10-Q

 UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549 

_______________________________________________________ 

FORM 10-Q

ý QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 For the quarterly period ended September 30, 2016

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 For the transition period from ____________ to ____________

Commission File Number

000-50056

MARTIN MIDSTREAM PARTNERS L.P.

(Exact name of registrant as specified in its charter)

Delaware	05-0527861
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)

4200 Stone Road

Kilgore, Texas 75662

(Address of principal executive offices, zip code)

Registrant’s telephone number, including area code: (903) 983-6200

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. 

Yes  x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 

Yes x No o

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

Large accelerated filer                   x	Accelerated filer   o
Non-accelerated filer   o (Do not check if a smaller reporting company)	Smaller reporting company  o

Indicated by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). 

Yes o No x

The number of the registrant’s Common Units outstanding at October 26, 2016, was 35,454,462.

	Page
PART I – FINANCIAL INFORMATION	2
Item 1. Financial Statements	2
Consolidated and Condensed Balance Sheets as of September 30, 2016 (unaudited) and December 31, 2015 (audited)	2
Consolidated and Condensed Statements of Operations for the Three and Nine Months Ended September 30, 2016 and 2015 (unaudited)	3
Consolidated and Condensed Statements of Capital for the Nine Months Ended September 30, 2016 and 2015 (unaudited)	6
Consolidated and Condensed Statements of Cash Flows for the Nine Months Ended September 30, 2016 and 2015 (unaudited)	7
Notes to Consolidated and Condensed Financial Statements	8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3. Quantitative and Qualitative Disclosures About Market Risk	51
Item 4. Controls and Procedures	52
PART II. OTHER INFORMATION	53
Item 1. Legal Proceedings	53
Item 1A. Risk Factors	53
Item 6. Exhibits	53

1

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED BALANCE SHEETS

(Dollars in thousands)

	September 30, 2016			December 31, 2015
	(Unaudited)			(Audited)
Assets
Cash	$	10		$	31
Accounts and other receivables, less allowance for doubtful accounts of $453 and $430, respectively	46,327			74,355
Product exchange receivables	159			1,050
Inventories	107,476			75,870
Due from affiliates	8,194			10,126
Fair value of derivatives	89			675
Other current assets	4,439			5,718
Assets held for sale	73,197			—
Total current assets	239,891			167,825
Property, plant and equipment, at cost	1,301,233			1,387,814
Accumulated depreciation	(411,821		)	(404,574		)
Property, plant and equipment, net	889,412			983,240
Goodwill	17,296			23,802
Investment in WTLPG	129,794			132,292
Note receivable - Martin Energy Trading LLC	15,000			15,000
Other assets, net	48,951			58,314
Total assets	$	1,340,344		$	1,380,473
Liabilities and Partners’ Capital
Trade and other accounts payable	$	60,462		$	81,180
Product exchange payables	10,188			12,732
Due to affiliates	3,879			5,738
Income taxes payable	550			985
Fair value of derivatives	209			—
Other accrued liabilities	14,804			18,533
Liabilities held for sale	23,400			—
Total current liabilities	113,492			119,168
Long-term debt, net	913,504			865,003
Fair value of derivatives	—			206
Other long-term obligations	2,435			2,217
Total liabilities	1,029,431			986,594
Commitments and contingencies (Note 16)
Partners’ capital	310,913			393,879
Total partners’ capital	310,913			393,879
Total liabilities and partners' capital	$	1,340,344		$	1,380,473

See accompanying notes to consolidated and condensed financial statements.

2

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

(Dollars and units in thousands, except per unit amounts)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
Revenues:
Terminalling and storage  *	$	30,770		$	33,578		$	93,565		$	100,828
Marine transportation  *	13,846			18,977			44,531			59,956
Natural gas services*	14,618			17,120			46,118			50,171
Sulfur services	2,700			3,090			8,100			9,270
Product sales: *
Natural gas services	57,378			86,714			207,368			330,803
Sulfur services	26,396			33,213			105,459			128,544
Terminalling and storage	28,829			33,329			85,349			102,901
	112,603			153,256			398,176			562,248
Total revenues	174,537			226,021			590,490			782,473
Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services *	50,658			80,709			184,781			307,039
Sulfur services *	21,510			26,144			73,734			95,685
Terminalling and storage *	23,540			28,237			70,306			87,977
	95,708			135,090			328,821			490,701
Expenses:
Operating expenses  *	39,488			45,310			121,542			138,399
Selling, general and administrative  *	8,049			8,666			24,364			26,507
Loss on impairment of goodwill	—			—			4,145			—
Depreciation and amortization	22,129			23,335			66,266			68,737
Total costs and expenses	165,374			212,401			545,138			724,344
Other operating income (loss)	13			(1,586		)	(1,582		)	(1,763		)
Operating income	9,176			12,034			43,770			56,366
Other income (expense):
Equity in earnings of WTLPG	1,120			2,363			3,602			5,752
Interest expense, net	(11,779		)	(11,994		)	(34,046		)	(32,465		)
Gain on retirement of senior unsecured notes	—			728			—			728
Other, net	730			399			866			757
Total other expense	(9,929		)	(8,504		)	(29,578		)	(25,228		)
Net income (loss) before taxes	(753		)	3,530			14,192			31,138
Income tax expense	(180		)	(200		)	(422		)	(814		)
Income (loss) from continuing operations	(933		)	3,330			13,770			30,324
Income from discontinued operations, net of income taxes	—			—			—			1,215
Net income (loss)	(933		)	3,330			13,770			31,539
Less general partner's interest in net (income) loss	18			(3,959		)	(8,062		)	(12,310		)
Less (income) loss allocable to unvested restricted units	3			(16		)	(36		)	(127		)
Limited partners' interest in net income (loss)	$	(912	)	$	(645	)	$	5,672		$	19,102

