Transmontaigne Partners (TLP) 10-K 14 Mar 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Feb. 28, 2017	Jun. 30, 2016
Document and Entity Information
Entity Registrant Name	TransMontaigne Partners L.P.
Entity Central Index Key	1,319,229
Document Type	10-K
Document Period End Date	Dec. 31, 2016
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Public Float			$ 529,973,697
Entity Common Stock, Shares Outstanding		16,161,262
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY

Consolidated balance sheets

Consolidated balance sheets - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 593	$ 681
Trade accounts receivable, net	9,297	5,973
Due from affiliates	653	1,080
Other current assets	9,903	2,410
Total current assets	20,446	10,144
Property, plant and equipment, net	416,748	388,423
Goodwill	8,485	8,485
Investments in unconsolidated affiliates	241,093	246,700
Other assets, net	2,922	2,935
TOTAL ASSETS	689,694	656,687
Current liabilities:
Trade accounts payable	7,928	10,874
Accrued liabilities	13,998	11,111
Total current liabilities	21,926	21,985
Other liabilities	3,234	2,731
Long-term debt	291,800	248,000
Total liabilities	316,960	272,716
Commitments and contingencies (Note 16)
Partners’ equity:
Common unitholders (16,137,650 units issued and outstanding at December 31, 2016 and 16,124,566 units issued and outstanding at December 31, 2015)	320,042	326,224
General partner interest (2% interest with 329,339 equivalent units outstanding at December 31, 2016 and 329,073 equivalent units outstanding at December 31, 2015)	52,692	57,747
Total partners’ equity	372,734	383,971
TOTAL LIABILITIES AND EQUITY	$ 689,694	$ 656,687

Consolidated balance sheets (Pa

Consolidated balance sheets (Parenthetical) - shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Consolidated balance sheets
Common unitholders, units issued	16,137,650	16,124,566
Common unitholders, units outstanding	16,137,650	16,124,566
General partner interest (as a percent)	2.00%	2.00%
General partner interest, equivalent units outstanding	329,339	329,073

Consolidated statements of inco

Consolidated statements of income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenue:
External customers	$ 156,506	$ 109,557	$ 75,909
Affiliates	8,418	42,953	74,153
Total revenue	164,924	152,510	150,062
Operating costs and expenses and other:
Direct operating costs and expenses	(68,415)	(64,033)	(66,183)
General and administrative expenses	(14,823)	(14,857)	(14,662)
Insurance expenses	(4,081)	(3,756)	(3,711)
Reimbursement of bonus awards expense	(2,540)	(1,303)	(1,500)
Depreciation and amortization	(32,383)	(30,650)	(29,522)
Earnings from unconsolidated affiliates	10,029	11,948	4,443
Total operating costs and expenses and other	(112,213)	(102,651)	(111,135)
Operating income	52,711	49,859	38,927
Other expenses:
Interest expense	(7,787)	(7,396)	(5,489)
Amortization of deferred financing costs	(818)	(774)	(975)
Total other expenses	(8,605)	(8,170)	(6,464)
Net earnings	44,106	41,689	32,463
Less-earnings allocable to general partner interest including incentive distribution rights	(9,340)	(7,506)	(7,167)
Net earnings allocable to limited partners	$ 34,766	$ 34,183	$ 25,296
Net earnings per limited partner unit-basic (in dollars per unit)	$ 2.14	$ 2.12	$ 1.57
Net earnings per limited partner unit-diluted (in dollars per unit)	$ 2.14	$ 2.12	$ 1.57

Consolidated statements of part

Consolidated statements of partners' equity - USD ($) $ in Thousands	Common units	General partner interest	Total
Balance at Dec. 31, 2013	$ 350,505	$ 57,962	$ 408,467
Increase (Decrease) in Partners' Capital
Distributions to unitholders	(42,561)	(7,283)	(49,844)
Equity-based compensation	721		721
Purchase of common units by our long-term incentive plan	(342)		(342)
Net earnings	25,296	7,167	32,463
Balance at Dec. 31, 2014	333,619	57,846	391,465
Increase (Decrease) in Partners' Capital
Distributions to unitholders	(42,897)	(7,605)	(50,502)
Equity-based compensation	1,411		1,411
Purchase of common units by our long-term incentive plan	(92)		(92)
Net earnings	34,183	7,506	41,689
Balance at Dec. 31, 2015	326,224	57,747	383,971
Increase (Decrease) in Partners' Capital
Distributions to unitholders	(44,211)	(8,898)	(53,109)
Equity-based compensation	3,128		3,128
Issuance of common units by our long-term incentive plan	135		135
TransMontaigne GP to maintain its 2% general partner interest		9	9
Excess of $12.0 million purchase price of hydrant system from TransMontaigne LLC over the carryover basis of the net assets		(5,506)	(5,506)
Net earnings	34,766	9,340	44,106
Balance at Dec. 31, 2016	$ 320,042	$ 52,692	$ 372,734

Consolidated statements of par6

Consolidated statements of partners' equity (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Consolidated statements of partners' equity
Purchase of common units by our long-term incentive plan (in units)		2,668	8,004
Issuance of common units due to vesting of restricted phantom units (in units)	19,008		20,500
Issuance of common units by our savings and retention program (in units)	2,094
General partner interest (as a percent)	2.00%	2.00%
Payment for acquisition of hydrant system from TransMontaigne LLC	$ 12,000

Consolidated statements of cash

Consolidated statements of cash flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities:
Net earnings	$ 44,106	$ 41,689	$ 32,463
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation and amortization	32,383	30,650	29,522
Earnings from unconsolidated affiliates	(10,029)	(11,948)	(4,443)
Distributions from unconsolidated affiliates	17,861	19,649	10,053
Equity-based compensation	3,263	1,411	721
Amortization of deferred financing costs	818	774	975
Amortization of deferred revenue	(248)	(1,268)	(2,437)
Unrealized (gain) on derivative instruments	(344)
Changes in operating assets and liabilities, net of effects from acquisitions and dispositions:
Trade accounts receivable, net	(2,987)	3,386	(2,838)
Due from affiliates	427	236	941
Other current assets	(7,082)	655	413
Amounts due under long-term terminaling services agreements, net	337	1,144	1,298
Deposits	(193)	(19)
Trade accounts payable	(2,092)	(155)	615
Accrued liabilities	2,887	1,276	(6,354)
Net cash provided by operating activities	79,107	87,480	60,929
Cash flows from investing activities:
Acquisition of terminal assets	(12,000)
Investments in unconsolidated affiliates	(2,225)	(4,726)	(43,681)
Capital expenditures	(54,864)	(29,427)	(7,021)
Net cash used in investing activities	(69,089)	(34,153)	(50,702)
Cash flows from financing activities:
Borrowings of debt under credit facility	199,900	101,900	136,700
Repayments of debt under credit facility	(156,100)	(105,900)	(96,700)
Deferred financing costs	(395)	(1,356)
Deferred shelf registration costs	(411)
Distributions paid to unitholders	(53,109)	(50,502)	(49,844)
Purchase of common units by our long-term incentive plan		(92)	(342)
Contribution of cash by TransMontaigne GP	9
Net cash used in financing activities	(10,106)	(55,950)	(10,186)
Increase (decrease) in cash and cash equivalents	(88)	(2,623)	41
Cash and cash equivalents at beginning of period	681	3,304	3,263
Cash and cash equivalents at end of period	593	681	3,304
Supplemental disclosures of cash flow information:
Cash paid for interest	8,097	7,298	5,496
Property, plant and equipment acquired with accounts payable	$ 5,114	$ 5,966	$ 1,273

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2016
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (a) Nature of business TransMontaigne Partners L.P. (“we,” “us,” “our,” “the Partnership”) was formed in February 2005 as a Delaware limited partnership. We provide integrated terminaling, storage, transportation and related services for companies engaged in the trading, distribution and marketing of light refined petroleum products, heavy refined petroleum products, crude oil, chemicals, fertilizers and other liquid products. We conduct our operations in the United States along the Gulf Coast, in the Midwest, in Houston and Brownsville, Texas, along the Mississippi and Ohio rivers, and in the Southeast. We are controlled by our general partner, TransMontaigne GP (“TransMontaigne GP”), which as of February 1, 2016 is a wholly‑owned indirect subsidiary of ArcLight Energy Partners Fund VI, L.P. (“ArcLight”). Prior to February 1, 2016, TransMontaigne LLC, a wholly-owned subsidiary of NGL Energy Partners LP (“NGL”), owned all the issued and outstanding ownership interests of TransMontaigne GP. Prior to July 1, 2014, Morgan Stanley Capital Group Inc. (“Morgan Stanley Capital Group”), a wholly‑owned subsidiary of Morgan Stanley and the principal commodities trading arm of Morgan Stanley, owned all of the issued and outstanding capital stock of TransMontaigne LLC, and, as a result, Morgan Stanley was the indirect owner of our general partner. Effective July 1, 2014, Morgan Stanley consummated the sale of its 100% ownership interest in TransMontaigne LLC to NGL. In addition to the sale of our general partner to NGL, NGL assumed Morgan Stanley Capital Group’s obligations under our light-oil terminaling services agreements in Florida and the Southeast regions, excluding the Collins/Purvis, Mississippi bulk storage terminals, which we refer to collectively as the “NGL acquisition”. Terminaling services agreements for our Collins/Purvis, Mississippi bulk storage and Cushing, Oklahoma terminals remained with Morgan Stanley Capital Group until October 30, 2015, at which time Morgan Stanley sold its global physical oil merchanting business to Castleton Commodities International LLC and Morgan Stanley Capital Group, with our consent, assigned its terminaling services agreements with us to Castleton Commodities International LLC. (b) Basis of presentation and use of estimates Our accounting and financial reporting policies conform to accounting principles generally accepted in the United States of America (“GAAP”). The accompanying consolidated financial statements include the accounts of TransMontaigne Partners L.P., a Delaware limited partnership, and its controlled subsidiaries. Investments where we do not have the ability to exercise control, but do have the ability to exercise significant influence, are accounted for using the equity method of accounting. All inter‑company accounts and transactions have been eliminated in the preparation of the accompanying consolidated financial statements. The preparation of financial statements in conformity with “GAAP” requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting periods. The following estimates, in management’s opinion, are subjective in nature, require the exercise of judgment, and/or involve complex analyses: useful lives of our plant and equipment and accrued environmental obligations. Changes in these estimates and assumptions will occur as a result of the passage of time and the occurrence of future events. Actual results could differ from these estimates. (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 from terminaling services fees, transportation fees, management fees and cost reimbursements, fees from other ancillary services and gains from the sale of refined products. Terminaling services revenue is recognized ratably over the term of the agreement for storage fees and minimum revenue commitments that are fixed at the inception of the agreement and when product is delivered to the customer for fees based on a rate per barrel of throughput; pipeline transportation revenue is recognized when the product has been delivered to the customer at the specified delivery location; management fee revenue and cost reimbursements are recognized as the services are performed or as the costs are incurred; ancillary service revenue is recognized as the services are performed; and gains from the sale of refined products are recognized when the title to the product is transferred. Pursuant to terminaling services agreements with certain of our throughput customers, we are entitled to the volume of product gained resulting from differences in the measurement of product volumes received and distributed at our terminaling facilities. Consistent with recognized industry practices, measurement differentials occur as the result of the inherent variances in measurement devices and methodology. We recognize as revenue the net proceeds from the sale of the net product gained. For the years ended December 31, 2016, 2015 and 2014, we recognized revenue of approximately $6.7 million, $7.5 million and $13.1 million, respectively, for net product gained. Within these amounts, approximately $0.3 million, $2.9 million and $7.5 million, respectively, were pursuant to terminaling services agreements with affiliate customers. (d) Cash and cash equivalents We consider all short‑term investments with a remaining maturity of three months or less at the date of purchase to be cash equivalents. (e) Property, plant and equipment Depreciation is computed using the straight‑line method. Estimated useful lives are 15 to 25 years for terminals and pipelines and 3 to 25 years for furniture, fixtures and equipment. All items of property, plant and equipment are carried at cost. Expenditures that increase capacity or extend useful lives are capitalized. Repairs and maintenance are expensed as incurred. We evaluate long‑lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset group may not be recoverable based on expected undiscounted future cash flows attributable to that asset group. If an asset group is impaired, the impairment loss to be recognized is the excess of the carrying amount of the asset group over its estimated fair value. (f) Investments in unconsolidated affiliates We account for our investments in unconsolidated affiliates, which we do not control but do have the ability to exercise significant influence over, using the equity method of accounting. Under this method, the investment is recorded at acquisition cost, increased by our proportionate share of any earnings and additional capital contributions and decreased by our proportionate share of any losses, distributions received and amortization of any excess investment. Excess investment is the amount by which our total investment exceeds our proportionate share of the book value of the net assets of the investment entity. We evaluate our investments in unconsolidated affiliates for impairment whenever events or circumstances indicate there is a loss in value of the investment that is other than temporary. In the event of impairment, we would record a charge to earnings to adjust the carrying amount to fair value. (g) Environmental obligations We accrue for environmental costs that relate to existing conditions caused by past operations when probable and reasonably estimable (see Note 10 of Notes to consolidated financial statements). Environmental costs include initial site surveys and environmental studies of potentially contaminated sites, costs for remediation and restoration of sites determined to be contaminated and ongoing monitoring costs, as well as fines, damages and other costs, including direct legal costs. Liabilities for environmental costs at a specific site are initially recorded, on an undiscounted basis, when it is probable that we will be liable for such costs, and a reasonable estimate of the associated costs can be made based on available information. Such an estimate includes our share of the liability for each specific site and the sharing of the amounts related to each site that will not be paid by other potentially responsible parties, based on enacted laws and adopted regulations and policies. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods. Estimates of our ultimate liabilities associated with environmental costs are difficult to make with certainty due to the number of variables involved, including the early stage of investigation at certain sites, the lengthy time frames required to complete remediation, technology changes, alternatives available and the evolving nature of environmental laws and regulations. We periodically file claims for insurance recoveries of certain environmental remediation costs with our insurance carriers under our comprehensive liability policies (see Note 5 of Notes to consolidated financial statements). We recognize our insurance recoveries as a credit to income in the period that we assess the likelihood of recovery as being probable (i.e., likely to occur). In connection with our previous acquisitions of certain terminals from TransMontaigne LLC, TransMontaigne LLC has agreed to indemnify us against certain potential environmental claims, losses and expenses at those terminals (see Note 2 of Notes to consolidated financial statements). (h) Asset retirement obligations Asset retirement obligations are legal obligations associated with the retirement of long‑lived assets that result from the acquisition, construction, development or normal use of the asset. Generally accepted accounting principles require that the fair value of a liability related to the retirement of long‑lived assets be recorded at the time a legal obligation is incurred. Once an asset retirement obligation is identified and a liability is recorded, a corresponding asset is recorded, which is depreciated over the remaining useful life of the asset. After the initial measurement, the liability is adjusted to reflect changes in the asset retirement obligation. If and when it is determined that a legal obligation has been incurred, the fair value of any liability is determined based on estimates and assumptions related to retirement costs, future inflation rates and interest rates. Our long‑lived assets consist of above‑ground storage facilities and underground pipelines. We are unable to predict if and when these long‑lived assets will become completely obsolete and require dismantlement. We have not recorded an asset retirement obligation, or corresponding asset, because the future dismantlement and removal dates of our long‑lived asset subject to legal obligation is indeterminable and the amount of any associated costs are believed to be insignificant. Changes in our assumptions and estimates may occur as a result of the passage of time and the occurrence of future events. (i)  Equity based compensation Generally accepted accounting principles require us to measure the cost of services received in exchange for an award of equity instruments based on the measurement‑date fair value of the award. That cost is recognized during the period services are provided in exchange for the award. (j) Accounting for derivative instruments Generally accepted accounting principles require us to recognize all derivative instruments at fair value in the consolidated balance sheets as assets or liabilities (see Note 9 of Notes to consolidated financial statements). Changes in the fair value of our derivative instruments are recognized in earnings. We did not have any derivative instruments at December 31, 2014. At December 31, 2016 and 2015, our derivative instruments were limited to interest rate swap agreements with an aggregate notional amount of $125.0 million and $75.0 million, respectively. Our derivative instruments at December 31, 2016 expire between March 25, 2018 and March 11, 2019. Pursuant to the terms of the interest rate swap agreements, we pay a blended fixed rate of approximately 1.01% and receive interest payments based on the one-month LIBOR. The net difference to be paid or received under the interest rate swap agreements is settled monthly and is recognized as an adjustment to interest expense. The fair value of our interest rate swap agreements are determined using a pricing model based on the LIBOR swap rate and other observable market data. At December 31, 2016 and 2015, the fair value of our interest rate swaps was approximately $0.3 million and $nil, respectively. (k) Income taxes No provision for U.S. federal income taxes has been reflected in the accompanying consolidated financial statements because we are treated as a partnership for federal income tax purposes. As a partnership, all income, gains, losses, expenses, deductions and tax credits generated by us flow through to our unitholders. (l) Net earnings per limited partner unit Net earnings allocable to the limited partners, for purposes of calculating net earnings per limited partner unit, are calculated under the two-class method and accordingly are net of the earnings allocable to the general partner interest and distributions payable to any restricted phantom units granted under our equity based compensation plans that participate in our distributions. The earnings allocable to the general partner interest include the distributions of available cash (as defined by our partnership agreement) attributable to the period to the general partner interest, net of adjustments for the general partner’s share of undistributed earnings, and the incentive distribution rights. Undistributed earnings are the difference between the earnings and the distributions attributable to the period. Undistributed earnings are allocated to the limited partners and general partner interest based on their respective sharing of earnings or losses specified in the partnership agreement, which is based on their ownership percentages of 98% and 2%, respectively. The incentive distribution rights are not allocated a portion of the undistributed earnings given they are not entitled to distributions other than from available cash. Further, the incentive distribution rights do not share in losses under our partnership agreement. Basic net earnings per limited partner unit is computed by dividing net earnings allocable to the limited partners by the weighted average number of limited partner units outstanding during the period. Diluted net earnings per limited partner unit is computed by dividing net earnings allocable to the limited partners by the weighted average number of limited partner units outstanding during the period and any potential dilutive securities outstanding during the period. (m) Comprehensive Income Entities that report items of other comprehensive income have the option to present the components of net income and comprehensive income in either one continuous financial statement, or two consecutive financial statements. As the Company has no components of comprehensive income other than net income (loss), no statement of comprehensive income has been presented. (n) Recent accounting pronouncements In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The objective of this update is to clarify the principles for recognizing revenue and to develop a common revenue standard. The core principle of the ASU is that an entity should recognize revenue for the transfer of goods or services equal to the amount that it expects to be entitled to receive for those goods or services. The ASU requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments. The ASU is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period and allows for both retrospective and modified retrospective methods of adoption. While we are currently evaluating the impact of ASU 2014-09 and all related ASU’s on a representative sample of individual customer contracts. Additionally, we are in the process of evaluating and designing the necessary changes to our business processes, systems and controls to support recognition and disclosure under the new standard. We are continuing our evaluation to determine the impact on our consolidated financial condition and results of operations. In February 2016, the FASB issued ASU 2016-02, Leases. The objective of this update is to improve financial reporting about leasing transactions. ASU 2016-02 is effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period. We are currently evaluating the potential impact that the adoption will have on our disclosures and financial statements. In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipt and Cash Payments, to add or clarify guidance on the classification of certain cash receipts and payments in the statement of cash flows. ASU 2016-15 is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. We are currently evaluating the potential impact that the adoption will have on our disclosures and financial statements. In January 2017, the FASB issued ASU 2017-04, Intangibles- Goodwill and Other: Simplifying the Test for Goodwill Impairment, to simplify the accounting for goodwill impairments by eliminating step 2 from the goodwill impairment test. ASU 2017-04 is effective for annual reporting periods beginning after December 15, 2019, including interim periods within that reporting period. We are currently evaluating the potential impact that the adoption will have on our disclosures and financial statements.

