMontaigne Inc. 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 Inc. 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 Inc. 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 Inc.’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 Inc. 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 Metroplex Energy, a wholly-owned subsidiary of RaceTrac Petroleum Inc. (“Metroplex”), 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 Metroplex 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 Metroplex on September 16, 2014.  The tankage at Port Manatee is expected to become available to Metroplex by the fall 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 at our Port Everglades North terminal.

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 lease agreement with Magellan Pipeline Company, L.P., covering 100% of the capacity of our Razorback system.

Under the Florida and Midwest terminaling services agreement, and taking into consideration the amendments to the agreement, Morgan Stanley Capital Group, and NGL as the successor to the agreement, is obligated to throughput a volume that will, at the fee and tariff schedule contained in the agreement, result in minimum throughput payments to us of approximately $21.1 million for the year ending December 31, 2014. 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—Fisher Island terminal.  We had a terminaling services agreement with TransMontaigne Inc. that expired on December 31, 2013. Under this agreement, TransMontaigne Inc. had agreed to throughput at our Fisher Island terminal in the Gulf Coast region a volume of fuel oils that, at the fee schedule contained in the agreement, resulted in revenue to us of approximately $1.8 million for the contract year ended December 31, 2013. In exchange for its minimum throughput commitment, we had agreed to provide TransMontaigne Inc. with approximately 185,000 barrels of fuel oil capacity.

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, effective July 1, 2014, 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, Morgan Stanley Capital Group, and NGL as the successor to the majority of the agreement, 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 $36.8 million for the year ending December 31, 2014; 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.

On December 20, 2013, Morgan Stanley Capital Group provided us 24 months’ prior notice that it will terminate its obligations under the Southeast terminaling services agreement relating to our Collins/Purvis terminal on December 31, 2015. This termination notice does not encompass the Collins/Purvis additional light oil tankage, which is part of a separate terminaling services agreement. Our firmly committed annual revenues under the Southeast terminaling services agreement with respect to the Collins/Purvis terminal are approximately $9.2 million.

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 September 30, 2014 and 2013, we recognized revenue of approximately $1.2 million and $1.0 million, respectively, related to this operations and reimbursement agreement. For the nine months ended September 30, 2014 and 2013, we recognized revenue of approximately $3.0 million and $2.8 million, respectively, related to this operations and reimbursement agreement.

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details 3) (TransMontaigne Inc., Maximum, USD $) In Millions, unless otherwise specified	Sep. 30, 2014
Florida and Midwest terminals
Environmental obligations
Obligation of TransMontaigne Inc. to indemnify the entity against certain potential environmental claims, losses and expenses	$ 15.0
Brownsville and River terminals
Environmental obligations
Obligation of TransMontaigne Inc. to indemnify the entity against certain potential environmental claims, losses and expenses	15.0
Southeast Terminals
Environmental obligations
Obligation of TransMontaigne Inc. to indemnify the entity against certain potential environmental claims, losses and expenses	15.0
Pensacola terminal
Environmental obligations
Obligation of TransMontaigne Inc. to indemnify the entity against certain potential environmental claims, losses and expenses	$ 2.5

XML

OTHER CURRENT ASSETS (Tables)

9 Months Ended

Sep. 30, 2014

OTHER CURRENT ASSETS

Schedule of other current assets (in thousands)

	September 30,		December 31,
	2014		2013
Amounts due from insurance companies	$	1,300	$	1,722
Additive detergent		1,613		1,718
Deposits and other assets		63		38
	$	2,976	$	3,478

XML

CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE (Tables)

9 Months Ended

Sep. 30, 2014

CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE

Schedule of trade accounts receivable, net (in thousands)

	September 30,		December 31,
	2014		2013
Trade accounts receivable	$	12,716	$	6,527
Less allowance for doubtful accounts		(464)		(100)
	$	12,252	$	6,427

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

	Three months				Nine months
	ended				ended
	September 30,				September 30,
	2014		2013		2014		2013
NGL Energy Partners LP	35	%	—	%	11	%	—	%
Morgan Stanley Capital Group	13	%	63	%	45	%	63	%

XML

PARTNERS' EQUITY (Details)	Sep. 30, 2014	Dec. 31, 2013
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
Common unitholders | Long-term incentive plan
Changes in number of units outstanding
Units outstanding at the beginning of the period	5,599	20,096
Units outstanding at the end of the period	5,599	20,096
General partner interest
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

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details 4) (USD $) In Millions, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Income taxes
Provision for U.S. federal income taxes	$ 0
Net earnings per limited partner unit
Limited partner interest (as a percent)	98.00%
General partner interest (as a percent)	2.00%	2.00%

XML

PROPERTY, PLANT AND EQUIPMENT, NET (Tables)

9 Months Ended

Sep. 30, 2014

PROPERTY, PLANT AND EQUIPMENT, NET

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

	September 30,		December 31,
	2014		2013
Land	$	52,519	$	52,519
Terminals, pipelines and equipment		565,065		562,077
Furniture, fixtures and equipment		2,101		1,861
Construction in progress		2,642		2,730
		622,327		619,187
Less accumulated depreciation		(234,187)		(212,142)
	$	388,140	$	407,045

XML

GOODWILL (Tables)

9 Months Ended

Sep. 30, 2014

GOODWILL

Schedule of goodwill (in thousands)

	September 30,		December 31,
	2014		2013
Brownsville terminals	$	8,485	$	8,485

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

9 Months Ended

Sep. 30, 2014

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 a wholly‑owned subsidiary of TransMontaigne Inc. At September 30, 2014, NGL Energy Partners LP (“NGL”) owned all of the issued and outstanding capital stock of TransMontaigne Inc., and, as a result, NGL is the indirect owner of our general partner. At September 30, 2014, TransMontaigne Inc. and NGL had a significant interest in our partnership through their indirect ownership of an approximate 20% 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 Inc., 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 Inc. to NGL. The sale resulted in a change in control of Partners, but did not result in a deemed termination of Partners for tax purposes.

In addition to the sale of our general partner to NGL, NGL acquired the common units owned by TransMontaigne Inc. and affiliates of Morgan Stanley, representing approximately 20% of our outstanding common units, and assumed Morgan Stanley Capital Group’s obligations under our light-oil terminaling service agreements in Florida and the Southeast regions, excluding the Collins/Purvis tankage (collectively, the “NGL Acquisition”). All other terminaling services agreements with Morgan Stanley Capital Group remained with Morgan Stanley Capital Group. The NGL Acquisition did not involve the sale or purchase of any of our common units held by the public and our common units continue to trade on the New York Stock Exchange.

(b) Basis of presentation and use of estimates

Our accounting and financial reporting policies conform to accounting principles and practices generally accepted in the United States of America. The accompanying consolidated financial statements include the accounts of TransMontaigne Partners L.P., a Delaware limited partnership, and its controlled subsidiaries. Investments where we do not have the ability to exercise control, but do have the ability to exercise significant influence, are accounted for using the equity method of accounting. All inter‑company accounts and transactions have been eliminated in the preparation of the accompanying consolidated financial statements. The accompanying consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly our financial position as of September 30, 2014 and December 31, 2013, our results of operations for the three and nine months ended September 30, 2014 and 2013 and our cash flows for the three and nine months ended September 30, 2014 and 2013.

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.

The accompanying consolidated financial statements include allocated general and administrative charges from TransMontaigne Inc. for indirect corporate overhead to cover costs of functions such as legal, accounting, treasury, engineering, environmental safety, information technology, and other corporate services (see Note 2 of Notes to consolidated financial statements). The allocated general and administrative expenses were approximately $2.8 million and $2.7 million for the three months ended September 30, 2014 and 2013, respectively. The allocated general and administrative expenses were approximately $8.3 million and $8.2 million for the nine months ended September 30, 2014 and 2013, respectively. The accompanying consolidated financial statements also include allocated insurance charges from TransMontaigne Inc. for 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 charges were approximately $0.9 million and $0.9 million for the three months ended September 30, 2014 and 2013, respectively. The allocated insurance charges were approximately $2.8 million and $2.8 million for the nine months ended September 30, 2014 and 2013, respectively. The accompanying consolidated financial statements also include reimbursement of bonus awards paid to TransMontaigne Services Inc. (a wholly‑ owned subsidiary of TransMontaigne Inc.) towards bonus awards granted by TransMontaigne Services Inc. to certain key officers and employees who provide services to Partners that vest over future periods. The reimbursement of bonus awards was approximately $0.4 million and $0.3 million for the three months ended September 30, 2014 and 2013, respectively. The reimbursement of bonus awards was approximately $1.1 million and $0.9 million for the nine months ended September 30, 2014 and 2013, respectively.

(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 throughput; transportation revenue is recognized when the product has been delivered to the customer at the specified delivery location; management fee revenue and cost reimbursements are recognized as the services are performed or as the costs are incurred; ancillary service revenue is recognized as the services are performed; and gains from the sale of refined products are recognized when the title to the product is transferred.

Pursuant to terminaling services agreements with certain of our throughput customers, we are entitled to the volume of product gained resulting from differences in the measurement of product volumes received and distributed at our terminaling facilities. Consistent with recognized industry practices, measurement differentials occur as the result of the inherent variances in measurement devices and methodology. We recognize as revenue the net proceeds from the sale of the product gained. For the three months ended September 30, 2014 and 2013, we recognized revenue of approximately $3.1 million and $3.3 million, respectively, for net product gained. Within these amounts, approximately $1.2 million and $2.9 million for the three months ended September 30, 2014 and 2013, respectively, were pursuant to terminaling services agreements with affiliate customers. For the nine months ended September 30, 2014 and 2013, we recognized revenue of approximately $10.8 million and $11.0 million, respectively, for net product gained. Within these amounts, approximately $6.1 million and $9.8 million for the nine months ended September 30, 2014 and 2013, 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 Inc. 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 (see Note 2 of Notes to consolidated financial statements). TransMontaigne Inc. 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 (see Note 2 of Notes to consolidated financial statements). TransMontaigne Inc. 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 (see Note 2 of Notes to consolidated financial statements). TransMontaigne Inc. 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 (see Note 2 of Notes to consolidated financial statements).

