Martin Midstream Partners (MMLP) 10-K 15 Feb 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Feb. 15, 2017	Jun. 30, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	MARTIN MIDSTREAM PARTNERS LP
Entity Central Index Key	1,176,334
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding (in shares)		35,450,562
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 674,298,933

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Assets
Cash	$ 15	$ 31
Trade and accrued accounts receivable, less allowance for doubtful accounts of $372 and $430 respectively	80,508	74,355
Product exchange receivables	207	1,050
Inventories	82,631	75,870
Due from affiliates	11,567	10,126
Fair value of derivatives	0	675
Other current assets	3,296	5,718
Assets held for sale	15,779	0
Total current assets	194,003	167,825
Property, plant and equipment, at cost	1,224,277	1,387,814
Accumulated depreciation	(378,593)	(404,574)
Property, plant and equipment, net	845,684	983,240
Goodwill	17,296	23,802
Investment in unconsolidated entities	129,506	132,292
Notes receivable - Martin Energy Trading LLC	15,000	15,000
Intangibles and other assets, net	44,874	58,314
Total Assets	1,246,363	1,380,473
Liabilities and Partners’ Capital
Trade and other accounts payable	70,249	81,180
Product exchange payables	7,360	12,732
Due to affiliates	8,474	5,738
Income taxes payable	870	985
Fair value of derivatives	3,904	0
Other accrued liabilities	26,717	18,533
Total current liabilities	117,574	119,168
Long-term debt, net	808,107	865,003
Fair value of derivatives	0	206
Other long-term obligations	8,676	2,217
Total liabilities	934,357	986,594
Commitments and contingencies
Partners’ capital	312,006	393,879
Total Liabilities and Partners' Capital	$ 1,246,363	$ 1,380,473

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Assets
Doubtful accounts for accounts and other receivables	$ 372	$ 430

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues:
Terminalling and storage	[1]	$ 123,132	$ 132,945	$ 130,506
Marine transportation	[1]	58,290	78,753	91,372
Natural gas storage services	[1]	61,133	64,858	22,991
Sulfur services		10,800	12,270	12,149
Product sales:
Natural gas services	[1]	330,200	458,302	990,844
Sulfur services	[1]	130,258	157,891	203,322
Terminalling and storage	[1]	113,578	131,825	190,957
Total product sales	[1]	574,036	748,018	1,385,123
Total revenues		827,391	1,036,844	1,642,141
Cost of products sold: (excluding depreciation and amortization)
Natural gas services		289,516	413,795	948,765
Sulfur services		87,963	114,766	159,782
Terminalling and storage		94,175	112,836	172,069
Total cost of products sold (excluding depreciation and amortization)		471,654	641,397	1,280,616
Expenses:
Operating expenses	[1]	158,864	183,466	184,049
Selling, general and administrative	[1]	34,385	36,788	36,316
Impairment of long-lived assets		26,953	10,629	3,445
Impairment of goodwill		4,145	0	0
Depreciation and amortization		92,132	92,250	68,830
Total costs and expenses		788,133	964,530	1,573,256
Other operating income (loss), net		33,400	(2,161)	(1,014)
Operating income		72,658	70,153	67,871
Other income (expense):
Equity in earnings of unconsolidated entities		4,714	8,986	5,466
Debt prepayment premium		0	0	(7,767)
Interest expense, net		(46,100)	(43,292)	(42,203)
Gain on retirement of senior unsecured notes		0	1,242	0
Reduction in fair value of investment in Cardinal due to the purchase of the controlling interest		0	0	(30,102)
Other, net		1,106	1,124	1,505
Total other income (expense)		(40,280)	(31,940)	(73,101)
Net income (loss) before taxes		32,378	38,213	(5,230)
Income tax expense		(726)	(1,048)	(1,137)
Income (loss) from continuing operations		31,652	37,165	(6,367)
Income (loss) from discontinued operations, net of income taxes		0	1,215	(5,338)
Net income (loss)		31,652	38,380	(11,705)
Less general partner's interest in net (income) loss		(8,419)	(16,338)	(3,503)
Less (income) loss allocable to unvested restricted units		(90)	(140)	32
Limited partner's interest in net income (loss)		$ 23,143	$ 21,902	$ (15,176)
[1]	*Related Party Transactions Included Above Year Ended December 31, 2016 2015 2014 Revenues: Terminalling and storage $ 82,437 $ 78,233 $ 74,467 Marine transportation 21,767 27,724 24,389 Natural gas services 699 878 — Product sales 3,034 5,671 7,661 Costs and expenses: Cost of products sold: (excluding depreciation and amortization) Natural gas services 22,886 25,797 37,703 Sulfur services 15,339 16,579 18,390 Terminalling and storage 13,838 17,718 36,341 Expenses: Operating expenses 70,841 77,871 79,577 Selling, general and administrative 25,890 24,968 23,679

CONSOLIDATED STATEMENTS OF OPE5

CONSOLIDATED STATEMENTS OF OPERATIONS - (Allocation of Net Income) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Limited partner interest:
Continuing operations	$ 23,143	$ 21,208	$ (8,255)
Discontinued operations	0	694	(6,921)
Limited partner's interest in net income (loss)	23,143	21,902	(15,176)
General partner interest:
Continuing operations	8,419	15,821	1,906
Discontinued operations	0	517	1,597
Net Income Allocated to General Partners	$ 8,419	$ 16,338	$ 3,503
Basic:
Continuing operations (in dollars per share)	$ 0.65	$ 0.60	$ (0.27)
Discontinued operations (in dollars per share)	0	0.02	(0.22)
Net Income, Basic (in dollars per share)	$ 0.65	$ 0.62	$ (0.49)
Weighted average limited partner units outstanding basic (in shares)	35,347,032	35,308,649	30,785,035
Diluted:
Continuing operations (in dollars per share)	$ 0.65	$ 0.60	$ (0.27)
Discontinued operations (in dollars per share)	0	0.02	(0.22)
Net Income, Diluted (in dollars per shares)	$ 0.65	$ 0.62	$ (0.49)
Weighted average limited partner units - diluted (in shares)	35,375,000	35,372,000	30,785,000

CONSOLIDATED STATEMENTS OF OPE6

CONSOLIDATED STATEMENTS OF OPERATIONS - (Related Party Transactions) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues:
Terminalling and storage	$ 82,437	$ 78,233	$ 74,467
Marine transportation	21,767	27,724	24,389
Natural gas services	699	878	0
Product sales	3,034	5,671	7,661
Cost of products sold: (excluding depreciation and amortization)
Natural gas services	22,886	25,797	37,703
Sulfur services	15,339	16,579	18,390
Terminalling and storage	13,838	17,718	36,341
Expenses:
Operating expenses	70,841	77,871	79,577
Selling, general and administrative	$ 25,890	$ 24,968	$ 23,679

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN CAPITAL - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Increase (Decrease) in Partners' Capital [Roll Forward]
Beginning balance	$ 393,879	$ 485,671	$ 260,417
Net income (loss)	31,652	38,380	(11,705)
Issuance of common units, net	(29)	(590)	331,728
General partner contribution		55	7,007
Cash distributions	(118,178)	(133,316)	(97,368)
Excess purchase price over carrying value of acquired assets		2,250	(4,948)
Unit-based compensation	904	1,429	817
Purchase of treasury units	(347)		(277)
Reimbursement of excess purchase price over carrying value of acquired assets	4,125
Ending balance	$ 312,006	$ 393,879	$ 485,671
Common
Increase (Decrease) in Partners' Capital [Roll Forward]
Purchase of treasury units (in shares)	(16,100)		(6,400)
Purchase of treasury units	$ (347)		$ (277)
Common | Common
Increase (Decrease) in Partners' Capital [Roll Forward]
Beginning balance (in shares)	35,456,612	35,365,912	26,625,026
Beginning balance	$ 380,845	$ 470,943	$ 254,028
Net income (loss)	23,233	22,042	$ (15,208)
Issuance of common units (in shares)			8,743,386
Issuance of common units, net	$ (29)	$ (590)	$ 331,728
Issuance of restricted units (in shares)	13,800	91,950	8,900
Forfeiture of restricted units (in shares)	(2,250)	(1,250)	(5,000)
Cash distributions	$ (104,137)	$ (115,229)	$ (95,197)
Excess purchase price over carrying value of acquired assets		2,250	(4,948)
Unit-based compensation	904	1,429	817
Reimbursement of excess purchase price over carrying value of acquired assets	4,125
Ending balance	$ 304,594	$ 380,845	$ 470,943
Ending balance (in shares)	35,452,062	35,456,612	35,365,912
General Partner
Increase (Decrease) in Partners' Capital [Roll Forward]
Beginning balance	$ 13,034	$ 14,728	$ 6,389
Net income (loss)	8,419	16,338	3,503
General partner contribution		55	7,007
Cash distributions	(14,041)	(18,087)	(2,171)
Ending balance	$ 7,412	$ 13,034	$ 14,728

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 income (loss)	$ 31,652	$ 38,380	$ (11,705)
Less: (Income) loss from discontinued operations	0	(1,215)	5,338
Net income (loss) from continuing operations	31,652	37,165	(6,367)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	92,132	92,250	68,830
Amortization of deferred debt issue costs	3,684	4,859	6,263
Amortization of discount on notes payable	0	0	1,305
Amortization of premium on notes payable	(306)	(324)	(245)
(Gain) loss on disposition or sale of property, plant, and equipment	(33,400)	2,149	1,353
Gain on retirement of senior unsecured notes	0	(1,242)	0
Impairment of long-lived assets	26,953	10,629	3,445
Impairment of goodwill	4,145	0	0
Equity in earnings unconsolidated entities	(4,714)	(8,986)	(5,466)
Reduction in fair value of investment in Cardinal due to the purchase of the controlling interest	0	0	30,102
Derivative (income) loss	4,133	(3,107)	(5,877)
Net cash received for commodity derivatives	(550)	143	3
Net cash received for interest rate derivatives	160	0	0
Net premiums received on derivatives that settled during the year on interest rate swaption contracts	630	2,495	6,692
Unit-based compensation	904	1,429	817
Preferred dividends from Martin Energy Trading	0	0	1,498
Return on investment	7,500	11,200	2,600
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables	(6,153)	59,479	29,025
Product exchange receivables	843	1,996	(319)
Inventories	(6,761)	12,799	5,680
Due from affiliates	(1,441)	4,386	(2,413)
Other current assets	2,478	891	4,123
Trade and other accounts payable	3,254	(44,153)	(26,349)
Product exchange payables	(5,372)	2,336	801
Due to affiliates	2,736	866	2,276
Income taxes payable	(115)	(189)	(30)
Other accrued liabilities	686	(2,802)	1,084
Change in other non-current assets and liabilities	(12,230)	(345)	181
Net cash provided by continuing operating activities	110,848	183,924	119,012
Net cash used in discontinued operating activities	0	(1,352)	(3,432)
Net cash provided by operating activities	110,848	182,572	115,580
Cash flows from investing activities:
Payments for property, plant, and equipment	(40,455)	(65,791)	(84,307)
Acquisitions, net of cash acquired	(2,150)	0	(102,696)
Payments for plant turnaround costs	(2,061)	(1,908)	(3,974)
Proceeds from sale of property, plant, and equipment	108,505	2,644	1,030
Proceeds from involuntary conversion of property, plant and equipment	0	0	2,475
Investments in unconsolidated entities	0	0	(134,030)
Return of investments from unconsolidated entities	0	0	225
Contributions to unconsolidated entities for operations	0	0	(3,386)
Net cash provided by (used in) continuing investing activities	63,839	(65,055)	(324,663)
Net cash provided by discontinued investing activities	0	41,250	0
Net cash provided by (used in) investing activities	63,839	(23,805)	(324,663)
Cash flows from financing activities:
Payments of long-term debt	(386,700)	(308,836)	(1,533,087)
Proceeds from long-term debt	331,700	282,000	1,493,250
Net proceeds from issuance of common units	(29)	(590)	331,728
General partner contributions	0	55	7,007
Excess purchase price over carrying value of acquired assets	0	0	(4,948)
Reimbursement of excess purchase price over carrying value of acquired assets	4,125	2,250	0
Purchase of treasury units	(347)	0	(277)
Payments of debt issuance costs	(5,274)	(341)	(3,722)
Cash distributions paid	(118,178)	(133,316)	(97,368)
Net cash provided by (used in) financing activities	(174,703)	(158,778)	192,583
Net decrease in cash	(16)	(11)	(16,500)
Cash at beginning of year	31	42	16,542
Cash at end of year	$ 15	$ 31	$ 42

Organization and Description of

Organization and Description of Business	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Description of Business	Organization and Description of Business Martin Midstream Partners L.P. (the "Partnership") is a publicly traded limited partnership with a diverse set of operations focused primarily in the United States ("U.S.") Gulf Coast region. Its four primary business lines include: terminalling and storage services for petroleum products and by-products including the refining of naphthenic crude oil and the blending and packaging of finished lubricants; natural gas services, including liquids transportation and distribution services and natural gas storage; sulfur and sulfur-based products processing, manufacturing, marketing and distribution; and marine transportation services for petroleum products and by-products. The petroleum products and by-products the Partnership collects, transports, stores and distributes are produced primarily by major and independent oil and gas companies who often turn to third parties, such as the Partnership, for the transportation and disposition of these products. In addition to these major and independent oil and gas companies, the Partnership's primary customers include independent refiners, large chemical companies, fertilizer manufacturers and other wholesale purchasers of these products. The Partnership operates primarily in the U.S. Gulf Coast region, which is a major hub for petroleum refining, natural gas gathering and processing and support services for the oil and gas exploration and production industry. On August 30, 2013, Martin Resource Management completed the sale of a 49% non-controlling voting interest ( 50% economic interest) in MMGP Holdings, LLC ("Holdings"), a newly-formed sole member of Martin Midstream GP LLC ("MMGP"), the general partner of the Partnership, to certain affiliated investment funds managed by Alinda Capital Partners ("Alinda"). Upon closing the transaction, Alinda appointed two

Significant Accounting Policies

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Significant Accounting Policies	Significant Accounting Policies (a) Principles of Presentation and Consolidation The consolidated financial statements include the financial statements of the Partnership and its wholly-owned subsidiaries and equity method investees. In the opinion of the management of the Partnership’s general partner, all adjustments and elimination of significant intercompany balances necessary for a fair presentation of the Partnership’s results of operations, financial position and cash flows for the periods shown have been made. All such adjustments are of a normal recurring nature. In addition, the Partnership evaluates its relationships with other entities to identify whether they are variable interest entities under certain provisions of the Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC"), 810-10 and to assess whether it is the primary beneficiary of such entities. If the determination is made that the Partnership is the primary beneficiary, then that entity is included in the consolidated financial statements in accordance with ASC 810-10. No such variable interest entities exist as of December 31, 2016 or 2015. As discussed in Note 5, on February 12, 2015, the Partnership sold all six 16,101 barrel liquefied petroleum gas ("LPG") pressure barges, collectively referred to as the "Floating Storage Assets." These assets were acquired on February 28, 2013. On December 19, 2014, the Partnership made the decision to dispose of the Floating Storage Assets. As a result, the Partnership has presented the results of operations and cash flows of the Floating Storage Assets as discontinued operations for the years ended December 31, 2015 and and 2014. (b) Product Exchanges The Partnership enters into product exchange agreements with third parties, whereby the Partnership agrees to exchange natural gas liquids ("NGLs") and sulfur with third parties. The Partnership records the balance of exchange products due to other companies under these agreements at quoted market product prices and the balance of exchange products due from other companies at the lower of cost or market. Cost is determined using the first-in, first-out ("FIFO") method. Product exchanges with the same counterparty are entered into in contemplation of one another and are combined. The net amount related to location differentials is reported in "Product sales" or "Cost of products sold" in the Consolidated Statements of Operations. (c) Inventories Inventories are stated at the lower of cost or market. Cost is generally determined by using the FIFO method for all inventories except lubricants and lubricants packaging inventories. Lubricants and lubricants packaging inventories cost is determined using standard cost, which approximates actual cost, computed on a FIFO basis. (d) Revenue Recognition Terminalling and Storage – Revenue is recognized for storage contracts based on the contracted monthly tank fixed fee. For throughput contracts, revenue is recognized based on the volume moved through the Partnership’s terminals at the contracted rate. For the Partnership’s tolling agreement, revenue is recognized based on the contracted monthly reservation fee and throughput volumes moved through the facility. When lubricants and drilling fluids are sold by truck or rail, revenue is recognized upon delivering product to the customers as title to the product transfers when the customer physically receives the product. Natural Gas Services – NGL distribution revenue is recognized when product is delivered by truck, rail, or pipeline to the Partnership's NGL customers. Natural gas storage revenue is recognized when the service is provided to the customer. Sulfur Services – Revenue from sulfur product sales is recognized when the customer takes title to the product. Revenue from sulfur services is recognized as deliveries are made during each monthly period. Marine Transportation – Revenue is recognized for time charters based on a per day rate. For contracted trips, revenue is recognized upon completion of the particular trip. (e) Equity Method Investments The Partnership uses the equity method of accounting for investments in unconsolidated entities where the ability to exercise significant influence over such entities exists. Investments in unconsolidated entities consist of capital contributions and advances plus the Partnership’s share of accumulated earnings as of the entities’ latest fiscal year-ends, less capital withdrawals and distributions. Investments in excess of the underlying net assets of equity method investees, specifically identifiable to property, plant and equipment, are amortized over the useful life of the related assets. Excess investment representing equity method goodwill is not amortized but is evaluated for impairment, annually. Under certain provisions of ASC 350-20, related to goodwill, this goodwill is not subject to amortization and is accounted for as a component of the investment. Equity method investments are subject to impairment under the provisions of ASC 323-10, which relates to the equity method of accounting for investments in common stock. No portion of the net income from these entities is included in the Partnership’s operating income. (f) Property, Plant, and Equipment Owned property, plant, and equipment is stated at cost, less accumulated depreciation. Owned buildings and equipment are depreciated using straight-line method over the estimated lives of the respective assets. Equipment under capital leases is stated at the present value of minimum lease payments less accumulated amortization. Equipment under capital leases is amortized on a straight line basis over the estimated useful life of the asset. Routine maintenance and repairs are charged to operating expense while costs of betterments and renewals are capitalized. When an asset is retired or sold, its cost and related accumulated depreciation are removed from the accounts, and the difference between net book value of the asset and proceeds from disposition is recognized as gain or loss. (g) Goodwill and Other Intangible Assets Goodwill is subject to a fair-value based impairment test on an annual basis, or more often if events or circumstances indicate there may be impairment. The Partnership is required to identify its reporting units and determine the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets. The Partnership is required to determine the fair value of each reporting unit and compare it to the carrying amount of the reporting unit. To the extent the carrying amount of a reporting unit exceeds the fair value of the reporting unit, the Partnership would be required to perform the second step of the impairment test, as this is an indication that the reporting unit goodwill may be impaired. When assessing the recoverability of goodwill and other intangible assets, the Partnership may first assess qualitative factors in determining whether it is more likely than not that the fair value of a reporting unit or other intangible asset is less than its carrying amount. After assessing qualitative factors, if the Partnership determines that it is not more likely than not that the fair value of a reporting unit or other intangible asset is less than its carrying amount, then performing a quantitative assessment is not required. If an initial qualitative assessment indicates that it is more likely than not the carrying amount exceeds the fair value of a reporting unit or other intangible asset, a quantitative analysis will be performed. The Partnership may also elect to bypass the qualitative assessment and proceed directly to a quantitative analysis depending on the facts and circumstances. Of the Partnership's four reporting units, the terminalling and storage, natural gas services, and sulfur services reporting units contain goodwill. During the second quarter of 2016, the Partnership experienced an impairment of all the goodwill in the Partnership's marine transportation reporting unit. See Note 8 for more information. In performing a quantitative analysis, recoverability of goodwill for each reporting unit is measured using a weighting of the discounted cash flow method and two market approaches (the guideline public company method and the guideline transaction method). The discounted cash flow model incorporates discount rates commensurate with the risks involved. Use of a discounted cash flow model is common practice in assessing impairment in the absence of available transactional market evidence to determine the fair value. The key assumptions used in the discounted cash flow valuation model include discount rates, growth rates, cash flow projections and terminal value rates. Discount rates, growth rates and cash flow projections are the most sensitive and susceptible to change as they require significant management judgment. Discount rates are determined by using a weighted average cost of capital ("WACC"). The WACC considers market and industry data as well as company-specific risk factors for each reporting unit in determining the appropriate discount rate to be used. The discount rate utilized for each reporting unit is indicative of the return an investor would expect to receive for investing in such a business. Management, considering industry and company specific historical and projected data, develops growth rates and cash flow projections for each reporting unit. Terminal value rate determination follows common methodology of capturing the present value of perpetual cash flow estimates beyond the last projected period assuming a constant WACC and low long-term growth rates. If the calculated fair value is less than the current carrying amount, impairment of the reporting unit may exist. If the recoverability test indicates potential impairment, the Partnership calculates an implied fair value of goodwill for the reporting unit. The implied fair value of goodwill is determined in a manner similar to how goodwill is calculated in a business combination. If the implied fair value of goodwill exceeds the carrying amount of goodwill assigned to the reporting unit, there is no impairment. If the carrying amount of goodwill assigned to a reporting unit exceeds the implied fair value of the goodwill, an impairment loss is recorded to write down the carrying amount. An impairment loss cannot exceed the carrying amount of goodwill assigned to a reporting unit but may indicate certain long-lived and amortizable intangible assets associated with the reporting unit may require additional impairment testing Significant changes in these estimates and assumptions could materially affect the determination of fair value for each reporting unit which could give rise to future impairment. Changes to these estimates and assumptions can include, but may not be limited to, varying commodity prices, volume changes and operating costs due to market conditions and/or alternative providers of services. Other intangible assets that have finite lives are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable. An impairment is indicated if the carrying amount of a long-lived intangible asset exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If impairment is indicated, the Partnership would record an impairment loss equal to the difference between the carrying value and the fair value of the asset. There were no intangible asset impairments in 2016, 2015 or 2014. (h) Debt Issuance Costs Debt issuance costs relating to the Partnership’s revolving credit facility and senior unsecured notes are deferred and amortized over the terms of the debt arrangements and are shown, net of accumulated amortization, as a reduction of the related long-term debt. In connection with the issuance, amendment, expansion and restatement of debt arrangements, the Partnership incurred debt issuance costs of $5,274 , $341 and $3,722 in the years ended December 31, 2016, 2015 and 2014, respectively. During 2016, the Partnership made certain strategic amendments to its credit facility which, among other things, decreased its borrowing capacity from $700,000 to $664,444 and extended the maturity date of the facility from March 28, 2018 to March 28, 2020. In connection with the amendment, the Partnership expensed $820 of unamortized debt issuance costs determined not to have continuing benefit. During 2015, the Partnership repurchased on the open market an aggregate $26,200 of 7.25% senior unsecured notes. The repurchase transaction resulted in the write-off of $235 of existing debt issuance costs that were determined not to have continuing benefit. On August 14, 2015, the Partnership reduced its borrowing capacity under the revolving credit facility from $900,000 to $700,000 , resulting in the write-off of $1,625 of deferred debt costs that were determined not to have continuing benefit. Due to the redemption of the remaining $175,000 of 8.875% senior unsecured notes in 2014 and a reduction in the number of lenders under the Partnership’s multi-bank credit agreement, $3,078 of the existing debt issuance costs were determined not to have continuing benefit and were expensed during the year ended December 31, 2014. Remaining unamortized deferred issuance costs are amortized over the term of each respective revised debt arrangement. Amortization and write-off of debt issuance costs, which is included in interest expense, totaled $3,684 , $4,859 and $6,263 for the years ended December 31, 2016, 2015 and 2014, respectively. Accumulated amortization amounted to $14,265 and $10,581 at December 31, 2016 and 2015, respectively. (i) Impairment of Long-Lived Assets In accordance with ASC 360-10, long-lived assets, such as property, plant and equipment, and intangible assets with definite lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset. Assets to be disposed of would be separately presented in the balance sheet and reported at the lower of the carrying amount or fair value less costs to sell and would no longer be depreciated. The assets and liabilities of a disposed group classified as held for sale would be presented separately in the appropriate asset and liability sections of the balance sheet. In the fourth quarter of 2016, the Partnership identified a triggering event related to certain organic growth projects in the Smackover Refinery and Specialty Terminals divisions of the Partnership's Terminalling and Storage segment. These triggering events were the decision to not move forward with certain expansion projects due to the evaporation of the economic viability of the projects. Additionally, a triggering event was identified related to the planned disposition of certain assets that were no longer deemed core assets to the Partnership's Martin Lubricants division. As a result, an impairment charge of $15,252 was recorded in the Terminalling and Storage segment results of operations for the year ended December 31, 2016. In the fourth quarter of 2016, the Partnership identified a triggering event related to the planned disposition of certain assets that were no longer deemed core assets in the Partnership's Marine Transportation business. The triggering event was the assets' inability to generate cash flows in recent quarters and going forward. As a result, an impairment charge of $11,701 was recorded in the Marine Transportation segment results of operations in the fourth quarter of 2016. In the fourth quarter of 2015, the Partnership identified a triggering event related to the condensate splitter project in the specialty terminals division of the Partnership's Terminalling and Storage segment. The triggering event was the decision to not move forward with the project due to the evaporation of the economic viability of the project. As a result, an impairment charge of $9,305 was recorded in the Terminalling and Storage segment results of operations for the year ended December 31, 2015. In the fourth quarter of 2015, the Partnership identified a triggering event related to one inland push boat and three inland tank barges in the Marine Transportation segment. The triggering event was the assets' inability to generate cash flows in recent quarters and going forward. As a result, an impairment charge of $1,324 was recorded in the Marine Transportation segment results of operations in the fourth quarter of 2015. In the third quarter of 2014, the Partnership identified a triggering event related to one offshore tow in the Marine Transportation segment. The triggering event was the tow's inability to generate cash flows in recent quarters. As a result, an impairment charge of $3,445 was recorded in the Marine Transportation segment results of operations in the third quarter of 2014. No other triggering events occurred in 2015, 2014 or 2013 that would require an additional assessment for impairment of long-lived assets. (j) Asset Retirement Obligations Under ASC 410-20, which relates to accounting requirements for costs associated with legal obligations to retire tangible, long-lived assets, the Partnership records an asset retirement obligation ("ARO") at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted over time towards the ultimate obligation amount and the capitalized costs are depreciated over the useful life of the related asset. (k) Derivative Instruments and Hedging Activities In accordance with certain provisions of ASC 815-10 related to accounting for derivative instruments and hedging activities, all derivatives and hedging instruments are included in the Consolidated Balance Sheets as an asset or liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings. Derivative instruments not designated as hedges are marked to market with all market value adjustments being recorded in the Consolidated Statements of Operations. (l) Use of Estimates Management has made a number of estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with accounting principles generally accepted in the U.S. Actual results could differ from those estimates. (m) Indirect Selling, General and Administrative Expenses Indirect selling, general and administrative expenses are incurred by Martin Resource Management and allocated to the Partnership to cover costs of centralized corporate functions such as accounting, treasury, engineering, information technology, risk management and other corporate services. Such expenses are based on the percentage of time spent by Martin Resource Management’s personnel that provide such centralized services. Under an omnibus agreement with Martin Resource Management, the Partnership is required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. For the years ended December 31, 2016, 2015 and 2014, the conflicts committee of the Partnership's general partner ("Conflicts Committee") approved reimbursement amounts of $13,033 , $13,679 and $12,535 , respectively, reflecting the Partnership's allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually. (n) Environmental Liabilities and Litigation The Partnership’s policy is to accrue for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study. Such accruals are adjusted as further information develops or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable. (o) Trade and Accrued Accounts Receivable and Allowance for Doubtful Accounts. Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts is the Partnership’s best estimate of the amount of probable credit losses in the Partnership’s existing accounts receivable. (p) Deferred Catalyst Costs The cost of the periodic replacement of catalysts is deferred and amortized over the catalyst’s estimated useful life, which ranges from 12 to 36 months. (q) Deferred Turnaround Costs The Partnership capitalizes the cost of major turnarounds and amortizes these costs over the estimated period to the next turnaround, which ranges from 12 to 36 months. (r) Income Taxes The Partnership is subject to the Texas margin tax, which is considered a state income tax, and is included in income tax expense on the Consolidated Statements of Operations. Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed as an income tax and, therefore, the recognition of deferred taxes applies to the margin tax. The impact on deferred taxes as a result of this provision is immaterial. (s) Comprehensive Income