See accompanying notes to consolidated and condensed financial statements.

*Related Party Transactions Shown Below

3

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

(Dollars and units in thousands, except per unit amounts)

*Related Party Transactions Included Above

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2016		2015		2016		2015
Revenues:*
Terminalling and storage	$	20,649	$	15,091	$	62,197	$	58,626
Marine transportation	4,861		6,552		17,308		19,919
Natural gas services	132		—		574		—
Product Sales	723		1,731		2,391		5,079
Costs and expenses:*
Cost of products sold: (excluding depreciation and amortization)
Natural gas services	2,946		6,470		10,829		20,198
Sulfur services	3,678		3,387		11,300		10,629
Terminalling and storage	3,766		3,227		11,232		14,261
Expenses:
Operating expenses	17,810		19,290		53,255		58,605
Selling, general and administrative	5,748		5,922		18,091		17,765

See accompanying notes to consolidated and condensed financial statements.

4

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

(Dollars and units in thousands, except per unit amounts)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016		2015
Allocation of net income (loss) attributable to:
Limited partner interest:
Continuing operations	$	(912	)	$	(645	)	$	5,672	$	18,366
Discontinued operations	—			—			—		736
	$	(912	)	$	(645	)	$	5,672	$	19,102
General partner interest:
Continuing operations	$	(18	)	$	3,959		$	8,062	$	11,836
Discontinued operations	—			—			—		474
	$	(18	)	$	3,959		$	8,062	$	12,310
Net income (loss) per unit attributable to limited partners:
Basic:
Continuing operations	$	(0.03	)	$	(0.02	)	$	0.16	$	0.52
Discontinued operations	—			—			—		0.02
	$	(0.03	)	$	(0.02	)	$	0.16	$	0.54
Weighted average limited partner units - basic	35,346			35,308			35,358		35,309
Diluted:
Continuing operations	$	(0.03	)	$	(0.02	)	$	0.16	$	0.52
Discontinued operations	—			—			—		0.02
	$	(0.03	)	$	(0.02	)	$	0.16	$	0.54
Weighted average limited partner units - diluted	35,346			35,308			35,381		35,369

See accompanying notes to consolidated and condensed financial statements.

5

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF CAPITAL

(Unaudited)

(Dollars in thousands)

	Partners’ Capital
	Common Limited					General Partner Amount
	Units		Amount						Total
Balances - January 1, 2015	35,365,912		$	470,943		$	14,728		$	485,671
Net income	—		19,229			12,310			31,539
Issuance of common units, net	—		(330		)	—			(330		)
Issuance of restricted units	91,950		—			—			—
Forfeiture of restricted units	(1,250	)	—			—			—
General partner contribution	—		—			55			55
Cash distributions	—		(86,420		)	(13,526		)	(99,946		)
Reimbursement of excess purchase price over carrying value of acquired assets	—		1,500			—			1,500
Unit-based compensation	—		1,080			—			1,080
Balances - September 30, 2015	35,456,612		$	406,002		$	13,567		$	419,569
Balances - January 1, 2016	35,456,612		$	380,845		$	13,034		$	393,879
Net income	—		5,708			8,062			13,770
Issuance of common units, net of issuance related costs	—		(28		)	—			(28		)
Issuance of restricted units	13,800		—			—			—
Forfeiture of restricted units	(500	)	—			—			—
Cash distributions	—		(86,410		)	(13,680		)	(100,090		)
Unit-based compensation	—		712			—			712
Reimbursement of excess purchase price over carrying value of acquired assets	—		3,000			—			3,000
Purchase of treasury units	(15,200	)	(330		)	—			(330		)
Balances - September 30, 2016	35,454,712		$	303,497		$	7,416		$	310,913

See accompanying notes to consolidated and condensed financial statements.