TRANSACTIONS WITH AFFILIATES

TRANSACTIONS WITH AFFILIATES	12 Months Ended
	Dec. 31, 2016
TRANSACTIONS WITH AFFILIATES
TRANSACTIONS WITH AFFILIATES	(2) TRANSACTIONS WITH AFFILIATES Omnibus agreement. On May 27, 2005 we entered into an omnibus agreement with TransMontaigne LLC and our general partner, which agreement has been subsequently amended from time to time. In connection with the ArcLight acquisition of our general partner, effective February 1, 2016, we entered into the second amended and restated omnibus agreement to consent to the assignment of the omnibus agreement from TransMontaigne LLC to Gulf TLP Holdings LLC , an ArcLight subsidiary, to waive the automatic termination that would have occurred at such time as TransMontaigne LLC ceased to control our general partner and to remove certain legacy provisions that were no longer applicable to the Partnership. The omnibus agreement will continue in effect until the earlier of (i) ArcLight ceasing to control our general partner or (ii) the election of either us or the owner, following at least 24 months’ prior written notice to the other parties. Under the omnibus agreement we pay Gulf TLP Holdings, the owner of TransMontaigne GP, an administrative fee for the provision of various general and administrative services for our benefit. For the years ended December 31, 2016, 2015 and 2014, the annual administrative fee paid to the owner of TransMontaigne GP was approximately $11.4 million, $11.3 million and $11.1 million, respectively. If we acquire or construct additional facilities, the owner of TransMontaigne GP may propose a revised administrative fee covering the provision of services for such additional facilities, subject to approval by the conflicts committee of our general partner. The administrative fee is recognized as a component of general and administrative expense and encompasses services to perform centralized corporate functions, such as legal, accounting, treasury, insurance administration and claims processing, health, safety and environmental, information technology, human resources, credit, payroll, taxes, engineering and other corporate services. The omnibus agreement further provides that we pay the owner of TransMontaigne GP for insurance policies purchased on our behalf to cover our facilities and operations. For the years ended December 31, 2016, 2015 and 2014, the insurance expense paid to the owner of TransMontaigne GP was approximately $3.1 million, $3.8 million and $3.7 million, respectively. Beginning October 31, 2016, we contracted directly with insurance carriers for the majority of our insurance requirements. For the years ended December 31, 2016, 2015 and 2014, the expense associated with insurance contracted directly by us was $1.0 million, $nil and $nil, respectively. We also pay the owner of TransMontaigne GP for direct operating costs and expenses, such as salaries of operational personnel performing services on‑site at our terminals and pipelines and the cost of their employee benefits, including 401(k) and health insurance benefits. Under the omnibus agreement we have agreed to reimburse the owner of TransMontaigne GP for incentive bonus awards made to key employees under the owner’s savings and retention program, provided the compensation committee and the conflicts committee of our general partner approve the annual awards granted under the plan. Effective April 13, 2015 and beginning with the 2015 incentive bonus award, we have the option to provide the reimbursement in either a cash payment or the delivery of our common units to the owner of TransMontaigne GP or directly to the award recipients, with the reimbursement made in accordance with the underlying vesting and payment schedule of the savings and retention program. Prior to the 2015 incentive bonus award, we reimbursed our portion of the incentive bonus awards by making cash payments to the owner of TransMontaigne GP over the first year that each applicable award was granted. For the years ended December 31, 2016, 2015 and 2014, the expense associated with the reimbursement of incentive bonus awards was approximately $2.5 million, $1.3 million and $1.5 million, respectively. Environmental indemnification. In connection with our acquisition of the Florida and Midwest terminals on May 27, 2005, TransMontaigne LLC agreed to indemnify us against certain potential environmental claims, losses and expenses that were identified on or before May 27, 2010, and that were associated with the ownership or operation of the Florida and Midwest terminals prior to May 27, 2005. TransMontaigne LLC’s maximum liability for this indemnification obligation is $15.0 million. TransMontaigne LLC has no obligation to indemnify us for losses until such aggregate losses exceed $250,000. TransMontaigne LLC has no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after May 27, 2005. In connection with our acquisition of the Brownsville, Texas and River terminals on December 31, 2006, TransMontaigne LLC agreed to indemnify us against potential environmental claims, losses and expenses that were identified on or before December 31, 2011, and that were associated with the ownership or operation of the Brownsville and River facilities prior to December 31, 2006. TransMontaigne LLC’s maximum liability for this indemnification obligation is $15.0 million. TransMontaigne LLC has no obligation to indemnify us for losses until such aggregate losses exceed $250,000. The deductible amount, cap amount and limitation of time for indemnification do not apply to any environmental liabilities known to exist as of December 31, 2006. TransMontaigne LLC has no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after December 31, 2006. In connection with our acquisition of the Southeast terminals on December 31, 2007, TransMontaigne LLC agreed to indemnify us against potential environmental claims, losses and expenses that were identified on or before December 31, 2012, and that were associated with the ownership or operation of the Southeast terminals prior to December 31, 2007. TransMontaigne LLC’s maximum liability for this indemnification obligation is $15.0 million. TransMontaigne LLC has no obligation to indemnify us for losses until such aggregate losses exceed $250,000. The deductible amount, cap amount and limitation of time for indemnification do not apply to any environmental liabilities known to exist as of December 31, 2007. TransMontaigne LLC has no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after December 31, 2007. In connection with our acquisition of the Pensacola terminal on March 1, 2011, TransMontaigne LLC agreed to indemnify us against potential environmental claims, losses and expenses that were identified on or before March 1, 2016, and that were associated with the ownership or operation of the Pensacola terminal prior to March 1, 2011. TransMontaigne LLC’s maximum liability for this indemnification obligation is $2.5 million. TransMontaigne LLC has no obligation to indemnify us for losses until such aggregate losses exceed $200,000. The deductible amount, cap amount and limitation of time for indemnification do not apply to any environmental liabilities known to exist as of March 1, 2011. TransMontaigne LLC has no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after March 1, 2011. The forgoing environmental indemnification obligations of TransMontaigne LLC to us remain in place and were not affected by ArcLight’s acquisition of our general partner. Terminaling services agreement—Brownsville terminals. In September 2016, we entered into a terminaling services agreement with Frontera relating to our Brownsville, Texas facility that will expire in June 2019, subject to a two-year automatic renewal unless terminated by either party upon 180 days’ prior notice. Under this agreement, Frontera has agreed to throughput a volume of light oil product at our terminal that, at the fee schedule contained in the agreement, will result in minimum throughput payments to us of approximately $1.3 million per year. In exchange for its minimum throughput commitment, we have agreed to provide Frontera with approximately 151,000 barrels of storage capacity. For the years ended December 31, 2016, 2015 and 2014, we recognized approximately $0.5 million, $nil and $nil, respectively, of revenue related to this agreement. Direct transfer agreement—Brownsville terminals. In September 2012, we entered into a direct transfer agreement with Frontera relating to our Brownsville, Texas facility. Under this agreement, Frontera agreed to provide services to us related to the use of certain Frontera assets. This agreement was terminated on August 31, 2016. For the years ended December 31, 2016, 2015 and 2014, we recognized approximately $0.2 million, $0.4 million and $0.7 million, respectively, of expense related to this agreement. Operations and reimbursement agreement—Frontera. We have a 50% ownership interest in Frontera Brownsville LLC joint venture, or “Frontera”. We have agreed to operate Frontera, in accordance with an operations and reimbursement agreement executed between us and Frontera, for a management fee that is based on our costs incurred. Our agreement with Frontera stipulates that we may resign as the operator at any time with the prior written consent of Frontera, or that we may be removed as the operator for good cause, which includes material noncompliance with laws and material failure to adhere to good industry practice regarding health, safety or environmental matters. For the years ended December 31, 2016, 2015 and 2014, we recognized approximately $5.0 million, $4.4 million and $4.0 million, respectively, of revenue related to this operations and reimbursement agreement. 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 a third party customer 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 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 the third party on September 16, 2014. The tankage at Port Manatee became available to the third party in July of 2015, upon the completion of certain enhancements at this facility. On October 31, 2014, NGL provided us the required 18 months’ prior notice that it would terminate its remaining obligations under the Florida terminaling services agreement effective April 30, 2016, which constitutes NGL’s light oil terminaling capacity for approximately 1.1 million barrels at our Port Everglades North, Florida terminal. On April 30, 2016, NGL amended the agreement to retain approximately 0.1 million barrels of this capacity. As of July 15, 2016 we have re-contracted the remaining capacity to third party customers at similar rates charged to NGL. Effective May 31, 2014, the Florida tanks dedicated to bunker fuels were no longer subject to the Florida and Midwest terminaling services agreement. A majority of this capacity has been re‑contracted to third parties effective June 1, 2014 and November 19, 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, which was simultaneous with our entry into a ten-year capacity agreement with a third party, covering 100% of the capacity of our Razorback system. Under the Florida and Midwest terminaling services agreement, taking into consideration terminations, Morgan Stanley Capital Group, and NGL as the successor to the agreement, was obligated to throughput a volume that, at the fee and tariff schedule contained in the agreement, resulted in minimum throughput payments to us of approximately $0.8 million, $5.0 million and $21.0 million for the years ended December 31, 2016, 2015 and 2014, respectively. 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 in August 2012. Under this agreement, Morgan Stanley Capital Group has agreed to throughput a volume of crude oil at our terminal that, 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. Further, on October 27, 2015, upon the sale of Morgan Stanley’s global physical oil merchanting business to Castleton Commodities International LLC, Morgan Stanley Capital Group, with our consent, assigned all its terminaling services agreements with us to Castleton Commodities International LLC. 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 bulk storage tankage. The terminaling services agreement provisions pertaining to the Collins/Purvis bulk storage tankage remained with Morgan Stanley Capital Group, and subsequent to the NGL acquisition the revenue associated with the Collins/Purvis bulk storage tankage is recorded as revenue from external customers as opposed to revenue from affiliates. In connection with the ArcLight acquisition of our general partner, our Southeast terminaling services agreement with NGL was amended to extend the term of the agreement through July 31, 2040 at the prevailing contract rate terms contained within the agreement. Subsequent to January 31, 2023, NGL has the ability to terminate the agreement at any time upon at least 24 months’ prior notice of its intent to terminate the agreement. Subsequent to the ArcLight acquisition, effective February 1, 2016, revenue associated with the Southeast terminaling services agreement is recorded as revenue from external customers as opposed to revenue from affiliates. Under this agreement, Morgan Stanley Capital Group, and NGL as the successor to the majority of the agreement, was obligated to throughput a volume of refined product at our Southeast terminals that, at the fee schedule contained in the agreement, resulted in minimum throughput payments to us of approximately $27.0 million, $27.0 million and $36.8 million for the years ended December 31, 2016, 2015 and 2014, respectively. Terminaling services agreement—Collins/Purvis bulk storage 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 bulk storage 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 construct storage tanks and associated infrastructure to provide approximately 700,000 barrels of additional light oil capacity at the Collins/Purvis bulk storage 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, at each fee schedule contained in the agreement, result in minimum throughput payments to us of approximately $4.1 million for each one-year period following the in‑service date of July 2011. Subsequent to the NGL acquisition, effective July 1, 2014, revenue associated with the Collins/Purvis bulk storage additional light oil tankage is recorded as revenue from external customers as opposed to revenue from affiliates. Further, on October 27, 2015, upon the sale of Morgan Stanley’s global physical oil merchanting business to Castleton Commodities International LLC, Morgan Stanley Capital Group, with our consent, assigned all its terminaling services agreements with us to Castleton Commodities International LLC. 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, Louisiana 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, 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 a third party. 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.