Recent Accounting Pronouncement

Recent Accounting Pronouncements	12 Months Ended
	Dec. 31, 2016
Accounting Changes and Error Corrections [Abstract]
Recent Accounting Pronouncements	Recent Accounting Pronouncements In August 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments . This ASU is intended to clarify the presentation of cash receipts and payments in specific situations. The amendments in this ASU are effective for financial statements issued for annual periods beginning after December 15, 2017, including interim periods within those annual periods, and early application is permitted. The Partnership does not anticipate that ASU 2016-15 will have a material effect on its consolidated financial statements and related disclosures. In February 2016, the FASB issued ASU 2016-02, Leases . This ASU amends the existing accounting standards for lease accounting, including requiring lessees to recognize most leases on their balance sheets and making targeted changes to lessor accounting. ASU 2016-02 is effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period. Early adoption of this standard is permitted. The standard requires a modified retrospective transition approach for all leases existing at, or entered into after, the date of initial application, with an option to use certain transition relief. The Partnership is evaluating the effect that ASU 2016-02 will have on its consolidated financial statements and related disclosures. In July 2015, the FASB issued ASU No. 2015-11, Inventory: Simplifying the Measurement of Inventory, which applies only to inventory for which cost is determined by methods other than last-in, first-out and the retail inventory method. This includes inventory that is measured using first-in, first-out or average cost. Inventory within the scope of this standard is required to be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The new standard will be effective on January 1, 2017. The Partnership does not anticipate that ASU 2015-11 will have a material effect on its consolidated financial statements and related disclosures. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers , which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective. The new standard is effective for the Partnership on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method. The Partnership is currently determining the overall impacts that ASU 2014-09 will have on its contract

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
Acquisitions	Acquisitions Cardinal Gas Storage Partners LLC On August 29, 2014, the Partnership acquired from Energy Capital Partners ("ECP") all of ECP’s approximate 57.8% Category A membership interests in Cardinal Gas Storage Partners LLC ("Cardinal") for cash consideration of approximately $120,973 , subject to certain post-closing adjustments. Prior to the acquisition, the Partnership owned an approximate 42.2% interest in the Category A membership interests in Cardinal. Based on the application of purchase accounting, the Partnership reduced the carrying value of its existing investment in Cardinal at the acquisition date by $30,102 , which was recognized in the Partnership's Consolidated Statements of Operations for the year ended December 31, 2014. Concurrent with the closing of the transaction, the Partnership retired all of the project level financing of various Cardinal subsidiaries. The Partnership funded the acquisition and repayment of the project financings with borrowings under its revolving credit facility and the use of restricted cash acquired. The total purchase price is as follows: Cash payment for 57.8% interest in Cardinal $ 120,973 Fair value of the Partnership's previously owned 42.2% interest in Cardinal 87,613 Total $ 208,586 Assets acquired and liabilities assumed were recorded in the Natural Gas Services segment at fair value in the following purchase price allocation which was finalized in the fourth quarter of 2014: Restricted cash $ 17,566 Other current assets 9,385 Property, plant and equipment 390,895 Intangible and other assets 80,135 Project level finance debt (282,087 ) Other current liabilities (6,713 ) Other non-current liabilities (595 ) Total $ 208,586 Intangible assets consist of above-market gas storage customer contracts which are amortized based upon the terms of the individual contracts. At the acquisition date, the weighted average life of these contracts, based upon contracted volumes, was 5.1 years . The Partnership’s results of operations from the Cardinal acquisition include revenues and net income of $61,233 and $16,157 , respectively, for the year ended December 31, 2016, $64,881 and $11,899 , respectively, for the year ended December 31, 2015, and revenues and net income of $22,991 and $1,916 , respectively, for the period from August 29, 2014 to December 31, 2014. Natural Gas Liquids ("NGL") Storage Assets On May 31, 2014, the Partnership acquired certain NGL storage assets, located in Arcadia, Louisiana, from a subsidiary of Martin Resource Management for $7,388 . This acquisition is considered a transfer of net assets between entities under common control. The acquisition of these assets was recorded at the historical carrying value of the assets at the acquisition date. The Partnership recorded the purchase in the following allocation: Property, plant and equipment $ 2,453 Current liabilities (13 ) $ 2,440 The excess of the purchase price over the carrying value of the assets of $4,948 was recorded as an adjustment to "Partners' capital." This transaction was funded with borrowings under the Partnership's revolving credit facility. As no individual line item of the historical financial statements of the assets was in excess of 3% of the Partnership's relative financial statement captions, the Partnership elected not to retrospectively recast the historical financial information to include these assets. West Texas LPG Pipeline L.P. On May 14, 2014, the Partnership acquired from a subsidiary of Atlas Pipeline Partners L.P. ("Atlas"), all of the outstanding membership interests in Atlas Pipeline NGL Holdings, LLC and Atlas Pipeline NGL Holdings II, LLC (collectively, "Atlas Holdings") for cash of approximately $134,400 . The purchase price was subsequently reduced $501 due to a post-closing working capital adjustment. This transaction was recorded in "Investments in unconsolidated entities" in the Partnership's Consolidated Balance Sheet. Atlas Holdings owned a 19.8% limited partnership interest and a 0.2% general partnership interest in West Texas LPG Pipeline L.P. ("WTLPG"). At the time of the purchase, WTLPG was operated by Chevron Pipe Line Company. The 80% interest was subsequently sold to ONEOK Partners, L.P. who assumed operational responsibility. WTLPG owns an approximate 2,300 mile common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. This acquisition will enable the Partnership to participate in the transportation of NGL production in West Texas and other basins along the WTLPG pipeline route. This acquisition of the WTLPG business complements the Partnership's existing East Texas NGL pipeline that delivers Y-grade NGLs from East Texas production areas into Beaumont, Texas on a smaller scale. This transaction was funded with borrowings under the Partnership's revolving credit facility. Pro Forma Unaudited Financial Information for Cardinal and WTLPG The following pro forma unaudited consolidated results of operations have been prepared as if the acquisitions of Cardinal and WTLPG occurred at the beginning of fiscal 2014: Year Ended December 31, 2014 Revenue: As reported $ 1,642,141 Pro forma $ 1,688,629 Net income (loss) from continuing operations attributable to limited partners: As reported $ (8,255 ) Pro forma $ 1,676 Net loss from discontinued operations attributable to limited partners: As reported $ (6,921 ) Pro forma $ (6,921 ) Net income (loss) from continuing operations per unit attributable to limited partners - basic As reported $ (0.27 ) Pro forma $ 0.05 Net loss from discontinued operations per unit attributable to limited partners - basic As reported $ (0.22 ) Pro forma $ (0.22 ) Net income (loss) from continuing operations per unit attributable to limited partners - diluted As reported $ (0.27 ) Pro forma $ 0.05 Net loss from discontinued operations per unit attributable to limited partners - diluted As reported $ (0.22 ) Pro forma $ (0.22 )

Discontinued Operations, Divest

Discontinued Operations, Divestitures, and Assets Held for Sale	12 Months Ended
	Dec. 31, 2016
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations, Divestitures, and Assets Held for Sale	Discontinued Operations, Divestitures, and Assets Held for Sale Long-Lived Assets Held for Sale In the fourth quarter of 2016, the Partnership identified certain assets that were no longer deemed core to the operations of the Partnership in the Smackover refinery and Martin Lubricants divisions of the Terminalling and Storage segment as well as the inland and offshore divisions of the Marine Transportation segment. These assets were deemed non-core due to the each asset's inability to generate cash flows in recent quarters as well as the expected cash flows in future quarters. As a result, an impairment charge of $15,252 and $11,701 was recorded in the Terminalling and Storage and Marine Transportation segments, respectively, for the year ended December 31, 2016 and was presented as "Impairment of long-lived assets" in the Partnership's Consolidated Statements of Operations. At December 31, 2016, the assets met the criteria to be classified as held for sale in accordance with ASC 360-10 and are presented at the assets' fair value less cost to sell by segment in current assets as follows: December 31, 2016 Terminalling and storage $ 10,852 Marine transportation 4,927 Assets held for sale $ 15,779 The non-core assets discussed above did not qualify for discontinued operations presentation under the guidance of ASC 205-20. Divestitures Divestiture of Terminalling Assets. On December 21, 2016, the Partnership sold its 900,000 barrel crude oil storage terminal, refined product barge terminal, certain pipelines and related easements as well as dockage and trans-loading assets located in Corpus Christi, Texas (collectively the "CCCT Assets") to NuStar Logistics, L.P. (“NuStar”) for gross consideration of $107,000 plus the reimbursement of certain capital expenditures and prepaid items of $2,057 . The Partnership received net proceeds of approximately $93,347 after transaction fees and expenses as well as the application of certain net cash payments previously received by us in conjunction with its mandated relocation of certain dockage assets to the purchase price in the amount of $13,400 . Proceeds from the sale were used to reduce outstanding borrowings under the Partnership's revolving credit facility. The Partnership recorded a gain from the divestiture of $37,345 , which was included in "Other operating income, net on the Partnership's Consolidated Statements of Operations for the year ended December 31, 2016. Net income attributable to the CCCT Assets included in the Partnership's Consolidated Statements of Operations was $43,804 , $10,880 , and $16,241 for the years ended December 31, 2016, 2015, and 2014, respectively. The divestiture of the CCCT Assets did not qualify for discontinued operations presentation under the guidance of ASC 205-20. Divestiture of Floating Storage Assets. On February 12, 2015, the Partnership sold all six 16,101 barrel liquefied petroleum gas ("LPG") pressure barges, collectively referred to as the Floating Storage Assets for $41,250 . These assets were acquired on February 28, 2013. The Partnership classified the results of operations of these assets, which were previously presented as a component of the Natural Gas Services segment, as discontinued operations in the Consolidated Statements of Operations for 2015 and 2014. The Partnership has retrospectively adjusted its prior period consolidated financial statements to comparably classify the amounts related to the operations and cash flows of the Floating Storage Assets as discontinued operations. The Floating Storage Assets were presented as discontinued operations under the guidance prior to the Partnership's adoption of ASU 2014-08 related to discontinued operations. The adoption of the amended guidance was effective for the Partnership January 1, 2015. The Floating Storage Assets’ operating results, which are included in income from discontinued operations, were as follows: Year Ended December 31, 2016 2015 2014 Total revenues from third parties 1 $ — $ 791 $ 51,264 Total costs and expenses and other, net, excluding depreciation and amortization — 1,038 55,068 Depreciation and amortization — — 1,534 Other operating income, net 2 — 1,462 — Income (loss) from discontinued operations before income taxes — 1,215 (5,338 ) Income tax expense — — — Income (loss) from discontinued operations, net of income taxes $ — $ 1,215 $ (5,338 ) 1 Total revenues from third parties excludes intercompany revenues of $0 and $0 and $5,241 for the years ended December 31, 2016, 2015 and 2014, respectively. 2

Inventories

Inventories	12 Months Ended
	Dec. 31, 2016
Inventory Disclosure [Abstract]
Inventories	Inventories Components of inventories at December 31, 2016 and 2015 were as follows: 2016 2015 Natural gas liquids $ 33,656 $ 20,959 Sulfur 8,521 13,812 Sulfur based products 19,107 19,400 Lubricants 18,276 18,675 Other 3,071 3,024 $ 82,631 $ 75,870

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, Plant and Equipment At December 31, 2016 and 2015 , property, plant and equipment consisted of the following: Depreciable Lives 2016 2015 Land — $ 20,679 $ 23,931 Improvements to land and buildings 10-25 years 135,852 159,160 Storage equipment 5-50 years 168,839 191,095 Marine vessels 4-25 years 181,659 257,858 Operating plant and equipment 3-50 years 620,303 631,728 Base Gas — 43,799 43,799 Furniture, fixtures and other equipment 3-20 years 19,034 4,375 Transportation equipment 3-7 years 1,738 2,237 Construction in progress 32,374 73,631 $ 1,224,277 $ 1,387,814 Depreciation expense for the years ended December 31, 2016 , 2015 and 2014 was $72,405 , $67,134 and $56,309 . Additions to property, plant and equipment included in accounts payable at December 31, 2016 and 2015 were $1,819 and $6,004

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2016
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	Goodwill The following table represents the goodwill balance at December 31, 2015 , changes during the year, and the resulting balances at December 31, 2016 : 2015 Impairment 1 CCCT Assets 2 2016 Carrying amount of goodwill: Terminalling and storage $ 14,229 $ — $ (2,361 ) $ 11,868 Natural gas services 79 — — $ 79 Sulfur services 5,349 — — $ 5,349 Marine transportation 4,145 (4,145 ) — $ — Total goodwill $ 23,802 $ (4,145 ) $ (2,361 ) $ 17,296 1 During the second quarter of 2016, the Partnership determined that the state of market conditions in the Marine Transportation reporting unit, including the demand for utilization, day rates and the current oversupply of inland tank barges, indicated that an impairment of goodwill may exist. As a result, the Partnership assessed qualitative factors and determined that the Partnership could not conclude it was more likely than not that the fair value of goodwill exceeded its carrying value. In turn, the Partnership prepared a quantitative analysis of the fair value of the goodwill as of June 30, 2016, based on the weighted average valuation of the aforementioned income and market based valuation approaches. The underlying results of the valuation were driven by our actual results during the six months ended June 30, 2016 and the pricing and market conditions existing as of June 30, 2016, which were below our forecasts at the time of the previous goodwill assessments. Other key estimates, assumptions and inputs used in the valuation included long-term growth rates, discounts rates, terminal values, valuation multiples and relative valuations when comparing the reporting unit to similar businesses or asset bases. Upon completion of the analysis, a $4,145 impairment of all goodwill in the Marine Transportation reporting unit was incurred during the second quarter of 2016. The Partnership did not recognize any other goodwill impairment losses for the year ended December 31, 2016. 2

Leases

Leases	12 Months Ended
	Dec. 31, 2016
Leases [Abstract]
Leases	Leases The Partnership has numerous non-cancelable operating leases primarily for terminal facilities and transportation and other equipment. The leases generally provide that all expenses related to the equipment are to be paid by the lessee. Management expects to renew or enter into similar leasing arrangements for similar equipment upon the expiration of the current lease agreements. The Partnership also has cancelable operating lease land rentals and outside marine vessel charters. The Partnership’s future minimum lease obligations as of December 31, 2016 consist of the following: Fiscal year Operating Leases 2017 $ 10,458 2018 5,633 2019 4,036 2020 3,389 2021 1,041 Thereafter 8,449 Total $ 33,006 Rent expense for continuing operating leases for the years ended December 31, 2016 , 2015 and 2014 was $19,005 , $18,831 and $18,724