(h) Asset retirement obligations

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

The functional currency of Partners and its U.S.‑based subsidiaries is the U.S. Dollar. The functional currency of our Mexico operations, which we sold effective August 8, 2013 (see Note 3 of Notes to consolidated financial statements), was the Mexican Peso. The assets and liabilities of our foreign subsidiaries were translated at period‑end rates of exchange, and revenue and expenses were translated at average exchange rates prevailing for the period. The resulting translation adjustments, net of related income taxes, were recorded as a component of other comprehensive income in the consolidated statements of comprehensive income. Gains and losses from the re‑measurement of foreign currency transactions (transactions denominated in a currency other than the entity’s functional currency) were included in other income (expenses) in the consolidated statements of comprehensive income.

(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. Certain of our Mexican subsidiaries were corporations for Mexican tax purposes and, therefore, were subject to Mexican federal and provincial income taxes. Effective August 8, 2013, we sold our Mexico operations, including the Mexican corporations (see Note 3 of Notes to consolidated financial statements).

Partners accounts for U.S. state income taxes and Mexican federal and provincial income taxes under the asset and liability method pursuant to generally accepted accounting principles. Mexican federal and provincial income taxes and 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.

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INVESTMENTS IN UNCONSOLIDATED AFFILIATES (Tables)

9 Months Ended

Sep. 30, 2014

INVESTMENTS IN UNCONSOLIDATED AFFILIATES

Summary of investments in unconsolidated affiliates

					Carrying value
	Percentageof ownership				(in thousands)
	September 30,		December 31,		September 30,		December 31,
	2014		2013		2014		2013
BOSTCO	42.5	%	42.5	%	$	228,361	$	186,181
Frontera	50	%	50	%		24,318		25,424
Total investments in unconsolidated affiliates					$	252,679	$	211,605

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

	Three months				Nine months
	ended				ended
	September 30,				September 30,
	2014		2013		2014		2013
BOSTCO	$	1,368	$	—	$	2,617	$	—
Frontera		285		234		474		270
Total earnings from unconsolidated affiliates	$	1,653	$	234	$	3,091	$	270

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

	Three months				Nine months
	ended				ended
	September 30,				September 30,
	2014		2013		2014		2013
BOSTCO	$	20,283	$	23,412	$	43,635	$	94,216
Frontera		—		—		45		152
Total additional capital investments in unconsolidated affiliates	$	20,283	$	23,412	$	43,680	$	94,368

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

	Three months				Nine months
	ended				ended
	September 30,				September 30,
	2014		2013		2014		2013
BOSTCO	$	2,915	$	—	$	4,072	$	—
Frontera		344		328		1,625		877
Total cash distributions received from unconsolidated affiliates	$	3,259	$	328	$	5,697	$	877

Summary of financial information of unconsolidated affiliates

Balance sheets:

	BOSTCO				Frontera
	September 30,		December 31,		September 30,		December 31,
	2014		2013		2014		2013
Current assets	$	52,164	$	30,776	$	4,662	$	4,465
Long‑term assets		514,301		458,707		45,311		47,691
Current liabilities		(47,264)		(66,469)		(1,337)		(1,308)
Long‑term liabilities		—		—		—		—
Net assets	$	519,201	$	423,014	$	48,636	$	50,848

Statements of comprehensive income (loss):

	BOSTCO				Frontera
	Three months				Three months
	ended				ended
	September 30,				September 30,
	2014		2013		2014		2013
Operating revenue	$	14,708	$	—	$	3,474	$	3,231
Operating expenses		(11,119)		—		(2,904)		(2,763)
Net earnings and comprehensive income	$	3,589	$	—	$	570	$	468
	BOSTCO				Frontera
	Nine months				Nine months
	ended				ended
	September 30,				September 30,
	2014		2013		2014		2013
Operating revenue	$	35,451	$	—	$	9,934	$	8,946
Operating expenses		(28,812)		—		(8,986)		(8,406)
Net earnings and comprehensive income	$	6,639	$	—	$	948	$	540

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BUSINESS SEGMENTS (Tables)

9 Months Ended

Sep. 30, 2014

BUSINESS SEGMENTS

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

	Three months				Nine months
	ended				ended
	September 30,				September 30,
	2014		2013		2014		2013
Gulf Coast Terminals:
Terminaling services fees, net	$	10,215	$	11,515	$	33,290	$	35,018
Other		2,318		1,973		9,406		6,802
Revenue		12,533		13,488		42,696		41,820
Direct operating costs and expenses		(5,115)		(5,180)		(14,656)		(15,642)
Net margins		7,418		8,308		28,040		26,178
Midwest Terminals and Pipeline System:
Terminaling services fees, net		2,032		1,992		6,039		5,927
Pipeline transportation fees		414		365		1,155		1,082
Other		612		691		1,622		1,871
Revenue		3,058		3,048		8,816		8,880
Direct operating costs and expenses		(682)		(841)		(2,254)		(2,305)
Net margins		2,376		2,207		6,562		6,575
Brownsville Terminals:
Terminaling services fees, net		1,624		1,631		4,588		5,390
Pipeline transportation fees		372		1,712		1,100		5,173
Other		2,932		2,950		9,076		7,803
Revenue		4,928		6,293		14,764		18,366
Direct operating costs and expenses		(3,597)		(4,303)		(10,528)		(11,712)
Net margins		1,331		1,990		4,236		6,654
River Terminals:
Terminaling services fees, net		2,336		2,188		6,450		7,604
Other		146		112		536		599
Revenue		2,482		2,300		6,986		8,203
Direct operating costs and expenses		(1,940)		(2,121)		(5,575)		(5,931)
Net margins		542		179		1,411		2,272
Southeast Terminals:
Terminaling services fees, net		11,131		11,356		34,086		34,792
Other		1,571		1,889		5,767		6,609
Revenue		12,702		13,245		39,853		41,401
Direct operating costs and expenses		(5,180)		(5,398)		(15,289)		(16,275)
Net margins		7,522		7,847		24,564		25,126
Total net margins		19,189		20,531		64,813		66,805
Direct general and administrative expenses		(1,086)		(1,201)		(2,466)		(2,952)
Allocated general and administrative expenses		(2,782)		(2,741)		(8,346)		(8,222)
Allocated insurance expense		(942)		(935)		(2,769)		(2,828)
Reimbursement of bonus awards		(375)		(313)		(1,125)		(938)
Depreciation and amortization		(7,400)		(7,392)		(22,196)		(22,191)
Loss on disposition of assets		—		(1,398)		—		(1,398)
Earnings from unconsolidated affiliates		1,653		234		3,091		270
Operating income		8,257		6,785		31,002		28,546
Other expenses, net		(1,737)		(781)		(4,404)		(2,780)
Net earnings	$	6,520	$	6,004	$	26,598	$	25,766

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

	Three months ended  September 30, 2014
			Midwest
	Gulf Coast		Terminals and		Brownsville		River		Southeast
	Terminals		Pipeline System		Terminals		Terminals		Terminals		Total
Revenue:
External customers	$	8,373	$	3,058	$	3,777	$	2,367	$	4,555	$	22,130
NGL Energy Partners LP		4,160		—		—		115		8,082		12,357
Frontera		—		—		1,151		—		—		1,151
TransMontaigne Inc.		—		—		—		—		65		65
Total revenue	$	12,533	$	3,058	$	4,928	$	2,482	$	12,702	$	35,703
Capital expenditures	$	289	$	10	$	73	$	137	$	217	$	726
Identifiable assets	$	123,817	$	23,658	$	44,322	$	54,104	$	169,107	$	415,008
Cash and cash equivalents												726
Investments in unconsolidated affiliates												252,679
Deferred financing costs												1,382
Other												559
Total assets											$	670,354

	Three months ended  September 30, 2013
			Midwest
	Gulf Coast		Terminals and		Brownsville		River		Southeast
	Terminals		Pipeline System		Terminals		Terminals		Terminals		Total
Revenue:
External customers	$	3,872	$	472	$	5,341	$	2,023	$	937	$	12,645
Morgan Stanley Capital Group		9,166		2,576		—		277		12,259		24,278
Frontera		—		—		952		—		—		952
TransMontaigne Inc.		450		—		—		—		49		499
Total revenue	$	13,488	$	3,048	$	6,293	$	2,300	$	13,245	$	38,374
Capital expenditures	$	40	$	50	$	274	$	223	$	599	$	1,186

	Nine months ended September 30, 2014
			Midwest
	Gulf Coast		Terminals and		Brownsville		River		Southeast
	Terminals		Pipeline System		Terminals		Terminals		Terminals		Total
Revenue:
External customers	$	21,054	$	5,830	$	11,779	$	6,202	$	6,362	$	51,227
NGL Energy Partners LP		4,160		—		—		115		8,082		12,357
Morgan Stanley Capital Group		17,472		2,986		—		669		25,248		46,375
Frontera		—		—		2,985		—		—		2,985
TransMontaigne Inc.		10		—		—		—		161		171
Total revenue	$	42,696	$	8,816	$	14,764	$	6,986	$	39,853	$	113,115
Capital expenditures	$	678	$	39	$	994	$	732	$	895	$	3,338