TERMINAL ACQUISITION FROM AFFIL

TERMINAL ACQUISITION FROM AFFILIATE	12 Months Ended
	Dec. 31, 2016
TERMINAL ACQUISITION FROM AFFILIATE
TERMINAL ACQUISITION FROM AFFILIATE	(3) TERMINAL ACQUISITION FROM AFFILIATE Effective January 28, 2016, we acquired from TransMontaigne LLC its Port Everglades, Florida hydrant system for a cash payment of $12.0 million. The hydrant system encompasses a system for fueling cruise ships. The acquisition of the hydrant system from TransMontaigne LLC has been recorded at the carryover basis in a manner similar to a reorganization of entities under common control. Accordingly, we recorded the assets at their net book value of $6.5 million with the remaining purchase price of $5.5 million recorded as a reduction to the general partner equity interest. TransMontaigne LLC controlled our general partner on the acquisition date, the difference between the consideration we paid to TransMontaigne LLC and the carryover basis of the net assets purchased has been reflected in the accompanying consolidated balance sheets and statement of partners’ equity as a decrease to the general partner’s interest. The accompanying consolidated financial statements include the assets, liabilities and results of operations of the hydrant system from January 28, 2016. As this transaction is not considered material to our consolidated financial statements we did not recast prior period consolidated financial statements.

CONCENTRATION OF CREDIT RISK AN

CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE	12 Months Ended
	Dec. 31, 2016
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. These concentrations of customers may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. Our customers’ historical financial and operating information is analyzed prior to extending credit. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions we may request letters of credit, prepayments or guarantees. We maintain allowances for potentially uncollectible accounts receivable. Trade accounts receivable, net consists of the following (in thousands): December 31, December 31, 2016 2015 Trade accounts receivable $ $ Less allowance for doubtful accounts $ $ The following table presents a rollforward of our allowance for doubtful accounts (in thousands): Balance at Balance at beginning Charged to end of of period expenses Deductions period 2016 $ $ $ $ 2015 $ $ $ — $ 2014 $ $ $ — $ The following customers accounted for at least 10% of our consolidated revenue in at least one of the periods presented in the accompanying consolidated statements of income: Year ended Year ended Year ended December 31, December 31, December 31, 2016 2015 2014 NGL Energy Partners LP % % % Castleton Commodities International LLC % — % — % RaceTrac Petroleum Inc. % % % Morgan Stanley Capital Group — % % % On October 27, 2015, upon the sale of Morgan Stanley’s global physical oil merchanting business to Castleton Commodities International LLC, Morgan Stanley Capital Group, with our consent, assigned all its remaining terminaling services agreements with us to Castleton Commodities International LLC.

OTHER CURRENT ASSETS

OTHER CURRENT ASSETS	12 Months Ended
	Dec. 31, 2016
OTHER CURRENT ASSETS
OTHER CURRENT ASSETS	(5) OTHER CURRENT ASSETS Other current assets are as follows (in thousands): December 31, December 31, 2016 2015 Amounts due from insurance companies $ $ Additive detergent Prepaid insurance — Deposits and other assets $ $ Amounts due from insurance companies. We periodically file claims for recovery of environmental remediation costs with our insurance carriers under our comprehensive liability policies. We recognize our insurance recoveries in the period that we assess the likelihood of recovery as being probable (i.e., likely to occur). At December 31, 2016 and 2015, we have recognized amounts due from insurance companies of approximately $1.8 million and $0.8 million, respectively, representing our best estimate of our probable insurance recoveries. During the year ended December 31, 2016, we received reimbursements from insurance companies of approximately $0.5 million. During the year ended December 31, 2016 we increased our estimate of probable future insurance recoveries by approximately $1.5 million. Prepaid Insurance. On October 31, 2016, we contracted directly with insurance carriers for the majority of our insurance requirements. Prior to October 31, 2016, we paid the owner of TransMontaigne GP a monthly insurance reimbursement for insurance policies purchased on our behalf to cover our facilities and operations under the omnibus agreement. At December 31, 2016 and 2015, we have recognized prepaid insurance of approximately $4.7 million and $nil, respectively.

PROPERTY, PLANT AND EQUIPMENT,

PROPERTY, PLANT AND EQUIPMENT, NET	12 Months Ended
	Dec. 31, 2016
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): December 31, December 31, 2016 2015 Land $ $ Terminals, pipelines and equipment Furniture, fixtures and equipment Construction in progress Less accumulated depreciation $ $

GOODWILL

GOODWILL	12 Months Ended
	Dec. 31, 2016
GOODWILL.
GOODWILL	(7) GOODWILL Goodwill is as follows (in thousands): December 31, December 31, 2016 2015 Brownsville terminals $ $ Goodwill is required to be tested for impairment annually unless events or changes in circumstances indicate it is more likely than not that an impairment loss has been incurred at an interim date. Our annual test for the impairment of goodwill is performed as of December 31. The impairment test is performed at the reporting unit level. Our reporting units are our operating segments (see Note 18 of Notes to consolidated financial statements). The fair value of each reporting unit is determined on a stand‑alone basis from the perspective of a market participant and represents an estimate of the price that would be received to sell the unit as a whole in an orderly transaction between market participants at the measurement date. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered to be impaired. At December 31, 2016 and 2015, our only reporting unit that contained goodwill was our Brownsville terminals. Our estimate of the fair value of our Brownsville terminals at December 31, 2016 and 2015 substantially exceeded its carrying amount. Accordingly, we did not recognize any goodwill impairment charges during the years ended December 31, 2016 and 2015, respectively. 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.

INVESTMENTS IN UNCONSOLIDATED A

INVESTMENTS IN UNCONSOLIDATED AFFILIATES	12 Months Ended
	Dec. 31, 2016
INVESTMENTS IN UNCONSOLIDATED AFFILIATES
INVESTMENTS IN UNCONSOLIDATED AFFILIATES	(8) INVESTMENTS IN UNCONSOLIDATED AFFILIATES At December 31, 2016 and 2015, our investments in unconsolidated affiliates include a 42.5% Class A ownership interest in Battleground Oil Specialty Terminal Company LLC (“BOSTCO”) and a 50% ownership interest in Frontera Brownsville LLC (“Frontera”). BOSTCO is a terminal facility located on the Houston Ship Channel that encompasses approximately 7.1 million barrels of distillate, residual and other black oil product storage. Class A and Class B ownership interests share in cash distributions on a 96.5% and 3.5% basis, respectively. Class B ownership interests do not have voting rights and are not required to make capital investments. Frontera is a terminal facility located in Brownsville, Texas that encompasses approximately 1.5 million barrels of light petroleum product storage, as well as related ancillary facilities. The following table summarizes our investments in unconsolidated affiliates: Percentage of Carrying value ownership (in thousands) December 31, December 31, December 31, 2016 2015 2016 2015 BOSTCO % % $ $ Frontera % % Total investments in unconsolidated affiliates $ $ At December 31, 2016 and 2015, our investment in BOSTCO includes approximately $7.2 million and $7.4 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 amortized over the useful life of the assets. Excess investment is the amount by which our investment exceeds our proportionate share of the book value of the net assets of the BOSTCO entity. Earnings from investments in unconsolidated affiliates were as follows (in thousands): Year ended Year ended Year ended December 31, December 31, December 31, 2016 2015 2014 BOSTCO $ $ $ Frontera Total earnings from investments in unconsolidated affiliates $ $ $ Additional capital investments in unconsolidated affiliates were as follows (in thousands): Year ended Year ended Year ended December 31, December 31, December 31, 2016 2015 2014 BOSTCO $ $ $ Frontera Additional capital investments in unconsolidated affiliates $ $ $ Cash distributions received from unconsolidated affiliates were as follows (in thousands): Year ended Year ended Year ended December 31, December 31, December 31, 2016 2015 2014 BOSTCO $ $ $ Frontera Cash distributions received from unconsolidated affiliates $ $ $ The summarized financial information of our unconsolidated affiliates was as follows (in thousands): Balance sheets: BOSTCO Frontera December 31, December 31, December 31, December 31, 2016 2015 2016 2015 Current assets $ $ $ $ Long-term assets Current liabilities Long-term liabilities — — — Net assets $ $ $ $ Statements of income : BOSTCO Frontera Year ended Year ended December 31, December 31, 2016 2015 2014 2016 2015 2014 Revenue $ $ $ $ $ $ Expenses Net earnings from continuing operations $ $ $ $ $ $

OTHER ASSETS, NET

OTHER ASSETS, NET	12 Months Ended
	Dec. 31, 2016
OTHER ASSETS, NET
OTHER ASSETS, NET	(9) OTHER ASSETS, NET Other assets, net are as follows (in thousands): December 31, December 31, 2016 2015 Amounts due under long-term terminaling services agreements: External customers $ $ Affiliates — Deferred financing costs, net of accumulated amortization of $4,763 and $3,945, respectively Customer relationships, net of accumulated amortization of $2,092 and $1,890, respectively Unrealized gain on derivative instruments — Deposits and other assets $ $ Amounts due under long‑term terminaling services agreements. We have long‑term terminaling services agreements with certain of our customers that provide for minimum payments that increase at stated amounts over the terms of the respective agreements. We recognize as revenue the minimum payments under the long‑term terminaling services agreements on a straight‑line basis over the terms of the respective agreements. At December 31, 2016 and 2015, we have recognized revenue in excess of the minimum payments that are due through those respective dates under the long‑term terminaling services agreements resulting in an asset of approximately $0.7 million and $0.6 million, respectively. Deferred financing costs. Deferred financing costs are amortized using the effective interest method over the term of the related credit facility. 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. Expected future amortization expense for the customer relationships as of December 31, 2016 is as follows (in thousands): Years ending December 31, 2017 2018 2019 2020 2021 Thereafter Amortization expense $ $ $ — $ — $ — $ —

ACCRUED LIABILITIES

ACCRUED LIABILITIES	12 Months Ended
	Dec. 31, 2016
ACCRUED LIABILITIES
ACCRUED LIABILITIES	(10) ACCRUED LIABILITIES Accrued liabilities are as follows (in thousands): December 31, December 31, 2016 2015 Customer advances and deposits: External customers $ $ Affiliates Accrued property taxes Accrued environmental obligations Interest payable Accrued expenses and other $ $ Customer advances and deposits. We bill certain of our customers one month in advance for terminaling services to be provided in the following month. At December 31, 2016 and 2015, we have billed and collected from certain of our customers approximately $8.7 million and $7.3 million, respectively, in advance of the terminaling services being provided. Accrued environmental obligations. At December 31, 2016 and 2015, we have accrued environmental obligations of approximately $2.1 million and $1.0 million, respectively, representing our best estimate of our remediation obligations. Changes in our estimates of our future environmental remediation obligations may occur as a result of the passage of time and the occurrence of future events. The following table presents a rollforward of our accrued environmental obligations (in thousands): Balance at Balance at beginning Increase end of of period Payments in estimate period 2016 $ $ $ $ 2015 $ $ $ $ 2014 $ $ $ $

OTHER LIABILITIES

OTHER LIABILITIES	12 Months Ended
	Dec. 31, 2016
OTHER LIABILITIES
OTHER LIABILITIES	(11) OTHER LIABILITIES Other liabilities are as follows (in thousands): December 31, December 31, 2016 2015 Advance payments received under long-term terminaling services agreements $ $ Deferred revenue—ethanol blending fees and other projects $ $ Advance payments received under long‑term terminaling services agreements. We have long‑term terminaling services agreements with certain of our customers that provide for advance minimum payments. We recognize the advance minimum payments as revenue either on a straight‑line basis over the term of the respective agreements or when services have been provided based on volumes of product distributed. At December 31, 2016 and 2015, we have received advance minimum payments in excess of revenue recognized under these long‑term terminaling services agreements resulting in a liability of approximately $1.0 million and $0.6 million, respectively. Deferred revenue—ethanol blending fees and other projects. Pursuant to historical agreements with our customers, we agreed to undertake certain capital projects that primarily pertain to providing ethanol blending functionality at certain of our Southeast terminals. Upon completion of the projects, our customers have paid us lump‑sum amounts that will be recognized as revenue on a straight‑line basis over the remaining term of the agreements. At December 31, 2016 and 2015, we have unamortized deferred revenue of approximately $2.2 million and $2.2 million, respectively, for completed projects. During the years ended December 31, 2016, 2015 and 2014, we billed our customers approximately $0.5 million, $nil and $0.1 million, respectively, for completed projects. During the years ended December 31, 2016, 2015 and 2014, we recognized revenue on a straight‑line basis of approximately $0.5 million, $1.3 million and $2.4 million, respectively, for completed projects.

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2016
LONG-TERM DEBT
LONG-TERM DEBT	(12) LONG‑TERM DEBT Our senior secured credit facility, or the “credit facility”, that provided for a maximum borrowing line of credit equal to $400 million at December 31, 2016. The terms of the credit facility include covenants that restrict our ability to make cash distributions, acquisitions and investments, including investments in joint ventures. We may make distributions of cash to the extent of our “available cash” as defined in our partnership agreement. We may make acquisitions and investments that meet the definition of “permitted acquisitions”; “other investments” which may not exceed 5% of “consolidated net tangible assets”; and additional future “permitted JV investments” up to $125 million, which may include additional investments in BOSTCO. The principal balance of loans and any accrued and unpaid interest as of December 31, 2016 were due and payable in full on the then maturity date of, July 31, 2018. As of December 31, 2016 we had the option 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. For the years ended December 31, 2016, 2015 and 2014, the weighted average interest rate on borrowings under the credit facility was approximately 3.1%, 2.7% and 2.6%, respectively. At December 31, 2016 and 2015, our outstanding borrowings under the credit facility were $291.8 million and $248.0 million, respectively. At December 31, 2016 and 2015, our outstanding letters of credit were $0.4 million and $nil, respectively. Subsequent to December 31, 2016, we upsized and extended the credit facility (see Note 20 of Notes to consolidated financial statements). We have an effective universal shelf‑registration statement and prospectus on Form S‑3 with the SEC that expires in September 2019. TLP Finance Corp., our 100% owned subsidiary, may act as a co‑issuer of any debt securities issued pursuant to that registration statement. TransMontaigne Partners L.P. has no independent assets or operations. TLP Finance Corp. has no assets or operations. Our operations are conducted by subsidiaries of TransMontaigne Partners L.P. through our 100% owned operating company subsidiary, TransMontaigne Operating Company L.P. Each of TransMontaigne Operating Company L.P.s’ and our other 100% owned subsidiaries (other than TLP Finance Corp., whose sole purpose is to act as co‑issuer of any debt securities) may guarantee 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 TransMontaigne Partners L.P. or any guarantor to obtain funds from its subsidiaries by dividend or loan. None of the assets of TransMontaigne Partners L.P. or a guarantor represent restricted net assets pursuant to the guidelines established by the SEC.