Investments in Unconsolidated E

Investments in Unconsolidated Entities and Joint Ventures	12 Months Ended
	Dec. 31, 2016
Equity Method Investments and Joint Ventures [Abstract]
Investments in Unconsolidated Entities and Joint Ventures	Investments in Unconsolidated Entities and Joint Ventures On August 29, 2014, the Partnership acquired ECP's approximate 57.8% Category A interest in Cardinal. Prior to the acquisition, the Partnership owned an approximate 42.2% Category A interest in Cardinal which was accounted for by the equity method. See Note 4 for discussion of the acquisition of the remaining interests. On May 14, 2014, the Partnership acquired from a subsidiary of Atlas, all of the outstanding membership interests in Atlas Holdings for cash of approximately $134,400 at closing. The purchase price was subsequently reduced $501 due to a post-closing working capital adjustment. Atlas Holdings owned a 19.8% limited partner interest and a 0.2% general partner interest in WTLPG. At the time of the purchase, WTLPG was operated by Chevron Pipe Line Company. The 80% interest was subsequently sold to ONEOK Partners, L.P. who assumed operational responsibility. WTLPG owns an approximate 2,300 mile common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. The Partnership recognizes its combined 20% interest in WTLPG as "Investment in unconsolidated entities" on its Consolidated Balance Sheet. The Partnership accounts for its ownership interest in WTLPG under the equity method of accounting with recognition of its ownership interest in the income of WTLPG as "Equity in earnings of unconsolidated entities" on its Consolidated Statement of Operations. In March 2013, the Partnership acquired 100% of the preferred interests in Martin Energy Trading LLC ("MET"), a subsidiary of Martin Resource Management for $15,000 . On August 31, 2014, MET converted its preferred equity to subordinated debt. The resulting $15,000 note receivable from MET bears an annual interest rate of 15% and matures August 31, 2026. MET may prepay any or all of the note balance after September 1, 2016. See Note 13. These investments are accounted for by the equity method. Selected financial information for significant unconsolidated equity method investees is as follows: As of December 31, Years ended December 31, Total Assets Long-Term Debt Members’ Equity/Partners' Capital Revenues Net Income 2016 WTLPG $ 812,464 $ — $ 790,406 $ 88,468 $ 23,883 2015 WTLPG $ 819,342 $ — $ 804,023 $ 100,708 $ 46,294 2014 WTLPG $ 827,697 $ — $ 818,546 $ 95,315 $ 38,698 Cardinal 1 $ — $ — $ — $ 46,488 $ 1,911 1 Financial information for Cardinal includes revenues and net income for the 2014 period prior to the Partnership's acquisition of the 57.8% interest not previously owned. As of December 31, 2016 and 2015, the Partnership’s interest in cash of the unconsolidated equity method investees was $631 and $1,060

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements The Partnership uses a valuation framework based upon inputs that market participants use in pricing certain assets and liabilities. These inputs are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources. Unobservable inputs represent the Partnership's own market assumptions. Unobservable inputs are used only if observable inputs are unavailable or not reasonably available without undue cost and effort. The two types of inputs are further prioritized into the following hierarchy: Level 1: Quoted market prices in active markets for identical assets or liabilities. Level 2: Observable market based inputs or unobservable inputs that are corroborated by market data. Level 3: Unobservable inputs that reflect the entity's own assumptions and are not corroborated by market data. Assets and liabilities measured at fair value on a recurring basis are summarized below: Level 2 December 31, 2016 2015 Commodity derivative contracts, net $ (3,904 ) $ 675 Interest rate derivative contracts — (206 ) The Partnership is required to disclose estimated fair values for its financial instruments. Fair value estimates are set forth below for these financial instruments. The following methods and assumptions were used to estimate the fair value of each class of financial instrument: • Accounts and other receivables, trade and other accounts payable, accrued interest payable, other accrued liabilities, income taxes payable and due from/to affiliates: The carrying amounts approximate fair value due to the short maturity and highly liquid nature of these instruments, and as such these have been excluded from the table below. There is negligible credit risk associated with these instruments. • Note receivable and long-term debt including current portion: The carrying amount of the revolving credit facility approximates fair value due to the debt having a variable interest rate and is in Level 2. The Partnership has not had any indicators which represent a change in the market spread associated with its variable interest rate debt. • The estimated fair value of the senior unsecured notes is based on market prices of similar debt. The estimated fair value of the note receivable from Martin Energy Trading was determined by calculating the net present value of the payments over the life of the note. The note is considered Level 3 due to the lack of observable inputs for similar transactions between related parties. December 31, 2016 December 31, 2015 Carrying Value Fair Value Carrying Value Fair Value Note receivable - MET $ 15,000 $ 15,797 $ 15,000 $ 15,830 2021 Senior unsecured notes 372,239 377,882 371,861 318,000

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities	Derivative Instruments and Hedging Activities The Partnership’s revenues and cost of products sold are materially impacted by changes in NGL prices. Additionally, the Partnership's results of operations are materially impacted by changes in interest rates. In an effort to manage its exposure to these risks, the Partnership periodically enters into various derivative instruments, including commodity and interest rate hedges. All of the Partnership's derivatives are non-hedge derivatives and therefore all changes in fair values are recognized as gains and losses in the earnings of the periods in which they occur. (a) Commodity Derivative Instruments The Partnership from time to time has used derivatives to manage the risk of commodity price fluctuation. Commodity risk is the adverse effect on the value of a liability or future purchase that results from a change in commodity price. The Partnership has established a hedging policy and monitors and manages the commodity market risk associated with potential commodity risk exposure. In addition, the Partnership has focused on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction. The Partnership has entered into hedging transactions as of December 31, 2016 to protect a portion of its commodity price risk exposure. These hedging arrangements are in the form of swaps for NGLs. The Partnership has instruments totaling a notional quantity of 731,000 barrels settling during the period from January 31, 2017 through June 30, 2017. These instruments settle against the applicable pricing source for each grade and location. MET serves as the counterparty for all positions outstanding at December 31, 2016. Due to the acquisition of the remaining interests of Cardinal on August 29, 2014, the Partnership acquired a notional quantity of 3,631,740 MMBtu of natural gas call options with a strike price of $4.50 per MMBtu. These options managed the purchase of base gas at Monroe Gas Storage Company, LLC for the portion of base gas that was leased with Credit Suisse at the acquisition date and was scheduled to be returned in January and February 2015. The options were set to settle in two increments of 2,345,498 MMBtu and 1,286,242 MMBtu on January 31, 2015 and February 28, 2015, respectively. On December 31, 2014, the Partnership terminated these options, resulting in a termination benefit of $3 , which was recorded in "Other, net" in the Partnership's Consolidated Statement of Operations for the year ended December 31, 2014. (b) Interest Rate Derivative Instruments The Partnership is exposed to market risks associated with interest rates. Market risk is the adverse effect on the value of a financial instrument that results from a change in interest rates. We minimize this market risk by establishing and monitoring parameters that limit the types and degree of market risk that may be undertaken. The Partnership enters into interest rate swaps to manage interest rate risk associated with the Partnership’s variable rate credit facility and it's senior unsecured notes. As of December 31, 2015, the Partnership had a fixed-to-variable interest rate swap agreement with a notional principal amount of $50,000 , effectively converting the interest expense associated with a portion of the Partnership's 2021 senior unsecured notes from fixed rate to variable rate based on the LIBOR interest rate. The Partnership's swap agreement has a termination date that corresponds to the maturity date of the 2021 senior unsecured notes. As of December 31, 2015, the maximum length of time over which the Partnership has hedged a portion of its exposure to the variability in the value of this debt due to interest rate risk is through December of 2020. This instrument is recorded on the Partnership's Consolidated Balance Sheets at December 31, 2015 in "Fair value of derivatives" as a non current liability of $206 . This position terminated on January 7, 2016, resulting in a benefit of $160 . During the twelve months ended December 31, 2016 and 2015, the Partnership entered into contracts which provided the counterparty the option to enter into swap contracts to hedge the Partnership's exposure to changes in the fair value of its senior unsecured notes ("interest rate swaptions"). In connection with the interest rate swaption contracts, the Partnership received premiums of $630 and $2,495 , which represented their fair value on the date the transactions were initiated and were initially recorded as derivative liabilities on the Partnership's Consolidated Balance Sheet, during the twelve months ended December 31, 2016 and 2015, respectively. Each of the interest rate swaptions was fully amortized as of December 31, 2016. Interest rate swaption contract premiums received are amortized over the period from initiation of the contract through their termination date. For the twelve months ended December 31, 2016 and 2015, the Partnership recognized $630 and $2,495 , respectively, of premium in "Interest expense, net" on the Partnership's Consolidated Statement of Operations related to the interest rate swaption contracts. On April 1, 2014, the Partnership entered into two fixed-to-variable interest rate swap agreements with an aggregate notional amount of $100,000 each to hedge its exposure to changes in the fair value of its senior unsecured notes. On May 14, 2014 the Partnership terminated these swaps and received a termination benefit of $2,380 upon cancellation of these swap agreements. This amount was recorded in "Interest expense, net" in the Partnership's Consolidated Statement of Operations for the year ended December 31, 2014. Additionally, subsequent to the termination on May 14, 2014, the Partnership entered into two fixed-to-variable interest rate swap agreements on May 14, 2014 with an aggregate notional amount of $100,000 each to hedge its exposure to changes in the fair value of its senior unsecured notes. In August 2014, the Partnership received a scheduled swap settlement related to these agreements totaling $976 . This amount was recorded in "Interest expense, net" in the Partnership's Consolidated Statement of Operations for the year ended December 31, 2014. On September 18, 2014, the Partnership entered into a fixed-to-variable interest rate swap agreement, with an aggregate notional amount of $50,000 , to hedge its exposure to changes in the fair value of its senior unsecured notes. On October 9, 2014, the Partnership terminated each of its three outstanding swaps, receiving a termination benefit of $2,125 , which was recorded in "Interest expense, net" in the Partnership's Consolidated Statement of Operations for the year ended December 31, 2014. Subsequent to the termination on October 9, 2014, the Partnership entered into two fixed-to-variable interest rate swap agreements, each with an aggregate notional amount of $50,000 to hedge its exposure to changes in the fair value of its senior unsecured notes. On October 14, 2014, the Partnership terminated each of these two swaps, receiving a termination benefit of $500 , which was recorded in "Interest expense, net" in the Partnership's Consolidated Statement of Operations for the year ended December 31, 2014. Subsequent to the termination on October 14, 2014, the Partnership entered into two fixed-to-variable interest rate swap agreements, each with an aggregate notional amount of $50,000 to hedge its exposure to changes in the fair value of its senior unsecured notes. On October 14, 2014, the Partnership terminated each of these two swaps, receiving a termination benefit of $711 , which was recorded in "Interest expense, net" in the Partnership's Consolidated Statement of Operations for the year ended December 31, 2014. For information regarding fair value amounts and gains and losses on interest rate derivative instruments and related hedged items, see "Tabular Presentation of Gains and Losses on Derivative Instruments and Related Hedged Items" below. (c) Tabular Presentation of Gains and Losses on Derivative Instruments The following table summarizes the fair values and classification of the Partnership’s derivative instruments in its Consolidated Balance Sheets: Fair Values of Derivative Instruments in the Consolidated Balance Sheet Derivative Assets Derivative Liabilities Fair Values Fair Values Balance Sheet Location December 31, 2016 December 31, 2015 Balance Sheet Location December 31, 2016 December 31, 2015 Derivatives not designated as hedging instruments: Current: Commodity contracts Fair value of derivatives $ — $ 675 Fair value of derivatives $ 3,904 $ — Derivatives not designated as hedging instruments: Non Current: Non Current: Interest rate contracts Fair value of derivatives — — Fair value of derivatives — 206 Total derivatives not designated as hedging instruments $ — $ 675 $ 3,904 $ 206 Effect of Derivative Instruments on the Consolidated Statement of Operations For the Twelve Months Ended December 31, 2016, 2015, and 2014 Location of Gain or (Loss) Recognized in Income on Derivatives Amount of Gain or (Loss) Recognized in Income on Derivatives 2016 2015 2014 Derivatives not designated as hedging instruments: Interest rate swaption contracts Interest expense $ (630 ) $ 2,495 $ — Interest rate contracts Interest expense (366 ) (206 ) 6,692 Commodity contracts Cost of products sold 5,129 818 — Commodity contracts Other income — — (815 ) Total derivatives not designated as hedging instruments $ 4,133 $ 3,107 $ 5,877

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions As of December 31, 2016 , Martin Resource Management owned 6,264,532 of the Partnership’s common units representing approximately 17.7% of the Partnership’s outstanding limited partnership units. Martin Resource Management controls the Partnership's general partner by virtue of its 51% voting interest in Holdings, the sole member of the Partnership's general partner. The Partnership’s general partner, MMGP, owns a 2% general partner interest in the Partnership and the Partnership’s incentive distribution rights. The Partnership’s general partner’s ability, as general partner, to manage and operate the Partnership, and Martin Resource Management’s ownership as of December 31, 2016 , of approximately 17.7% of the Partnership’s outstanding limited partnership units, effectively gives Martin Resource Management the ability to veto some of the Partnership’s actions and to control the Partnership’s management. The following is a description of the Partnership’s material related party agreements: Omnibus Agreement Omnibus Agreement . The Partnership and its general partner are parties to the Omnibus Agreement dated November 1, 2002, with Martin Resource Management that governs, among other things, potential competition and indemnification obligations among the parties to the agreement, related party transactions, the provision of general administration and support services by Martin Resource Management and the Partnership’s use of certain Martin Resource Management trade names and trademarks. The Omnibus Agreement was amended on November 25, 2009, to include processing crude oil into finished products including naphthenic lubricants, distillates, asphalt and other intermediate cuts. The Omnibus Agreement was amended further on October 1, 2012, to permit the Partnership to provide certain lubricant packaging products and services to Martin Resource Management. Non-Competition Provisions . Martin Resource Management has agreed for so long as it controls the general partner of the Partnership, not to engage in the business of: • providing terminalling and storage services for petroleum products and by-products including the refining, blending and packaging of finished lubricants; • providing marine transportation of petroleum products and by-products; • distributing NGLs; and • manufacturing and selling sulfur-based fertilizer products and other sulfur-related products. This restriction does not apply to: • the ownership and/or operation on the Partnership’s behalf of any asset or group of assets owned by it or its affiliates; • any business operated by Martin Resource Management, including the following: ◦ providing land transportation of various liquids; ◦ distributing fuel oil, sulfuric acid, marine fuel and other liquids; ◦ providing marine bunkering and other shore-based marine services in Texas, Louisiana, Mississippi, Alabama, and Florida; ◦ operating a crude oil gathering business in Stephens, Arkansas; ◦ providing crude oil gathering, refining, and marketing services of base oils, asphalt, and distillate products in Smackover, Arkansas; ◦ providing crude oil marketing and transportation from the well head to the end market; ◦ operating an environmental consulting company; ◦ operating an engineering services company; ◦ supplying employees and services for the operation of the Partnership's business; ◦ ◦ operating a crude oil, natural gas, natural gas liquids, and biofuels optimization business; and ◦ operating, solely for the Partnership's account, the asphalt facilities in Omaha, Nebraska, Port Neches, Texas and South Houston, Texas. • any business that Martin Resource Management acquires or constructs that has a fair market value of less than $5,000 ; • any business that Martin Resource Management acquires or constructs that has a fair market value of $5,000 or more if the Partnership has been offered the opportunity to purchase the business for fair market value and the Partnership declines to do so with the concurrence of the Conflicts Committee; and • any business that Martin Resource Management acquires or constructs where a portion of such business includes a restricted business and the fair market value of the restricted business is $5,000 or more and represents less than 20% of the aggregate value of the entire business to be acquired or constructed; provided that, following completion of the acquisition or construction, the Partnership will be provided the opportunity to purchase the restricted business. Services. Under the Omnibus Agreement, Martin Resource Management provides the Partnership with corporate staff, support services, and administrative services necessary to operate the Partnership’s business. The Omnibus Agreement requires the Partnership to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes on the Partnership’s behalf or in connection with the operation of the Partnership’s business. There is no monetary limitation on the amount the Partnership is required to reimburse Martin Resource Management for direct expenses. In addition to the direct expenses, under the Omnibus Agreement, the Partnership is required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. Effective January 1, 2017, through December 31, 2017, the Conflicts Committee approved an annual reimbursement amount for indirect expenses of $16,416 . The Partnership reimbursed Martin Resource Management for $13,033 , $13,679 and $12,535 of indirect expenses for the years ended December 31, 2016, 2015 and 2014, respectively. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually. These indirect expenses are intended to cover the centralized corporate functions Martin Resource Management provides for the Partnership, such as accounting, treasury, clerical, engineering, legal, billing, information technology, administration of insurance, general office expenses and employee benefit plans and other general corporate overhead functions the Partnership shares with Martin Resource Management retained businesses. The provisions of the Omnibus Agreement regarding Martin Resource Management’s services will terminate if Martin Resource Management ceases to control the general partner of the Partnership. Related Party Transactions . The Omnibus Agreement prohibits the Partnership from entering into any material agreement with Martin Resource Management without the prior approval of the Conflicts Committee. For purposes of the Omnibus Agreement, the term material agreements means any agreement between the Partnership and Martin Resource Management that requires aggregate annual payments in excess of then-applicable agreed upon reimbursable amount of indirect general and administrative expenses. Please read "Services" above. License Provisions. Under the Omnibus Agreement, Martin Resource Management has granted the Partnership a nontransferable, nonexclusive, royalty-free right and license to use certain of its trade names and marks, as well as the trade names and marks used by some of its affiliates. Amendment and Termination. The Omnibus Agreement may be amended by written agreement of the parties; provided, however, that it may not be amended without the approval of the Conflicts Committee if such amendment would adversely affect the unitholders. The Omnibus Agreement was first amended on November 25, 2009, to permit the Partnership to provide refining services to Martin Resource Management. The Omnibus Agreement was amended further on October 1, 2012, to permit the Partnership to provide certain lubricant packaging products and services to Martin Resource Management. Such amendments were approved by the Conflicts Committee. The Omnibus Agreement, other than the indemnification provisions and the provisions limiting the amount for which the Partnership will reimburse Martin Resource Management for general and administrative services performed on its behalf, will terminate if the Partnership is no longer an affiliate of Martin Resource Management. Motor Carrier Agreement Motor Carrier Agreement. The Partnership is a party to a motor carrier agreement effective January 1, 2006 as amended, with Martin Transport, Inc., a wholly owned subsidiary of Martin Resource Management through which Martin Transport, Inc. operates its land transportation operations. Under the agreement, Martin Transport, Inc. agreed to transport the Partnership's NGLs as well as other liquid products. Term and Pricing. The agreement has an initial term that expired in December 2007 but automatically renews for consecutive one year periods unless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicable term. The Partnership has the right to terminate this agreement at any time by providing 90 days prior notice. Under this agreement, Martin Transport, Inc. transports the Partnership’s NGL shipments as well as other liquid products. These rates are subject to any adjustments which are mutually agreed or in accordance with a price index. Additionally, during the term of the agreement, shipping charges are also subject to fuel surcharges determined on a weekly basis in accordance with the U.S. Department of Energy’s national diesel price list. Indemnification. Martin Transport has indemnified us against all claims arising out of the negligence or willful misconduct of Martin Transport and its officers, employees, agents, representatives and subcontractors. We indemnified Martin Transport against all claims arising out of the negligence or willful misconduct of us and our officers, employees, agents, representatives and subcontractors. In the event a claim is the result of the joint negligence or misconduct of Martin Transport and us, our indemnification obligations will be shared in proportion to each party’s allocable share of such joint negligence or misconduct. Marine Agreements Marine Transportation Agreement . The Partnership is a party to a marine transportation agreement effective January 1, 2006, as amended, under which the Partnership provides marine transportation services to Martin Resource Management on a spot-contract basis at applicable market rates. Effective each January 1, this agreement automatically renews for consecutive one year periods unless either party terminates the agreement by giving written notice to the other party at least 60 days prior to the expiration of the then applicable term. The fees the Partnership charges Martin Resource Management are based on applicable market rates. Marine Fuel. The Partnership is a party to an agreement with Martin Resource Management dated November 1, 2002 under which Martin Resource Management provides the Partnership with marine fuel from its locations in the Gulf of Mexico at a fixed rate in excess of a price index. Under this agreement, the Partnership agreed to purchase all of its marine fuel requirements that occur in the areas serviced by Martin Resource Management. Terminal Services Agreements Diesel Fuel Terminal Services Agreement. Effective January 1, 2016, the Partnership entered into a new terminalling services agreement under which the Partnership provides terminal services to Martin Resource Management for marine fuel distribution. The per gallon throughput fee the Partnership charges under this agreement was increased when compared to the previous agreement and may be adjusted annually based on a price index. This agreement was amended on January 1, 2017 to reduce the minimum throughput requirements under such agreement. Miscellaneous Terminal Services Agreements. The Partnership is currently party to several terminal services agreements and from time to time the Partnership may enter into other terminal service agreements for the purpose of providing terminal services to related parties. Individually, each of these agreements is immaterial but when considered in the aggregate they could be deemed material. These agreements are throughput based with a minimum volume commitment. Generally, the fees due under these agreements are adjusted annually based on a price index. Other Agreements Cross Tolling Agreement. The Partnership is a party to an amended and restated tolling agreement with Cross Oil Refining and Marketing, Inc. ("Cross") dated October 28, 2014, under which the Partnership processes crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts for Cross. The tolling agreement expires November 25, 2031. Under this tolling agreement, Cross agreed to process a minimum of 6,500 barrels per day of crude oil at the facility at a fixed price per barrel. Any additional barrels are processed at a modified price per barrel. In addition, Cross agreed to pay a monthly reservation fee and a periodic fuel surcharge fee based on certain parameters specified in the tolling agreement. All of these fees (other than the fuel surcharge) are subject to escalation annually based upon the greater of 3% or the increase in the Consumer Price Index for a specified annual period. In addition, on the third, sixth and ninth anniversaries of the agreement, the parties can negotiate an upward or downward adjustment in the fees subject to their mutual agreement. Sulfuric Acid Sales Agency Agreement . The Partnership is party to a second amended and restated sulfuric acid sales agency agreement dated August 5, 2013, under which Martin Resource Management purchases and markets the sulfuric acid produced by the Partnership’s sulfuric acid production plant at Plainview, Texas, that is not consumed by the Partnership’s internal operations. This agreement, as amended, will remain in place until the Partnership terminates it by providing 180 days’ written notice. Under this agreement, the Partnership sells all of its excess sulfuric acid to Martin Resource Management. Martin Resource Management then markets such acid to third-parties and the Partnership shares in the profit of Martin Resource Management’s sales of the excess acid to such third parties. Other Miscellaneous Agreements. From time to time the Partnership enters into other miscellaneous agreements with Martin Resource Management for the provision of other services or the purchase of other goods. The tables below summarize the related party transactions that are included in the related financial statement captions on the face of the Partnership’s Consolidated Statements of Operations. The revenues, costs and expenses reflected in these tables are tabulations of the related party transactions that are recorded in the corresponding caption of the Consolidated Statements of Operations and do not reflect a statement of profits and losses for related party transactions. The impact of related party revenues from sales of products and services is reflected in the Consolidated Statements of Operations as follows: Revenues: 2016 2015 2014 Terminalling and storage $ 82,437 $ 78,233 $ 74,467 Marine transportation 21,767 27,724 24,389 Natural gas services 699 878 — Product sales: Natural gas services 8 196 3,064 Sulfur services 2,006 3,639 3,921 Terminalling and storage 1,020 1,836 676 3,034 5,671 7,661 $ 107,937 $ 112,506 $ 106,517 The impact of related party cost of products sold is reflected in the Consolidated Statements of Operations as follows: Cost of products sold: Natural gas services $ 22,886 $ 25,797 $ 37,703 Sulfur services 15,339 16,579 18,390 Terminalling and storage 13,838 17,718 36,341 $ 52,063 $ 60,094 $ 92,434 The impact of related party operating expenses is reflected in the Consolidated Statements of Operations as follows: Operating expenses: Marine transportation $ 28,107 $ 32,373 $ 37,703 Natural gas services 9,258 8,639 4,870 Sulfur services 5,995 6,928 7,479 Terminalling and storage 27,481 29,931 29,525 $ 70,841 $ 77,871 $ 79,577 The impact of related party selling, general and administrative expenses is reflected in the Consolidated Statements of Operations as follows: Selling, general and administrative: Marine transportation $ 30 $ 29 $ 30 Natural gas services 7,566 6,216 6,039 Sulfur services 2,732 2,760 3,201 Terminalling and storage 2,526 2,284 1,874 Indirect overhead allocation, net of reimbursement 13,036 13,679 12,535 $ 25,890 $ 24,968 $ 23,679 Other Related Party Transactions As discussed in Note 10, during March 2013, the Partnership acquired 100% of the preferred interests in MET, a subsidiary of Martin Resource Management, for $15,000 . On August 31, 2014, MET converted its preferred equity to subordinated debt. The resulting $15,000 note receivable from MET bears an annual interest rate of 15% and matures August 31, 2026. MET may prepay any or all of the note balance on or after September 1, 2016. The note is recorded in "Note receivable - Martin Energy Trading LLC" on the Partnership's Consolidated Balance Sheet. Interest income for the years ended December 31, 2016, 2015, and 2014 was $2,256 , $2,250 and $752 , respectively, and is included in "Interest expense, net" in the Consolidated Statements of Operations.