	Nine months ended September 30, 2013
			Midwest
	Gulf Coast		Terminals and		Brownsville		River		Southeast
	Terminals		Pipeline System		Terminals		Terminals		Terminals		Total
Revenue:
External customers	$	11,689	$	1,406	$	15,561	$	7,723	$	2,837	$	39,216
Morgan Stanley Capital Group		28,769		7,474		—		456		38,455		75,154
Frontera		—		—		2,805		—		—		2,805
TransMontaigne Inc.		1,362		—		—		24		109		1,495
Total revenue	$	41,820	$	8,880	$	18,366	$	8,203	$	41,401	$	118,670
Capital expenditures	$	1,495	$	1,446	$	1,172	$	1,175	$	6,274	$	11,562

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ACCRUED LIABILITIES (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Mar. 31, 2014	Sep. 30, 2014	Dec. 31, 2013
Customer advances and deposits:
External customers	$ 1,882,000		$ 1,882,000	$ 475,000
Morgan Stanley Capital Group	96,000		96,000	6,264,000
Customer advances and deposits	1,978,000		1,978,000	6,739,000
Accrued property taxes	3,584,000		3,584,000	767,000
Accrued environmental obligations	1,603,000		1,603,000	1,966,000
Interest payable	179,000		179,000	163,000
Rebate due to Morgan Stanley Capital Group	1,780,000		1,780,000	3,793,000
Accrued expenses and other	2,642,000		2,642,000	2,761,000
Accrued liabilities	11,766,000		11,766,000	16,189,000
Period for billing of customers in advance for terminaling services			1 month
Payments towards environmental remediation obligations	100,000		500,000
Increase in remediation obligations due to change in estimate			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 Morgan Stanley Capital Group		$ 3,800,000

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Consolidated balance sheets (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$ 726	$ 3,263
Trade accounts receivable, net	12,252	6,427
Due from affiliates	1,011	2,257
Other current assets	2,976	3,478
Total current assets	16,965	15,425
Property, plant and equipment, net	388,140	407,045
Goodwill	8,485	8,485
Investments in unconsolidated affiliates	252,679	211,605
Other assets, net	4,085	5,872
TOTAL ASSETS	670,354	648,432
Current liabilities:
Trade accounts payable	4,010	5,717
Due to affiliates	52
Accrued liabilities	11,766	16,189
Total current liabilities	15,828	21,906
Other liabilities	4,247	6,059
Long-term debt	252,000	212,000
Total liabilities	272,075	239,965
Partners' equity:
Common unitholders (16,124,566 units issued and outstanding at September 30, 2014 and December 31, 2013)	340,298	350,505
General partner interest (2% interest with 329,073 equivalent units outstanding at September 30, 2014 and December 31, 2013)	57,981	57,962
Total partners' equity	398,279	408,467
TOTAL LIABILITIES AND EQUITY	$ 670,354	$ 648,432

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TRANSACTIONS WITH AFFILIATES (Details) (USD $)	3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended							3 Months Ended	9 Months Ended		3 Months Ended		9 Months Ended					9 Months Ended			9 Months Ended			9 Months Ended			9 Months Ended		0 Months Ended	9 Months Ended		12 Months Ended	9 Months Ended				0 Months Ended	9 Months Ended							3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014 TransMontaigne Inc.	Sep. 30, 2013 TransMontaigne Inc.	Sep. 30, 2014 TransMontaigne Inc.	Sep. 30, 2013 TransMontaigne Inc.	Sep. 30, 2014 TransMontaigne Inc. Florida and Midwest terminals Maximum	Sep. 30, 2014 TransMontaigne Inc. Brownsville and River terminals Maximum	Sep. 30, 2014 TransMontaigne Inc. Southeast Terminals Maximum	Sep. 30, 2014 TransMontaigne Inc. Pensacola terminal Maximum	Jul. 01, 2014 TransMontaigne Inc. Morgan Stanley [Member]	Sep. 30, 2013 Morgan Stanley Capital Group	Sep. 30, 2014 Morgan Stanley Capital Group	Sep. 30, 2013 Morgan Stanley Capital Group	Sep. 30, 2014 Frontera	Sep. 30, 2013 Frontera	Sep. 30, 2014 Frontera	Sep. 30, 2013 Frontera	Sep. 30, 2014 Omnibus agreement TransMontaigne Inc.	Sep. 30, 2014 Omnibus agreement TransMontaigne Inc. Minimum	Sep. 30, 2014 Environmental indemnification TransMontaigne Inc. Florida and Midwest terminals	Sep. 30, 2014 Environmental indemnification TransMontaigne Inc. Florida and Midwest terminals Minimum	Sep. 30, 2014 Environmental indemnification TransMontaigne Inc. Florida and Midwest terminals Maximum	Sep. 30, 2014 Environmental indemnification TransMontaigne Inc. Brownsville and River terminals	Sep. 30, 2014 Environmental indemnification TransMontaigne Inc. Brownsville and River terminals Minimum	Sep. 30, 2014 Environmental indemnification TransMontaigne Inc. Brownsville and River terminals Maximum	Sep. 30, 2014 Environmental indemnification TransMontaigne Inc. Southeast Terminals	Sep. 30, 2014 Environmental indemnification TransMontaigne Inc. Southeast Terminals Minimum	Sep. 30, 2014 Environmental indemnification TransMontaigne Inc. Southeast Terminals Maximum	Sep. 30, 2014 Environmental indemnification TransMontaigne Inc. Pensacola terminal	Sep. 30, 2014 Environmental indemnification TransMontaigne Inc. Pensacola terminal Minimum	Sep. 30, 2014 Environmental indemnification TransMontaigne Inc. Pensacola terminal Maximum	Mar. 01, 2014 Terminaling services agreement-Florida and Midwest terminals	Sep. 30, 2014 Terminaling services agreement-Florida and Midwest terminals Morgan Stanley Capital Group Minimum	Sep. 30, 2014 Terminaling services agreement-Florida and Midwest terminals Morgan Stanley Capital Group Minimum Forecast	Dec. 31, 2013 Terminaling services agreement-Fisher Island terminal TransMontaigne Inc. bbl	Sep. 30, 2014 Terminaling services agreement-Cushing terminal Morgan Stanley Capital Group bbl	Sep. 30, 2014 Terminaling services agreement-Cushing terminal Morgan Stanley Capital Group Minimum	Sep. 30, 2014 Terminaling services agreement-Cushing terminal Morgan Stanley Capital Group Minimum Forecast	Sep. 30, 2014 Terminaling services agreement-Southeast terminals Morgan Stanley Capital Group	Dec. 20, 2013 Terminaling services agreement-Southeast terminals Morgan Stanley Capital Group Minimum	Sep. 30, 2014 Terminaling services agreement-Southeast terminals Morgan Stanley Capital Group Minimum	Sep. 30, 2014 Terminaling services agreement-Southeast terminals Morgan Stanley Capital Group Minimum Forecast	Sep. 30, 2014 Terminaling services agreement-Collins/Purvis Additional Light Oil Tankage Morgan Stanley Capital Group bbl	Sep. 30, 2014 Terminaling services agreement-Collins/Purvis Additional Light Oil Tankage Morgan Stanley Capital Group Minimum	Sep. 30, 2014 Terminaling services agreement-Collins/Purvis Additional Light Oil Tankage Morgan Stanley Capital Group Minimum Forecast	Sep. 30, 2014 Barge dock services agreement-Baton Rouge dock Morgan Stanley Capital Group	Sep. 30, 2014 Barge dock services agreement-Baton Rouge dock Morgan Stanley Capital Group Forecast	Sep. 30, 2014 Operations and reimbursement agreement-Frontera Frontera	Sep. 30, 2013 Operations and reimbursement agreement-Frontera Frontera	Sep. 30, 2014 Operations and reimbursement agreement-Frontera Frontera	Sep. 30, 2013 Operations and reimbursement agreement-Frontera Frontera
Transactions with affiliates
Ownership interest sold (as a percent)													100.00%
Percentage of ownership																																																			50.00%		50.00%
Notice period for termination of service agreement																						24 months																	180 days				24 months	24 months			24 months		180 days
Annual administrative fee paid	$ 2,782,000	$ 2,741,000	$ 8,346,000	$ 8,222,000	$ 2,800,000	$ 2,700,000	$ 8,300,000	$ 8,200,000
Annual insurance reimbursement paid	942,000	935,000	2,769,000	2,828,000	900,000	900,000	2,800,000	2,800,000
Reimbursement of incentive payment grants to key employees of related party	375,000	313,000	1,125,000	938,000	400,000	300,000	1,100,000	900,000
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%
Period, following receipt of the notice, to purchase the subject facilities by related party																					45 days
Percentage of fees offered by third party agreed to be paid for right of refusal to contract																						105.00%
Maximum liability for indemnification obligation									15,000,000	15,000,000	15,000,000	2,500,000													15,000,000			15,000,000			15,000,000			2,500,000
Liability for indemnification obligation, if aggregate losses do not exceed specified amount																							0			0			0
Aggregate losses for indemnification obligation																								250,000			250,000			250,000			200,000
Liability for indemnification obligation related to environmental claims made as a result of additions to or modifications of environmental laws																							0			0			0			0
Automatic renewal period of service agreement																																							5 years										5 years
Notice period to be served by the entity for termination of service agreement effective at any time after July 31, 2023																																												24 months
Throughput revenue	13,573,000	25,729,000	61,888,000	79,454,000	65,000	499,000	171,000	1,495,000						24,278,000	46,375,000	75,154,000	1,151,000	952,000	2,985,000	2,805,000																	21,100,000	1,800,000			4,300,000	9,200,000			36,800,000			4,100,000
Term of lease agreement																																			10 years
Percentage of the capacity covered with Magellan Pipeline Company, L.P.																																			100.00%
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				120 days				30 days			30 days		120 days
Storage capacity agreed to be provided in exchange for related party's minimum revenue commitment (in barrels)																																						185,000	1,000,000							700,000
Ownership interest in joint venture (as a percent)																																																			50.00%		50.00%
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
Remaining period, following the first three year period after the in-service date, over which minimum throughput payments are received																																																		7 years
Revenue recognized																																																			$ 1,200,000	$ 1,000,000	$ 3,000,000	$ 2,800,000