PARTNERS' EQUITY

PARTNERS' EQUITY	12 Months Ended
	Dec. 31, 2016
PARTNERS' EQUITY
PARTNERS' EQUITY	(13) PARTNERS’ EQUITY The number of units outstanding is as follows: General Common partner units equivalent units Units outstanding at December 31, 2014 and 2015 Issuance of common units by our long-term incentive plan — Issuance of common units by our savings and retention program — TransMontaigne GP to maintain its 2% general partner interest — Units outstanding at December 31, 2016 TransMontaigne GP had historically acquired outstanding common units on the open market under a purchase program for purposes of delivering vested units to the independent directors of our general partner on behalf of TransMontaigne Services LLC’s long‑term incentive plan. The purchase program concluded with its final purchase of 667 units on the program’s scheduled termination date of April 1, 2015. Beginning in 2016, grants of restricted phantom units under the TLP Management Services long-term incentive plan are to be settled by us through the issuance of common units pursuant to our registration statement on Form S-8. At December 31, 2016 and 2015, common units outstanding include nil and 8,018 common units, respectively, held on behalf of TransMontaigne Services LLC’s long‑term incentive plan. In connection with the ArcLight acquisition of our general partner, effective February 1, 2016, 15,750 restricted phantom units previously granted to the independent directors vested and were satisfied via the delivery of 8,018 existing common units and issuance of 7,732 new units. On October 21, 2016 we issued an additional 3,258 common units to our independent directors for a total of 19,008 common units delivered to the independent directors for the year ended December 31, 2016.

EQUITY BASED COMPENSATION

EQUITY BASED COMPENSATION	12 Months Ended
	Dec. 31, 2016
EQUITY BASED COMPENSATION
EQUITY BASED COMPENSATION	(14) EQUITY BASED COMPENSATION TransMontaigne GP is our general partner and manages our operations and activities. Prior to February 1, 2016, TransMontaigne GP was a wholly owned subsidiary of TransMontaigne LLC, which is a wholly owned subsidiary of NGL. TransMontaigne Services LLC, which is a wholly owned subsidiary of TransMontaigne LLC, had a long‑term incentive plan and a savings and retention program to compensate through incentive bonus awards certain employees and independent directors of our general partner who provided services with respect to the business of our general partner. Long-term incentive plan. On February 26, 2016, the board of our general partner approved, subject to the approval of our common unitholders, the TLP Management Services 2016 long-term incentive plan and the TLP Management Services savings and retention program (discussed further below) which constitutes a program under, and is subject to, the TLP Management Services long-term incentive plan, which replaced the TransMontaigne Services LLC long-term incentive plan and the TransMontaigne Services LLC savings and retention program. TLP Management Services is a wholly owned indirect subsidiary of ArcLight and employs all the officers and employees who provide services to our partnership and such entity provides payroll and maintains all employee benefits programs on behalf of our partnership. On July 12, 2016, we held a special meeting of our common unitholders at which time the TLP Management Services long-term incentive plan and savings and retention program were approved by the partnership’s unitholders. The TLP Management Services long-term incentive plan operates in a manner similar to the TransMontaigne Services LLC long-term incentive plan used previously. The TLP Management Services long-term incentive plan reserves 750,000 common units to be granted as awards under the plan, with such amount subject to adjustment as provided for under the terms of the plan if there is a change in our common units, such as a unit split or other reorganization. The common units authorized to be granted under the TLP Management Services long-term incentive plan are registered pursuant to a registration statement on Form S-8. The TLP Management Services long‑term incentive plan is administered by the compensation committee of the board of directors of our general partner and is used for grants of units to the independent directors of our general partner. The grants to the independent directors of our general partner under the TransMontaigne Services LLC long-term incentive plan had historically vested and were payable annually in equal tranches over a four-year period, subject to accelerated vesting upon a change in control of TransMontaigne GP. Ownership in the awards was subject to forfeiture until the vesting date, but recipients had distribution and voting rights from the date of the grant. The grants to the independent directors of our general partner under the TLP Management Services long-term incentive plan are immediately vested and not subject to forfeiture. Activity under the long-term incentive plan is as follows: Restricted NYSE phantom closing units price Restricted phantom units outstanding at January 1, 2014 Grant on March 31, 2014 $ Vesting on March 31, 2014 $ Vesting on July 1, 2014 $ Grant on September 30, 2014 $ Restricted phantom units outstanding at December 31, 2014 Vesting on September 30, 2015 $ Grant on October 14, 2015 $ Restricted phantom units outstanding at December 31, 2015 Vesting on February 1, 2016 $ Grant on October 21, 2016 $ Vesting on October 21, 2016 $ Restricted phantom units outstanding at December 31, 2016 — Generally accepted accounting principles require us to measure the cost of board member services received in exchange for an award of equity instruments based on the grant‑date fair value of the award. That cost is recognized over the vesting period on a straight line basis during which a board member is required to provide services in exchange for the award with the costs being accelerated upon the occurrence of accelerated vesting events, such as a change in control of our general partner. In connection with the ArcLight acquisition of our general partner, effective February 1, 2016, 15,750 restricted phantom units previously granted to the independent directors vested and were satisfied via the delivery of our common units. On October 21, 2016, we granted and issued an additional 3,258 common units to our independent directors under the TLP Management Services long‑term incentive plan. In connection with Morgan Stanley’s sale of its 100% ownership interest in TransMontaigne LLC to NGL, effective July 1, 2014, all 15,000 of the then outstanding restricted phantom units vested, and equivalent common units were delivered to the independent directors of our general partner at that time. As of July 1, 2014, we recognized in general and administrative expenses the remaining grant date fair value pertaining to these 15,000 restricted phantom units, of approximately $0.6 million, as equity‑based compensation because the requisite service period for these restricted phantom units had been completed upon the change in control. For awards to the independent directors of our general partner, equity‑based compensation expense of approximately $722,000, $108,000 and $721,000 is included in general and administrative expenses for the years ended December 31, 2016, 2015 and 2014, respectively. Savings and retention program. On February 26, 2016, the board of our general partner unanimously approved the new TLP Management Services savings and retention program , subject to the approval of our common unitholders, for employees who provide services with respect to our business . This plan is intended to constitute a program under, and be subject to, the TLP Management Services 2016 long-term incentive plan described above. The new savings and retention program was used for incentive bonus awards in March 2016 and is intended to be used for future awards to employees of TLP Management Services who provide services to the partnership. The new savings and retention program operates in a manner substantially similar to the TransMontaigne Services LLC savings and retention plan used previously. The restricted phantom units awarded and accrued under the savings and retention program are subject to forfeiture until the vesting date. Recipients have distribution equivalent rights from the date of grant that accrue additional restricted phantom units equivalent to the value of quarterly distributions paid by us on each of our outstanding common units. Recipients of restricted phantom units under the savings and retention program do not have voting rights. The purpose of the savings and retention program is to provide for the reward and retention of participants by providing them with bonus awards that vest over future service periods. Awards under the program generally become vested as to 50% of a participant’s annual award as of the first day of the month that falls closest to the second anniversary of the grant date, and the remaining 50% as of the first day of the month that falls closest to the third anniversary of the grant date, subject to earlier vesting upon a participant’s attainment of the age and length of service thresholds, retirement, death or disability, involuntary termination without cause, or termination of a participant’s employment following a change in control of the partnership, our general partner or TLP Management Services, as specified in the program. A person will satisfy the age and length of service thresholds of the program upon the attainment of the earliest of (a) age sixty, (b) age fifty five and ten years of service as an officer of TLP Management Services or any of its affiliates or predecessors, or (c) age fifty and twenty years of service as an employee of TLP Management Services or any of its affiliates or predecessors. Effective April 13, 2015 and beginning with the 2015 incentive bonus award and continuing under the new savings and retention program, under the omnibus agreement we have the option to provide the reimbursement in either a cash payment or the delivery of our common units to the savings and retention program or alternatively directly to the award recipients, with the reimbursement made in accordance with the underlying vesting and payment schedule of the savings and retention program. Our reimbursement for the 2015 and 2016 incentive bonus awards is reduced for forfeitures and is increased for the value of quarterly distributions accrued under the distribution equivalent rights. We have the intent and ability to settle our reimbursement for the 2015 and 2016 incentive bonus awards in our common units, and accordingly, effective April 13, 2015, we began accounting for the incentive bonus awards as an equity award. Prior to the 2015 incentive bonus award, we reimbursed our portion of the incentive bonus awards through monthly cash payments to the savings and retention program over the first year that each applicable award was granted. For certain senior level employees, including the executive officers of our general partner, all prior grants under the TransMontaigne Services LLC savings and retention program vested upon the change in control of our general partner as a result of the ArcLight acquisition that occurred on February 1, 2016. Given that we do not have any employees to provide corporate and support services and instead we contract for such services under the omnibus agreement, generally accepted accounting principles require us to classify the savings and retention program awards as a non-employee award and measure the cost of services received in exchange for an award of equity instruments based on the vesting‑date fair value of the award. That cost, or an estimate of that cost in the case of unvested restricted phantom units, is recognized over the period during which services are provided in exchange for the award. For the years ended December 31, 2016, 2015 and 2014, the expenses associated with the reimbursement of incentive bonus awards were approximately $2.5 million, $1.3 million and $1.5 million respectively. Activity related to our equity based awards granted under the savings and retention program for services performed under the omnibus agreement is as follows: Weighted Weighted average average Vested price Unvested price Restricted phantom units outstanding at December 31, 2015 $ $ Vesting of units $ $ Unit accrual for distributions paid $ $ Grant of units $ $ Issuance of units $ — $ — Restricted phantom units outstanding at December 31, 2016 $ $ Vested and expected to vest at December 31, 2016 $

NET EARNINGS PER LIMITED PARTNE

NET EARNINGS PER LIMITED PARTNER UNIT	12 Months Ended
	Dec. 31, 2016
NET EARNINGS PER LIMITED PARTNER UNIT
NET EARNINGS PER LIMITED PARTNER UNIT	(15) NET EARNINGS PER LIMITED PARTNER UNIT The following table reconciles net earnings to earnings allocable to limited partners and sets forth the computation of basic and diluted net earnings per limited partner unit (in thousands): Year ended Year ended Year ended December 31, December 31, December 31, 2016 2015 2014 Net earnings $ $ $ Less: Distributions payable on behalf of incentive distribution rights Distributions payable on behalf of general partner interest Earnings allocable to general partner interest less than distributions payable to general partner interest Earnings allocable to general partner interest including incentive distribution rights Net earnings allocable to limited partners per the consolidated statements of income Less distributions payable for unvested long-term incentive plan grants — Net earnings allocable to limited partners for calculating net earnings per limited partner unit $ $ $ Basic weighted average units Diluted weighted average units Net earnings per limited partner unit—basic $ $ $ Net earnings per limited partner unit—diluted $ $ $ Pursuant to our partnership agreement we are required to distribute available cash (as defined by our partnership agreement) as of the end of the reporting period. Such distributions are declared within 45 days after the end of each quarter. The following table sets forth the distribution declared per common unit attributable to the periods indicated: Distribution January 1, 2014 through March 31, 2014 $ April 1, 2014 through June 30, 2014 $ July 1, 2014 through September 30, 2014 $ October 1, 2014 through December 31, 2014 $ January 1, 2015 through March 31, 2015 $ April 1, 2015 through June 30, 2015 $ July 1, 2015 through September 30, 2015 $ October 1, 2015 through December 31, 2015 $ January 1, 2016 through March 31, 2016 $ April 1, 2016 through June 30, 2016 $ July 1, 2016 through September 30, 2016 $ October 1, 2016 through December 31, 2016 $

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2016
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES	(16) COMMITMENTS AND CONTINGENCIES Contract commitments. At December 31, 2016, we have contractual commitments of approximately $16.0 million for the supply of services, labor and materials related to capital projects that currently are under development. We expect that these contractual commitments will be paid during the year ending December 31, 2017. Operating leases. We lease property and equipment under non‑cancelable operating leases that extend through August 2030. At December 31, 2016, future minimum lease payments under these non‑cancelable operating leases are as follows (in thousands): Years ending December 31: 2017 $ 2018 2019 2020 2021 Thereafter $ 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 $2.7 million in future periods. Rental expense under operating leases was approximately $3.4 million, $3.5 million and $3.5 million for the years ended December 31, 2016, 2015 and 2014, respectively. Legal proceedings. We are party to various legal, regulatory and other matters arising from the day-to-day operations of our business that may result in claims against us. While the ultimate impact of any proceedings cannot be predicted with certainty, our management believes that the resolution of any of our pending legal proceedings will not have a material adverse effect on our business, financial position, results of operations or cash flows. The King Ranch natural-gas-processing plant in Kleberg County, Texas owned and operated by a third party, was shut down as a result of a fire at the plant beginning in November 2013. This plant supplies a significant amount of liquefied petroleum gas, or “LPG,” to our third-party customer, Nieto Trading, B.V. (“Nieto”), which transports LPG through our Ella Brownsville and Diamondback pipelines, and has contracted for the LPG storage capacity at our Brownsville terminals. The King Ranch plant became operational again in late November 2014. Nieto claimed that the fire at the King Ranch plant constituted a force majeure event that relieved Nieto of its obligation to pay certain fees required under the related terminaling services agreement for failure to throughput a minimum number of barrels of LPG (“deficiency fees”). We did not believe that the King Ranch fire qualified as a force majeure event under the terminaling services agreement, or that, even if it did, it relieved Nieto of its obligation to pay the deficiency fees. In September, 2014, we filed a complaint for damages and declaratory relief in the Supreme Court of the State of New York, County of New York, against Nieto, by which we sought damages and a declaratory judgment clarifying our rights to receive the deficiency fees under the terminaling services agreement. In February 2016 we entered into a settlement agreement and mutual release with Nieto that included a one-time settlement payment to us and an increase in the throughput fee under the terminaling services agreement for the remaining term. In connection therewith, the litigation was dismissed with prejudice.