Supplemental Balance Sheet Info

Supplemental Balance Sheet Information	12 Months Ended
	Dec. 31, 2016
Balance Sheet Related Disclosures [Abstract]
Supplemental Balance Sheet Information	Supplemental Balance Sheet Information Components of "Intangibles and other assets, net" at December 31, 2016 and 2015 were as follows: 2016 2015 Customer contracts and relationships, net $ 36,528 $ 50,452 Other intangible assets 2,280 1,818 Other 6,066 6,044 $ 44,874 $ 58,314 Other intangible assets consist of covenants not-to-compete, technology-based assets, and customer relationships. Aggregate amortization expense for customer contracts and other intangible assets included in continuing operations was $19,548 , $22,115 , and $9,772 , for the years ended December 31, 2016 , 2015 and 2014 , respectively, and accumulated amortization amounted to $48,876 and $32,842 at December 31, 2016 and 2015 , respectively. Estimated amortization expense for customer contract and relationships and other intangible assets for the years subsequent to December 31, 2016 are as follows: 2017 - $11,804 ; 2018 - $7,472 ; 2019 - $4,471 ; 2020 - $4,440 ; 2021 - $4,319 ; subsequent years - $6,302 . Components of "Other accrued liabilities" at December 31, 2016 and 2015 were as follows: 2016 2015 Accrued interest $ 10,629 $ 10,365 Asset retirement obligations 7,953 — Property and other taxes payable 6,443 6,668 Accrued payroll 1,672 1,389 Other 20 111 $ 26,717 $ 18,533 The schedule below summarizes the changes in our asset retirement obligations: Year Ended December 31, 2016 2015 (In thousands) Beginning asset retirement obligations $ 2,163 $ 2,052 Revisions to existing liabilities 1 14,379 — Accretion 178 111 Liabilities settled (302 ) — Ending asset retirement obligations 16,418 2,163 Current portion of asset retirement obligations 2 (7,953 ) — Long-term portion of asset retirement obligations 3 $ 8,465 $ 2,163 1 Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, discount rates, and the estimated remaining useful life of the assets. The 2016 revisions reflect changes in removal cost estimates and the estimated remaining useful life of assets. 2 The current portion of asset retirement obligations is included in "Other current liabilities" on the Partnership's Consolidated Balance Sheets. 3

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt At December 31, 2016 and 2015 , long-term debt consisted of the following: 2016 2015 $664,444 1 Revolving credit facility at variable interest rate (3.76% 2 weighted average at December 31, 2016), due March 2020 secured by substantially all of the Partnership’s assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in the Partnership’s operating subsidiaries and equity method investees, net of unamortized debt issuance costs of $7,132 and $4,858, respectively 3 $ 435,868 $ 493,142 $400,000 Senior notes, 7.25% interest, including unamortized premium of $1,262 and $1,568, respectively, also net of unamortized debt issuance costs of $2,823 and $3,507 respectively, issued $250,000 February 2013 and $150,000 April 2014, $26,200 repurchased during 2015, due February 2021, unsecured 3,4 372,239 371,861 Total long-term debt $ 808,107 $ 865,003 1 On April 27, 2016, the Partnership made certain strategic amendments to its credit facility which, among other things, decreased its borrowing capacity from $700,000 to $664,444 and extended the maturity date of the facility from March 28, 2018 to March 28, 2020. The reduction in capacity resulted in the write-off of $820 of deferred debt costs. 2 Interest rate fluctuates based on the LIBOR rate plus an applicable margin set on the date of each advance. The margin above LIBOR is set every three months. Indebtedness under the credit facility bears interest at LIBOR plus an applicable margin or the base prime rate plus an applicable margin. All amounts outstanding at December 31, 2016 and December 31, 2015 were at LIBOR plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 2.00% to 3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 1.00% to 2.00% . The applicable margin for LIBOR borrowings at December 31, 2016 is 3.00% . The credit facility contains various covenants which limit the Partnership’s ability to make certain investments and acquisitions; enter into certain agreements; incur indebtedness; sell assets; and make certain amendments to the Omnibus Agreement. The Partnership is permitted to make quarterly distributions so long as no event of default exists. 3 The Partnership is in compliance with all debt covenants as of December 31, 2016. 4 The 2021 indentures restrict the Partnership’s ability to sell assets; pay distributions or repurchase units or redeem or repurchase subordinated debt; make investments; incur or guarantee additional indebtedness or issue preferred units; and consolidate, merge or transfer all or substantially all of its assets. Many of these covenants will terminate if the notes achieve an investment grade rating from each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no default (as defined in the indentures) has occurred. The Partnership paid cash interest, net of proceeds received from interest rate swaptions, in the amount of $46,046 , $43,376 , and $37,112 for the years ended December 31, 2016, 2015 and 2014, respectively. Capitalized interest was $1,126 , $1,944 , and $1,437

Partners' Capital

Partners' Capital	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Partners' Capital	Partners' Capital As of December 31, 2016, partners’ capital consisted of 35,452,062 common limited partner units, representing a 98% partnership interest and a 2.0% general partner interest. Martin Resource Management, through subsidiaries, owned 6,264,532 of the Partnership's common limited partnership units representing approximately 17.7% of the Partnership's outstanding common limited partnership units. MMGP, the Partnership's general partner, owns the 2.0% general partnership interest. The partnership agreement of the Partnership (the "Partnership Agreement") contains specific provisions for the allocation of net income and losses to each of the partners for purposes of maintaining their respective partner capital accounts. Issuance of Common Units On September 29, 2014, the Partnership completed a public offering of 3,450,000 common units at a price of $36.91 per common unit, before the payment of underwriters' discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 3,450,000 common units, net of underwriters' discounts, commissions and offering expenses, were $122,176 . The Partnership's general partner contributed $2,599 in cash to the Partnership in conjunction with the issuance in order to maintain its 2.0% general partner interest in the Partnership. All of the net proceeds were used to pay down outstanding amounts under the Partnership's revolving credit facility. On August 29, 2014, the Partnership closed a private equity sale with Martin Resource Management, under which Martin Resource Management invested $45,000 in cash in exchange for 1,171,265 common units. The pricing of $38.42 per common unit was based on the 10 -day weighted average price of the Partnership's common units for the 10 trading days ending August 8, 2014. In connection with the issuance of these common units, the Partnership's general partner contributed $918 in order to maintain its 2.0% general partner interest in the Partnership. All of the net proceeds were used to pay down outstanding amounts under the Partnership's revolving credit facility. On May 12, 2014, the Partnership completed a public offering of 3,600,000 common units at a price of $41.51 per common unit, before the payment of underwriters' discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 3,600,000 common units, net of underwriters' discounts, commissions and offering expenses, were $143,431 . The Partnership's general partner contributed $3,049 in cash to the Partnership in conjunction with the issuance in order to maintain its 2.0% general partner interest in the Partnership. All of the net proceeds were used to pay down outstanding amounts under the Partnership's revolving credit facility. In March 2014, the Partnership entered into an equity distribution agreement with multiple underwriters (the "Sales Agents") for the ongoing distribution of the Partnership's common units. Pursuant to this program, the Partnership offered and sold common unit equity through the Sales Agents for aggregate proceeds of $0 and $21,501 for the years ended December 31, 2015 and 2014, respectively. The Partnership paid $ 591 and $380 in equity issuance related costs for the years ended December 31, 2015 and 2014, respectively. Under the the program, the Partnership issued 522,121 common units during the year ended December 31, 2014. Common units issued were at market prices prevailing at the time of the sale. The Partnership also received capital contributions from the Partnership's general partner of $441 during the year ended December 31, 2014 related to these issuances to maintain its 2.0% general partner interest in the Partnership. The net proceeds from the common unit issuances were used to pay down outstanding amounts under the Partnership's revolving credit facility. Incentive Distribution Rights MMGP, holds a 2.0% general partner interest and certain incentive distribution rights ("IDRs") in the Partnership. IDRs are a separate class of non-voting limited partner interest that may be transferred or sold by the general partner under the terms of the Partnership Agreement, and represent the right to receive an increasing percentage of cash distributions after the minimum quarterly distribution and any cumulative arrearages on common units once certain target distribution levels have been achieved. The Partnership is required to distribute all of its available cash from operating surplus, as defined in the Partnership Agreement. The target distribution levels entitle the general partner to receive 2.0% of quarterly cash distributions up to $0.55 per unit, 15% of quarterly cash distributions in excess of $0.55 per unit until all unitholders have received $0.625 per unit, 25% of quarterly cash distributions in excess of $0.625 per unit until all unitholders have received $0.75 per unit and 50% of quarterly cash distributions in excess of $0.75 per unit. For the years ended December 31, 2016, 2015 and 2014, the general partner was allocated $7,786 , $15,571 , and $0 in incentive distributions. Distributions of Available Cash The Partnership distributes all of its available cash (as defined in the Partnership Agreement) within 45 days after the end of each quarter to unitholders of record and to the general partner. Available cash is generally defined as all cash and cash equivalents of the Partnership on hand at the end of each quarter less the amount of cash reserves its general partner determines in its reasonable discretion is necessary or appropriate to: (i) provide for the proper conduct of the Partnership’s business; (ii) comply with applicable law, any debt instruments or other agreements; or (iii) provide funds for distributions to unitholders and the general partner for any one or more of the next four quarters, plus all cash on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Net Income per Unit The Partnership follows the provisions of the FASB ASC 260-10 related to earnings per share, which addresses the application of the two-class method in determining income per unit for master limited partnerships having multiple classes of securities that may participate in partnership distributions accounted for as equity distributions. Undistributed earnings are allocated to the general partner and limited partners utilizing the contractual terms of the Partnership Agreement. Distributions to the general partner pursuant to the IDRs are limited to available cash that will be distributed as defined in the Partnership Agreement. Accordingly, the Partnership does not allocate undistributed earnings to the general partner for the IDRs because the general partner's share of available cash is the maximum amount that the general partner would be contractually entitled to receive if all earnings for the period were distributed. When current period distributions are in excess of earnings, the excess distributions for the period are to be allocated to the general partner and limited partners based on their respective sharing of losses specified in the Partnership Agreement. Additionally, as required under FASB ASC 260-10-45-61A, unvested share-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities, as defined in FASB ASC 260-10-20, for earnings per unit calculations. For purposes of computing diluted net income per unit, the Partnership uses the more dilutive of the two-class and if-converted methods. Under the if-converted method, the weighted-average number of subordinated units outstanding for the period is added to the weighted-average number of common units outstanding for purposes of computing basic net income per unit and the resulting amount is compared to the diluted net income per unit computed using the two-class method. The following is a reconciliation of net income from continuing operations and net income from discontinued operations allocated to the general partner and limited partners for purposes of calculating net income attributable to limited partners per unit: Years Ended December 31, 2016 2015 2014 Continuing operations: Income (loss) from continuing operations $ 31,652 $ 37,165 $ (6,367 ) Less general partner’s interest in net income: Distributions payable on behalf of IDRs 7,786 15,078 2,033 Distributions payable on behalf of general partner interest 2,058 2,585 1,181 General partner interest in undistributed loss (1,425 ) (1,842 ) (1,308 ) Less income (loss) allocable to unvested restricted units 90 136 (18 ) Limited partners’ interest in net income (loss) $ 23,143 $ 21,208 $ (8,255 ) Years Ended December 31, 2016 2015 2014 Discontinued operations: Income (loss) from discontinued operations $ — $ 1,215 $ (5,338 ) Less general partner’s interest in net income: Distributions payable on behalf of IDRs — 493 1,704 Distributions payable on behalf of general partner interest — 84 990 General partner interest in undistributed loss — (60 ) (1,097 ) Less income (loss) allocable to unvested restricted units — 4 (14 ) Limited partners’ interest in net income (loss) $ — $ 694 $ (6,921 ) The Partnership allocates the general partner's share of earnings between continuing and discontinued operations as a proportion of net income from continuing and discontinued operations to total net income. The weighted average units outstanding for basic net income per unit were 35,347,032 , 35,308,649 and 30,785,035 for the years ended December 31, 2016 , 2015 and 2014 , respectively. All outstanding units were included in the computation of diluted earnings per unit and weighted based on the number of days such units were outstanding during the period presented. For diluted net income per unit, the weighted average units outstanding were increased by 28,231 and 62,880

Unit Based Awards

Unit Based Awards	12 Months Ended
	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Unit Based Awards	Unit Based Awards The Partnership recognizes compensation cost related to stock-based awards to employees in its consolidated financial statements in accordance with certain provisions of ASC 718. The Partnership recognizes compensation costs related to stock-based awards to directors under certain provisions of ASC 505-50-55 related to equity-based payments to non-employees. Amounts recognized in selling, general, and administrative expense in the consolidated financial statements with respect to these plans are as follows: For the Year Ended December 31, 2016 2015 2014 Employees $ 783 $ 1,338 $ 537 Non-employee directors 121 91 280 Total unit-based compensation expense $ 904 $ 1,429 $ 817 Long-Term Incentive Plans The Partnership's general partner has a long term incentive plan for employees and directors of the general partner and its affiliates who perform services for the Partnership. The plan consists of two components, restricted units and unit options. The plan currently permits the grant of awards covering an aggregate of 725,000 common units, 241,667 of which may be awarded in the form of restricted units and 483,333 of which may be awarded in the form of unit options. The plan is administered by the compensation committee of the general partner’s board of directors ("Compensation Committee"). Restricted Units. A restricted unit is a unit that is granted to grantees with certain vesting restrictions. Once these restrictions lapse, the grantee is entitled to full ownership of the unit without restrictions. In addition, the restricted units will vest upon a change of control of the Partnership, the general partner or Martin Resource Management or if the general partner ceases to be an affiliate of Martin Resource Management. The Partnership intends the issuance of the common units upon vesting of the restricted units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive, and the Partnership will receive no remuneration for the units. The restricted units issued to directors generally vest in equal annual installments over a four -year period. Restricted units issued to employees generally cliff vest after three years of service. The restricted units are valued at their fair value at the date of grant which is equal to the market value of common units on such date. A summary of the restricted unit activity for the year ended December 31, 2016 is provided below: Number of Units Weighted Average Grant-Date Fair Value Per Unit Non-vested, beginning of year 150,474 $ 28.89 Granted 13,800 $ 15.13 Vested (58,224 ) $ 30.61 Forfeited (2,250 ) $ 28.50 Non-Vested, end of year 103,800 $ 26.54 Aggregate intrinsic value, end of year $ 1,905 A summary of the restricted units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) during the years ended December 31, 2016, 2015 and 2014 is provided below: For the Year Ended December 31, 2016 2015 2014 Aggregate intrinsic value of units vested $ 1,233 $ 110 $ 514 Fair value of units vested $ 1,773 $ 128 $ 450 As of December 31, 2016, there was $1,058 of unrecognized compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 1.5 years. Unit Options.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The operations of a partnership are generally not subject to income taxes because its income is taxed directly to its partners. The Partnership is subject to the Texas margin tax, which is considered a state income tax, and is included in income tax expense on the Consolidated Statements of Operations. Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed as an income tax and, therefore, the recognition of deferred taxes applies to the margin tax. The impact on deferred taxes as a result of this provision is immaterial. State income taxes attributable to the Texas margin tax of $726 , $1,048 and $1,137 were recorded in income tax expense for the years ended December 31, 2016 , 2015 and 2014 , respectively. A current income tax liability of $870 , and $985 existed at December 31, 2016 and 2015 , respectively. Cash paid for income taxes was $841 , $1,237 , and $1,167 for the years ended December 31, 2016 , 2015 and 2014 , respectively. The Bipartisan Budget Act of 2015 provides that any tax adjustments resulting from partnership audits will generally be determined, and any resulting tax, interest and penalties collected, at the partnership level for tax years beginning after December 31, 2017. The Bipartisan Budget Act of 2015 allows a partnership to elect to apply these provisions to any return of the partnership filed for partnership taxable years beginning after the date of the enactment, November 2, 2015. The Partnership does not intend to elect to apply these provisions for any tax return filed for partnership taxable years beginning before January 1, 2018.