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Consolidated statements of partners' equity (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Consolidated statements of partners' equity
Public offering of common units (in units)		1,667,500
Proceeds from offering, underwriters' discounts and offering expenses (in dollars)		$ 3,462
General partner interest (as a percent)	2.00%	2.00%
Purchase of common units by our long-term incentive plan and from affiliate	6,003	13,069
Issuance of common units by our long-term incentive plan due to vesting of restricted phantom units	20,500	10,608

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NET EARNINGS PER LIMITED PARTNER UNIT (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended						9 Months Ended		12 Months Ended
	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Mar. 31, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
NET EARNINGS PER LIMITED PARTNER UNIT
Net earnings	$ 6,520				$ 6,004		$ 26,598	$ 25,766	$ 34,726
Less:
Distributions payable on behalf of incentive distribution rights	(1,682)				(1,445)		(4,967)	(3,895)
Distributions payable on behalf of general partner interest	(219)				(214)		(655)	(595)
Earnings allocable to general partner interest less than (in excess of) distributions payable to general partner interest	122				123		222	157
Earnings allocable to general partner interest including incentive distribution rights	(1,779)				(1,536)		(5,400)	(4,333)
Net earnings allocable to limited partners	4,741				4,468		21,198	21,433
Less distribution payable on behalf of unvested long-term incentive plan grants	(6)				(9)		(26)	(41)
Net earnings allocable to limited partners for calculating net earnings per limited partner unit	$ 4,735				$ 4,459		$ 21,172	$ 21,392
Basic weighted average units	16,120				15,676		16,110	14,857
Net earnings per limited partner unit-basic (in dollars per unit)	$ 0.29				$ 0.28		$ 1.31	$ 1.44
Diluted weighted average units	16,120				15,676		16,110	14,857
Net earnings per limited partner unit-diluted (in dollars per unit)	$ 0.29				$ 0.28		$ 1.31	$ 1.44
Period for declaration of distribution, maximum							45 days
Distribution declared per common unit
Distribution declared per common unit (in dollars per unit)	$ 0.665	$ 0.665	$ 0.660	$ 0.650	$ 0.650	$ 0.640

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OTHER LIABILITIES (Tables)

9 Months Ended

Sep. 30, 2014

OTHER LIABILITIES

Schedule of other liabilities (in thousands)

	September 30,		December 31,
	2014		2013
Advance payments received under long-term terminaling services agreements	$	312	$	297
Deferred revenue—ethanol blending fees and other projects		3,935		5,762
	$	4,247	$	6,059

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COMMITMENTS AND CONTINGENCIES

9 Months Ended

Sep. 30, 2014

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

(15) COMMITMENTS AND CONTINGENCIES

Contract commitments.  At September 30, 2014, we have contractual commitments of approximately $5.8 million for the supply of services, labor and materials related to capital projects that currently are under development. We expect that these contractual commitments will be paid within the next twelve months.

Operating leases.  We lease property and equipment under non‑ cancelable operating leases that extend through August 2030. At September 30, 2014, future minimum lease payments under these non‑cancelable operating leases are as follows (in thousands):

Years ending December 31:
2014 (remainder of the year)	$	882
2015		3,841
2016		3,967
2017		2,997
2018		601
Thereafter		4,002
	$	16,290

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 $1.3million in future periods.

Rental expense under operating leases was approximately $0.9 million and $0.9 million for the three months ended September 30, 2014 and 2013, respectively.  Rental expense under operating leases was approximately $2.6 million and $2.6 million for the nine months ended September 30, 2014 and 2013, respectively.

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PARTNERS' EQUITY (Tables)

9 Months Ended

Sep. 30, 2014

PARTNERS' EQUITY

Schedule of number of units outstanding

	Common	General
	units	partner units
Units outstanding at September 30, 2014 and December 31, 2013	16,124,566	329,073

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DISCLOSURES ABOUT FAIR VALUE

9 Months Ended

Sep. 30, 2014

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 September 30, 2014 and December 31, 2013.

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.

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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Consolidated statements of cash flows (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Cash flows from operating activities:
Net earnings	$ 6,520	$ 6,004	$ 26,598	$ 25,766
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation and amortization	7,400	7,392	22,196	22,191
Loss on disposition of assets		1,398		1,398
Earnings from unconsolidated affiliates	(1,653)	(234)	(3,091)	(270)
Distributions from unconsolidated affiliates	3,259	328	5,697	877
Deferred equity-based compensation	584	81	698	285
Amortization of deferred financing costs	244	244	732	732
Utility deposits returned		135		135
Amortization of deferred revenue	(510)	(793)	(1,921)	(2,978)
Amounts due under long-term terminaling services agreements, net	306	353	919	996
Changes in operating assets and liabilities:
Trade accounts receivable, net	(3,614)	(812)	(5,733)	(1,824)
Due from affiliates	2,438	890	1,246	1,275
Other current assets	273	112	502	(157)
Trade accounts payable	(1,302)	596	(1,507)	(2,256)
Due to affiliates	52	(387)	52	(40)
Accrued liabilities	978	(1,571)	(4,423)	88
Net cash provided by operating activities	14,975	13,736	41,965	46,218
Cash flows from investing activities:
Proceeds from sale of assets		2,109		2,109
Investments in unconsolidated affiliates	(20,283)	(23,412)	(43,680)	(94,368)
Capital expenditures	(726)	(1,186)	(3,338)	(11,562)
Net cash used in investing activities	(21,009)	(22,489)	(47,018)	(103,821)
Cash flows from financing activities:
Net proceeds from issuance of common units		69,190		69,190
Deferred issuance costs				(398)
Contribution of cash by TransMontaigne GP		1,474		1,474
Borrowings of debt under credit facility	56,000	26,500	112,000	146,000
Repayments of debt under credit facility	(38,000)	(73,500)	(72,000)	(123,000)
Distributions paid to unitholders	(12,621)	(12,133)	(37,219)	(33,334)
Purchase of common units by our long-term incentive plan	(88)	(335)	(265)	(501)
Net cash provided by financing activities	5,291	11,196	2,516	59,431
Increase (decrease) in cash and cash equivalents	(743)	2,443	(2,537)	1,828
Foreign currency translation effect on cash		3		49
Cash and cash equivalents at beginning of period	1,469	6,176	3,263	6,745
Cash and cash equivalents at end of period	726	8,622	726	8,622
Supplemental disclosures of cash flow information:
Cash paid for interest	1,473	579	3,658	1,933
Property, plant and equipment acquired with accounts payable	$ 518	$ 381	$ 518	$ 381

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Consolidated balance sheets (Parenthetical)	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
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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ACCRUED LIABILITIES

9 Months Ended

Sep. 30, 2014

ACCRUED LIABILITIES

ACCRUED LIABILITIES

(10) ACCRUED LIABILITIES

Accrued liabilities are as follows (in thousands):

	September 30,		December 31,
	2014		2013
Customer advances and deposits:
External customers	$	1,882	$	475
Affiliates		96		6,264
		1,978		6,739
Accrued property taxes		3,584		767
Accrued environmental obligations		1,603		1,966
Interest payable		179		163
Rebate due to customers		1,780		3,793
Accrued expenses and other		2,642		2,761
	$	11,766	$	16,189

Customer advances and deposits.  We bill certain of our customers one month in advance for terminaling services to be provided in the following month. At September 30, 2014 and December 31, 2013, we have billed and collected from certain of our customers approximately $2.0 million and $6.7 million, respectively, in advance of the terminaling services being provided.

Accrued environmental obligations.  At September 30, 2014 and December 31, 2013, we have accrued environmental obligations of approximately $1.6 million and $2.0 million, respectively, representing our best estimate of our remediation obligations. During the three and nine months ended September 30, 2014, we made payments of approximately $0.1 million and $0.5 million, respectively, towards our environmental remediation obligations. During the three and nine months ended September 30, 2014, we increased our remediation obligations by approximately $nil and $0.1 million, respectively, to reflect a change in 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 customers.  Pursuant to our terminaling services agreement related to the Southeast terminals, 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. At September 30, 2014 and December 31, 2013, we have accrued a liability due to these customers of approximately $1.8 million and $3.8 million, respectively. During the three months ended March 31, 2014, we paid approximately $3.8 million to our customers for the rebate due for the year ended December 31, 2013.