DISCLOSURES ABOUT FAIR VALUE

DISCLOSURES ABOUT FAIR VALUE	12 Months Ended
	Dec. 31, 2016
DISCLOSURES ABOUT FAIR VALUE
DISCLOSURES ABOUT FAIR VALUE	(17) DISCLOSURES ABOUT FAIR VALUE “GAAP” defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. GAAP also establishes a fair value hierarchy that prioritizes the use of higher‑level inputs for valuation techniques used to measure fair value. The three levels of the fair value hierarchy are: (1) Level 1 inputs, which are quoted prices (unadjusted) in active markets for identical assets or liabilities; (2) Level 2 inputs, which are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly; and (3) Level 3 inputs, which are unobservable inputs for the asset or liability. The fair values of the following financial instruments represent our best estimate of the amounts that would be received to sell those assets or that would be paid to transfer those liabilities in an orderly transaction between market participants at that date. Our fair value measurements maximize the use of observable inputs. However, in situations where there is little, if any, market activity for the asset or liability at the measurement date, the fair value measurement reflects our judgments about the assumptions that market participants would use in pricing the asset or liability based on the best information available in the circumstances. The following methods and assumptions were used to estimate the fair value of financial instruments at December 31, 2016 and 2015. Cash and cash equivalents. The carrying amount approximates fair value because of the short‑term maturity of these instruments. The fair value is categorized in Level 1 of the fair value hierarchy. Derivative instruments. The carrying amount of our interest rate swaps as of December 31, 2016 and 2015 was determined using a pricing model based on the LIBOR swap rate and other observable market data. The fair value is categorized in Level 2 of the fair value hierarchy. 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.

BUSINESS SEGMENTS

BUSINESS SEGMENTS	12 Months Ended
	Dec. 31, 2016
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): Year ended Year ended Year ended December 31, December 31, December 31, 2016 2015 2014 Gulf Coast Terminals: Terminaling services fees $ $ $ Other Revenue Direct operating costs and expenses Net margins Midwest Terminals and Pipeline System: Terminaling services fees Pipeline transportation fees Other Revenue Direct operating costs and expenses Net margins Brownsville Terminals: Terminaling services fees Pipeline transportation fees Other Revenue Direct operating costs and expenses Net margins River Terminals: Terminaling services fees Other Revenue Direct operating costs and expenses Net margins Southeast Terminals: Terminaling services fees Other Revenue Direct operating costs and expenses Net margins Total net margins General and administrative expenses Insurance expenses Reimbursement of bonus awards expense Depreciation and amortization Earnings from unconsolidated affiliates Operating income Other expenses Net earnings $ $ $ Supplemental information about our business segments is summarized below (in thousands): Year ended December 31, 2016 Midwest Terminals and Gulf Coast Pipeline Brownsville River Southeast Terminals System Terminals Terminals Terminals Total Revenue: External customers $ $ $ $ $ $ NGL Energy Partners LP — — — Frontera — — — — Revenue $ $ $ $ $ $ Capital expenditures $ $ $ $ $ $ Identifiable assets $ $ $ $ $ $ Cash and cash equivalents Investments in unconsolidated affiliates Deferred financing costs Other Total assets $ Year ended December 31, 2015 Midwest Terminals and Gulf Coast Pipeline Brownsville River Southeast Terminals System Terminals Terminals Terminals Total Revenue: External customers $ $ $ $ $ $ NGL Energy Partners LP — Frontera — — — — Revenue $ $ $ $ $ $ Capital expenditures $ $ $ $ $ $ Identifiable assets $ $ $ $ $ $ Cash and cash equivalents Investments in unconsolidated affiliates Deferred financing costs Other Total assets $ Year ended December 31, 2014 Midwest Terminals and Gulf Coast Pipeline Brownsville River Southeast Terminals System Terminals Terminals Terminals Total Revenue: External customers $ $ $ $ $ $ NGL Energy Partners LP — Morgan Stanley Capital Group — Frontera — — — — Revenue $ $ $ $ $ $ Capital expenditures $ $ $ $ $ $ Identifiable assets $ $ $ $ $ $

FINANCIAL RESULTS BY QUARTER (U

FINANCIAL RESULTS BY QUARTER (UNAUDITED)	12 Months Ended
	Dec. 31, 2016
FINANCIAL RESULTS BY QUARTER (UNAUDITED)
FINANCIAL RESULTS BY QUARTER (UNAUDITED)	(19) FINANCIAL RESULTS BY QUARTER (UNAUDITED) Three months ended Year ended March 31, June 30, September 30, December 31, December 31, 2016 2016 2016 2016 2016 (in thousands except per unit amounts) Revenue $ $ $ $ $ Direct operating costs and expenses General and administrative expenses Insurance expenses Reimbursement of bonus awards Depreciation and amortization Earnings from unconsolidated affiliates Operating income Other expenses Net earnings $ $ $ $ $ Net earnings per limited partner unit—basic and diluted $ $ $ $ $ Three months ended Year ended March 31, June 30, September 30, December 31, December 31, 2015 2015 2015 2015 2015 (in thousands except per unit amounts) Revenue $ $ $ $ $ Direct operating costs and expenses General and administrative expenses Insurance expenses Reimbursement of bonus awards Depreciation and amortization Earnings from unconsolidated affiliates Operating income Other expenses Net earnings $ $ $ $ $ Net earnings per limited partner unit—basic and diluted $ $ $ $ $

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	12 Months Ended
	Dec. 31, 2016
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS	(20) SUBSEQUENT EVENTS On January 16, 2017, we announced a distribution of $0.71 per unit for the period from October 1, 2016 through December 31, 2016, and we paid the distribution on February 8, 2017 to unitholders of record on January 31, 2017. On March 13 2017, we amended our credit facility to extend the maturity date to March 31, 2022 and increase the maximum borrowing line of credit from $400 million to $600 million, and allow for up to $175 million in additional future “permitted JV investments”, which may include additional investments in BOSTCO. The amendment allows for, at our request, the maximum borrowing line of credit to be increased by an additional $250 million, subject to the approval of the administrative agent and the receipt of additional commitments from one or more lenders. We may elect to have loans under the credit facility bear interest either (i) at a rate of LIBOR plus a margin, or (ii) at the base rate plus a margin. The amendment decreased the rate of LIBOR plus a margin from a range of 2% to 3% to 1.75% to 2.75% depending on the total leverage ratio then in effect and decreased the base rate plus a margin from 1% to 2% to 0.75% to 1.75% depending on the total leverage ratio then in effect.

SUMMARY OF SIGNIFICANT ACCOUN28

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2016
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of business	(a) Nature of business TransMontaigne Partners L.P. (“we,” “us,” “our,” “the Partnership”) was formed in February 2005 as a Delaware limited partnership. We provide integrated terminaling, storage, transportation and related services for companies engaged in the trading, distribution and marketing of light refined petroleum products, heavy refined petroleum products, crude oil, chemicals, fertilizers and other liquid products. We conduct our operations in the United States along the Gulf Coast, in the Midwest, in Houston and Brownsville, Texas, along the Mississippi and Ohio rivers, and in the Southeast. We are controlled by our general partner, TransMontaigne GP (“TransMontaigne GP”), which as of February 1, 2016 is a wholly‑owned indirect subsidiary of ArcLight Energy Partners Fund VI, L.P. (“ArcLight”). Prior to February 1, 2016, TransMontaigne LLC, a wholly-owned subsidiary of NGL Energy Partners LP (“NGL”), owned all the issued and outstanding ownership interests of TransMontaigne GP. Prior to July 1, 2014, Morgan Stanley Capital Group Inc. (“Morgan Stanley Capital Group”), a wholly‑owned subsidiary of Morgan Stanley and the principal commodities trading arm of Morgan Stanley, owned all of the issued and outstanding capital stock of TransMontaigne LLC, and, as a result, Morgan Stanley was the indirect owner of our general partner. Effective July 1, 2014, Morgan Stanley consummated the sale of its 100% ownership interest in TransMontaigne LLC to NGL. In addition to the sale of our general partner to NGL, NGL assumed Morgan Stanley Capital Group’s obligations under our light-oil terminaling services agreements in Florida and the Southeast regions, excluding the Collins/Purvis, Mississippi bulk storage terminals, which we refer to collectively as the “NGL acquisition”. Terminaling services agreements for our Collins/Purvis, Mississippi bulk storage and Cushing, Oklahoma terminals remained with Morgan Stanley Capital Group until October 30, 2015, at which time Morgan Stanley sold its global physical oil merchanting business to Castleton Commodities International LLC and Morgan Stanley Capital Group, with our consent, assigned its terminaling services agreements with us to Castleton Commodities International LLC.
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 generally accepted in the United States of America (“GAAP”). The accompanying consolidated financial statements include the accounts of TransMontaigne Partners L.P., a Delaware limited partnership, and its controlled subsidiaries. Investments where we do not have the ability to exercise control, but do have the ability to exercise significant influence, are accounted for using the equity method of accounting. All inter‑company accounts and transactions have been eliminated in the preparation of the accompanying consolidated financial statements. The preparation of financial statements in conformity with “GAAP” requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting periods. The following estimates, in management’s opinion, are subjective in nature, require the exercise of judgment, and/or involve complex analyses: useful lives of our plant and equipment and accrued environmental obligations. Changes in these estimates and assumptions will occur as a result of the passage of time and the occurrence of future events. Actual results could differ from these estimates.
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 from terminaling services fees, transportation fees, management fees and cost reimbursements, fees from other ancillary services and gains from the sale of refined products. Terminaling services revenue is recognized ratably over the term of the agreement for storage fees and minimum revenue commitments that are fixed at the inception of the agreement and when product is delivered to the customer for fees based on a rate per barrel of throughput; pipeline transportation revenue is recognized when the product has been delivered to the customer at the specified delivery location; management fee revenue and cost reimbursements are recognized as the services are performed or as the costs are incurred; ancillary service revenue is recognized as the services are performed; and gains from the sale of refined products are recognized when the title to the product is transferred. Pursuant to terminaling services agreements with certain of our throughput customers, we are entitled to the volume of product gained resulting from differences in the measurement of product volumes received and distributed at our terminaling facilities. Consistent with recognized industry practices, measurement differentials occur as the result of the inherent variances in measurement devices and methodology. We recognize as revenue the net proceeds from the sale of the net product gained. For the years ended December 31, 2016, 2015 and 2014, we recognized revenue of approximately $6.7 million, $7.5 million and $13.1 million, respectively, for net product gained. Within these amounts, approximately $0.3 million, $2.9 million and $7.5 million, 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 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). In connection with our previous acquisitions of certain terminals from TransMontaigne LLC, TransMontaigne LLC has agreed to indemnify us against certain potential environmental claims, losses and expenses at those terminals (see Note 2 of Notes to consolidated financial statements).
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 asset subject to legal obligation is indeterminable and the amount of any associated costs are believed to be insignificant. Changes in our assumptions and estimates may occur as a result of the passage of time and the occurrence of future events.
Equity-based compensation	(i)  Equity based compensation Generally accepted accounting principles require us to measure the cost of services received in exchange for an award of equity instruments based on the measurement‑date fair value of the award. That cost is recognized during the period services are provided in exchange for the award.
Accounting for derivative instruments	(j) Accounting for derivative instruments Generally accepted accounting principles require us to recognize all derivative instruments at fair value in the consolidated balance sheets as assets or liabilities (see Note 9 of Notes to consolidated financial statements). Changes in the fair value of our derivative instruments are recognized in earnings. We did not have any derivative instruments at December 31, 2014. At December 31, 2016 and 2015, our derivative instruments were limited to interest rate swap agreements with an aggregate notional amount of $125.0 million and $75.0 million, respectively. Our derivative instruments at December 31, 2016 expire between March 25, 2018 and March 11, 2019. Pursuant to the terms of the interest rate swap agreements, we pay a blended fixed rate of approximately 1.01% and receive interest payments based on the one-month LIBOR. The net difference to be paid or received under the interest rate swap agreements is settled monthly and is recognized as an adjustment to interest expense. The fair value of our interest rate swap agreements are determined using a pricing model based on the LIBOR swap rate and other observable market data. At December 31, 2016 and 2015, the fair value of our interest rate swaps was approximately $0.3 million and $nil, respectively.
Income taxes	(k) Income taxes No provision for U.S. federal income taxes has been reflected in the accompanying consolidated financial statements because we are treated as a partnership for federal income tax purposes. As a partnership, all income, gains, losses, expenses, deductions and tax credits generated by us flow through to our unitholders.
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 calculated under the two-class method and accordingly are net of the earnings allocable to the general partner interest and distributions payable to any restricted phantom units granted under our equity based compensation plans that participate in our distributions. The earnings allocable to the general partner interest include the distributions of available cash (as defined by our partnership agreement) attributable to the period to the general partner interest, net of adjustments for the general partner’s share of undistributed earnings, and the incentive distribution rights. Undistributed earnings are the difference between the earnings and the distributions attributable to the period. Undistributed earnings are allocated to the limited partners and general partner interest based on their respective sharing of earnings or losses specified in the partnership agreement, which is based on their ownership percentages of 98% and 2%, respectively. The incentive distribution rights are not allocated a portion of the undistributed earnings given they are not entitled to distributions other than from available cash. Further, the incentive distribution rights do not share in losses under our partnership agreement. Basic net earnings per limited partner unit is computed by dividing net earnings allocable to the limited partners by the weighted average number of limited partner units outstanding during the period. Diluted net earnings per limited partner unit is computed by dividing net earnings allocable to the limited partners by the weighted average number of limited partner units outstanding during the period and any potential dilutive securities outstanding during the period.
Comprehensive Income	(m) Comprehensive Income Entities that report items of other comprehensive income have the option to present the components of net income and comprehensive income in either one continuous financial statement, or two consecutive financial statements. As the Company has no components of comprehensive income other than net income (loss), no statement of comprehensive income has been presented.
Recent accounting pronouncements	(n) Recent accounting pronouncements In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The objective of this update is to clarify the principles for recognizing revenue and to develop a common revenue standard. The core principle of the ASU is that an entity should recognize revenue for the transfer of goods or services equal to the amount that it expects to be entitled to receive for those goods or services. The ASU requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments. The ASU is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period and allows for both retrospective and modified retrospective methods of adoption. While we are currently evaluating the impact of ASU 2014-09 and all related ASU’s on a representative sample of individual customer contracts. Additionally, we are in the process of evaluating and designing the necessary changes to our business processes, systems and controls to support recognition and disclosure under the new standard. We are continuing our evaluation to determine the impact on our consolidated financial condition and results of operations. In February 2016, the FASB issued ASU 2016-02, Leases. The objective of this update is to improve financial reporting about leasing transactions. ASU 2016-02 is effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period. We are currently evaluating the potential impact that the adoption will have on our disclosures and financial statements. In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipt and Cash Payments, to add or clarify guidance on the classification of certain cash receipts and payments in the statement of cash flows. ASU 2016-15 is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. We are currently evaluating the potential impact that the adoption will have on our disclosures and financial statements. In January 2017, the FASB issued ASU 2017-04, Intangibles- Goodwill and Other: Simplifying the Test for Goodwill Impairment, to simplify the accounting for goodwill impairments by eliminating step 2 from the goodwill impairment test. ASU 2017-04 is effective for annual reporting periods beginning after December 15, 2019, including interim periods within that reporting period. We are currently evaluating the potential impact that the adoption will have on our disclosures and financial statements.