Business Segments

Business Segments	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
Business Segments	Business Segments The Partnership has four reportable segments: terminalling and storage, natural gas services, marine transportation, and sulfur services. The Partnership’s reportable segments are strategic business units that offer different products and services. The operating income of these segments is reviewed by the chief operating decision maker to assess performance and make business decisions. The accounting policies of the operating segments are the same as those described in Note 2. The Partnership evaluates the performance of its reportable segments based on operating income. There is no allocation of administrative expenses or interest expense. The Natural Gas Services segment information below excludes the discontinued operations of the Floating Storage Assets for 2015 and 2014. See Note 5. Operating Revenues Intersegment Eliminations Operating Revenues After Eliminations Depreciation and Amortization Operating Income (Loss) after Eliminations Capital Expenditures and Plant Turnaround Costs Year Ended December 31, 2016: Terminalling and storage $ 242,363 $ (5,653 ) $ 236,710 $ 45,484 $ 40,660 $ 26,097 Natural gas services 391,333 — 391,333 28,081 41,438 4,807 Sulfur services 141,058 — 141,058 7,995 23,393 5,093 Marine transportation 61,233 (2,943 ) 58,290 10,572 (16,039 ) 2,334 Indirect selling, general, and administrative — — — — (16,794 ) — Total $ 835,987 $ (8,596 ) $ 827,391 $ 92,132 $ 72,658 $ 38,331 Year Ended December 31, 2015: Terminalling and storage $ 270,440 $ (5,670 ) $ 264,770 $ 38,731 $ 15,704 $ 40,421 Natural gas services 523,160 — 523,160 34,072 41,220 24,330 Sulfur services 170,161 — 170,161 8,455 23,604 1,201 Marine transportation 81,784 (3,031 ) 78,753 10,992 8,576 2,775 Indirect selling, general, and administrative — — — — (18,951 ) — Total $ 1,045,545 $ (8,701 ) $ 1,036,844 $ 92,250 $ 70,153 $ 68,727 Year Ended December 31, 2014: Terminalling and storage $ 326,654 $ (5,191 ) $ 321,463 $ 37,622 $ 24,993 $ 53,450 Natural gas services 1,013,835 — 1,013,835 13,090 34,574 24,194 Sulfur services 215,471 — 215,471 8,176 19,465 4,115 Marine transportation 97,049 (5,677 ) 91,372 9,942 7,551 11,498 Indirect selling, general, and administrative — — — — (18,712 ) — Total $ 1,653,009 $ (10,868 ) $ 1,642,141 $ 68,830 $ 67,871 $ 93,257 Revenues from two customers in the Natural Gas Services segment were $122,381 , $148,273 and $265,434 for the years ended December 31, 2016 , 2015 and 2014 , respectively. The Partnership's assets by reportable segment as of December 31, 2016 and 2015 , are as follows: 2016 2015 Total assets: Terminalling and storage $ 328,098 $ 417,202 Natural gas services 684,722 694,333 Sulfur services 125,356 134,108 Marine transportation 108,187 134,830 Total assets $ 1,246,363 $ 1,380,473

Quarterly Financial Information

Quarterly Financial Information	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Information	Quarterly Financial Information Consolidated Quarterly Income Statement Information (Unaudited) First Quarter Second Quarter Third Quarter Fourth Quarter (Dollar in thousands, except per unit amounts) 2016 Revenues $ 225,605 $ 190,348 $ 174,537 $ 236,901 Operating income 24,338 10,256 9,176 28,888 Equity in earnings of unconsolidated entities 1,677 805 1,120 1,112 Net income (loss) $ 15,914 $ (1,211 ) $ (933 ) $ 17,882 Limited partners' interest in net income (loss) per limited partner unit $ 0.33 $ (0.14 ) (0.03 ) $ 0.49 First Quarter Second Quarter Third Quarter Fourth Quarter (Dollar in thousands, except per unit amounts) 2015 Revenues $ 305,353 $ 251,099 $ 226,021 $ 254,371 Operating income 24,702 19,630 12,034 13,787 Equity in earnings of unconsolidated entities 1,740 1,649 2,363 3,234 Income from continuing operations 16,033 10,961 3,330 6,841 Income from discontinued operations 1,215 — — — Net income $ 17,248 $ 10,961 $ 3,330 $ 6,841 Limited partners' interest in net income (loss) per limited partner unit $ 0.37 0.19 (0.02 ) 0.08

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies From time to time, the Partnership is subject to various claims and legal actions arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Partnership. Pursuant to a Purchase Price Reimbursement Agreement between the Partnership and Martin Resource Management related to the Partnership’s acquisition of the Redbird Gas Storage LLC ("Redbird") Class A interests on October 2, 2012, beginning in the second quarter of 2015, Martin Resource Management will reimburse the Partnership $750 each quarter for four consecutive quarters as a reduction in the purchase price of the Redbird Class A interests. These payments are a result of Cardinal not achieving certain financial targets set forth in the Purchase Price Reimbursement Agreement. These payments are considered a reduction of the excess of the purchase price over the carrying value of the assets transferred to the Partnership from Martin Resource Management and will be recorded as an adjustment to "Partners' capital" in each quarter the payments are made. The agreement further provided for purchase price reimbursements of up to $4,500 related to 2016 in the event certain financial conditions are not met. For the years ended December 31, 2016 and 2015, the Partnership received $4,125 and $2,250 , respectively, related to the Purchase Price Reimbursement Agreement. The Partnership expects to receive the final payment of $1,125 under this agreement during the first quarter of 2017. In 2015, the Partnership was named as a defendant in the cause J. A. Davis Properties, LLC v. Martin Operating Partnership L.P., in the 38th Judicial District Court, Cameron Parish, Louisiana. The plaintiff alleges that the Partnership has breached a lease agreement by failing to perform work to the plaintiff's property as required under the lease agreement. The plaintiff originally sought to evict the Partnership from the leased property and to recover damages. Presently, the plaintiff is only pursuing damages. The Partnership intends to vigorously defend this matter and has asserted appropriate counterclaims against the plaintiff. At this time, the Partnership is unable to ascertain the damages, if any, that could ultimately be awarded against it. A trial on the merits is scheduled for July 10, 2017. On December 31, 2015, the Partnership received a demand from a customer in its lubricants packaging business for defense and indemnity in connection with at least five lawsuits filed against it in the United States District Courts, which

Condensed Consolidating Financi

Condensed Consolidating Financial Statements	12 Months Ended
	Dec. 31, 2016
Consolidating Financial Statements [Abstract]
Condensed Consolidating Financial Statements	Condensed Consolidating Financial Information

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2016
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events Repayment of Note Receivable. On February 14, 2017, the Partnership notified Martin Resource Management that it would be requesting voluntary repayment of the Note Receivable due from MET of $15,000 plus accrued interest and MET has agreed to do so in a timely manner. Acquisition of Terminalling Assets. On February 14, 2017, the Partnership entered into a Membership Interests Purchase Agreement (the “Purchase Agreement”) with Martin Resource Management and MRMC Equipment Holdings LLC, a wholly-owned subsidiary of Martin Resource Management, to acquire 100% of the membership interests of MEH South Texas Terminals LLC (“MEH”) for a purchase price of $ 27,420 (the “Hondo Acquisition”). MEH is currently constructing in Hondo, Texas an asphalt terminal facility (“the Hondo Terminal”), which will serve the asphalt market in San Antonio, Texas and surrounding areas. The Hondo Acquisition is expected to close on or about February 28, 2017. After closing, the Partnership will spend $8,580 to finalize construction of the Hondo Terminal with substantial completion expected to be on or about July 1, 2017. Martin Resource Management is obligated to pay us the amount required to complete the construction of the Hondo Terminal in excess of $8,580 , if any. Quarterly Distribution. On January 19, 2017, the Partnership declared a quarterly cash distribution of $0.50 per common unit for the fourth quarter of 2016, or $2.00

Significant Accounting Polici32

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Principles of Presentation and Consolidation	Principles of Presentation and Consolidation The consolidated financial statements include the financial statements of the Partnership and its wholly-owned subsidiaries and equity method investees. In the opinion of the management of the Partnership’s general partner, all adjustments and elimination of significant intercompany balances necessary for a fair presentation of the Partnership’s results of operations, financial position and cash flows for the periods shown have been made. All such adjustments are of a normal recurring nature. In addition, the Partnership evaluates its relationships with other entities to identify whether they are variable interest entities under certain provisions of the Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC"), 810-10 and to assess whether it is the primary beneficiary of such entities. If the determination is made that the Partnership is the primary beneficiary, then that entity is included in the consolidated financial statements in accordance with ASC 810-10. No such variable interest entities exist as of December 31, 2016 or 2015. As discussed in Note 5, on February 12, 2015, the Partnership sold all six 16,101 barrel liquefied petroleum gas ("LPG") pressure barges, collectively referred to as the "Floating Storage Assets." These assets were acquired on February 28, 2013. On December 19, 2014, the Partnership made the decision to dispose of the Floating Storage Assets. As a result, the Partnership has presented the results of operations and cash flows of the Floating Storage Assets as discontinued operations for the years ended December 31, 2015 and and 2014.
Product Exchanges	Product Exchanges The Partnership enters into product exchange agreements with third parties, whereby the Partnership agrees to exchange natural gas liquids ("NGLs") and sulfur with third parties. The Partnership records the balance of exchange products due to other companies under these agreements at quoted market product prices and the balance of exchange products due from other companies at the lower of cost or market. Cost is determined using the first-in, first-out ("FIFO") method.
Inventories	Inventories
Revenue Recognition	Revenue Recognition Terminalling and Storage – Revenue is recognized for storage contracts based on the contracted monthly tank fixed fee. For throughput contracts, revenue is recognized based on the volume moved through the Partnership’s terminals at the contracted rate. For the Partnership’s tolling agreement, revenue is recognized based on the contracted monthly reservation fee and throughput volumes moved through the facility. When lubricants and drilling fluids are sold by truck or rail, revenue is recognized upon delivering product to the customers as title to the product transfers when the customer physically receives the product. Natural Gas Services – NGL distribution revenue is recognized when product is delivered by truck, rail, or pipeline to the Partnership's NGL customers. Natural gas storage revenue is recognized when the service is provided to the customer. Sulfur Services – Revenue from sulfur product sales is recognized when the customer takes title to the product. Revenue from sulfur services is recognized as deliveries are made during each monthly period. Marine Transportation
Equity Method Investments	Equity Method Investments The Partnership uses the equity method of accounting for investments in unconsolidated entities where the ability to exercise significant influence over such entities exists. Investments in unconsolidated entities consist of capital contributions and advances plus the Partnership’s share of accumulated earnings as of the entities’ latest fiscal year-ends, less capital withdrawals and distributions. Investments in excess of the underlying net assets of equity method investees, specifically identifiable to property, plant and equipment, are amortized over the useful life of the related assets. Excess investment representing equity method goodwill is not amortized but is evaluated for impairment, annually. Under certain provisions of ASC 350-20, related to goodwill, this goodwill is not subject to amortization and is accounted for as a component of the investment. Equity method investments are subject to impairment under the provisions of ASC 323-10, which relates to the equity method of accounting for investments in common stock. No portion of the net income from these entities is included in the Partnership’s operating income.
Property, Plant and Equipment	Property, Plant, and Equipment Owned property, plant, and equipment is stated at cost, less accumulated depreciation. Owned buildings and equipment are depreciated using straight-line method over the estimated lives of the respective assets. Equipment under capital leases is stated at the present value of minimum lease payments less accumulated amortization. Equipment under capital leases is amortized on a straight line basis over the estimated useful life of the asset.
Goodwill and Other Intangible Assets	Goodwill and Other Intangible Assets Goodwill is subject to a fair-value based impairment test on an annual basis, or more often if events or circumstances indicate there may be impairment. The Partnership is required to identify its reporting units and determine the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets. The Partnership is required to determine the fair value of each reporting unit and compare it to the carrying amount of the reporting unit. To the extent the carrying amount of a reporting unit exceeds the fair value of the reporting unit, the Partnership would be required to perform the second step of the impairment test, as this is an indication that the reporting unit goodwill may be impaired. When assessing the recoverability of goodwill and other intangible assets, the Partnership may first assess qualitative factors in determining whether it is more likely than not that the fair value of a reporting unit or other intangible asset is less than its carrying amount. After assessing qualitative factors, if the Partnership determines that it is not more likely than not that the fair value of a reporting unit or other intangible asset is less than its carrying amount, then performing a quantitative assessment is not required. If an initial qualitative assessment indicates that it is more likely than not the carrying amount exceeds the fair value of a reporting unit or other intangible asset, a quantitative analysis will be performed. The Partnership may also elect to bypass the qualitative assessment and proceed directly to a quantitative analysis depending on the facts and circumstances. Of the Partnership's four reporting units, the terminalling and storage, natural gas services, and sulfur services reporting units contain goodwill. During the second quarter of 2016, the Partnership experienced an impairment of all the goodwill in the Partnership's marine transportation reporting unit. See Note 8 for more information. In performing a quantitative analysis, recoverability of goodwill for each reporting unit is measured using a weighting of the discounted cash flow method and two market approaches (the guideline public company method and the guideline transaction method). The discounted cash flow model incorporates discount rates commensurate with the risks involved. Use of a discounted cash flow model is common practice in assessing impairment in the absence of available transactional market evidence to determine the fair value. The key assumptions used in the discounted cash flow valuation model include discount rates, growth rates, cash flow projections and terminal value rates. Discount rates, growth rates and cash flow projections are the most sensitive and susceptible to change as they require significant management judgment. Discount rates are determined by using a weighted average cost of capital ("WACC"). The WACC considers market and industry data as well as company-specific risk factors for each reporting unit in determining the appropriate discount rate to be used. The discount rate utilized for each reporting unit is indicative of the return an investor would expect to receive for investing in such a business. Management, considering industry and company specific historical and projected data, develops growth rates and cash flow projections for each reporting unit. Terminal value rate determination follows common methodology of capturing the present value of perpetual cash flow estimates beyond the last projected period assuming a constant WACC and low long-term growth rates. If the calculated fair value is less than the current carrying amount, impairment of the reporting unit may exist. If the recoverability test indicates potential impairment, the Partnership calculates an implied fair value of goodwill for the reporting unit. The implied fair value of goodwill is determined in a manner similar to how goodwill is calculated in a business combination. If the implied fair value of goodwill exceeds the carrying amount of goodwill assigned to the reporting unit, there is no impairment. If the carrying amount of goodwill assigned to a reporting unit exceeds the implied fair value of the goodwill, an impairment loss is recorded to write down the carrying amount. An impairment loss cannot exceed the carrying amount of goodwill assigned to a reporting unit but may indicate certain long-lived and amortizable intangible assets associated with the reporting unit may require additional impairment testing Significant changes in these estimates and assumptions could materially affect the determination of fair value for each reporting unit which could give rise to future impairment. Changes to these estimates and assumptions can include, but may not be limited to, varying commodity prices, volume changes and operating costs due to market conditions and/or alternative providers of services.
Debt Issuance Costs	Debt Issuance Costs Debt issuance costs relating to the Partnership’s revolving credit facility and senior unsecured notes are deferred and amortized over the terms of the debt arrangements and are shown, net of accumulated amortization, as a reduction of the related long-term debt. In connection with the issuance, amendment, expansion and restatement of debt arrangements, the Partnership incurred debt issuance costs of $5,274 , $341 and $3,722 in the years ended December 31, 2016, 2015 and 2014, respectively. During 2016, the Partnership made certain strategic amendments to its credit facility which, among other things, decreased its borrowing capacity from $700,000 to $664,444 and extended the maturity date of the facility from March 28, 2018 to March 28, 2020. In connection with the amendment, the Partnership expensed $820 of unamortized debt issuance costs determined not to have continuing benefit. During 2015, the Partnership repurchased on the open market an aggregate $26,200 of 7.25% senior unsecured notes. The repurchase transaction resulted in the write-off of $235 of existing debt issuance costs that were determined not to have continuing benefit. On August 14, 2015, the Partnership reduced its borrowing capacity under the revolving credit facility from $900,000 to $700,000 , resulting in the write-off of $1,625 of deferred debt costs that were determined not to have continuing benefit. Due to the redemption of the remaining $175,000 of 8.875% senior unsecured notes in 2014 and a reduction in the number of lenders under the Partnership’s multi-bank credit agreement, $3,078 of the existing debt issuance costs were determined not to have continuing benefit and were expensed during the year ended December 31, 2014. Remaining unamortized deferred issuance costs are amortized over the term of each respective revised debt arrangement. Amortization and write-off of debt issuance costs, which is included in interest expense, totaled $3,684 , $4,859 and $6,263 for the years ended December 31, 2016, 2015 and 2014, respectively. Accumulated amortization amounted to $14,265 and $10,581
Impairment of Long-Lived Assets	Impairment of Long-Lived Assets In accordance with ASC 360-10, long-lived assets, such as property, plant and equipment, and intangible assets with definite lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset. Assets to be disposed of would be separately presented in the balance sheet and reported at the lower of the carrying amount or fair value less costs to sell and would no longer be depreciated. The assets and liabilities of a disposed group classified as held for sale would be presented separately in the appropriate asset and liability sections of the balance sheet. In the fourth quarter of 2016, the Partnership identified a triggering event related to certain organic growth projects in the Smackover Refinery and Specialty Terminals divisions of the Partnership's Terminalling and Storage segment. These triggering events were the decision to not move forward with certain expansion projects due to the evaporation of the economic viability of the projects. Additionally, a triggering event was identified related to the planned disposition of certain assets that were no longer deemed core assets to the Partnership's Martin Lubricants division. As a result, an impairment charge of $15,252 was recorded in the Terminalling and Storage segment results of operations for the year ended December 31, 2016. In the fourth quarter of 2016, the Partnership identified a triggering event related to the planned disposition of certain assets that were no longer deemed core assets in the Partnership's Marine Transportation business. The triggering event was the assets' inability to generate cash flows in recent quarters and going forward. As a result, an impairment charge of $11,701 was recorded in the Marine Transportation segment results of operations in the fourth quarter of 2016. In the fourth quarter of 2015, the Partnership identified a triggering event related to the condensate splitter project in the specialty terminals division of the Partnership's Terminalling and Storage segment. The triggering event was the decision to not move forward with the project due to the evaporation of the economic viability of the project. As a result, an impairment charge of $9,305 was recorded in the Terminalling and Storage segment results of operations for the year ended December 31, 2015. In the fourth quarter of 2015, the Partnership identified a triggering event related to one inland push boat and three inland tank barges in the Marine Transportation segment. The triggering event was the assets' inability to generate cash flows in recent quarters and going forward. As a result, an impairment charge of $1,324 was recorded in the Marine Transportation segment results of operations in the fourth quarter of 2015. In the third quarter of 2014, the Partnership identified a triggering event related to one offshore tow in the Marine Transportation segment. The triggering event was the tow's inability to generate cash flows in recent quarters. As a result, an impairment charge of $3,445
Asset Retirement Obligation	Asset Retirement Obligations Under ASC 410-20, which relates to accounting requirements for costs associated with legal obligations to retire tangible, long-lived assets, the Partnership records an asset retirement obligation ("ARO") at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted over time towards the ultimate obligation amount and the capitalized costs are depreciated over the useful life of the related asset.
Derivative Instruments and Hedging Activities	Derivative Instruments and Hedging Activities In accordance with certain provisions of ASC 815-10 related to accounting for derivative instruments and hedging activities, all derivatives and hedging instruments are included in the Consolidated Balance Sheets as an asset or liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings.
Use of Estimates	Use of Estimates
Indirect Selling, General and Administrative Expense	Indirect Selling, General and Administrative Expenses Indirect selling, general and administrative expenses are incurred by Martin Resource Management and allocated to the Partnership to cover costs of centralized corporate functions such as accounting, treasury, engineering, information technology, risk management and other corporate services. Such expenses are based on the percentage of time spent by Martin Resource Management’s personnel that provide such centralized services. Under an omnibus agreement with Martin Resource Management, the Partnership is required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. For the years ended December 31, 2016, 2015 and 2014, the conflicts committee of the Partnership's general partner ("Conflicts Committee") approved reimbursement amounts of $13,033 , $13,679 and $12,535
Environmental Liabilities and Litigation	Environmental Liabilities and Litigation
Trade and Accrued Accounts Receivable and Allowance for Doubtful Accounts	Trade and Accrued Accounts Receivable and Allowance for Doubtful Accounts.
Deferred Catalyst Costs	Deferred Catalyst Costs The cost of the periodic replacement of catalysts is deferred and amortized over the catalyst’s estimated useful life, which ranges from 12 to 36
Deferred Turnaround Costs	Deferred Turnaround Costs The Partnership capitalizes the cost of major turnarounds and amortizes these costs over the estimated period to the next turnaround, which ranges from 12 to 36
Income Taxes	Income Taxes The Partnership is subject to the Texas margin tax, which is considered a state income tax, and is included in income tax expense on the Consolidated Statements of Operations. Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed as an income tax and, therefore, the recognition of deferred taxes applies to the margin tax. The impact on deferred taxes as a result of this provision is immaterial.
Comprehensive Income	Comprehensive Income
Recent Accounting Pronouncements	Recent Accounting Pronouncements In August 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments . This ASU is intended to clarify the presentation of cash receipts and payments in specific situations. The amendments in this ASU are effective for financial statements issued for annual periods beginning after December 15, 2017, including interim periods within those annual periods, and early application is permitted. The Partnership does not anticipate that ASU 2016-15 will have a material effect on its consolidated financial statements and related disclosures. In February 2016, the FASB issued ASU 2016-02, Leases . This ASU amends the existing accounting standards for lease accounting, including requiring lessees to recognize most leases on their balance sheets and making targeted changes to lessor accounting. ASU 2016-02 is effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period. Early adoption of this standard is permitted. The standard requires a modified retrospective transition approach for all leases existing at, or entered into after, the date of initial application, with an option to use certain transition relief. The Partnership is evaluating the effect that ASU 2016-02 will have on its consolidated financial statements and related disclosures. In July 2015, the FASB issued ASU No. 2015-11, Inventory: Simplifying the Measurement of Inventory, which applies only to inventory for which cost is determined by methods other than last-in, first-out and the retail inventory method. This includes inventory that is measured using first-in, first-out or average cost. Inventory within the scope of this standard is required to be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The new standard will be effective on January 1, 2017. The Partnership does not anticipate that ASU 2015-11 will have a material effect on its consolidated financial statements and related disclosures. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers , which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective. The new standard is effective for the Partnership on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method. The Partnership is currently determining the overall impacts that ASU 2014-09 will have on its contract

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
Schedule of Business Acquisitions	The total purchase price is as follows: Cash payment for 57.8% interest in Cardinal $ 120,973 Fair value of the Partnership's previously owned 42.2% interest in Cardinal 87,613 Total $ 208,586
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	The Partnership recorded the purchase in the following allocation: Property, plant and equipment $ 2,453 Current liabilities (13 ) $ 2,440 Restricted cash $ 17,566 Other current assets 9,385 Property, plant and equipment 390,895 Intangible and other assets 80,135 Project level finance debt (282,087 ) Other current liabilities (6,713 ) Other non-current liabilities (595 ) Total $ 208,586
Pro Forma Information for Acquisition	The following pro forma unaudited consolidated results of operations have been prepared as if the acquisitions of Cardinal and WTLPG occurred at the beginning of fiscal 2014: Year Ended December 31, 2014 Revenue: As reported $ 1,642,141 Pro forma $ 1,688,629 Net income (loss) from continuing operations attributable to limited partners: As reported $ (8,255 ) Pro forma $ 1,676 Net loss from discontinued operations attributable to limited partners: As reported $ (6,921 ) Pro forma $ (6,921 ) Net income (loss) from continuing operations per unit attributable to limited partners - basic As reported $ (0.27 ) Pro forma $ 0.05 Net loss from discontinued operations per unit attributable to limited partners - basic As reported $ (0.22 ) Pro forma $ (0.22 ) Net income (loss) from continuing operations per unit attributable to limited partners - diluted As reported $ (0.27 ) Pro forma $ 0.05 Net loss from discontinued operations per unit attributable to limited partners - diluted As reported $ (0.22 ) Pro forma $ (0.22 )

Discontinued Operations, Dive34

Discontinued Operations, Divestitures, and Assets Held for Sale (Tables)	12 Months Ended
	Dec. 31, 2016
Discontinued Operations and Disposal Groups [Abstract]
Disclosure of long lived assets held-for-sale	At December 31, 2016, the assets met the criteria to be classified as held for sale in accordance with ASC 360-10 and are presented at the assets' fair value less cost to sell by segment in current assets as follows: December 31, 2016 Terminalling and storage $ 10,852 Marine transportation 4,927 Assets held for sale $ 15,779
Schedule of disposal groups including discontinued operations income statement and balance sheet	The Floating Storage Assets’ operating results, which are included in income from discontinued operations, were as follows: Year Ended December 31, 2016 2015 2014 Total revenues from third parties 1 $ — $ 791 $ 51,264 Total costs and expenses and other, net, excluding depreciation and amortization — 1,038 55,068 Depreciation and amortization — — 1,534 Other operating income, net 2 — 1,462 — Income (loss) from discontinued operations before income taxes — 1,215 (5,338 ) Income tax expense — — — Income (loss) from discontinued operations, net of income taxes $ — $ 1,215 $ (5,338 ) 1 Total revenues from third parties excludes intercompany revenues of $0 and $0 and $5,241 for the years ended December 31, 2016, 2015 and 2014, respectively. 2 Other operating income, net represents the gain on the disposition of the Floating Storage Assets.