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Document and Entity Information	9 Months Ended
	Sep. 30, 2014	Oct. 31, 2014
Document and Entity Information
Entity Registrant Name	TransMontaigne Partners L.P.
Entity Central Index Key	0001319229
Document Type	10-Q
Document Period End Date	Sep. 30, 2014
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	2014
Document Fiscal Period Focus	Q3

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OTHER LIABILITIES

9 Months Ended

Sep. 30, 2014

OTHER LIABILITIES

OTHER LIABILITIES

(11) OTHER LIABILITIES

Other liabilities are as follows (in thousands):

	September 30,		December 31,
	2014		2013
Advance payments received under long-term terminaling services agreements	$	312	$	297
Deferred revenue—ethanol blending fees and other projects		3,935		5,762
	$	4,247	$	6,059

Advance payments received under long‑term terminaling services agreements.  We have long‑term terminaling services agreements with certain of our customers that provide for advance minimum payments. We recognize the advance minimum payments as revenue either on a straight‑line basis over the term of the respective agreements or when services have been provided based on volumes of product distributed. At September 30, 2014 and December 31, 2013, 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 $0.3 million, respectively.

Deferred revenue—ethanol blending fees and other projects.  Pursuant to agreements with affiliates and others, 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, affiliates and others have paid us lump‑sum amounts that will be recognized as revenue on a straight‑line basis over the remaining term of the agreements. At September 30, 2014 and December 31, 2013, we have unamortized deferred revenue of approximately $3.9 million and $5.8 million, respectively, for completed projects. During the three months ended September 30, 2014 and 2013, we recognized revenue on a straight‑line basis of approximately $0.5 million and $0.8 million, respectively, for completed projects.  During the nine months ended September 30, 2014 and 2013, we recognized revenue on a straight‑line basis of approximately $1.9 million and $3.0 million, respectively, for completed projects.

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Consolidated statements of comprehensive income (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Revenue:
External customers	$ 22,130	$ 12,645	$ 51,227	$ 39,216
Affiliates	13,573	25,729	61,888	79,454
Total revenue	35,703	38,374	113,115	118,670
Operating costs and expenses and other:
Direct operating costs and expenses	(16,514)	(17,843)	(48,302)	(51,865)
Direct general and administrative expenses	(1,086)	(1,201)	(2,466)	(2,952)
Allocated general and administrative expenses	(2,782)	(2,741)	(8,346)	(8,222)
Allocated insurance expense	(942)	(935)	(2,769)	(2,828)
Reimbursement of bonus awards	(375)	(313)	(1,125)	(938)
Depreciation and amortization	(7,400)	(7,392)	(22,196)	(22,191)
Gain (loss) on disposition of assets		(1,398)		(1,398)
Earnings from unconsolidated affiliates	1,653	234	3,091	270
Total operating costs and expenses and other	(27,446)	(31,589)	(82,113)	(90,124)
Operating income	8,257	6,785	31,002	28,546
Other income (expenses):
Interest expense	(1,493)	(532)	(3,672)	(2,035)
Foreign currency transaction gain		(5)		(13)
Amortization of deferred financing costs	(244)	(244)	(732)	(732)
Total other expenses, net	(1,737)	(781)	(4,404)	(2,780)
Net earnings	6,520	6,004	26,598	25,766
Other comprehensive income-foreign currency translation adjustments		81		83
Comprehensive income	6,520	6,085	26,598	25,849
Net earnings	6,520	6,004	26,598	25,766
Less-earnings allocable to general partner interest including incentive distribution rights	(1,779)	(1,536)	(5,400)	(4,333)
Net earnings allocable to limited partners	$ 4,741	$ 4,468	$ 21,198	$ 21,433
Net earnings per limited partner unit-basic (in dollars per unit)	$ 0.29	$ 0.28	$ 1.31	$ 1.44
Net earnings per limited partner unit-diluted (in dollars per unit)	$ 0.29	$ 0.28	$ 1.31	$ 1.44

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OTHER CURRENT ASSETS

9 Months Ended

Sep. 30, 2014

OTHER CURRENT ASSETS

OTHER CURRENT ASSETS

(5) OTHER CURRENT ASSETS

Other current assets are as follows (in thousands):

	September 30,		December 31,
	2014		2013
Amounts due from insurance companies	$	1,300	$	1,722
Additive detergent		1,613		1,718
Deposits and other assets		63		38
	$	2,976	$	3,478

Amounts due from insurance companies.  We periodically file claims for recovery of environmental remediation costs with our insurance carriers under our comprehensive liability policies. We recognize our insurance recoveries in the period that we assess the likelihood of recovery as being probable (i.e., likely to occur). At September 30, 2014 and December 31, 2013, we have recognized amounts due from insurance companies of approximately $1.3 million and $1.7 million, respectively, representing our best estimate of our probable insurance recoveries. During the three and nine months ended September 30, 2014, we received reimbursements from insurance companies of approximately $0.1 million and $0.4 million, respectively. During the nine months ended September 30, 2014, we did not adjust our estimate of probable insurance recoveries.

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CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE

9 Months Ended

Sep. 30, 2014

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):

	September 30,		December 31,
	2014		2013
Trade accounts receivable	$	12,716	$	6,527
Less allowance for doubtful accounts		(464)		(100)
	$	12,252	$	6,427

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

	Three months				Nine months
	ended				ended
	September 30,				September 30,
	2014		2013		2014		2013
NGL Energy Partners LP	35	%	—	%	11	%	—	%
Morgan Stanley Capital Group	13	%	63	%	45	%	63	%

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NET EARNINGS PER LIMITED PARTNER UNIT

9 Months Ended

Sep. 30, 2014

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				Nine months ended
	September 30,				September 30,
	2014		2013		2014		2013
Net earnings	$	6,520	$	6,004	$	26,598	$	25,766
Less:
Distributions payable on behalf of incentive distribution rights		(1,682)		(1,445)		(4,967)		(3,895)
Distributions payable on behalf of general partner interest		(219)		(214)		(655)		(595)
Earnings allocable to general partner interest less than distributions payable to general partner interest		122		123		222		157
Earnings allocable to general partner interest including incentive distribution rights		(1,779)		(1,536)		(5,400)		(4,333)
Net earnings allocable to limited partners per the consolidated statements of comprehensive income	$	4,741	$	4,468	$	21,198	$	21,433
Less distributions payable on behalf of unvested long-term incentive plan grants		(6)		(9)		(26)		(41)
Net earnings allocable to limited partners for calculating net earnings per limited partner unit	$	4,735	$	4,459	$	21,172	$	21,392
Basic and diluted weighted average units		16,120		15,676		16,110		14,857
Net earnings per limited partner unit—basic and diluted	$	0.29	$	0.28	$	1.31	$	1.44

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, 2013 through March 31, 2013	$	0.640
April 1, 2013 through June 30, 2013	$	0.650
July 1, 2013 through September 30, 2013	$	0.650
October 1, 2013 through December 31, 2013	$	0.650
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

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LONG-TERM DEBT

9 Months Ended

Sep. 30, 2014

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 credit facility replaced in its entirety the senior secured credit facility that was in place as of December 31, 2010. The credit facility provides for a maximum borrowing line of credit equal to the lesser of (i) $350 million and (ii) 4.75 times Consolidated EBITDA (as defined: $355.7 million at September 30, 2014). 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.

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 “permitted JV investments”. Permitted JV investments include up to $225 million of investments in BOSTCO, the “Specified BOSTCO Investment”. In addition to the Specified BOSTCO Investment, under the terms of the credit facility, we may make an additional $75 million of other permitted JV investments (including additional investments in BOSTCO). The principal balance of loans and any accrued and unpaid interest are due and payable in full on the maturity date, March 9, 2016.

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 September 30, 2014.

For the three months ended September 30, 2014 and 2013, the weighted average interest rate on borrowings under the credit facility was approximately 2.7% and 2.7%, respectively.  For the nine months ended September 30, 2014 and 2013, the weighted average interest rate on borrowings under the credit facility was approximately 2.6% and 2.5%, respectively. At September 30, 2014 and December 31, 2013, our outstanding borrowings under the credit facility were $252million and $212 million, respectively. At September 30, 2014 and December 31, 2013, our outstanding letters of credit were approximately $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. 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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INVESTMENTS IN UNCONSOLIDATED AFFILIATES

9 Months Ended

Sep. 30, 2014

INVESTMENTS IN UNCONSOLIDATED AFFILIATES

INVESTMENTS IN UNCONSOLIDATED AFFILIATES

(8) INVESTMENTS IN UNCONSOLIDATED AFFILIATES

At September 30, 2014 and December 31, 2013, our investments in unconsolidated affiliates include a 42.5% interest in BOSTCO and a 50% interest in Frontera. BOSTCO is a terminal facility construction project for approximately 7.1 million barrels of storage capacity at an estimated cost of approximately $535 million. BOSTCO is located on the Houston Ship Channel and began initial commercial operations in the fourth quarter of 2013 (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:

					Carrying value
	Percentageof ownership				(in thousands)
	September 30,		December 31,		September 30,		December 31,
	2014		2013		2014		2013
BOSTCO	42.5	%	42.5	%	$	228,361	$	186,181
Frontera	50	%	50	%		24,318		25,424
Total investments in unconsolidated affiliates					$	252,679	$	211,605

At September 30, 2014 and December 31, 2013, our investment in BOSTCO includes approximately $7.7 million and $6.4 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 the BOSTCO entity.