CONCENTRATION OF CREDIT RISK 29

CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE (Tables)	12 Months Ended
	Dec. 31, 2016
CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE
Schedule of trade accounts receivable, net (in thousands)	Trade accounts receivable, net consists of the following (in thousands): December 31, December 31, 2016 2015 Trade accounts receivable $ $ Less allowance for doubtful accounts $ $
Schedule of allowance for doubtful accounts rollforward (in thousands)	The following table presents a rollforward of our allowance for doubtful accounts (in thousands): Balance at Balance at beginning Charged to end of of period expenses Deductions period 2016 $ $ $ $ 2015 $ $ $ — $ 2014 $ $ $ — $
Schedule of customer who accounted for at least 10% of consolidated revenue	Year ended Year ended Year ended December 31, December 31, December 31, 2016 2015 2014 NGL Energy Partners LP % % % Castleton Commodities International LLC % — % — % RaceTrac Petroleum Inc. % % % Morgan Stanley Capital Group — % % %

OTHER CURRENT ASSETS (Tables)

OTHER CURRENT ASSETS (Tables)	12 Months Ended
	Dec. 31, 2016
OTHER CURRENT ASSETS
Schedule of other current assets (in thousands)	Other current assets are as follows (in thousands): December 31, December 31, 2016 2015 Amounts due from insurance companies $ $ Additive detergent Prepaid insurance — Deposits and other assets $ $

PROPERTY, PLANT AND EQUIPMENT31

PROPERTY, PLANT AND EQUIPMENT, NET (Tables)	12 Months Ended
	Dec. 31, 2016
PROPERTY, PLANT AND EQUIPMENT, NET
Schedule of property, plant and equipment, net (in thousands)	Property, plant and equipment, net is as follows (in thousands): December 31, December 31, 2016 2015 Land $ $ Terminals, pipelines and equipment Furniture, fixtures and equipment Construction in progress Less accumulated depreciation $ $

GOODWILL (Tables)

GOODWILL (Tables)	12 Months Ended
	Dec. 31, 2016
GOODWILL.
Schedule of goodwill (in thousands)	Goodwill is as follows (in thousands): December 31, December 31, 2016 2015 Brownsville terminals $ $

INVESTMENTS IN UNCONSOLIDATED33

INVESTMENTS IN UNCONSOLIDATED AFFILIATES (Tables)	12 Months Ended
	Dec. 31, 2016
INVESTMENTS IN UNCONSOLIDATED AFFILIATES
Summary of investments in unconsolidated affiliates	Percentage of Carrying value ownership (in thousands) December 31, December 31, December 31, 2016 2015 2016 2015 BOSTCO % % $ $ Frontera % % Total investments in unconsolidated affiliates $ $
Schedule of earnings from investments in unconsolidated affiliates (in thousands)	Earnings from investments in unconsolidated affiliates were as follows (in thousands): Year ended Year ended Year ended December 31, December 31, December 31, 2016 2015 2014 BOSTCO $ $ $ Frontera Total earnings from investments in unconsolidated affiliates $ $ $
Schedule of additional capital investments in unconsolidated affiliates (in thousands)	Additional capital investments in unconsolidated affiliates were as follows (in thousands): Year ended Year ended Year ended December 31, December 31, December 31, 2016 2015 2014 BOSTCO $ $ $ Frontera Additional capital investments in unconsolidated affiliates $ $ $
Schedule of cash distributions received from unconsolidated affiliates (in thousands)	Cash distributions received from unconsolidated affiliates were as follows (in thousands): Year ended Year ended Year ended December 31, December 31, December 31, 2016 2015 2014 BOSTCO $ $ $ Frontera Cash distributions received from unconsolidated affiliates $ $ $
Summary of financial information of unconsolidated affiliates (in thousands)	The summarized financial information of our unconsolidated affiliates was as follows (in thousands): Balance sheets: BOSTCO Frontera December 31, December 31, December 31, December 31, 2016 2015 2016 2015 Current assets $ $ $ $ Long-term assets Current liabilities Long-term liabilities — — — Net assets $ $ $ $ Statements of income : BOSTCO Frontera Year ended Year ended December 31, December 31, 2016 2015 2014 2016 2015 2014 Revenue $ $ $ $ $ $ Expenses Net earnings from continuing operations $ $ $ $ $ $

OTHER ASSETS, NET (Tables)

OTHER ASSETS, NET (Tables)	12 Months Ended
	Dec. 31, 2016
OTHER ASSETS, NET
Schedule of other assets, net (in thousands)	Other assets, net are as follows (in thousands): December 31, December 31, 2016 2015 Amounts due under long-term terminaling services agreements: External customers $ $ Affiliates — Deferred financing costs, net of accumulated amortization of $4,763 and $3,945, respectively Customer relationships, net of accumulated amortization of $2,092 and $1,890, respectively Unrealized gain on derivative instruments — Deposits and other assets $ $
Schedule of expected amortization expense for customer relationships (in thousands)	Expected future amortization expense for the customer relationships as of December 31, 2016 is as follows (in thousands): Years ending December 31, 2017 2018 2019 2020 2021 Thereafter Amortization expense $ $ $ — $ — $ — $ —

ACCRUED LIABILITIES (Tables)

ACCRUED LIABILITIES (Tables)	12 Months Ended
	Dec. 31, 2016
ACCRUED LIABILITIES
Schedule of accrued liabilities (in thousands)	Accrued liabilities are as follows (in thousands): December 31, December 31, 2016 2015 Customer advances and deposits: External customers $ $ Affiliates Accrued property taxes Accrued environmental obligations Interest payable Accrued expenses and other $ $
Schedule of accrued environmental obligations (in thousands)	The following table presents a rollforward of our accrued environmental obligations (in thousands): Balance at Balance at beginning Increase end of of period Payments in estimate period 2016 $ $ $ $ 2015 $ $ $ $ 2014 $ $ $ $

OTHER LIABILITIES (Tables)

OTHER LIABILITIES (Tables)	12 Months Ended
	Dec. 31, 2016
OTHER LIABILITIES
Schedule of other liabilities (in thousands)	Other liabilities are as follows (in thousands): December 31, December 31, 2016 2015 Advance payments received under long-term terminaling services agreements $ $ Deferred revenue—ethanol blending fees and other projects $ $

PARTNERS' EQUITY (Tables)

PARTNERS' EQUITY (Tables)	12 Months Ended
	Dec. 31, 2016
PARTNERS' EQUITY
Schedule of number of units outstanding	General Common partner units equivalent units Units outstanding at December 31, 2014 and 2015 Issuance of common units by our long-term incentive plan — Issuance of common units by our savings and retention program — TransMontaigne GP to maintain its 2% general partner interest — Units outstanding at December 31, 2016

EQUITY BASED COMPENSATION (Tabl

EQUITY BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2016
Schedule of long-term incentive plan activity	Restricted NYSE phantom closing units price Restricted phantom units outstanding at January 1, 2014 Grant on March 31, 2014 $ Vesting on March 31, 2014 $ Vesting on July 1, 2014 $ Grant on September 30, 2014 $ Restricted phantom units outstanding at December 31, 2014 Vesting on September 30, 2015 $ Grant on October 14, 2015 $ Restricted phantom units outstanding at December 31, 2015 Vesting on February 1, 2016 $ Grant on October 21, 2016 $ Vesting on October 21, 2016 $ Restricted phantom units outstanding at December 31, 2016 —
TransMontaigne LLC-related party
Schedule of long-term incentive plan activity	Weighted Weighted average average Vested price Unvested price Restricted phantom units outstanding at December 31, 2015 $ $ Vesting of units $ $ Unit accrual for distributions paid $ $ Grant of units $ $ Issuance of units $ — $ — Restricted phantom units outstanding at December 31, 2016 $ $ Vested and expected to vest at December 31, 2016 $

NET EARNINGS PER LIMITED PART39

NET EARNINGS PER LIMITED PARTNER UNIT (Tables)	12 Months Ended
	Dec. 31, 2016
NET EARNINGS PER LIMITED PARTNER UNIT
Schedule of reconciliation of net earnings to net earnings allocable to limited partners (in thousands)	The following table reconciles net earnings to earnings allocable to limited partners and sets forth the computation of basic and diluted net earnings per limited partner unit (in thousands): Year ended Year ended Year ended December 31, December 31, December 31, 2016 2015 2014 Net earnings $ $ $ Less: Distributions payable on behalf of incentive distribution rights Distributions payable on behalf of general partner interest Earnings allocable to general partner interest less than distributions payable to general partner interest Earnings allocable to general partner interest including incentive distribution rights Net earnings allocable to limited partners per the consolidated statements of income Less distributions payable for unvested long-term incentive plan grants — Net earnings allocable to limited partners for calculating net earnings per limited partner unit $ $ $ Basic weighted average units Diluted weighted average units Net earnings per limited partner unit—basic $ $ $ Net earnings per limited partner unit—diluted $ $ $
Schedule of distribution declared per common unit attributable to the periods	Distribution January 1, 2014 through March 31, 2014 $ April 1, 2014 through June 30, 2014 $ July 1, 2014 through September 30, 2014 $ October 1, 2014 through December 31, 2014 $ January 1, 2015 through March 31, 2015 $ April 1, 2015 through June 30, 2015 $ July 1, 2015 through September 30, 2015 $ October 1, 2015 through December 31, 2015 $ January 1, 2016 through March 31, 2016 $ April 1, 2016 through June 30, 2016 $ July 1, 2016 through September 30, 2016 $ October 1, 2016 through December 31, 2016 $

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2016
COMMITMENTS AND CONTINGENCIES
Schedule of future minimum lease payments under non-cancelable operating leases (in thousands)	At December 31, 2016, future minimum lease payments under these non‑cancelable operating leases are as follows (in thousands): Years ending December 31: 2017 $ 2018 2019 2020 2021 Thereafter $

BUSINESS SEGMENTS (Tables)

BUSINESS SEGMENTS (Tables)	12 Months Ended
	Dec. 31, 2016
BUSINESS SEGMENTS
Schedule of information related to financial performance of business segments (in thousands)	The financial performance of our business segments is as follows (in thousands): Year ended Year ended Year ended December 31, December 31, December 31, 2016 2015 2014 Gulf Coast Terminals: Terminaling services fees $ $ $ Other Revenue Direct operating costs and expenses Net margins Midwest Terminals and Pipeline System: Terminaling services fees Pipeline transportation fees Other Revenue Direct operating costs and expenses Net margins Brownsville Terminals: Terminaling services fees Pipeline transportation fees Other Revenue Direct operating costs and expenses Net margins River Terminals: Terminaling services fees Other Revenue Direct operating costs and expenses Net margins Southeast Terminals: Terminaling services fees Other Revenue Direct operating costs and expenses Net margins Total net margins General and administrative expenses Insurance expenses Reimbursement of bonus awards expense Depreciation and amortization Earnings from unconsolidated affiliates Operating income Other expenses Net earnings $ $ $
Schedule of supplemental information about consolidated business segments (in thousands)	Supplemental information about our business segments is summarized below (in thousands): Year ended December 31, 2016 Midwest Terminals and Gulf Coast Pipeline Brownsville River Southeast Terminals System Terminals Terminals Terminals Total Revenue: External customers $ $ $ $ $ $ NGL Energy Partners LP — — — Frontera — — — — Revenue $ $ $ $ $ $ Capital expenditures $ $ $ $ $ $ Identifiable assets $ $ $ $ $ $ Cash and cash equivalents Investments in unconsolidated affiliates Deferred financing costs Other Total assets $ Year ended December 31, 2015 Midwest Terminals and Gulf Coast Pipeline Brownsville River Southeast Terminals System Terminals Terminals Terminals Total Revenue: External customers $ $ $ $ $ $ NGL Energy Partners LP — Frontera — — — — Revenue $ $ $ $ $ $ Capital expenditures $ $ $ $ $ $ Identifiable assets $ $ $ $ $ $ Cash and cash equivalents Investments in unconsolidated affiliates Deferred financing costs Other Total assets $ Year ended December 31, 2014 Midwest Terminals and Gulf Coast Pipeline Brownsville River Southeast Terminals System Terminals Terminals Terminals Total Revenue: External customers $ $ $ $ $ $ NGL Energy Partners LP — Morgan Stanley Capital Group — Frontera — — — — Revenue $ $ $ $ $ $ Capital expenditures $ $ $ $ $ $ Identifiable assets $ $ $ $ $ $

FINANCIAL RESULTS BY QUARTER 42

FINANCIAL RESULTS BY QUARTER (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2016
FINANCIAL RESULTS BY QUARTER (UNAUDITED)
Schedule of financial results by quarter	Three months ended Year ended March 31, June 30, September 30, December 31, December 31, 2016 2016 2016 2016 2016 (in thousands except per unit amounts) Revenue $ $ $ $ $ Direct operating costs and expenses General and administrative expenses Insurance expenses Reimbursement of bonus awards Depreciation and amortization Earnings from unconsolidated affiliates Operating income Other expenses Net earnings $ $ $ $ $ Net earnings per limited partner unit—basic and diluted $ $ $ $ $ Three months ended Year ended March 31, June 30, September 30, December 31, December 31, 2015 2015 2015 2015 2015 (in thousands except per unit amounts) Revenue $ $ $ $ $ Direct operating costs and expenses General and administrative expenses Insurance expenses Reimbursement of bonus awards Depreciation and amortization Earnings from unconsolidated affiliates Operating income Other expenses Net earnings $ $ $ $ $ Net earnings per limited partner unit—basic and diluted $ $ $ $ $

SUMMARY OF SIGNIFICANT ACCOUN43

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jul. 01, 2014
Revenue recognized from proceeds of sale of product gained	$ 6.7	$ 7.5	$ 13.1
Recognized revenue pursuant to terminaling services agreements with affiliate customers	$ 0.3	$ 2.9	$ 7.5
Morgan Stanley | NGL
Ownership interest sold (as a percent)				100.00%

SUMMARY OF SIGNIFICANT ACCOUN44

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Property (Details)	12 Months Ended
	Dec. 31, 2016
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

SUMMARY OF SIGNIFICANT ACCOUN45

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Taxes and Derivatives (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
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%
Interest rate swap
Accounting for derivative instruments
Notional amount	$ 125	$ 75
Fixed interest rate paid (as a percent)	1.01%
Derivative fair value	$ 0.3	$ 0

TRANSACTIONS WITH AFFILIATES (D

TRANSACTIONS WITH AFFILIATES (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Transactions with affiliates
Insurance expense paid	$ 1,305	$ 969	$ 912	$ 895	$ 944	$ 944	$ 934	$ 934	$ 4,081	$ 3,756	$ 3,711
Expense of insurance contracted with affiliates	3,374	3,605	3,446	4,398	3,607	3,952	3,474	3,824	14,823	14,857	14,662
Insurance expense									1,000	0	0
Reimbursement of bonus awards	$ 396	$ 251	$ 258	$ 1,635	$ 118	$ 121	$ 539	$ 525	2,540	1,303	1,500
TransMontaigne LLC-related party | Omnibus agreement
Transactions with affiliates
Administrative fee paid										11,300	11,100
Insurance expense paid										3,800	3,700
Reimbursement of bonus awards										$ 1,300	$ 1,500
Gulf TLP Holdings, LLC-related party | Omnibus agreement
Transactions with affiliates
Administrative fee paid									11,400
Insurance expense paid									3,100
Reimbursement of bonus awards									$ 2,500