Inventories (Tables)

Inventories (Tables)	12 Months Ended
	Dec. 31, 2016
Inventory Disclosure [Abstract]
Components of inventory	Components of inventories at December 31, 2016 and 2015 were as follows: 2016 2015 Natural gas liquids $ 33,656 $ 20,959 Sulfur 8,521 13,812 Sulfur based products 19,107 19,400 Lubricants 18,276 18,675 Other 3,071 3,024 $ 82,631 $ 75,870

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	At December 31, 2016 and 2015 , property, plant and equipment consisted of the following: Depreciable Lives 2016 2015 Land — $ 20,679 $ 23,931 Improvements to land and buildings 10-25 years 135,852 159,160 Storage equipment 5-50 years 168,839 191,095 Marine vessels 4-25 years 181,659 257,858 Operating plant and equipment 3-50 years 620,303 631,728 Base Gas — 43,799 43,799 Furniture, fixtures and other equipment 3-20 years 19,034 4,375 Transportation equipment 3-7 years 1,738 2,237 Construction in progress 32,374 73,631 $ 1,224,277 $ 1,387,814

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2016
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	The following table represents the goodwill balance at December 31, 2015 , changes during the year, and the resulting balances at December 31, 2016 : 2015 Impairment 1 CCCT Assets 2 2016 Carrying amount of goodwill: Terminalling and storage $ 14,229 $ — $ (2,361 ) $ 11,868 Natural gas services 79 — — $ 79 Sulfur services 5,349 — — $ 5,349 Marine transportation 4,145 (4,145 ) — $ — Total goodwill $ 23,802 $ (4,145 ) $ (2,361 ) $ 17,296 1 During the second quarter of 2016, the Partnership determined that the state of market conditions in the Marine Transportation reporting unit, including the demand for utilization, day rates and the current oversupply of inland tank barges, indicated that an impairment of goodwill may exist. As a result, the Partnership assessed qualitative factors and determined that the Partnership could not conclude it was more likely than not that the fair value of goodwill exceeded its carrying value. In turn, the Partnership prepared a quantitative analysis of the fair value of the goodwill as of June 30, 2016, based on the weighted average valuation of the aforementioned income and market based valuation approaches. The underlying results of the valuation were driven by our actual results during the six months ended June 30, 2016 and the pricing and market conditions existing as of June 30, 2016, which were below our forecasts at the time of the previous goodwill assessments. Other key estimates, assumptions and inputs used in the valuation included long-term growth rates, discounts rates, terminal values, valuation multiples and relative valuations when comparing the reporting unit to similar businesses or asset bases. Upon completion of the analysis, a $4,145 impairment of all goodwill in the Marine Transportation reporting unit was incurred during the second quarter of 2016. The Partnership did not recognize any other goodwill impairment losses for the year ended December 31, 2016. 2 This change represents goodwill disposed of as part of the Partnership's divestiture of the CCCT Assets. See Note 5.

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2016
Leases [Abstract]
Schedule of Future Minimum Obligations	The Partnership’s future minimum lease obligations as of December 31, 2016 consist of the following: Fiscal year Operating Leases 2017 $ 10,458 2018 5,633 2019 4,036 2020 3,389 2021 1,041 Thereafter 8,449 Total $ 33,006

Investments in Unconsolidated39

Investments in Unconsolidated Entities and Joint Ventures (Tables)	12 Months Ended
	Dec. 31, 2016
Equity Method Investments and Joint Ventures [Abstract]
Select financial information for significant unconsolidated equity-method investees	Selected financial information for significant unconsolidated equity method investees is as follows: As of December 31, Years ended December 31, Total Assets Long-Term Debt Members’ Equity/Partners' Capital Revenues Net Income 2016 WTLPG $ 812,464 $ — $ 790,406 $ 88,468 $ 23,883 2015 WTLPG $ 819,342 $ — $ 804,023 $ 100,708 $ 46,294 2014 WTLPG $ 827,697 $ — $ 818,546 $ 95,315 $ 38,698 Cardinal 1 $ — $ — $ — $ 46,488 $ 1,911 1 Financial information for Cardinal includes revenues and net income for the 2014 period prior to the Partnership's acquisition of the 57.8%

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	Assets and liabilities measured at fair value on a recurring basis are summarized below: Level 2 December 31, 2016 2015 Commodity derivative contracts, net $ (3,904 ) $ 675 Interest rate derivative contracts — (206 ) The Partnership is required to disclose estimated fair values for its financial instruments. Fair value estimates are set forth below for these financial instruments. The following methods and assumptions were used to estimate the fair value of each class of financial instrument: • Accounts and other receivables, trade and other accounts payable, accrued interest payable, other accrued liabilities, income taxes payable and due from/to affiliates: The carrying amounts approximate fair value due to the short maturity and highly liquid nature of these instruments, and as such these have been excluded from the table below. There is negligible credit risk associated with these instruments. • Note receivable and long-term debt including current portion: The carrying amount of the revolving credit facility approximates fair value due to the debt having a variable interest rate and is in Level 2. The Partnership has not had any indicators which represent a change in the market spread associated with its variable interest rate debt. • The estimated fair value of the senior unsecured notes is based on market prices of similar debt. The estimated fair value of the note receivable from Martin Energy Trading was determined by calculating the net present value of the payments over the life of the note. The note is considered Level 3 due to the lack of observable inputs for similar transactions between related parties. December 31, 2016 December 31, 2015 Carrying Value Fair Value Carrying Value Fair Value Note receivable - MET $ 15,000 $ 15,797 $ 15,000 $ 15,830 2021 Senior unsecured notes 372,239 377,882 371,861 318,000

Derivative Instruments and He41

Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Effect of derivative instruments on the Consolidated Balance Sheets	The following table summarizes the fair values and classification of the Partnership’s derivative instruments in its Consolidated Balance Sheets: Fair Values of Derivative Instruments in the Consolidated Balance Sheet Derivative Assets Derivative Liabilities Fair Values Fair Values Balance Sheet Location December 31, 2016 December 31, 2015 Balance Sheet Location December 31, 2016 December 31, 2015 Derivatives not designated as hedging instruments: Current: Commodity contracts Fair value of derivatives $ — $ 675 Fair value of derivatives $ 3,904 $ — Derivatives not designated as hedging instruments: Non Current: Non Current: Interest rate contracts Fair value of derivatives — — Fair value of derivatives — 206 Total derivatives not designated as hedging instruments $ — $ 675 $ 3,904 $ 206
Effect of derivative instruments on the Consolidated Statement of Operations	Effect of Derivative Instruments on the Consolidated Statement of Operations For the Twelve Months Ended December 31, 2016, 2015, and 2014 Location of Gain or (Loss) Recognized in Income on Derivatives Amount of Gain or (Loss) Recognized in Income on Derivatives 2016 2015 2014 Derivatives not designated as hedging instruments: Interest rate swaption contracts Interest expense $ (630 ) $ 2,495 $ — Interest rate contracts Interest expense (366 ) (206 ) 6,692 Commodity contracts Cost of products sold 5,129 818 — Commodity contracts Other income — — (815 ) Total derivatives not designated as hedging instruments $ 4,133 $ 3,107 $ 5,877

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
The Impact of Related Party Transactions	The impact of related party revenues from sales of products and services is reflected in the Consolidated Statements of Operations as follows: Revenues: 2016 2015 2014 Terminalling and storage $ 82,437 $ 78,233 $ 74,467 Marine transportation 21,767 27,724 24,389 Natural gas services 699 878 — Product sales: Natural gas services 8 196 3,064 Sulfur services 2,006 3,639 3,921 Terminalling and storage 1,020 1,836 676 3,034 5,671 7,661 $ 107,937 $ 112,506 $ 106,517 The impact of related party cost of products sold is reflected in the Consolidated Statements of Operations as follows: Cost of products sold: Natural gas services $ 22,886 $ 25,797 $ 37,703 Sulfur services 15,339 16,579 18,390 Terminalling and storage 13,838 17,718 36,341 $ 52,063 $ 60,094 $ 92,434 The impact of related party operating expenses is reflected in the Consolidated Statements of Operations as follows: Operating expenses: Marine transportation $ 28,107 $ 32,373 $ 37,703 Natural gas services 9,258 8,639 4,870 Sulfur services 5,995 6,928 7,479 Terminalling and storage 27,481 29,931 29,525 $ 70,841 $ 77,871 $ 79,577 The impact of related party selling, general and administrative expenses is reflected in the Consolidated Statements of Operations as follows: Selling, general and administrative: Marine transportation $ 30 $ 29 $ 30 Natural gas services 7,566 6,216 6,039 Sulfur services 2,732 2,760 3,201 Terminalling and storage 2,526 2,284 1,874 Indirect overhead allocation, net of reimbursement 13,036 13,679 12,535 $ 25,890 $ 24,968 $ 23,679

Supplemental Balance Sheet In43

Supplemental Balance Sheet Information (Tables)	12 Months Ended
	Dec. 31, 2016
Balance Sheet Related Disclosures [Abstract]
Schedule of Intangible and Other Assets, Net	Components of "Intangibles and other assets, net" at December 31, 2016 and 2015 were as follows: 2016 2015 Customer contracts and relationships, net $ 36,528 $ 50,452 Other intangible assets 2,280 1,818 Other 6,066 6,044 $ 44,874 $ 58,314
Schedule of Other Accrued Liabilities	Components of "Other accrued liabilities" at December 31, 2016 and 2015 were as follows: 2016 2015 Accrued interest $ 10,629 $ 10,365 Asset retirement obligations 7,953 — Property and other taxes payable 6,443 6,668 Accrued payroll 1,672 1,389 Other 20 111 $ 26,717 $ 18,533
Schedule of Asset Retirement Obligations	The schedule below summarizes the changes in our asset retirement obligations: Year Ended December 31, 2016 2015 (In thousands) Beginning asset retirement obligations $ 2,163 $ 2,052 Revisions to existing liabilities 1 14,379 — Accretion 178 111 Liabilities settled (302 ) — Ending asset retirement obligations 16,418 2,163 Current portion of asset retirement obligations 2 (7,953 ) — Long-term portion of asset retirement obligations 3 $ 8,465 $ 2,163 1 Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, discount rates, and the estimated remaining useful life of the assets. The 2016 revisions reflect changes in removal cost estimates and the estimated remaining useful life of assets. 2 The current portion of asset retirement obligations is included in "Other current liabilities" on the Partnership's Consolidated Balance Sheets. 3

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Schedule of long-term debt	At December 31, 2016 and 2015 , long-term debt consisted of the following: 2016 2015 $664,444 1 Revolving credit facility at variable interest rate (3.76% 2 weighted average at December 31, 2016), due March 2020 secured by substantially all of the Partnership’s assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in the Partnership’s operating subsidiaries and equity method investees, net of unamortized debt issuance costs of $7,132 and $4,858, respectively 3 $ 435,868 $ 493,142 $400,000 Senior notes, 7.25% interest, including unamortized premium of $1,262 and $1,568, respectively, also net of unamortized debt issuance costs of $2,823 and $3,507 respectively, issued $250,000 February 2013 and $150,000 April 2014, $26,200 repurchased during 2015, due February 2021, unsecured 3,4 372,239 371,861 Total long-term debt $ 808,107 $ 865,003 1 On April 27, 2016, the Partnership made certain strategic amendments to its credit facility which, among other things, decreased its borrowing capacity from $700,000 to $664,444 and extended the maturity date of the facility from March 28, 2018 to March 28, 2020. The reduction in capacity resulted in the write-off of $820 of deferred debt costs. 2 Interest rate fluctuates based on the LIBOR rate plus an applicable margin set on the date of each advance. The margin above LIBOR is set every three months. Indebtedness under the credit facility bears interest at LIBOR plus an applicable margin or the base prime rate plus an applicable margin. All amounts outstanding at December 31, 2016 and December 31, 2015 were at LIBOR plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 2.00% to 3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 1.00% to 2.00% . The applicable margin for LIBOR borrowings at December 31, 2016 is 3.00% . The credit facility contains various covenants which limit the Partnership’s ability to make certain investments and acquisitions; enter into certain agreements; incur indebtedness; sell assets; and make certain amendments to the Omnibus Agreement. The Partnership is permitted to make quarterly distributions so long as no event of default exists. 3 The Partnership is in compliance with all debt covenants as of December 31, 2016. 4 The 2021 indentures restrict the Partnership’s ability to sell assets; pay distributions or repurchase units or redeem or repurchase subordinated debt; make investments; incur or guarantee additional indebtedness or issue preferred units; and consolidate, merge or transfer all or substantially all of its assets. Many of these covenants will terminate if the notes achieve an investment grade rating from each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no default (as defined in the indentures) has occurred.

Partners' Capital (Tables)

Partners' Capital (Tables)	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Reconciliation of net income to partners interest in net income	The following is a reconciliation of net income from continuing operations and net income from discontinued operations allocated to the general partner and limited partners for purposes of calculating net income attributable to limited partners per unit: Years Ended December 31, 2016 2015 2014 Continuing operations: Income (loss) from continuing operations $ 31,652 $ 37,165 $ (6,367 ) Less general partner’s interest in net income: Distributions payable on behalf of IDRs 7,786 15,078 2,033 Distributions payable on behalf of general partner interest 2,058 2,585 1,181 General partner interest in undistributed loss (1,425 ) (1,842 ) (1,308 ) Less income (loss) allocable to unvested restricted units 90 136 (18 ) Limited partners’ interest in net income (loss) $ 23,143 $ 21,208 $ (8,255 ) Years Ended December 31, 2016 2015 2014 Discontinued operations: Income (loss) from discontinued operations $ — $ 1,215 $ (5,338 ) Less general partner’s interest in net income: Distributions payable on behalf of IDRs — 493 1,704 Distributions payable on behalf of general partner interest — 84 990 General partner interest in undistributed loss — (60 ) (1,097 ) Less income (loss) allocable to unvested restricted units — 4 (14 ) Limited partners’ interest in net income (loss) $ — $ 694 $ (6,921 )

Unit Based Awards (Tables)

Unit Based Awards (Tables)	12 Months Ended
	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of compensation costs related to unit based plan	Amounts recognized in selling, general, and administrative expense in the consolidated financial statements with respect to these plans are as follows: For the Year Ended December 31, 2016 2015 2014 Employees $ 783 $ 1,338 $ 537 Non-employee directors 121 91 280 Total unit-based compensation expense $ 904 $ 1,429 $ 817
Summary of restricted unit activity	A summary of the restricted unit activity for the year ended December 31, 2016 is provided below: Number of Units Weighted Average Grant-Date Fair Value Per Unit Non-vested, beginning of year 150,474 $ 28.89 Granted 13,800 $ 15.13 Vested (58,224 ) $ 30.61 Forfeited (2,250 ) $ 28.50 Non-Vested, end of year 103,800 $ 26.54 Aggregate intrinsic value, end of year $ 1,905
Summary of aggregate intrinsic value and fair value of units vested	A summary of the restricted units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) during the years ended December 31, 2016, 2015 and 2014 is provided below: For the Year Ended December 31, 2016 2015 2014 Aggregate intrinsic value of units vested $ 1,233 $ 110 $ 514 Fair value of units vested $ 1,773 $ 128 $ 450

Business Segments (Tables)

Business Segments (Tables)	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
Schedule of segment reporting information, by segment	The Natural Gas Services segment information below excludes the discontinued operations of the Floating Storage Assets for 2015 and 2014. See Note 5. Operating Revenues Intersegment Eliminations Operating Revenues After Eliminations Depreciation and Amortization Operating Income (Loss) after Eliminations Capital Expenditures and Plant Turnaround Costs Year Ended December 31, 2016: Terminalling and storage $ 242,363 $ (5,653 ) $ 236,710 $ 45,484 $ 40,660 $ 26,097 Natural gas services 391,333 — 391,333 28,081 41,438 4,807 Sulfur services 141,058 — 141,058 7,995 23,393 5,093 Marine transportation 61,233 (2,943 ) 58,290 10,572 (16,039 ) 2,334 Indirect selling, general, and administrative — — — — (16,794 ) — Total $ 835,987 $ (8,596 ) $ 827,391 $ 92,132 $ 72,658 $ 38,331 Year Ended December 31, 2015: Terminalling and storage $ 270,440 $ (5,670 ) $ 264,770 $ 38,731 $ 15,704 $ 40,421 Natural gas services 523,160 — 523,160 34,072 41,220 24,330 Sulfur services 170,161 — 170,161 8,455 23,604 1,201 Marine transportation 81,784 (3,031 ) 78,753 10,992 8,576 2,775 Indirect selling, general, and administrative — — — — (18,951 ) — Total $ 1,045,545 $ (8,701 ) $ 1,036,844 $ 92,250 $ 70,153 $ 68,727 Year Ended December 31, 2014: Terminalling and storage $ 326,654 $ (5,191 ) $ 321,463 $ 37,622 $ 24,993 $ 53,450 Natural gas services 1,013,835 — 1,013,835 13,090 34,574 24,194 Sulfur services 215,471 — 215,471 8,176 19,465 4,115 Marine transportation 97,049 (5,677 ) 91,372 9,942 7,551 11,498 Indirect selling, general, and administrative — — — — (18,712 ) — Total $ 1,653,009 $ (10,868 ) $ 1,642,141 $ 68,830 $ 67,871 $ 93,257
Assets by segment	The Partnership's assets by reportable segment as of December 31, 2016 and 2015 , are as follows: 2016 2015 Total assets: Terminalling and storage $ 328,098 $ 417,202 Natural gas services 684,722 694,333 Sulfur services 125,356 134,108 Marine transportation 108,187 134,830 Total assets $ 1,246,363 $ 1,380,473

Quarterly Financial Informati48

Quarterly Financial Information (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	Consolidated Quarterly Income Statement Information (Unaudited) First Quarter Second Quarter Third Quarter Fourth Quarter (Dollar in thousands, except per unit amounts) 2016 Revenues $ 225,605 $ 190,348 $ 174,537 $ 236,901 Operating income 24,338 10,256 9,176 28,888 Equity in earnings of unconsolidated entities 1,677 805 1,120 1,112 Net income (loss) $ 15,914 $ (1,211 ) $ (933 ) $ 17,882 Limited partners' interest in net income (loss) per limited partner unit $ 0.33 $ (0.14 ) (0.03 ) $ 0.49 First Quarter Second Quarter Third Quarter Fourth Quarter (Dollar in thousands, except per unit amounts) 2015 Revenues $ 305,353 $ 251,099 $ 226,021 $ 254,371 Operating income 24,702 19,630 12,034 13,787 Equity in earnings of unconsolidated entities 1,740 1,649 2,363 3,234 Income from continuing operations 16,033 10,961 3,330 6,841 Income from discontinued operations 1,215 — — — Net income $ 17,248 $ 10,961 $ 3,330 $ 6,841 Limited partners' interest in net income (loss) per limited partner unit $ 0.37 0.19 (0.02 ) 0.08

Organization and Description 49

Organization and Description of Business (Details)	Aug. 30, 2013representative	Dec. 31, 2016segment
Schedule of Equity Method Investments [Line Items]
Number of primary business lines | segment		4
Ownership percentage		98.00%
Martin Resource Management
Schedule of Equity Method Investments [Line Items]
Ownership percentage	49.00%
Economic ownership percentage by parent	50.00%
Number of representatives appointed to board of directors | representative	2