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

	Three months				Nine months
	ended				ended
	September 30,				September 30,
	2014		2013		2014		2013
BOSTCO	$	1,368	$	—	$	2,617	$	—
Frontera		285		234		474		270
Total earnings from unconsolidated affiliates	$	1,653	$	234	$	3,091	$	270

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

	Three months				Nine months
	ended				ended
	September 30,				September 30,
	2014		2013		2014		2013
BOSTCO	$	20,283	$	23,412	$	43,635	$	94,216
Frontera		—		—		45		152
Total additional capital investments in unconsolidated affiliates	$	20,283	$	23,412	$	43,680	$	94,368

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

	Three months				Nine months
	ended				ended
	September 30,				September 30,
	2014		2013		2014		2013
BOSTCO	$	2,915	$	—	$	4,072	$	—
Frontera		344		328		1,625		877
Total cash distributions received from unconsolidated affiliates	$	3,259	$	328	$	5,697	$	877

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

Balance sheets:

	BOSTCO				Frontera
	September 30,		December 31,		September 30,		December 31,
	2014		2013		2014		2013
Current assets	$	52,164	$	30,776	$	4,662	$	4,465
Long‑term assets		514,301		458,707		45,311		47,691
Current liabilities		(47,264)		(66,469)		(1,337)		(1,308)
Long‑term liabilities		—		—		—		—
Net assets	$	519,201	$	423,014	$	48,636	$	50,848

Statements of comprehensive income (loss):

	BOSTCO				Frontera
	Three months				Three months
	ended				ended
	September 30,				September 30,
	2014		2013		2014		2013
Operating revenue	$	14,708	$	—	$	3,474	$	3,231
Operating expenses		(11,119)		—		(2,904)		(2,763)
Net earnings and comprehensive income	$	3,589	$	—	$	570	$	468
	BOSTCO				Frontera
	Nine months				Nine months
	ended				ended
	September 30,				September 30,
	2014		2013		2014		2013
Operating revenue	$	35,451	$	—	$	9,934	$	8,946
Operating expenses		(28,812)		—		(8,986)		(8,406)
Net earnings and comprehensive income	$	6,639	$	—	$	948	$	540

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BUSINESS SEGMENTS (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2012
Segments of business
Total revenue	$ 35,703	$ 38,374	$ 113,115	$ 118,670
Direct operating costs and expenses	(16,514)	(17,843)	(48,302)	(51,865)
Net margins	19,189	20,531	64,813	66,805
Direct general and administrative expenses, net	(1,086)	(1,201)	(2,466)	(2,952)
Allocated general and administrative expenses	(2,782)	(2,741)	(8,346)	(8,222)
Allocated insurance expense	(942)	(935)	(2,769)	(2,828)
Reimbursement of bonus awards	(375)	(313)	(1,125)	(938)
Depreciation and amortization	(7,400)	(7,392)	(22,196)	(22,191)
Gain (loss) on disposition of assets		(1,398)		(1,398)
Earnings from unconsolidated affiliates	1,653	234	3,091	270
Operating income	8,257	6,785	31,002	28,546
Other expenses, net	(1,737)	(781)	(4,404)	(2,780)
Net earnings	6,520	6,004	26,598	25,766	34,726
External customers	22,130	12,645	51,227	39,216
Revenue from affiliates	13,573	25,729	61,888	79,454
Capital expenditures	726	1,186	3,338	11,562
Identifiable assets	415,008		415,008
Cash and cash equivalents	726	8,622	726	8,622	3,263	1,469	6,176	6,745
Investments in unconsolidated affiliates	252,679		252,679		211,605
Deferred financing costs	1,382		1,382		2,113
Other	559		559
TOTAL ASSETS	670,354		670,354		648,432
NGL Energy Partners LP
Segments of business
Revenue from affiliates	12,357		12,357
Morgan Stanley Capital Group
Segments of business
Revenue from affiliates		24,278	46,375	75,154
Frontera
Segments of business
Revenue from affiliates	1,151	952	2,985	2,805
TransMontaigne Inc.
Segments of business
Allocated general and administrative expenses	(2,800)	(2,700)	(8,300)	(8,200)
Allocated insurance expense	(900)	(900)	(2,800)	(2,800)
Reimbursement of bonus awards	(400)	(300)	(1,100)	(900)
Revenue from affiliates	65	499	171	1,495
Gulf Coast Terminals
Segments of business
Terminaling services fees, net	10,215	11,515	33,290	35,018
Other	2,318	1,973	9,406	6,802
Total revenue	12,533	13,488	42,696	41,820
Direct operating costs and expenses	(5,115)	(5,180)	(14,656)	(15,642)
Net margins	7,418	8,308	28,040	26,178
External customers	8,373	3,872	21,054	11,689
Capital expenditures	289	40	678	1,495
Identifiable assets	123,817		123,817
Gulf Coast Terminals | NGL Energy Partners LP
Segments of business
Revenue from affiliates	4,160		4,160
Gulf Coast Terminals | Morgan Stanley Capital Group
Segments of business
Revenue from affiliates		9,166	17,472	28,769
Gulf Coast Terminals | TransMontaigne Inc.
Segments of business
Revenue from affiliates		450	10	1,362
Midwest Terminals and Pipeline System
Segments of business
Terminaling services fees, net	2,032	1,992	6,039	5,927
Pipeline transportation fees	414	365	1,155	1,082
Other	612	691	1,622	1,871
Total revenue	3,058	3,048	8,816	8,880
Direct operating costs and expenses	(682)	(841)	(2,254)	(2,305)
Net margins	2,376	2,207	6,562	6,575
External customers	3,058	472	5,830	1,406
Capital expenditures	10	50	39	1,446
Identifiable assets	23,658		23,658
Midwest Terminals and Pipeline System | Morgan Stanley Capital Group
Segments of business
Revenue from affiliates		2,576	2,986	7,474
Brownsville terminals
Segments of business
Terminaling services fees, net	1,624	1,631	4,588	5,390
Pipeline transportation fees	372	1,712	1,100	5,173
Other	2,932	2,950	9,076	7,803
Total revenue	4,928	6,293	14,764	18,366
Direct operating costs and expenses	(3,597)	(4,303)	(10,528)	(11,712)
Net margins	1,331	1,990	4,236	6,654
External customers	3,777	5,341	11,779	15,561
Capital expenditures	73	274	994	1,172
Identifiable assets	44,322		44,322
Brownsville terminals | Frontera
Segments of business
Revenue from affiliates	1,151	952	2,985	2,805
River terminals
Segments of business
Terminaling services fees, net	2,336	2,188	6,450	7,604
Other	146	112	536	599
Total revenue	2,482	2,300	6,986	8,203
Direct operating costs and expenses	(1,940)	(2,121)	(5,575)	(5,931)
Net margins	542	179	1,411	2,272
External customers	2,367	2,023	6,202	7,723
Capital expenditures	137	223	732	1,175
Identifiable assets	54,104		54,104
River terminals | NGL Energy Partners LP
Segments of business
Revenue from affiliates	115		115
River terminals | Morgan Stanley Capital Group
Segments of business
Revenue from affiliates		277	669	456
River terminals | TransMontaigne Inc.
Segments of business
Revenue from affiliates				24
Southeast Terminals
Segments of business
Terminaling services fees, net	11,131	11,356	34,086	34,792
Other	1,571	1,889	5,767	6,609
Total revenue	12,702	13,245	39,853	41,401
Direct operating costs and expenses	(5,180)	(5,398)	(15,289)	(16,275)
Net margins	7,522	7,847	24,564	25,126
External customers	4,555	937	6,362	2,837
Capital expenditures	217	599	895	6,274
Identifiable assets	169,107		169,107
Southeast Terminals | NGL Energy Partners LP
Segments of business
Revenue from affiliates	8,082		8,082
Southeast Terminals | Morgan Stanley Capital Group
Segments of business
Revenue from affiliates		12,259	25,248	38,455
Southeast Terminals | TransMontaigne Inc.
Segments of business
Revenue from affiliates	$ 65	$ 49	$ 161	$ 109

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PROPERTY, PLANT AND EQUIPMENT, NET

9 Months Ended

Sep. 30, 2014

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):

	September 30,		December 31,
	2014		2013
Land	$	52,519	$	52,519
Terminals, pipelines and equipment		565,065		562,077
Furniture, fixtures and equipment		2,101		1,861
Construction in progress		2,642		2,730
		622,327		619,187
Less accumulated depreciation		(234,187)		(212,142)
	$	388,140	$	407,045

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GOODWILL

9 Months Ended

Sep. 30, 2014

GOODWILL

GOODWILL

(7) GOODWILL

Goodwill is as follows (in thousands):

	September 30,		December 31,
	2014		2013
Brownsville terminals	$	8,485	$	8,485

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

At September 30, 2014 and December 31, 2013, our only reporting unit that contained goodwill was our Brownsville terminals. Our estimate of the fair value of our Brownsville terminals at December 31, 2013 exceeded its carrying amount. Accordingly, we did not recognize any goodwill impairment charges during the year ended December 31, 2013 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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OTHER ASSETS, NET

9 Months Ended

Sep. 30, 2014

OTHER ASSETS, NET

OTHER ASSETS, NET

(9) OTHER ASSETS, NET

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

	September 30,		December 31,
	2014		2013
Amounts due under long-term terminaling services agreements:
External customers	$	760	$	592
Affiliates		1,074		2,146
		1,834		2,738
Deferred financing costs, net of accumulated amortization of $3,034 and $2,303, respectively		1,382		2,113
Customer relationships, net of accumulated amortization of $1,637 and $1,485, respectively		793		945
Deposits and other assets		76		76
	$	4,085	$	5,872

Amounts due under long‑term terminaling services agreements.  We have long‑term terminaling services agreements with certain of our customers that provide for minimum payments that increase over the terms of the respective agreements. We recognize as revenue the minimum payments under the long‑term terminaling services agreements on a straight‑line basis over the term of the respective agreements. At September 30, 2014 and December 31, 2013, 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 $1.8 million and $2.7 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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ACCRUED LIABILITIES (Tables)

9 Months Ended

Sep. 30, 2014

ACCRUED LIABILITIES

Schedule of accrued liabilities (in thousands)