TRANSACTIONS WITH AFFILIATES -

TRANSACTIONS WITH AFFILIATES - Agreements (Details)

Apr. 30, 2016bbl

Oct. 31, 2014bbl

Feb. 28, 2014

Sep. 30, 2016bbl

May 31, 2013USD ($)

Jul. 31, 2011bbl

Jan. 31, 2010bbl

Dec. 31, 2016USD ($)

Dec. 31, 2015USD ($)

Dec. 31, 2014USD ($)

Mar. 01, 2011USD ($)

Dec. 31, 2007USD ($)

Dec. 31, 2006USD ($)

May 27, 2005USD ($)

Transactions with affiliates

Throughput revenue

$ 8,418,000

$ 42,953,000

$ 74,153,000

Frontera

Transactions with affiliates

Throughput revenue

5,457,000

4,416,000

4,035,000

Environmental indemnification | TransMontaigne LLC-related party | Florida and Midwest terminals

Transactions with affiliates

Maximum liability for indemnification obligation

$ 15,000,000

Liability for indemnification obligation, if aggregate losses do not exceed specified amount

$ 250,000

Environmental indemnification | TransMontaigne LLC-related party | Brownsville, Texas and River terminals

Transactions with affiliates

Maximum liability for indemnification obligation

$ 15,000,000

Liability for indemnification obligation, if aggregate losses do not exceed specified amount

$ 250,000

Environmental indemnification | TransMontaigne LLC-related party | Southeast terminals

Transactions with affiliates

Maximum liability for indemnification obligation

$ 15,000,000

Liability for indemnification obligation, if aggregate losses do not exceed specified amount

$ 250,000

Environmental indemnification | TransMontaigne LLC-related party | Pensacola terminal

Transactions with affiliates

Maximum liability for indemnification obligation

$ 2,500,000

Liability for indemnification obligation, if aggregate losses do not exceed specified amount

$ 200,000

Terminaling services agreement-Florida and Midwest terminals | Florida and Midwest terminals

Transactions with affiliates

Percentage of capacity of Razorback terminals and the Razorback pipeline covered under the agreement

100.00%

Term of lease agreement

10 years

Terminaling services agreement-Florida and Midwest terminals | Florida and Midwest terminals | Minimum

Transactions with affiliates

Throughput revenue

800,000

5,000,000

21,000,000

Terminaling services agreement-Florida and Midwest terminals | NGL

Transactions with affiliates

Notice period for termination of service agreement

18 months

Storage capacity agreed to be provided (in barrels) | bbl

100,000

1,100,000

Terminaling services agreement-Cushing terminal | Morgan Stanley Capital Group

Transactions with affiliates

Notice period for termination of service agreement

180 days

Storage capacity agreed to be provided (in barrels) | bbl

1,000,000

Term of lease agreement

1 year

Automatic renewal period of service agreement

5 years

Terminaling services agreement-Cushing terminal | Morgan Stanley Capital Group | Minimum

Transactions with affiliates

Revenue per the agreement

4,300,000

Terminaling services agreement-Southeast terminals | NGL | Minimum

Transactions with affiliates

Throughput revenue

27,000,000

27,000,000

36,800,000

Terminaling services agreement-Collins/Purvis | Morgan Stanley Capital Group

Transactions with affiliates

Notice period for termination of service agreement

24 months

Storage capacity agreed to be provided (in barrels) | bbl

700,000

Term of lease agreement

1 year

Revenue per the agreement

4,100,000

Barge dock services agreement-Baton Rouge dock | Morgan Stanley Capital Group

Transactions with affiliates

Notice period for termination of service agreement

180 days

Automatic renewal period of service agreement

5 years

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

Terminaling services agreement-Brownsville LPG | Frontera | Brownsville terminals

Transactions with affiliates

Automatic renewal period of service agreement

2 years

Terminaling services agreement-Brownsville LLC | Frontera | Brownsville terminals

Transactions with affiliates

Notice period for termination of service agreement

180 days

Storage capacity agreed to be provided (in barrels) | bbl

151,000

Throughput revenue

500,000

0

0

Revenue per the agreement

1,300,000

Direct transfer agreement | Frontera | Brownsville terminals

Transactions with affiliates

Expense related to agreement

$ 200,000

400,000

700,000

Operations and reimbursement agreement-Frontera | Frontera

Transactions with affiliates

Ownership interest in joint venture (as a percent)

50.00%

Revenue recognized

$ 5,000,000

$ 4,400,000

$ 4,000,000

TERMINAL ACQUISITION FROM AFF48

TERMINAL ACQUISITION FROM AFFILIATE (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Jan. 28, 2016
Dispositions
Payment for acquisition of hydrant system from TransMontaigne LLC	$ 12,000
Remaining purchase price	$ 5,506
Port Everglades-hydrant system
Dispositions
Net book value		$ 6,500

CONCENTRATION OF CREDIT RISK 49

CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Concentration of credit risk and trade accounts receivable
Trade accounts receivable	$ 9,416	$ 6,448
Less allowance for doubtful accounts	(119)	(475)
Trade accounts receivable, net	9,297	5,973
Changes in allowance for doubtful accounts during the period
Balance at beginning of period	475	464	$ 100
Charged to expenses	298	11	364
Deductions	(654)
Balance at end of period	$ 119	$ 475	$ 464
NGL Energy Partners LP
Concentration of credit risk and trade accounts receivable
Percentage of total revenue generated by major customer	23.00%	25.00%	16.00%
Castleton Commodities International LLC
Concentration of credit risk and trade accounts receivable
Percentage of total revenue generated by major customer	14.00%
RaceTrac Petroleum Inc
Concentration of credit risk and trade accounts receivable
Percentage of total revenue generated by major customer	12.00%	11.00%	7.00%
Morgan Stanley Capital Group
Concentration of credit risk and trade accounts receivable
Percentage of total revenue generated by major customer		10.00%	37.00%

OTHER CURRENT ASSETS (Details)

OTHER CURRENT ASSETS (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
OTHER CURRENT ASSETS
Amounts due from insurance companies	$ 1,810	$ 774
Additive detergent	1,364	1,411
Prepaid insurance	4,684
Deposits and other assets	2,045	225
Other current assets	9,903	$ 2,410
Reimbursements from insurance companies	500
Increase in estimated insurance recovery	$ 1,500

PROPERTY, PLANT AND EQUIPMENT51

PROPERTY, PLANT AND EQUIPMENT, NET (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Property, plant and equipment, net
Property, plant and equipment, gross	$ 720,677	$ 660,331
Less accumulated depreciation	(303,929)	(271,908)
Property, plant and equipment, net	416,748	388,423
Land
Property, plant and equipment, net
Property, plant and equipment, gross	53,079	53,079
Terminals, pipelines and equipment
Property, plant and equipment, net
Property, plant and equipment, gross	651,783	595,883
Furniture, fixtures and equipment
Property, plant and equipment, net
Property, plant and equipment, gross	4,100	2,665
Construction in progress
Property, plant and equipment, net
Property, plant and equipment, gross	$ 11,715	$ 8,704

GOODWILL (Details)

GOODWILL (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Goodwill
Goodwill	$ 8,485	$ 8,485
Brownsville terminals
Goodwill
Goodwill	$ 8,485	$ 8,485

INVESTMENTS IN UNCONSOLIDATED53

INVESTMENTS IN UNCONSOLIDATED AFFILIATES (Details) $ in Thousands, bbl in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016USD ($)	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2016USD ($)bbl	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
INVESTMENTS IN UNCONSOLIDATED AFFILIATES
Carrying value of investments in unconsolidated affiliates	$ 241,093				$ 246,700				$ 241,093	$ 246,700
Earnings from unconsolidated affiliates	$ 3,089	$ 2,960	$ 2,130	$ 1,850	$ 2,184	$ 2,191	$ 5,517	$ 2,056	10,029	11,948	$ 4,443
Additional capital investments in unconsolidated affiliates									2,225	4,726	43,681
Cash distributions received from unconsolidated affiliates									$ 17,861	$ 19,649	10,053
BOSTCO
INVESTMENTS IN UNCONSOLIDATED AFFILIATES
Storage capacity | bbl									7.1
Percentage of ownership	42.50%				42.50%				42.50%	42.50%
Carrying value of investments in unconsolidated affiliates	$ 217,941				$ 223,214				$ 217,941	$ 223,214
Excess investment	7,200				7,400				7,200	7,400
Earnings from unconsolidated affiliates									6,933	9,968	3,853
Additional capital investments in unconsolidated affiliates									2,125	4,226	43,635
Cash distributions received from unconsolidated affiliates									14,331	16,900	7,749
Balance sheets:
Current assets	23,237				21,079				23,237	21,079
Long-term assets	485,331				500,982				485,331	500,982
Current liabilities	(12,799)				(15,064)				(12,799)	(15,064)
Net assets	$ 495,769				$ 506,997				495,769	506,997
Statements of comprehensive income (loss):
Revenue									66,863	70,710	49,924
Expenses									(48,149)	(45,787)	(40,185)
Net earnings from continuing operations									$ 18,714	$ 24,923	9,739
Frontera
INVESTMENTS IN UNCONSOLIDATED AFFILIATES
Storage capacity | bbl									1.5
Percentage of ownership	50.00%				50.00%				50.00%	50.00%
Carrying value of investments in unconsolidated affiliates	$ 23,152				$ 23,486				$ 23,152	$ 23,486
Earnings from unconsolidated affiliates									3,096	1,980	590
Additional capital investments in unconsolidated affiliates									100	500	46
Cash distributions received from unconsolidated affiliates									3,530	2,749	2,304
Balance sheets:
Current assets	5,779				4,156				5,779	4,156
Long-term assets	41,966				44,194				41,966	44,194
Current liabilities	(1,172)				(1,376)				(1,172)	(1,376)
Long-term liabilities	(269)								(269)
Net assets	$ 46,304				$ 46,974				46,304	46,974
Statements of comprehensive income (loss):
Revenue									18,958	16,083	13,464
Expenses									(12,766)	(12,121)	(12,284)
Net earnings from continuing operations									$ 6,192	$ 3,962	$ 1,180
Class A Member Ownership Interest | BOSTCO
INVESTMENTS IN UNCONSOLIDATED AFFILIATES
Cash distributions, allocation percentage									96.50%
Class B Member Ownership Interest | BOSTCO
INVESTMENTS IN UNCONSOLIDATED AFFILIATES
Cash distributions, allocation percentage									3.50%

OTHER ASSETS, NET (Details)

OTHER ASSETS, NET (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Amounts due under long-term terminaling services agreements:
External customers	$ 656	$ 12
Affiliates		567
Amounts due under long-term terminaling services agreements	656	579
Deferred financing costs, net of accumulated amortization of $4,763 and $3,945, respectively	1,298	1,721
Customer relationships, net of accumulated amortization of $2,092 and $1,890, respectively	338	540
Unrealized gain on derivative instruments	344
Deposits and other assets	286	95
Other assets, net	2,922	2,935
Accumulated amortization of deferred financing costs	4,763	3,945
Accumulated amortization of customer relationships	$ 2,092	$ 1,890
Amortization period of customer relationships	12 years
Amortization expense for customer relationships
2,017	$ 202
2,018	$ 136

ACCRUED LIABILITIES (Details)

ACCRUED LIABILITIES (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Customer advances and deposits:
External customers	$ 8,602	$ 4,925
Affiliates	108	2,352
Customer advances and deposits	8,710	7,277
Accrued property taxes	1,061	1,019
Accrued environmental obligations	2,107	1,047
Interest payable	232	141
Accrued expenses and other	1,888	1,627
Accrued liabilities	$ 13,998	11,111
Period for billing of customers in advance for terminaling services	1 month
Accrued environmental obligations
Balance at beginning of period	$ 1,047	1,524	$ 1,966
Payments	(1,322)	(513)	(560)
Increase in estimate	2,382	36	118
Balance at end of period	$ 2,107	$ 1,047	$ 1,524

OTHER LIABILITIES (Details)

OTHER LIABILITIES (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
OTHER LIABILITIES
Advance payments received under long-term terminaling services agreements	$ 994	$ 580
Deferred revenue-ethanol blending fees and other projects	2,240	2,151
Other liabilities	3,234	2,731
Revenue billed	500	0	$ 100
Recognized revenue on a straight line basis for completed projects	$ 500	$ 1,300	$ 2,400

LONG-TERM DEBT (Details)

LONG-TERM DEBT (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
TLP Finance Corp
Long-term debt
Ownership interest in subsidiary (as a percent)	100.00%
TransMontaigne Operating Company L.P
Long-term debt
Ownership interest in subsidiary (as a percent)	100.00%
Maximum
Long-term debt
Other investments as a percentage of consolidated net tangible assets	5.00%
Permitted JV investments subject to liquidity	$ 125
Credit facility
Long-term debt
Maximum borrowing capacity	$ 400
Weighted average interest rate on borrowings (as a percent)	3.10%	2.70%	2.60%
Outstanding borrowings under credit facility	$ 291.8	$ 248
Outstanding borrowings under letters of credit	$ 0.4	$ 0
Credit facility | Minimum
Long-term debt
Commitment fee on unused amount of commitments (as a percent)	0.375%
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%
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%

PARTNERS' EQUITY (Details)

PARTNERS' EQUITY (Details) - shares	Oct. 21, 2016	Feb. 01, 2016	Oct. 14, 2015	Sep. 30, 2015	Sep. 30, 2014	Jul. 01, 2014	Mar. 31, 2014	Dec. 31, 2016	Dec. 31, 2015
Changes in number of units outstanding
Issuance of common units by our savings and retention program (in units)								2,094
Long-term incentive plan
Information related to public offering
Common units held on behalf of TransMontaigne Services LLC's long-term incentive plan								750,000
Restricted phantom units
Information related to public offering
Grant (in units)	3,258		9,000		9,000		6,000
Vesting (in units)	3,258	15,750		2,250		15,000	5,500
Common units
Changes in number of units outstanding
Units outstanding at the beginning of the period								16,124,566
Issuance of common units by our long-term incentive plan	3,258	7,732						10,990
Issuance of common units by our savings and retention program (in units)								2,094
TransMontaigne GP to maintain its 2% general partner interest								0
Units outstanding at the end of the period								16,137,650
Information related to public offering
Vesting (in units)								19,008
Common units | Long-term incentive plan
Information related to public offering
Common units held on behalf of TransMontaigne Services LLC's long-term incentive plan								0	8,018
General partner interest
Changes in number of units outstanding
Units outstanding at the beginning of the period								329,073
Issuance of common units by our long-term incentive plan								0
Issuance of common units by our savings and retention program (in units)								0
TransMontaigne GP to maintain its 2% general partner interest								266
Units outstanding at the end of the period								329,339