Significant Accounting Polici50

Significant Accounting Policies (Details)	Apr. 27, 2016USD ($)	Aug. 14, 2015USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2014USD ($)	Dec. 31, 2016USD ($)segment	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Apr. 26, 2016USD ($)	Aug. 13, 2015USD ($)	Feb. 12, 2015bargebbl
Equity Method Investments
Number of pressure barges disposed of | barge											6
Volume of pressure barges disposed of (in bbl) | bbl											16,101
Goodwill and Other Intangibles
Number of reporting units | segment						4
Debt Issuance Costs
Debt issuance cost						$ 5,274,000	$ 341,000	$ 3,722,000
Write off of existing debt issuance costs								3,078,000
Amortization of debt issuance costs						3,684,000	4,859,000	6,263,000
Accumulated amortization of debt issuance costs			$ 14,265,000	$ 10,581,000		14,265,000	10,581,000
Impairment of Long-Lived Assets
Impairment of long-lived assets						26,953,000	10,629,000	3,445,000
Indirect Selling, General and Administrative Expenses
Indirect selling, general and administrative expenses						$ 13,033,000	13,679,000	$ 12,535,000
Minimum
Deferred Catalyst Costs
Catalyst, useful life (in months)						12 months
Deferred Turnaround Costs
Turnarounds, useful life (in months)						12 months
Maximum
Deferred Catalyst Costs
Catalyst, useful life (in months)						36 months
Deferred Turnaround Costs
Turnarounds, useful life (in months)						36 months
Terminalling and storage
Impairment of Long-Lived Assets
Impairment of long-lived assets						$ 15,252	9,305,000
Marine transportation
Impairment of Long-Lived Assets
Impairment of long-lived assets			11,701	1,324,000	$ 3,445,000
Revolving Loan Facility
Debt Issuance Costs
Face amount	$ 664,444,000		$ 664,444,000	700,000,000		664,444,000	700,000,000		$ 700,000,000
Write off of existing debt issuance costs	$ 820,000	$ 1,625,000				$ 820,000
Borrowing capacity		$ 700,000,000								$ 900,000,000
Senior Unsecured Notes 7.25% | Senior Notes
Debt Issuance Costs
Write off of existing debt issuance costs							235,000
Amount of debt repurchased				$ 26,200,000			$ 26,200,000
Fixed rate cost				7.25%			7.25%
Senior Notes 8.875% | Senior Notes
Debt Issuance Costs
Fixed rate cost								8.875%
Aggregate redemption value								$ 175,000,000

Acquisitions - Cardinal Gas Sto

Acquisitions - Cardinal Gas Storage Partners LLC (Details) - USD ($) $ in Thousands	Aug. 29, 2014	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	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Aug. 28, 2014
Business Acquisition [Line Items]
Reduced carrying value of existing investment											$ 0	$ 0	$ 30,102
Revenues		$ 236,901	$ 174,537	$ 190,348	$ 225,605	$ 254,371	$ 226,021	$ 251,099	$ 305,353		827,391	1,036,844	1,642,141
Net income (loss)		$ 17,882	$ (933)	$ (1,211)	$ 15,914	$ 6,841	$ 3,330	$ 10,961	$ 17,248		31,652	38,380	$ (11,705)
Cardinal Gas Storage Partners LLC
Business Acquisition [Line Items]
Additional voting interests acquired (percentage)	57.80%
Cash payment for 57.8% interest in Cardinal	$ 120,973
Ownership percentage by parent														42.20%
Reduced carrying value of existing investment	$ 30,102
Weighted average useful life	5 years 1 month 6 days
Revenues										$ 22,991	61,233	64,881
Net income (loss)										$ 1,916	$ 16,157	$ 11,899

Acquisitions - Schedule of Purc

Acquisitions - Schedule of Purchase Price (Details) - Cardinal Gas Storage Partners LLC - USD ($) $ in Thousands	Aug. 29, 2014	Aug. 28, 2014
Business Acquisition [Line Items]
Cash payment for 57.8% interest in Cardinal	$ 120,973
Fair value of the Partnership's previously owned 42.2% interest in Cardinal	87,613
Total	$ 208,586
Additional voting interests acquired (percentage)	57.80%
Ownership percentage by parent		42.20%

Acquisitions - Purchase Price A

Acquisitions - Purchase Price Allocation (Details) - Cardinal Gas Storage Partners LLC $ in Thousands	Aug. 29, 2014USD ($)
Business Acquisition [Line Items]
Restricted cash	$ 17,566
Other current assets	9,385
Property, plant and equipment	390,895
Intangible and other assets	80,135
Project level finance debt	(282,087)
Other current liabilities	(6,713)
Other non-current liabilities	(595)
Total	$ 208,586

Acquisitions - Natural Gas Liqu

Acquisitions - Natural Gas Liquids Storage Assets (Details) - USD ($) $ in Thousands	May 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Excess purchase price over carrying value		$ 0	$ 0	$ 4,948
Martin Resource Management
Business Acquisition [Line Items]
Purchase price of acquisition	$ 7,388
Martin Resource Management | Partners' Capital
Business Acquisition [Line Items]
Excess purchase price over carrying value	$ 4,948
Excess of the purchase price over the carrying value, percentage	3.00%

Acquisitions - Natural Gas Li55

Acquisitions - Natural Gas Liquids Storage Assets (Carrying Value of Assets) (Details) - Martin Resource Management $ in Thousands	May 31, 2014USD ($)
Business Acquisition [Line Items]
Property, plant and equipment	$ 2,453
Current liabilities	(13)
Total	$ 2,440

Acquisitions - West Texas LPG P

Acquisitions - West Texas LPG Pipeline Limited Partnership (Details) $ in Thousands	May 14, 2014USD ($)mi	May 14, 2014USD ($)mi	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Business Acquisition [Line Items]
Payment to acquire unconsolidated entities			$ 0	$ 0	$ 134,030
West Texas LPG Pipeline L.P.
Business Acquisition [Line Items]
Ownership percentage	20.00%	20.00%
Length common carrier pipeline (in miles) | mi	2,300	2,300
West Texas LPG Pipeline L.P. | Common
Business Acquisition [Line Items]
Ownership percentage	19.80%	19.80%
West Texas LPG Pipeline L.P. | General Partner
Business Acquisition [Line Items]
Ownership percentage	0.20%	0.20%
West Texas LPG Pipeline L.P. | ONEOK Partners, L.P.
Business Acquisition [Line Items]
Ownership percentage by parent	80.00%	80.00%
Atlas Holdings
Business Acquisition [Line Items]
Payment to acquire unconsolidated entities	$ 134,400	$ 134,400
Reduction in post closing working capital adjustment	$ 501	$ 501

Acquisitions - Pro Forma Financ

Acquisitions - Pro Forma Financial Information for Cardinal and WTLPG (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
Revenues:
As reported	$ 236,901	$ 174,537	$ 190,348	$ 225,605	$ 254,371	$ 226,021	$ 251,099	$ 305,353	$ 827,391	$ 1,036,844	$ 1,642,141
Net income (loss) from continuing operations attributable to limited partners:
As reported									23,143	21,208	(8,255)
Net loss from discontinued operations attributable to limited partners:
As reported									$ 0	$ 694	$ (6,921)
Net income (loss) from continuing operations per unit attributable to limited partners - basic
As reported (in dollars per share)									$ 0.65	$ 0.60	$ (0.27)
Net loss from discontinued operations per unit attributable to limited partners - basic
As reported (in dollars per share)									0	0.02	(0.22)
Net income (loss) from continuing operations per unit attributable to limited partners - diluted
As reported (in dollars per share)									0.65	0.60	(0.27)
Net loss from discontinued operations per unit attributable to limited partners - diluted
As reported (in dollars per share)									$ 0	$ 0.02	$ (0.22)
Common | Cardinal and West Texas Pipeline Limited Partnership
Revenues:
As reported											$ 1,642,141
Pro forma											1,688,629
Net income (loss) from continuing operations attributable to limited partners:
As reported											(8,255)
Pro forma											1,676
Net loss from discontinued operations attributable to limited partners:
As reported											(6,921)
Pro forma											$ (6,921)
Net income (loss) from continuing operations per unit attributable to limited partners - basic
As reported (in dollars per share)											$ (0.27)
Pro forma (in dollars per share)											0.05
Net loss from discontinued operations per unit attributable to limited partners - basic
As reported (in dollars per share)											(0.22)
Pro forma (in dollars per share)											(0.22)
Net income (loss) from continuing operations per unit attributable to limited partners - diluted
As reported (in dollars per share)											(0.27)
Pro forma (in dollars per share)											0.05
Net loss from discontinued operations per unit attributable to limited partners - diluted
As reported (in dollars per share)											(0.22)
Pro forma (in dollars per share)											$ (0.22)

Discontinued Operations, Dive58

Discontinued Operations, Divestitures, and Assets Held for Sale (Narrative) (Details)	Dec. 21, 2016USD ($)bbl	Feb. 12, 2015USD ($)bargebbl	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of pressure barges disposed of | barge		6
Volume of pressure barges disposed of (in bbl) | bbl		16,101
CCCT Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from dock relocation	$ 13,400
Gain from divestiture			$ 37,345
Net income			43,804,000	$ 10,880,000	$ 16,241,000
CCCT Assets | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of barrels in crude oil storage terminal (in bbl) | bbl	900,000
Sale price	$ 107,000
Reimbursement of capital expenditures and prepaid Items	2,057
Proceeds from divestiture of businesses	$ 93,347
Floating Storage Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of pressure barges disposed of | barge		6
Volume of pressure barges disposed of (in bbl) | bbl		16,101
Floating Storage Assets | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture of businesses		$ 41,250,000
Terminalling and storage | Discontinued Operations, Held-for-sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment of long-lived assets			15,252,000
Marine transportation | Discontinued Operations, Held-for-sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment of long-lived assets			$ 11,701,000

Discontinued Operations, Dive59

Discontinued Operations, Divestitures, and Assets Held for Sale (Long-Lived Assets Held-for-Sale) (Details) - Discontinued Operations, Held-for-sale, Not Discontinued Operations $ in Thousands	Dec. 31, 2016USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long lived assets held-for-sale fair value disclosure	$ 15,779
Terminalling and storage
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long lived assets held-for-sale fair value disclosure	10,852
Marine transportation
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long lived assets held-for-sale fair value disclosure	$ 4,927

Discontinued Operations, Dive60

Discontinued Operations, Divestitures, and Assets Held for Sale (Operating Results) (Details) - USD ($) $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total costs and expenses and other, net, excluding depreciation and amortization					$ (788,133)	$ (964,530)	$ (1,573,256)
Depreciation and amortization					(92,132)	(92,250)	(68,830)
Income from discontinued operations, net of income taxes	$ 0	$ 0	$ 0	$ 1,215	0	1,215	(5,338)
Floating Storage Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total revenues from third parties					0	791	51,264
Total costs and expenses and other, net, excluding depreciation and amortization					0	(1,038)	(55,068)
Depreciation and amortization					0	0	(1,534)
Other operating income					0	1,462	0
Income from discontinued operations before income taxes					0	1,215	(5,338)
Income tax expense					0	0	0
Income from discontinued operations, net of income taxes					0	1,215	(5,338)
Intersegment Eliminations | Floating Storage Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total revenues from third parties					$ 0	$ 0	$ 5,241

Inventories (Details)

Inventories (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Inventory Disclosure [Abstract]
Natural gas liquids	$ 33,656	$ 20,959
Sulfur	8,521	13,812
Sulfur based products	19,107	19,400
Lubricants	18,276	18,675
Other	3,071	3,024
Inventories	$ 82,631	$ 75,870

Property, Plant and Equipment62

Property, Plant and Equipment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Property, plant and equipment, at cost	$ 1,224,277	$ 1,387,814
Depreciation expense	72,405	67,134	$ 56,309
Additions to property, plant and equipment included in accounts payable	1,819	6,004
Land
Property, Plant and Equipment [Line Items]
Property, plant and equipment, at cost	20,679	23,931
Improvements to land and buildings
Property, Plant and Equipment [Line Items]
Property, plant and equipment, at cost	$ 135,852	159,160
Improvements to land and buildings | Minimum
Property, Plant and Equipment [Line Items]
Depreciable lives (in years)	10 years
Improvements to land and buildings | Maximum
Property, Plant and Equipment [Line Items]
Depreciable lives (in years)	25 years
Storage equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment, at cost	$ 168,839	191,095
Storage equipment | Minimum
Property, Plant and Equipment [Line Items]
Depreciable lives (in years)	5 years
Storage equipment | Maximum
Property, Plant and Equipment [Line Items]
Depreciable lives (in years)	50 years
Marine vessels
Property, Plant and Equipment [Line Items]
Property, plant and equipment, at cost	$ 181,659	257,858
Marine vessels | Minimum
Property, Plant and Equipment [Line Items]
Depreciable lives (in years)	4 years
Marine vessels | Maximum
Property, Plant and Equipment [Line Items]
Depreciable lives (in years)	25 years
Operating plant and equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment, at cost	$ 620,303	631,728
Operating plant and equipment | Minimum
Property, Plant and Equipment [Line Items]
Depreciable lives (in years)	3 years
Operating plant and equipment | Maximum
Property, Plant and Equipment [Line Items]
Depreciable lives (in years)	50 years
Base Gas
Property, Plant and Equipment [Line Items]
Property, plant and equipment, at cost	$ 43,799	43,799
Furniture, fixtures and other equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment, at cost	$ 19,034	4,375
Furniture, fixtures and other equipment | Minimum
Property, Plant and Equipment [Line Items]
Depreciable lives (in years)	3 years
Furniture, fixtures and other equipment | Maximum
Property, Plant and Equipment [Line Items]
Depreciable lives (in years)	20 years
Transportation equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment, at cost	$ 1,738	2,237
Transportation equipment | Minimum
Property, Plant and Equipment [Line Items]
Depreciable lives (in years)	3 years
Transportation equipment | Maximum
Property, Plant and Equipment [Line Items]
Depreciable lives (in years)	7 years
Construction in progress
Property, Plant and Equipment [Line Items]
Property, plant and equipment, at cost	$ 32,374	$ 73,631

Goodwill (Details)

Goodwill (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Goodwill [Roll Forward]
Goodwill, beginning balance	$ 23,802
Impairment	(4,145)	$ 0	$ 0
CCCT Assets	(2,361)
Goodwill, ending balance	17,296	23,802
Terminalling and storage
Goodwill [Roll Forward]
Goodwill, beginning balance	14,229
Impairment	0
CCCT Assets	(2,361)
Goodwill, ending balance	11,868	14,229
Natural gas services
Goodwill [Roll Forward]
Goodwill, beginning balance	79
Impairment	0
CCCT Assets	0
Goodwill, ending balance	79	79
Sulfur services
Goodwill [Roll Forward]
Goodwill, beginning balance	5,349
Impairment	0
CCCT Assets	0
Goodwill, ending balance	5,349	5,349
Marine transportation
Goodwill [Roll Forward]
Goodwill, beginning balance	4,145
Impairment	(4,145)
CCCT Assets	0
Goodwill, ending balance	$ 0	$ 4,145

Leases (Details)

Leases (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Leases
2,017	$ 10,458
2,018	5,633
2,019	4,036
2,020	3,389
2,021	1,041
Thereafter	8,449
Total	33,006
Rent expense for operating leases	$ 19,005	$ 18,831	$ 18,724

Investments in Unconsolidated65

Investments in Unconsolidated Entities and Joint Ventures (Details) $ in Thousands	Aug. 31, 2014USD ($)	Aug. 29, 2014	May 14, 2014USD ($)mi	May 14, 2014USD ($)mi	Mar. 31, 2013USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Aug. 28, 2014
Schedule of Equity Method Investments [Line Items]
Payment to acquire unconsolidated entities						$ 0	$ 0	$ 134,030
Notes receivable						15,000	15,000
Partnership's interest in cash of the unconsolidated equity method investees						$ 631	$ 1,060
West Texas LPG Pipeline L.P.
Schedule of Equity Method Investments [Line Items]
Ownership percentage			20.00%	20.00%
Length common carrier pipeline (in miles) | mi			2,300	2,300
West Texas LPG Pipeline L.P. | Common
Schedule of Equity Method Investments [Line Items]
Ownership percentage			19.80%	19.80%
West Texas LPG Pipeline L.P. | General Partner
Schedule of Equity Method Investments [Line Items]
Ownership percentage			0.20%	0.20%
West Texas LPG Pipeline L.P. | ONEOK Partners, L.P.
Schedule of Equity Method Investments [Line Items]
Remaining ownership percentage in investment			80.00%	80.00%
Martin Energy Trading LLC
Schedule of Equity Method Investments [Line Items]
Ownership percentage					100.00%
Proceeds from sale of equity method investment					$ 15,000
Annual interest rate percentage of note receivable	15.00%
Martin Energy Trading LLC | Notes Receivable
Schedule of Equity Method Investments [Line Items]
Notes receivable	$ 15,000
Cardinal Gas Storage Partners LLC
Schedule of Equity Method Investments [Line Items]
Additional voting interests acquired (percentage)		57.80%
Remaining ownership percentage in investment									42.20%
Atlas Holdings
Schedule of Equity Method Investments [Line Items]
Payment to acquire unconsolidated entities			$ 134,400	$ 134,400
Reduction in post closing working capital adjustment			$ 501	$ 501

Investments in Unconsolidated66

Investments in Unconsolidated Entities and Joint Ventures - Information for Significant Unconsolidated Equity Method Investees (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
WTLPG
Schedule of Equity Method Investments [Line Items]
Total Assets	$ 812,464	$ 819,342	$ 827,697
Long-Term Debt	0	0	0
Members’ Equity/Partners' Capital	790,406	804,023	818,546
Revenues	88,468	100,708	95,315
Net Income	$ 23,883	$ 46,294	38,698
Cardinal
Schedule of Equity Method Investments [Line Items]
Total Assets			0
Long-Term Debt			0
Members’ Equity/Partners' Capital			0
Revenues			46,488
Net Income			$ 1,911

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Recurring | Commodity derivative contracts, net | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset	$ (3,904)	$ 675
Recurring | Interest rate derivative contracts | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liability	0	(206)
Nonrecurring | Carrying Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Note receivable - MET	15,000	15,000
Nonrecurring | Carrying Value | 2021 Senior unsecured notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Senior notes	372,239	371,861
Nonrecurring | Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Note receivable - MET	15,797	15,830
Nonrecurring | Fair Value | 2021 Senior unsecured notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Senior notes	$ 377,882	$ 318,000

Derivative Instruments and He68

Derivative Instruments and Hedging Activities (Details)	Jan. 07, 2016USD ($)	Feb. 28, 2015MMBTU	Jan. 31, 2015MMBTU	Oct. 14, 2014USD ($)derivative	Oct. 09, 2014USD ($)derivative	Aug. 29, 2014MMBTUincrement$ / MMBTU	May 14, 2014USD ($)derivative	Aug. 31, 2014USD ($)	Dec. 31, 2016USD ($)bbl	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Oct. 10, 2014USD ($)derivative	Sep. 18, 2014USD ($)	Apr. 01, 2014USD ($)derivative
Derivative [Line Items]
Noncurrent derivative liability									$ 0	$ 206,000
Commodity derivative contracts, net
Derivative [Line Items]
Notional quantity (in bbl) | bbl									731,000
Interest Rate Swap
Derivative [Line Items]
Early extinguishment termination fees received	$ 160,000			$ 711,000	$ 2,125,000		$ 2,380,000
Notional principal amount				$ 50,000,000			$ 100,000,000			50,000,000		$ 50,000,000	$ 50,000,000	$ 100,000,000
Premiums received									$ 630,000	2,495,000
Number of agreements | derivative				2			2					2		2
Number of agreements terminated | derivative				2	3
Interest Rate Swap | October 9, 2014
Derivative [Line Items]
Early extinguishment termination fees received				$ 500,000
Number of agreements terminated | derivative				2
Interest Expense | Interest Rate Swap
Derivative [Line Items]
Premiums received									$ 630,000	2,495,000
Amount of gain(loss) on derivatives								$ 976,000
Fair Value of Derivatives | Interest Rate Swap
Derivative [Line Items]
Noncurrent derivative liability										$ 206,000
Call Option | Commodity derivative contracts, net
Derivative [Line Items]
Notional quantity (in MMBtu) | MMBTU		1,286,242	2,345,498			3,631,740
Strike price (in dollars per MMBtu) | $ / MMBTU						4.50
Number of increments options were settled in | increment						2
Early extinguishment termination fees received											$ 3,000

Derivative Instruments and He69

Derivative Instruments and Hedging Activities - Balance Sheet Derivatives (Details) - Not Designated as Hedging Instrument - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Derivative asset, fair value	$ 0	$ 675
Derivative liability, fair value	3,904	206
Commodity derivative contracts, net | Fair Value of Derivatives, Current
Derivatives, Fair Value [Line Items]
Derivative asset, fair value	0	675
Derivative liability, fair value	3,904	0
Interest rate derivative contracts | Fair Value of Derivatives, Noncurrent
Derivatives, Fair Value [Line Items]
Derivative asset, fair value	0	0
Derivative liability, fair value	$ 0	$ 206

Derivative Instruments and He70

Derivative Instruments and Hedging Activities - Effect of derivative instruments on the Consolidated Statement of Operations (Details) - Not Designated as Hedging Instrument - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain(loss) on derivatives	$ 4,133	$ 3,107	$ 5,877
Interest rate swaption contracts | Interest Expense
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain(loss) on derivatives	(630)	2,495	0
Interest rate derivative contracts | Interest Expense
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain(loss) on derivatives	(366)	(206)	6,692
Commodity derivative contracts, net | Cost of Products Sold
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain(loss) on derivatives	5,129	818	0
Commodity derivative contracts, net | Other Income
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain(loss) on derivatives	$ 0	$ 0	$ (815)

Related Party Transactions (Det

Related Party Transactions (Details) - shares	Sep. 29, 2014	Aug. 29, 2014	May 12, 2014	Dec. 31, 2016	Dec. 31, 2014
Related Party Transaction [Line Items]
General partner interest percentage	2.00%	2.00%	2.00%	2.00%	2.00%
Martin Resource Management
Related Party Transaction [Line Items]
Number of shares owned (in shares)				6,264,532
Ownership percentage				17.70%
General partner interest percentage				2.00%
Martin Resource Management | MMGP Holdings, LLC
Related Party Transaction [Line Items]
General partner interest percentage				51.00%

Related Party Transactions - Om

Related Party Transactions - Omnibus Agreement Narrative (Details) - Omnibus Agreement - Martin Resource Management - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Noncompete restriction threshold	$ 5,000,000
Noncompete restriction ownership option opportunity threshold minimum	5,000,000
Noncompete restriction ownership option opportunity threshold minimum with equity limitation	$ 5,000,000
Equity limitation on ownership restriction percentage	20.00%
Approved annual reimbursements for indirect expenses	$ 16,416,000
Indirect expenses reimbursed	$ 13,033,000	$ 13,679,000	$ 12,535,000