	September 30,		December 31,
	2014		2013
Customer advances and deposits:
External customers	$	1,882	$	475
Affiliates		96		6,264
		1,978		6,739
Accrued property taxes		3,584		767
Accrued environmental obligations		1,603		1,966
Interest payable		179		163
Rebate due to customers		1,780		3,793
Accrued expenses and other		2,642		2,761
	$	11,766	$	16,189

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INVESTMENTS IN UNCONSOLIDATED AFFILIATES (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
INVESTMENTS IN UNCONSOLIDATED AFFILIATES
Carrying value of investments in unconsolidated affiliates	$ 252,679,000		$ 252,679,000		$ 211,605,000
Total earnings from unconsolidated affiliates	1,653,000	234,000	3,091,000	270,000
Total additional capital investments in unconsolidated affiliates	20,283,000	23,412,000	43,680,000	94,368,000
Total cash distributions received from unconsolidated affiliates	3,259,000	328,000	5,697,000	877,000
BOSTCO
INVESTMENTS IN UNCONSOLIDATED AFFILIATES
Percentage of ownership	42.50%		42.50%		42.50%
Storage capacity of storage tanks, the construction of which is involved in the initial phase of acquisition (in barrels)			7,100,000
Estimated construction cost of storage tanks, the construction of which is involved in the initial phase of acquisition			535,000,000
Carrying value of investments in unconsolidated affiliates	228,361,000		228,361,000		186,181,000
Excess investment	7,700,000		7,700,000		6,400,000
Total earnings from unconsolidated affiliates	1,368,000		2,617,000
Total additional capital investments in unconsolidated affiliates	20,283,000	23,412,000	43,635,000	94,216,000
Total cash distributions received from unconsolidated affiliates	2,915,000		4,072,000
Balance sheets:
Current assets	52,164,000		52,164,000		30,776,000
Long-term assets	514,301,000		514,301,000		458,707,000
Current liabilities	(47,264,000)		(47,264,000)		(66,469,000)
Net assets	519,201,000		519,201,000		423,014,000
Statements of comprehensive income (loss):
Operating revenue	14,708,000		35,451,000
Operating expenses	(11,119,000)		(28,812,000)
Net earnings (loss) and comprehensive income (loss)	3,589,000		6,639,000
Frontera
INVESTMENTS IN UNCONSOLIDATED AFFILIATES
Percentage of ownership	50.00%		50.00%		50.00%
Light petroleum product storage capacity (in barrels)	1,500,000		1,500,000
Carrying value of investments in unconsolidated affiliates	24,318,000		24,318,000		25,424,000
Total earnings from unconsolidated affiliates	285,000	234,000	474,000	270,000
Total additional capital investments in unconsolidated affiliates			45,000	152,000
Total cash distributions received from unconsolidated affiliates	344,000	328,000	1,625,000	877,000
Balance sheets:
Current assets	4,662,000		4,662,000		4,465,000
Long-term assets	45,311,000		45,311,000		47,691,000
Current liabilities	(1,337,000)		(1,337,000)		(1,308,000)
Net assets	48,636,000		48,636,000		50,848,000
Statements of comprehensive income (loss):
Operating revenue	3,474,000	3,231,000	9,934,000	8,946,000
Operating expenses	(2,904,000)	(2,763,000)	(8,986,000)	(8,406,000)
Net earnings (loss) and comprehensive income (loss)	$ 570,000	$ 468,000	$ 948,000	$ 540,000

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LONG-TERM INCENTIVE PLAN

9 Months Ended

Sep. 30, 2014

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 Inc. TransMontaigne Services Inc. is an indirect wholly owned subsidiary of TransMontaigne Inc. TransMontaigne Services Inc. employs the personnel who provide support to TransMontaigne Inc.’s operations, as well as our operations. TransMontaigne Services Inc. 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 2,428,377 units, which amount will automatically increase on an annual basis by 2% of the total outstanding common and subordinated units, if any, at the end of the preceding fiscal year. At September 30, 2014, 2,179,457 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. TransMontaigne GP purchases 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 6,003 and 5,727 common units pursuant to the program during the nine months ended September 30, 2014 and 2013, respectively.

Information about restricted phantom unit activity for the year ended December 31, 2013 and the nine months ended September 30, 2014 is as follows:

		Restricted	NYSE
	Availablefor	phantom	closing
	future grant	units	price
Units outstanding at December 31, 2013	1,871,966	14,500
Automatic increase in units available for future grant on January 1, 2014	322,491	—
Grant on March 31, 2014	(6,000)	6,000	$	43.08
Vesting on March 31, 2014	—	(5,500)	$	43.08
Vesting on July 1, 2014	—	(15,000)	$	43.80
Grant on September 30, 2014	(9,000)	9,000	$	41.24
Units outstanding at September 30, 2014	2,179,457	9,000

On March 31, 2014, TransMontaigne Services Inc. granted 6,000 restricted phantom units, respectively, to the independent directors of our general partner. We typically recognize the deferred equity‑based compensation expense associated with these annual grants 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 Inc. Accordingly, as a result of Morgan Stanley’s sale of its 100% ownership interest in TransMontaigne Inc. 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.  As of July 1, 2014, we recognized the remaining grant date fair value pertaining to these 15,000 restricted phantom units, of approximately $0.6 million, as deferred equity‑based compensation expense because the requisite service period for these restricted phantom units had been completed upon the change in control.

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 plan to 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 $584,000 and $81,000 is included in direct general and administrative expenses for the three months ended September 30, 2014 and 2013, respectively.  Deferred equity‑based compensation of approximately $698,000 and $285,000 is included in direct general and administrative expenses for the nine months ended September 30, 2014 and 2013, respectively.

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SUBSEQUENT EVENT

9 Months Ended

Sep. 30, 2014

SUBSEQUENT EVENT

SUBSEQUENT EVENT

(19) SUBSEQUENT EVENT

On October 16, 2014, Charles L. Dunlap notified Partners of his intention to retire from his position as Chief Executive Officer of our general partner and as President, Chief Executive Officer and member of the board of directors of TransMontaigne Inc., and the other subsidiaries of Partners and TransMontaigne Inc., each to be effective November 7, 2014.  As a result of Mr. Dunlap’s resignation, on October 20, 2014, the board of directors of TransMontaigne GP appointed Frederick W. Boutin to serve as Chief Executive Officer of our general partner, effective November 7, 2014. Mr. Boutin has also been appointed to serve as the President and Chief Executive Officer of TransMontaigne Inc., effective November 7, 2014.  In connection with Mr. Boutin’s appointment to Chief Executive Officer, on October 20, 2014, the board of directors of TransMontaigne GP appointed Robert T. Fuller to serve as the Executive Vice President, Chief Financial Officer, Chief Accounting Officer and Treasurer of our general partner, effective November 7, 2014. Mr. Fuller has also been appointed to serve as the Executive Vice President, Chief Financial Officer and Treasurer of TransMontaigne Inc., effective November 7, 2014.

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 at our Port Everglades, Florida North terminal.

On October 13, 2014, we announced a distribution of $0.665 per unit for the period from July 1, 2014 through September 30, 2014. This distribution is payable on November 7, 2014 to unitholders of record on October 31, 2014.

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PROPERTY, PLANT AND EQUIPMENT, NET (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Property, plant and equipment, net
Property, plant and equipment, gross	$ 622,327	$ 619,187
Less accumulated depreciation	(234,187)	(212,142)
Property, plant and equipment, net	388,140	407,045
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	565,065	562,077
Furniture, fixtures and equipment
Property, plant and equipment, net
Property, plant and equipment, gross	2,101	1,861
Construction in progress
Property, plant and equipment, net
Property, plant and equipment, gross	$ 2,642	$ 2,730

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $)	3 Months Ended		9 Months Ended		12 Months Ended	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Sep. 30, 2014 TransMontaigne Inc.	Sep. 30, 2013 TransMontaigne Inc.	Sep. 30, 2014 TransMontaigne Inc.	Sep. 30, 2013 TransMontaigne Inc.	Sep. 30, 2014 Trans Montaigne Inc. and Morgan Stanley	Jul. 01, 2014 Trans Montaigne Inc. and Morgan Stanley	Jul. 01, 2014 Morgan Stanley [Member] TransMontaigne Inc.
Nature of business
Limited partner interest (as a percent)			98.00%							20.00%
General partner interest (as a percent)			2.00%		2.00%					2.00%
Ownership interest sold (as a percent)												100.00%
Limited partnership interest transferred as part of sale (as a percent)											20.00%
Basis of presentation and use of estimates
Allocated general and administrative expenses	$ 2,782,000	$ 2,741,000	$ 8,346,000	$ 8,222,000		$ 2,800,000	$ 2,700,000	$ 8,300,000	$ 8,200,000
Allocated insurance charges	942,000	935,000	2,769,000	2,828,000		900,000	900,000	2,800,000	2,800,000
Reimbursement of incentive payment grants to key employees of related party	375,000	313,000	1,125,000	938,000		400,000	300,000	1,100,000	900,000
Accounting for terminal and pipeline operations
Revenue recognized from proceeds of sale of product gained	3,100,000	3,300,000	10,800,000	11,000,000
Recognized revenue pursuant to terminaling services agreements with affiliate customers	$ 1,200,000	$ 2,900,000	$ 6,100,000	$ 9,800,000