EQUITY BASED COMPENSATION (Deta

EQUITY BASED COMPENSATION (Details) - USD ($)	Oct. 21, 2016	Feb. 01, 2016	Oct. 14, 2015	Sep. 30, 2015	Apr. 01, 2015	Sep. 30, 2014	Jul. 01, 2014	Mar. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Restricted phantom units
Incentive plan activity
Units, unvested, outstanding at the beginning of the period									15,750	9,000	14,500
Vesting (in units)	(3,258)	(15,750)		(2,250)			(15,000)	(5,500)
Grant (in units)	3,258		9,000			9,000		6,000
Units, unvested, outstanding at the end of the period							15,000			15,750	9,000
Vesting (in dollars per unit)	$ 41.45	$ 30.41		$ 27.20			$ 43.80	$ 43.08
Grant (in dollars per unit)	$ 41.45		$ 31.11			$ 41.24		$ 43.08
Additional disclosures
Equity-based compensation							$ 600,000
Restricted phantom units | TransMontaigne LLC-related party
Incentive plan activity
Units, unvested, outstanding at the beginning of the period									30,616
Vesting (in units)									(23,513)
Unit accrual for distributions paid (in units)									2,390
Grant (in units)									28,945
Units, unvested, outstanding at the end of the period									38,438	30,616
Outstanding at the beginning of the period (in dollars per unit)									$ 36.80
Vesting (in dollars per unit)									32.05
Units accrual for distributions paid (in dollars per unit)									38.45
Grant (in dollars per unit)									34.23
Outstanding at the end of the period (in dollars per unit)									$ 34.90	$ 36.80
Units outstanding at the beginning of the period (in units)									30,203
Vesting (in units)									23,513
Unit accrual for distributions (in units)									5,474
Grant (in units)									31,022
Issuance (in units)									(2,094)
Units outstanding at the end of the period (in units)									88,118	30,203
Vested and expected to vest (in units)									126,556
Outstanding at the beginning of the period (in dollars per unit)									$ 36.80
Vesting (in dollars per unit)									32.05
Unit accrual for distributions paid (in dollars per unit)									37.45
Grant (in dollars per unit)									34.23
Issuance (in dollars per unit)									42.37
Outstanding at the end of the period (in dollars per unit)									35.82	$ 36.80
Vested and expected to vest (in dollars per unit)									$ 35.54
Additional disclosures
Equity-based compensation									$ 2,500,000	$ 1,300,000	$ 1,500,000
Restricted phantom units | TLP Management Services LLC
Additional disclosures
Vesting (as a percent)									50.00%
Restricted phantom units | TLP Management Services LLC | Vesting Tranche One
Additional disclosures
Earlier vesting, age threshold (in years)									60 years
Restricted phantom units | TLP Management Services LLC | Vesting Tranche Two
Additional disclosures
Earlier vesting, age threshold (in years)									55 years
Earlier vesting, length of service threshold (in years)									10 years
Restricted phantom units | TLP Management Services LLC | Vesting Tranche Three
Additional disclosures
Earlier vesting, age threshold (in years)									50 years
Earlier vesting, length of service threshold (in years)									20 years
Long-term incentive plan
Long-term incentive plan
Authorized units									750,000
Additional disclosures
Equity-based compensation									$ 722,000	$ 108,000	$ 721,000
Long-term incentive plan | Common units | TransMontaigne GP
Long-term incentive plan
Vesting period									4 years
Number of common units purchased					667

NET EARNINGS PER LIMITED PART60

NET EARNINGS PER LIMITED PARTNER UNIT (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended												12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
NET EARNINGS PER LIMITED PARTNER UNIT
Net earnings	$ 13,201	$ 11,885	$ 10,310	$ 8,710	$ 11,667	$ 7,712	$ 12,188	$ 10,122					$ 44,106	$ 41,689	$ 32,463
Less:
Distributions payable on behalf of incentive distribution rights													(8,630)	(6,808)	(6,650)
Distributions payable on behalf of general partner interest													(916)	(877)	(874)
Earnings allocable to general partner interest less than distributions payable to general partner interest													206	179	357
Earnings allocable to general partner interest including incentive distribution rights													(9,340)	(7,506)	(7,167)
Net earnings allocable to limited partners													34,766	34,183	25,296
Less distributions payable for unvested long-term incentive plan grants														(27)	(32)
Net earnings allocable to limited partners for calculating net earnings per limited partner unit													$ 34,766	$ 34,156	$ 25,264
Basic weighted average units													16,210	16,137	16,114
Diluted weighted average units													16,229	16,146	16,114
Net earnings per limited partner unit-basic (in dollars per unit)													$ 2.14	$ 2.12	$ 1.57
Net earnings per limited partner unit-diluted (in dollars per unit)													$ 2.14	$ 2.12	$ 1.57
Period for declaration of distribution, maximum													45 days
Distribution declared per common unit (in dollars per unit)	$ 0.710	$ 0.700	$ 0.690	$ 0.680	$ 0.670	$ 0.665	$ 0.665	$ 0.665	$ 0.665	$ 0.665	$ 0.665	$ 0.660

COMMITMENTS AND CONTINGENCIES61

COMMITMENTS AND CONTINGENCIES (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
COMMITMENTS AND CONTINGENCIES
Contractual commitments for supply of services, labor and materials	$ 16,000
Future minimum lease payments under non-cancelable operating leases
2,017	3,914
2,018	1,667
2,019	1,653
2,020	1,500
2,021	1,431
Thereafter	3,612
Total	13,777
Expected minimum sublease rentals to be received	2,700
Rental expense under operating leases	$ 3,400	$ 3,500	$ 3,500

BUSINESS SEGMENTS (Details)

BUSINESS SEGMENTS (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segments of business
Total revenue	$ 42,524	$ 40,638	$ 41,136	$ 40,626	$ 40,310	$ 37,269	$ 37,034	$ 37,897	$ 164,924	$ 152,510	$ 150,062
Direct operating costs and expenses	(17,758)	(17,048)	(17,703)	(15,906)	(16,552)	(16,655)	(15,872)	(14,954)	(68,415)	(64,033)	(66,183)
Net margins									96,509	88,477	83,879
General and administrative expenses	(3,374)	(3,605)	(3,446)	(4,398)	(3,607)	(3,952)	(3,474)	(3,824)	(14,823)	(14,857)	(14,662)
Insurance expenses	(1,305)	(969)	(912)	(895)	(944)	(944)	(934)	(934)	(4,081)	(3,756)	(3,711)
Reimbursement of bonus awards expense	(396)	(251)	(258)	(1,635)	(118)	(121)	(539)	(525)	(2,540)	(1,303)	(1,500)
Depreciation and amortization	(8,215)	(8,169)	(8,064)	(7,935)	(8,126)	(7,711)	(7,476)	(7,337)	(32,383)	(30,650)	(29,522)
Earnings from unconsolidated affiliates	3,089	2,960	2,130	1,850	2,184	2,191	5,517	2,056	10,029	11,948	4,443
Operating income	14,565	13,556	12,883	11,707	13,147	10,077	14,256	12,379	52,711	49,859	38,927
Other expenses	(1,364)	(1,671)	(2,573)	(2,997)	(1,480)	(2,365)	(2,068)	(2,257)	(8,605)	(8,170)	(6,464)
Net earnings	13,201	$ 11,885	$ 10,310	$ 8,710	11,667	$ 7,712	$ 12,188	$ 10,122	44,106	41,689	32,463
External customers									156,506	109,557	75,909
Revenue from affiliates									8,418	42,953	74,153
Capital expenditures									54,864	29,427	7,021
Identifiable assets	440,891				407,067				440,891	407,067	409,574
Cash and cash equivalents	593				681				593	681	3,304	$ 3,263
Investments in unconsolidated affiliates	241,093				246,700				241,093	246,700
Deferred financing costs	1,298				1,721				1,298	1,721
Other	5,819				518				5,819	518
TOTAL ASSETS	689,694				656,687				689,694	656,687
NGL Energy Partners LP
Segments of business
Revenue from affiliates									2,961	38,537	23,743
Morgan Stanley Capital Group
Segments of business
Revenue from affiliates											46,375
Frontera
Segments of business
Revenue from affiliates									5,457	4,416	4,035
Gulf Coast Terminals
Segments of business
Terminaling services fees									45,903	42,049	43,777
Other									10,807	11,659	11,432
Total revenue									56,710	53,708	55,209
Direct operating costs and expenses									(22,952)	(19,147)	(19,426)
Net margins									33,758	34,561	35,783
External customers									56,586	48,430	30,695
Capital expenditures									7,675	9,236	1,893
Identifiable assets	126,457				120,590				126,457	120,590	122,366
Gulf Coast Terminals | NGL Energy Partners LP
Segments of business
Revenue from affiliates									124	5,278	7,042
Gulf Coast Terminals | Morgan Stanley Capital Group
Segments of business
Revenue from affiliates											17,472
Midwest Terminals and Pipeline System
Segments of business
Terminaling services fees									8,590	8,330	8,164
Pipeline transportation fees									1,732	1,694	1,569
Other									879	1,398	2,080
Total revenue									11,201	11,422	11,813
Direct operating costs and expenses									(3,220)	(3,000)	(3,134)
Net margins									7,981	8,422	8,679
External customers									11,201	11,422	8,827
Capital expenditures									871	1,129	484
Identifiable assets	21,919				22,990				21,919	22,990	23,702
Midwest Terminals and Pipeline System | Morgan Stanley Capital Group
Segments of business
Revenue from affiliates											2,986
Brownsville terminals
Segments of business
Terminaling services fees									8,234	8,037	6,280
Pipeline transportation fees									5,057	4,919	1,745
Other									12,194	12,747	13,414
Total revenue									25,485	25,703	21,439
Direct operating costs and expenses									(11,338)	(12,152)	(14,253)
Net margins									14,147	13,551	7,186
External customers									20,028	21,277	17,397
Capital expenditures									1,428	3,753	1,387
Identifiable assets	43,878				45,287				43,878	45,287	45,742
Brownsville terminals | NGL Energy Partners LP
Segments of business
Revenue from affiliates										10	7
Brownsville terminals | Frontera
Segments of business
Revenue from affiliates									5,457	4,416	4,035
River terminals
Segments of business
Terminaling services fees									9,664	9,316	8,566
Other									2,914	878	742
Total revenue									12,578	10,194	9,308
Direct operating costs and expenses									(7,957)	(7,126)	(7,976)
Net margins									4,621	3,068	1,332
External customers									12,578	9,765	8,408
Capital expenditures									2,788	4,888	1,433
Identifiable assets	53,005				54,213				53,005	54,213	54,042
River terminals | NGL Energy Partners LP
Segments of business
Revenue from affiliates										429	231
River terminals | Morgan Stanley Capital Group
Segments of business
Revenue from affiliates											669
Southeast terminals
Segments of business
Terminaling services fees									53,699	46,503	45,070
Other									5,251	4,980	7,223
Total revenue									58,950	51,483	52,293
Direct operating costs and expenses									(22,948)	(22,608)	(21,394)
Net margins									36,002	28,875	30,899
External customers									56,113	18,663	10,582
Capital expenditures									42,102	10,421	1,824
Identifiable assets	$ 195,632				$ 163,987				195,632	163,987	163,722
Southeast terminals | NGL Energy Partners LP
Segments of business
Revenue from affiliates									$ 2,837	$ 32,820	16,463
Southeast terminals | Morgan Stanley Capital Group
Segments of business
Revenue from affiliates											$ 25,248

FINANCIAL RESULTS BY QUARTER 63

FINANCIAL RESULTS BY QUARTER (UNAUDITED) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Financial Results by Quarter
Revenue	$ 42,524	$ 40,638	$ 41,136	$ 40,626	$ 40,310	$ 37,269	$ 37,034	$ 37,897	$ 164,924	$ 152,510	$ 150,062
Direct operating costs and expenses	(17,758)	(17,048)	(17,703)	(15,906)	(16,552)	(16,655)	(15,872)	(14,954)	(68,415)	(64,033)	(66,183)
General and administrative expenses	(3,374)	(3,605)	(3,446)	(4,398)	(3,607)	(3,952)	(3,474)	(3,824)	(14,823)	(14,857)	(14,662)
Insurance expenses	(1,305)	(969)	(912)	(895)	(944)	(944)	(934)	(934)	(4,081)	(3,756)	(3,711)
Reimbursement of bonus awards	(396)	(251)	(258)	(1,635)	(118)	(121)	(539)	(525)	(2,540)	(1,303)	(1,500)
Depreciation and amortization	(8,215)	(8,169)	(8,064)	(7,935)	(8,126)	(7,711)	(7,476)	(7,337)	(32,383)	(30,650)	(29,522)
Earnings from unconsolidated affiliates	3,089	2,960	2,130	1,850	2,184	2,191	5,517	2,056	10,029	11,948	4,443
Operating income	14,565	13,556	12,883	11,707	13,147	10,077	14,256	12,379	52,711	49,859	38,927
Other expenses	(1,364)	(1,671)	(2,573)	(2,997)	(1,480)	(2,365)	(2,068)	(2,257)	(8,605)	(8,170)	(6,464)
Net earnings	$ 13,201	$ 11,885	$ 10,310	$ 8,710	$ 11,667	$ 7,712	$ 12,188	$ 10,122	$ 44,106	$ 41,689	$ 32,463
Net earnings per limited partner unit-basic and diluted (in dollars per unit)	$ 0.65	$ 0.58	$ 0.50	$ 0.41	$ 0.60	$ 0.37	$ 0.64	$ 0.51	$ 2.14	$ 2.12

SUBSEQUENT EVENT (Details)

SUBSEQUENT EVENT (Details) - USD ($) $ / shares in Units, $ in Millions

Mar. 13, 2017

Mar. 12, 2017

Feb. 08, 2017

Jan. 16, 2017

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2016

Subsequent Event

Distribution announced per unit (in dollars per unit)

$ 0.710

$ 0.700

$ 0.690

$ 0.680

$ 0.670

$ 0.665

$ 0.665

$ 0.665

$ 0.665

$ 0.665

$ 0.665

$ 0.660

Maximum

Subsequent Event

Permitted JV investments subject to liquidity

$ 125

Subsequent event

Subsequent Event

Distribution announced per unit (in dollars per unit)

$ 0.71

Distribution paid per unit (in dollars per unit)

$ 0.71

Maximum borrowing capacity

$ 600

$ 400

Permitted JV investments subject to liquidity

175

Optional increase to maximum borrowing capacity

$ 250

Credit facility

Subsequent Event

Maximum borrowing capacity

$ 400

$ 400

Credit facility | LIBOR | Maximum

Subsequent Event

Margin interest above reference rate (as a percent)

3.00%

Credit facility | LIBOR | Minimum

Subsequent Event

Margin interest above reference rate (as a percent)

2.00%

Credit facility | Base Rate | Maximum

Subsequent Event

Margin interest above reference rate (as a percent)

2.00%

Credit facility | Base Rate | Minimum

Subsequent Event

Margin interest above reference rate (as a percent)

1.00%

Credit facility | Subsequent event | LIBOR | Maximum

Subsequent Event

Margin interest above reference rate (as a percent)

2.75%

3.00%

Credit facility | Subsequent event | LIBOR | Minimum

Subsequent Event

Margin interest above reference rate (as a percent)

1.75%

2.00%

Credit facility | Subsequent event | Base Rate | Maximum

Subsequent Event

Margin interest above reference rate (as a percent)

1.75%

2.00%

Credit facility | Subsequent event | Base Rate | Minimum

Subsequent Event

Margin interest above reference rate (as a percent)

0.75%

1.00%