Related Party Transactions - Mo

Related Party Transactions - Motor Carrier Agreement (Details) - Motor Carrier Agreement - Martin Resource Management	12 Months Ended
	Dec. 31, 2016
Related Party Transaction [Line Items]
Automatic consecutive term renewal (in years)	1 year
Termination written notice, minimum (in days)	30 days
Partnership notice period to terminate agreement (in days)	90 days

Related Party Transactions - Ma

Related Party Transactions - Marine Agreements (Details) - Marine Transportation Agreement - Martin Resource Management	12 Months Ended
	Dec. 31, 2016
Related Party Transaction [Line Items]
Automatic consecutive term renewal (in years)	1 year
Termination written notice, minimum (in days)	60 days

Related Party Transactions - Ot

Related Party Transactions - Other Agreements (Details) - Martin Resource Management	12 Months Ended
	Dec. 31, 2016bbl_per_day
Cross Tolling Agreement
Related Party Transaction [Line Items]
Production minimum per day (in bbl)	6,500
Annual escalation benchmark percentage	3.00%
Sulfuric Acid Sales Agency Agreement
Related Party Transaction [Line Items]
Partnership notice period to terminate agreement (in days)	180 days

Related Party Transactions - Sc

Related Party Transactions - Schedule of the impact of Related Party Transactions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues:
Terminalling and storage	$ 82,437	$ 78,233	$ 74,467
Marine transportation	21,767	27,724	24,389
Natural gas services	699	878	0
Product sales:
Product Sales Related Party	3,034	5,671	7,661
Cost of products sold:
Natural gas services	22,886	25,797	37,703
Sulfur services	15,339	16,579	18,390
Terminalling and storage	13,838	17,718	36,341
Operating expenses:
Operating expenses	70,841	77,871	79,577
Related Party
Product sales:
Product Sales Related Party	3,034	5,671	7,661
Revenue from related parties	107,937	112,506	106,517
Cost of products sold:
Natural gas services	22,886	25,797	37,703
Sulfur services	15,339	16,579	18,390
Costs of products sold	52,063	60,094	92,434
Operating expenses:
Operating expenses	70,841	77,871	79,577
Selling, general and administrative:
Selling, general and administrative	25,890	24,968	23,679
Related Party | Terminalling and storage
Revenues:
Terminalling and storage	82,437	78,233	74,467
Product sales:
Product Sales Related Party	1,020	1,836	676
Cost of products sold:
Terminalling and storage	13,838	17,718	36,341
Operating expenses:
Operating expenses	27,481	29,931	29,525
Selling, general and administrative:
Selling, general and administrative	2,526	2,284	1,874
Related Party | Marine transportation
Revenues:
Marine transportation	21,767	27,724	24,389
Operating expenses:
Operating expenses	28,107	32,373	37,703
Selling, general and administrative:
Selling, general and administrative	30	29	30
Related Party | Natural gas services
Revenues:
Natural gas services	699	878	0
Product sales:
Product Sales Related Party	8	196	3,064
Operating expenses:
Operating expenses	9,258	8,639	4,870
Selling, general and administrative:
Selling, general and administrative	7,566	6,216	6,039
Related Party | Sulfur services
Product sales:
Product Sales Related Party	2,006	3,639	3,921
Operating expenses:
Operating expenses	5,995	6,928	7,479
Selling, general and administrative:
Selling, general and administrative	2,732	2,760	3,201
Related Party | Indirect overhead allocation, net of reimbursement [Member]
Selling, general and administrative:
Selling, general and administrative	$ 13,036	$ 13,679	$ 12,535

Related Party Transactions - 77

Related Party Transactions - Other Related Party Transactions (Details) - USD ($) $ in Thousands	Aug. 31, 2014	Mar. 31, 2013	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Notes receivable			$ 15,000	$ 15,000
Martin Energy Trading LLC
Related Party Transaction [Line Items]
Ownership percentage		100.00%
Proceeds from sale of equity method investment		$ 15,000
Interest rate, note receivable due from related party	15.00%
Notes Receivable | Martin Energy Trading LLC
Related Party Transaction [Line Items]
Notes receivable	$ 15,000
Interest Expense | Martin Energy Trading LLC
Related Party Transaction [Line Items]
Interest income from related parties			$ 2,256	$ 2,250	$ 752

Supplemental Balance Sheet In78

Supplemental Balance Sheet Information - Other Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Balance Sheet Related Disclosures [Abstract]
Customer contracts and relationships, net	$ 36,528	$ 50,452
Other intangible assets	2,280	1,818
Other	6,066	6,044
Intangible and other assets, net	$ 44,874	$ 58,314

Supplemental Balance Sheet In79

Supplemental Balance Sheet Information - Other Intangible Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Balance Sheet Related Disclosures [Abstract]
Amortization of intangible assets	$ 19,548	$ 22,115	$ 9,772
Accumulated amortization	48,876	$ 32,842
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2,017	11,804
2,018	7,472
2,019	4,471
2,020	4,440
2,021	4,319
Subsequent years	$ 6,302

Supplemental Balance Sheet In80

Supplemental Balance Sheet Information - Other Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Balance Sheet Related Disclosures [Abstract]
Accrued interest	$ 10,629	$ 10,365
Asset retirement obligations	7,953	0
Property and other taxes payable	6,443	6,668
Accrued payroll	1,672	1,389
Other	20	111
Total other accrued liabilities	$ 26,717	$ 18,533

Supplemental Balance Sheet In81

Supplemental Balance Sheet Information - Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning asset retirement obligations	$ 2,163	$ 2,052
Revisions to existing liabilities	14,379	0
Accretion	178	111
Liabilities settled	(302)	0
Ending asset retirement obligations	$ 2,163	$ 2,052	$ 16,418	$ 2,163
Current portion of asset retirement obligations			(7,953)	0
Long-term portion of asset retirement obligations			$ 8,465	$ 2,163

Long-Term Debt (Details)

Long-Term Debt (Details) - USD ($)	Apr. 27, 2016	Aug. 14, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Apr. 26, 2016	Apr. 30, 2014	Feb. 28, 2013
Debt Instrument [Line Items]
Total long-term debt			$ 808,107,000	$ 865,003,000
Write off of existing debt issuance costs					$ 3,078,000
Cash paid for interest			46,046,000	43,376,000	37,112,000
Capitalized interest			1,126,000	1,944,000	$ 1,437,000
Revolving Loan Facility
Debt Instrument [Line Items]
Total long-term debt			435,868,000	493,142,000
Face amount	$ 664,444,000		664,444,000	700,000,000		$ 700,000,000
Unamortized debt issuance costs			$ 7,132,000	4,858,000
Weighted average interest rate			3.76%
Write off of existing debt issuance costs	$ 820,000	$ 1,625,000	$ 820,000
Revolving Loan Facility | LIBOR
Debt Instrument [Line Items]
Applicable margins			3.00%
Revolving Loan Facility | Minimum | LIBOR
Debt Instrument [Line Items]
Applicable margins			2.00%
Revolving Loan Facility | Minimum | Prime Rate
Debt Instrument [Line Items]
Applicable margins			1.00%
Revolving Loan Facility | Maximum | LIBOR
Debt Instrument [Line Items]
Applicable margins			3.00%
Revolving Loan Facility | Maximum | Prime Rate
Debt Instrument [Line Items]
Applicable margins			2.00%
Senior Notes | Senior Notes 7.250%
Debt Instrument [Line Items]
Total long-term debt			$ 372,239,000	371,861,000
Face amount				$ 400,000,000			$ 150,000,000	$ 250,000,000
Fixed rate cost				7.25%
Unamortized debt issuance costs			2,823,000	$ 3,507,000
Unamortized premium			$ 1,262,000	1,568,000
Amount of debt repurchased				$ 26,200,000

Partners' Capital (Details)

Partners' Capital (Details) - shares	Sep. 29, 2014	Aug. 29, 2014	May 12, 2014	Dec. 31, 2016	Dec. 31, 2014
Limited Partners' Capital Account [Line Items]
Common limited partner units (in shares)				35,452,062
Ownership percentage				98.00%
General partner interest percentage	2.00%	2.00%	2.00%	2.00%	2.00%
Martin Resource Management
Limited Partners' Capital Account [Line Items]
Common limited partner units (in shares)				6,264,532
Ownership percentage				17.70%
General partner interest percentage				2.00%

Partners' Capital - Issuance of

Partners' Capital - Issuance of Common Units (Details) - USD ($)	Sep. 29, 2014	Aug. 29, 2014	Aug. 08, 2014	May 12, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Limited Partners' Capital Account [Line Items]
Share price (in dollars per share)		$ 38.42
Proceeds from issuance of common units	$ 122,176,000			$ 143,431,000
General partner contribution	$ 2,599,000			$ 3,049,000
General partner interest percentage	2.00%	2.00%		2.00%	2.00%		2.00%
Private placement of units in cash		$ 45,000,000
Common units sold in private equity sale (in shares)		1,171,265					522,121
Trading period for weighted average price of common units (in days)			10 days
General partner contribution to maintain GP interest		$ 918,000			$ 0	$ 55,000	$ 7,007,000
Aggregate proceeds from issuance of common units						0	21,501,000
Equity issuance related costs						$ 591,000	380,000
Public Offering
Limited Partners' Capital Account [Line Items]
Units issued in public offering (in shares)	3,450,000			3,600,000
Share price (in dollars per share)	$ 36.91			$ 41.51
General Partner
Limited Partners' Capital Account [Line Items]
General partner contribution to maintain GP interest							$ 441,000

Partners' Capital - Incentive D

Partners' Capital - Incentive Distribution Rights (Details) - USD ($) $ / shares in Units, $ in Thousands	Sep. 29, 2014	Aug. 29, 2014	May 12, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Limited Partners' Capital Account [Line Items]
General partner interest percentage	2.00%	2.00%	2.00%	2.00%		2.00%
Martin Midstream GP LLC
Limited Partners' Capital Account [Line Items]
General partner interest percentage				2.00%
Distributions payable on behalf of IDRs				$ 7,786	$ 15,571	$ 0
Martin Midstream GP LLC | Target Level 1
Limited Partners' Capital Account [Line Items]
Target cash distribution, percent				2.00%
Target cash distribution (in dollars per share)				$ 0.55
Martin Midstream GP LLC | Target Level 2
Limited Partners' Capital Account [Line Items]
Target cash distribution, percent				15.00%
Target cash distribution (in dollars per share)				$ 0.625
Martin Midstream GP LLC | Target Level 3
Limited Partners' Capital Account [Line Items]
Target cash distribution, percent				25.00%
Target cash distribution (in dollars per share)				$ 0.75
Martin Midstream GP LLC | Target Level 4
Limited Partners' Capital Account [Line Items]
Target cash distribution, percent				50.00%

Partners' Capital - Distributio

Partners' Capital - Distributions of Available Cash (Details)	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Distribution period (in days)	45 days

Partners' Capital - Reconciliat

Partners' Capital - Reconciliation of net income to partners interest in net income (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
Reconciliation of Net Income from Continuing and Discontinued Operations [Line Items]
Net income (loss)	$ 17,882	$ (933)	$ (1,211)	$ 15,914	$ 6,841	$ 3,330	$ 10,961	$ 17,248	$ 31,652	$ 38,380	$ (11,705)
Less general partner’s interest in net income:
Less income (loss) allocable to unvested restricted units									(90)	(140)	32
Limited partner's interest in net income (loss)									23,143	21,902	(15,176)
Continuing operations:
Reconciliation of Net Income from Continuing and Discontinued Operations [Line Items]
Net income (loss)									31,652	37,165	(6,367)
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs									7,786	15,078	2,033
Distributions payable on behalf of general partner interest									2,058	2,585	1,181
General partner interest in undistributed loss									(1,425)	(1,842)	(1,308)
Less income (loss) allocable to unvested restricted units									90	136	(18)
Limited partner's interest in net income (loss)									23,143	21,208	(8,255)
Discontinued operations:
Reconciliation of Net Income from Continuing and Discontinued Operations [Line Items]
Net income (loss)									0	1,215	(5,338)
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs									0	493	1,704
Distributions payable on behalf of general partner interest									0	84	990
General partner interest in undistributed loss									0	(60)	(1,097)
Less income (loss) allocable to unvested restricted units									0	4	(14)
Limited partner's interest in net income (loss)									$ 0	$ 694	$ (6,921)

Partners' Capital - Net Income

Partners' Capital - Net Income per Unit Narrative (Details) - shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Equity [Abstract]
Weighted average limited partner units outstanding basic (in shares)	35,347,032	35,308,649	30,785,035
Increase in units outstanding due to the dilutive effect of restricted units granted (in shares)	28,231	62,880

Unit Based Awards - Schedule of

Unit Based Awards - Schedule of compensation costs relate to unit based plan (Details) - Selling, General and Administrative Expense - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 904	$ 1,429	$ 817
Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	783	1,338	537
Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 121	$ 91	$ 280

Unit Based Awards (Details)

Unit Based Awards (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)plan_componentshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of plan components | plan_component	2
Number of shares authorized (in shares)	725,000
Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized (in shares)	241,667
Compensation costs not yet recognized | $	$ 1,058
Weighted average period for recognition (in years)	1 year 6 months
Restricted Units | Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)	4 years
Restricted Units | Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)	3 years
Unit options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized (in shares)	483,333

Unit Based Awards - Summary of

Unit Based Awards - Summary of restricted unit activity (Details) - Restricted Units $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)$ / sharesshares
Number of Units
Non-vested, beginning of period, numbers of units (in shares) | shares	150,474
Granted, number of units (in shares) | shares	13,800
Vested, number of units (in shares) | shares	(58,224)
Forfeited, number of units (in shares) | shares	(2,250)
Non-vested, end of period, number of units (in shares) | shares	103,800
Weighted Average Grant-Date Fair Value Per Unit
Non-vested, beginning of period, weighted average grant-date fair value per unit (in dollars per share) | $ / shares	$ 28.89
Granted, weighted average grant-date fair value per unit (in dollars per share) | $ / shares	15.13
Vested, weighted average grant-date fair value per unit (in dollars per share) | $ / shares	30.61
Forfeited, weighted average grant-date fair value per unit (in dollars per share) | $ / shares	28.50
Non-vested, end of period, weighted average grant-date fair value per unit (in dollars per share) | $ / shares	$ 26.54
Aggregate intrinsic value, end of period | $	$ 1,905

Unit Based Awards - Summary o92

Unit Based Awards - Summary of aggregate intrinsic value and fair value of units vested (Details) - Restricted Units - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate intrinsic value of units vested	$ 1,233	$ 110	$ 514
Fair value of units vested	$ 1,773	$ 128	$ 450

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Loss Carryforwards [Line Items]
Deferred tax liability	$ 870	$ 985
Cash paid for income taxes	841	1,237	$ 1,167
Texas | State
Operating Loss Carryforwards [Line Items]
State income taxes	$ 726	$ 1,048	$ 1,137

Business Segments (Details)

Business Segments (Details) $ in Thousands	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 ($)segment	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Segment Reporting Information [Line Items]
Number of reporting units | segment									4
Revenues	$ 236,901	$ 174,537	$ 190,348	$ 225,605	$ 254,371	$ 226,021	$ 251,099	$ 305,353	$ 827,391	$ 1,036,844	$ 1,642,141
Depreciation and Amortization									92,132	92,250	68,830
Operating Income (Loss) after Eliminations	28,888	$ 9,176	$ 10,256	$ 24,338	13,787	$ 12,034	$ 19,630	$ 24,702	72,658	70,153	67,871
Capital Expenditures and Plant Turnaround Costs									38,331	68,727	93,257
Total Assets [Abstract]
Total assets	1,246,363				1,380,473				1,246,363	1,380,473
Operating Revenues
Segment Reporting Information [Line Items]
Revenues									835,987	1,045,545	1,653,009
Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues									(8,596)	(8,701)	(10,868)
Indirect selling, general, and administrative
Segment Reporting Information [Line Items]
Depreciation and Amortization									0	0	0
Operating Income (Loss) after Eliminations									(16,794)	(18,951)	(18,712)
Capital Expenditures and Plant Turnaround Costs									0	0	0
Terminalling and storage
Segment Reporting Information [Line Items]
Revenues									236,710	264,770	321,463
Depreciation and Amortization									45,484	38,731	37,622
Operating Income (Loss) after Eliminations									40,660	15,704	24,993
Capital Expenditures and Plant Turnaround Costs									26,097	40,421	53,450
Total Assets [Abstract]
Total assets	328,098				417,202				328,098	417,202
Terminalling and storage | Operating Revenues
Segment Reporting Information [Line Items]
Revenues									242,363	270,440	326,654
Terminalling and storage | Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues									(5,653)	(5,670)	(5,191)
Natural gas services
Segment Reporting Information [Line Items]
Revenues									391,333	523,160	1,013,835
Depreciation and Amortization									28,081	34,072	13,090
Operating Income (Loss) after Eliminations									41,438	41,220	34,574
Capital Expenditures and Plant Turnaround Costs									4,807	24,330	24,194
Total Assets [Abstract]
Total assets	684,722				694,333				684,722	694,333
Natural gas services | Revenue | Customer concentration risk
Segment Reporting Information [Line Items]
Revenues									122,381	148,273	265,434
Natural gas services | Operating Revenues
Segment Reporting Information [Line Items]
Revenues									391,333	523,160	1,013,835
Natural gas services | Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues									0	0	0
Sulfur services
Segment Reporting Information [Line Items]
Revenues									141,058	170,161	215,471
Depreciation and Amortization									7,995	8,455	8,176
Operating Income (Loss) after Eliminations									23,393	23,604	19,465
Capital Expenditures and Plant Turnaround Costs									5,093	1,201	4,115
Total Assets [Abstract]
Total assets	125,356				134,108				125,356	134,108
Sulfur services | Operating Revenues
Segment Reporting Information [Line Items]
Revenues									141,058	170,161	215,471
Sulfur services | Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues									0	0	0
Marine transportation
Segment Reporting Information [Line Items]
Revenues									58,290	78,753	91,372
Depreciation and Amortization									10,572	10,992	9,942
Operating Income (Loss) after Eliminations									(16,039)	8,576	7,551
Capital Expenditures and Plant Turnaround Costs									2,334	2,775	11,498
Total Assets [Abstract]
Total assets	$ 108,187				$ 134,830				108,187	134,830
Marine transportation | Operating Revenues
Segment Reporting Information [Line Items]
Revenues									61,233	81,784	97,049
Marine transportation | Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues									$ (2,943)	$ (3,031)	$ (5,677)

Quarterly Financial Informati95

Quarterly Financial Information (Details) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016USD ($)$ / unit	Sep. 30, 2016USD ($)$ / unit	Jun. 30, 2016USD ($)$ / unit	Mar. 31, 2016USD ($)$ / unit	Dec. 31, 2015USD ($)$ / unit	Sep. 30, 2015USD ($)$ / unit	Jun. 30, 2015USD ($)$ / unit	Mar. 31, 2015USD ($)$ / unit	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 236,901	$ 174,537	$ 190,348	$ 225,605	$ 254,371	$ 226,021	$ 251,099	$ 305,353	$ 827,391	$ 1,036,844	$ 1,642,141
Operating income	28,888	9,176	10,256	24,338	13,787	12,034	19,630	24,702	72,658	70,153	67,871
Equity in earnings of unconsolidated entities	1,112	1,120	805	1,677	3,234	2,363	1,649	1,740	4,714	8,986	5,466
Income from continuing operations					6,841	3,330	10,961	16,033	31,652	37,165	(6,367)
Income from discontinued operations					0	0	0	1,215	0	1,215	(5,338)
Net income (loss)	$ 17,882	$ (933)	$ (1,211)	$ 15,914	$ 6,841	$ 3,330	$ 10,961	$ 17,248	$ 31,652	$ 38,380	$ (11,705)
Limited partners' interest in net income (loss) per limited partner unit (in dollars per shares) | $ / unit	0.49	(0.03)	(0.14)	0.33	0.08	(0.02)	0.19	0.37

Commitments and Contingencies (

Commitments and Contingencies (Details) $ in Thousands	Dec. 31, 2015lawsuit	Oct. 02, 2012USD ($)quarter	Mar. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Martin Resource Management
Loss Contingencies [Line Items]
Quarterly purchase price reimbursement for non compliance		$ 750		$ 4,125	$ 2,250
Quarterly purchase price reimbursement for non compliance, number of consecutive quarters | quarter		4
Maximum purchase price reimbursement for non compliance				$ 4,500
Scenario, Forecast | Martin Resource Management
Loss Contingencies [Line Items]
Maximum purchase price reimbursement for non compliance			$ 1,125
Lubricants Packaging Business for Defense and Indemnity
Loss Contingencies [Line Items]
Number of lawsuits filed | lawsuit	5

Subsequent Events (Details)

Subsequent Events (Details) - USD ($) $ / shares in Units, $ in Thousands	Feb. 14, 2017	Jan. 19, 2017
Subsequent Event
Subsequent Event [Line Items]
Dividends declared (in dollars per share)		$ 0.50
Annualized dividends declared (in dollars per share)		$ 2
MEH South Texas Terminals LLC | Subsequent Event
Subsequent Event [Line Items]
Business acquisition, percentage of voting interests acquired	100.00%
Purchase price of acquisition	$ 27,420
Construction costs	8,580
Martin Resource Management | MEH South Texas Terminals LLC | Subsequent Event
Subsequent Event [Line Items]
Obligation to repay construction costs in excess of stated amount	8,580
Scenario, Forecast | Martin Resource Management
Subsequent Event [Line Items]
Proceeds from collection of notes receivable	$ 15,000