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Consolidated statements of partners' equity (USD $) In Thousands, unless otherwise specified	Common unitholders	General partner interest	Accumulated other comprehensive income (loss)	Total
Balance at Dec. 31, 2012	$ 292,648	$ 56,564	$ (475)	$ 348,737
Increase (Decrease) in Partners' Capital
Proceeds from offering of 1,667,500 common units, net of underwriters' discounts and offering expenses of $3,462	68,774			68,774
Contribution of cash by TransMontaigne GP to maintain its 2% general partner interest		1,474		1,474
Distributions to unitholders	(39,466)	(6,005)		(45,471)
Deferred equity-based compensation related to restricted phantom units	337			337
Purchase of 6,003 and 13,069 common units by our long-term incentive plan and from affiliate for the nine months ended September 30, 2014 and the year ended December 31, 2013	(585)			(585)
Net earnings	28,797	5,929		34,726
Other comprehensive income-foreign currency translation adjustments			83	83
Foreign currency translation adjustments reclassified into loss upon the sale of the Mexico operations			392	392
Balance at Dec. 31, 2013	350,505	57,962		408,467
Increase (Decrease) in Partners' Capital
Distributions to unitholders	(31,838)	(5,381)		(37,219)
Deferred equity-based compensation related to restricted phantom units	698			698
Purchase of 6,003 and 13,069 common units by our long-term incentive plan and from affiliate for the nine months ended September 30, 2014 and the year ended December 31, 2013	(265)			(265)
Net earnings	21,198	5,400		26,598
Balance at Sep. 30, 2014	$ 340,298	$ 57,981		$ 398,279

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TERMINAL ACQUISITIONS AND DISPOSITIONS

9 Months Ended

Sep. 30, 2014

TERMINAL ACQUISITIONS AND DISPOSITIONS

TERMINAL ACQUISITIONS AND DISPOSITIONS

(3) TERMINAL ACQUISITIONS AND DISPOSITIONS

Investment in BOSTCO.  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, distillates and other black oils. The initial phase of BOSTCO involved the construction of 51 storage tanks with approximately 6.2 million barrels of storage capacity at a cost of approximately $480 million. 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 that is estimated to cost approximately $55 million. The expansion is supported by a long‑term leased storage and handling services contract with Morgan Stanley Capital Group and includes six,  150,000 barrel, ultra‑low sulphur diesel tanks, additional pipeline and deepwater vessel dock access and high‑speed loading at a rate of 25,000 barrels per hour. Work on the 900,000 barrel expansion started in the second quarter of 2013, and was placed into service by 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 estimated overall construction cost of approximately $535 million. We expect our total payments for the initial and the expansion projects to be approximately $235 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.

Disposition of Mexico operations.  Effective August 8, 2013, we sold our Mexico operations to an unaffiliated third party for cash proceeds of approximately $2.1 million, net of $0.2 million in bank accounts sold related to the Mexico operations. The Mexico operations consisted of a 7,000 barrel liquefied petroleum gas storage terminal in Matamoros, Mexico and a seven mile pipeline system connecting the Matamoros terminal to our Diamondback pipeline system at the U.S. border, which connects to our Brownville, Texas terminals. The net carrying amount of the Mexico operations was approximately $3.4 million, which was in excess of the net cash proceeds, resulting in an approximate $1.3 million loss on disposition of assets. The accompanying consolidated financial statements exclude the assets, liabilities and results of the Mexico operations subsequent to August 8, 2013.

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COMMITMENTS AND CONTINGENCIES (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
COMMITMENTS AND CONTINGENCIES
Contractual commitments for supply of services, labor and materials	$ 5,800,000		$ 5,800,000
Future minimum lease payments under non-cancelable operating leases
2014 (remainder of the year)	882,000		882,000
2015	3,841,000		3,841,000
2016	3,967,000		3,967,000
2017	2,997,000		2,997,000
2018	601,000		601,000
Thereafter	4,002,000		4,002,000
Total	16,290,000		16,290,000
Expected minimum sublease rentals to be received	1,300,000		1,300,000
Rental expense under operating leases	$ 900,000	$ 900,000	$ 2,600,000	$ 2,600,000

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

9 Months Ended

Sep. 30, 2014

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 a wholly‑owned subsidiary of TransMontaigne Inc. At September 30, 2014, NGL Energy Partners LP (“NGL”) owned all of the issued and outstanding capital stock of TransMontaigne Inc., and, as a result, NGL is the indirect owner of our general partner. At September 30, 2014, TransMontaigne Inc. and NGL had a significant interest in our partnership through their indirect ownership of an approximate 20% limited partner interest, a 2% general partner interest and the incentive distribution rights.

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 September 30, 2014 and December 31, 2013, our results of operations for the three and nine months ended September 30, 2014 and 2013 and our cash flows for the three and nine months ended September 30, 2014 and 2013.

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.

The accompanying consolidated financial statements include allocated general and administrative charges from TransMontaigne Inc. for indirect corporate overhead to cover costs of functions such as legal, accounting, treasury, engineering, environmental safety, information technology, and other corporate services (see Note 2 of Notes to consolidated financial statements). The allocated general and administrative expenses were approximately $2.8 million and $2.7 million for the three months ended September 30, 2014 and 2013, respectively. The allocated general and administrative expenses were approximately $8.3 million and $8.2 million for the nine months ended September 30, 2014 and 2013, respectively. The accompanying consolidated financial statements also include allocated insurance charges from TransMontaigne Inc. for 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 charges were approximately $0.9 million and $0.9 million for the three months ended September 30, 2014 and 2013, respectively. The allocated insurance charges were approximately $2.8 million and $2.8 million for the nine months ended September 30, 2014 and 2013, respectively. The accompanying consolidated financial statements also include reimbursement of bonus awards paid to TransMontaigne Services Inc. (a wholly‑ owned subsidiary of TransMontaigne Inc.) towards bonus awards granted by TransMontaigne Services Inc. to certain key officers and employees who provide services to Partners that vest over future periods. The reimbursement of bonus awards was approximately $0.4 million and $0.3 million for the three months ended September 30, 2014 and 2013, respectively. The reimbursement of bonus awards was approximately $1.1 million and $0.9 million for the nine months ended September 30, 2014 and 2013, respectively.

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 throughput; transportation revenue is recognized when the product has been delivered to the customer at the specified delivery location; management fee revenue and cost reimbursements are recognized as the services are performed or as the costs are incurred; ancillary service revenue is recognized as the services are performed; and gains from the sale of refined products are recognized when the title to the product is transferred.

Pursuant to terminaling services agreements with certain of our throughput customers, we are entitled to the volume of product gained resulting from differences in the measurement of product volumes received and distributed at our terminaling facilities. Consistent with recognized industry practices, measurement differentials occur as the result of the inherent variances in measurement devices and methodology. We recognize as revenue the net proceeds from the sale of the product gained. For the three months ended September 30, 2014 and 2013, we recognized revenue of approximately $3.1 million and $3.3 million, respectively, for net product gained. Within these amounts, approximately $1.2 million and $2.9 million for the three months ended September 30, 2014 and 2013, respectively, were pursuant to terminaling services agreements with affiliate customers. For the nine months ended September 30, 2014 and 2013, we recognized revenue of approximately $10.8 million and $11.0 million, respectively, for net product gained. Within these amounts, approximately $6.1 million and $9.8 million for the nine months ended September 30, 2014 and 2013, 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 Inc. 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 (see Note 2 of Notes to consolidated financial statements). TransMontaigne Inc. 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 (see Note 2 of Notes to consolidated financial statements). TransMontaigne Inc. 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 (see Note 2 of Notes to consolidated financial statements). TransMontaigne Inc. 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 (see Note 2 of Notes to consolidated financial statements).

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 service 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.

Foreign currency translation and transactions

(j) Foreign currency translation and transactions

The functional currency of Partners and its U.S.‑based subsidiaries is the U.S. Dollar. The functional currency of our Mexico operations, which we sold effective August 8, 2013 (see Note 3 of Notes to consolidated financial statements), was the Mexican Peso. The assets and liabilities of our foreign subsidiaries were translated at period‑end rates of exchange, and revenue and expenses were translated at average exchange rates prevailing for the period. The resulting translation adjustments, net of related income taxes, were recorded as a component of other comprehensive income in the consolidated statements of comprehensive income. Gains and losses from the re‑measurement of foreign currency transactions (transactions denominated in a currency other than the entity’s functional currency) were included in other income (expenses) in the consolidated statements of comprehensive income.

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. Certain of our Mexican subsidiaries were corporations for Mexican tax purposes and, therefore, were subject to Mexican federal and provincial income taxes. Effective August 8, 2013, we sold our Mexico operations, including the Mexican corporations (see Note 3 of Notes to consolidated financial statements).

Partners accounts for U.S. state income taxes and Mexican federal and provincial income taxes under the asset and liability method pursuant to generally accepted accounting principles. Mexican federal and provincial income taxes and 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.

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COMMITMENTS AND CONTINGENCIES (Tables)

9 Months Ended

Sep. 30, 2014

COMMITMENTS AND CONTINGENCIES

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

Years ending December 31:
2014 (remainder of the year)	$	882
2015		3,841
2016		3,967
2017		2,997
2018		601
Thereafter		4,002
	$	16,290

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PARTNERS' EQUITY

9 Months Ended

Sep. 30, 2014

PARTNERS' EQUITY

PARTNERS' EQUITY

(13) PARTNERS’ EQUITY

The number of units outstanding is as follows:

	Common	General
	units	partner units
Units outstanding at September 30, 2014 and December 31, 2013	16,124,566	329,073

At September 30, 2014 and December 31, 2013, common units outstanding include 5,599 and 20,096 common units, respectively, held on behalf of TransMontaigne Services Inc.’s long‑term incentive plan.