6

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

(Dollars in thousands)

	Nine Months Ended
	September 30,
	2016			2015
Cash flows from operating activities:
Net income	$	13,770		$	31,539
Less: Income from discontinued operations, net of income taxes	—			(1,215		)
Net income from continuing operations	13,770			30,324
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	66,266			68,737
Amortization and write-off of deferred debt issuance costs	2,965			4,142
Amortization of premium on notes payable	(230		)	(246		)
Loss on sale of property, plant and equipment	1,582			1,751
Loss on impairment of goodwill	4,145			—
Gain on retirement of senior unsecured notes	—			(728		)
Equity in earnings of unconsolidated entities	(3,602		)	(5,752		)
Derivative income	(1,867		)	(2,137		)
Net cash received for commodity derivatives	1,666			—
Net cash received for interest rate derivatives	160			—
Net premiums received on derivatives that settled during the year on interest rate swaption contracts	630			2,495
Unit-based compensation	712			1,080
Cash distributions from WTLPG	6,100			7,800
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables	28,028			69,967
Product exchange receivables	891			909
Inventories	(31,606		)	(3,134		)
Due from affiliates	1,932			3,348
Other current assets	(4,693		)	354
Trade and other accounts payable	(15,782		)	(59,124		)
Product exchange payables	(2,544		)	6,360
Due to affiliates	(1,859		)	(1,935		)
Income taxes payable	(435		)	(386		)
Other accrued liabilities	(3,729		)	(8,490		)
Change in other non-current assets and liabilities	(765		)	(999		)
Net cash provided by continuing operating activities	61,735			114,336
Net cash used in discontinued operating activities	—			(1,352		)
Net cash provided by operating activities	61,735			112,984
Cash flows from investing activities:
Payments for property, plant and equipment	(31,884		)	(40,123		)
Acquisition of intangible assets	(2,150		)	—
Payments for plant turnaround costs	(1,614		)	(1,754		)
Proceeds from sale of property, plant and equipment	2,174			1,985
Proceeds from involuntary conversion of property, plant and equipment	23,400			—
Net cash used in continuing investing activities	(10,074		)	(39,892		)
Net cash provided by discontinued investing activities	—			41,250
Net cash provided by (used in) investing activities	(10,074		)	1,358
Cash flows from financing activities:
Payments of long-term debt	(219,700		)	(224,310		)
Proceeds from long-term debt	270,700			209,000
Proceeds from issuance of common units, net of issuance related costs	(28		)	(330		)
General partner contribution	—			55
Purchase of treasury units	(330		)	—
Payment of debt issuance costs	(5,234		)	(340		)
Reimbursement of excess purchase price over carrying value of acquired assets	3,000			1,500
Cash distributions paid	(100,090		)	(99,946		)
Net cash used in financing activities	(51,682		)	(114,371		)
Net decrease in cash	(21		)	(29		)
Cash at beginning of period	31			42
Cash at end of period	$	10		$	13
Non-cash additions to property, plant and equipment	$	1,068		$	4,389

See accompanying notes to consolidated and condensed financial statements.

7

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2016

(Unaudited)

(1) General

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:  natural gas services, including liquids transportation and distribution services and natural gas storage; terminalling and storage services for petroleum products and by-products including the refining of naphthenic crude oil, blending and packaging of finished lubricants; sulfur and sulfur-based products processing, manufacturing, marketing and distribution; and marine transportation services for petroleum products and by-products.

The Partnership’s unaudited consolidated and condensed financial statements have been prepared in accordance with the requirements of Form 10-Q and United States Generally Accepted Accounting Principles ("U.S. GAAP") for interim financial reporting. Accordingly, these financial statements have been condensed and do not include all of the information and footnotes required by U.S. GAAP for annual audited financial statements of the type contained in the Partnership’s annual reports on Form 10-K. 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 financial position, results of operations, and cash flows for the periods shown have been made. All such adjustments are of a normal recurring nature. Results for such interim periods are not necessarily indicative of the results of operations for the full year. These financial statements should be read in conjunction with the Partnership’s audited consolidated financial statements and notes thereto included in the Partnership’s annual report on Form 10-K for the year ended December 31, 2015, filed with the Securities and Exchange Commission (the "SEC") on February 29, 2016, as amended by Amendment No. 1 on Form 10-K/A for the year ended December 31, 2015 filed on March 30, 2016.

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 and condensed financial statements in conformity with U.S. GAAP.  Actual results could differ from those estimates.

As discussed further in Note 3, on October 14, 2016, the Partnership entered into a definitive agreement with NuStar Logistics, L.P. (“NuStar”) to sell its 900,000 barrel crude oil storage terminal, its refined product barge terminal, certain pipelines and related easements as well as dockage and trans-loading assets located in Corpus Christi, Texas ("CCCT Assets") for gross consideration of $107,000 plus the reimbursement of certain capital expenditures and prepaid items. The Partnership expects to receive net proceeds of approximately $93,000 after transaction fees and expenses as well as the application of certain net cash payments previously received by the Partnership in conjunction with its mandated relocation of certain dockage assets to the purchase price in the amount of $13,400. The Partnership expects to close the transaction prior to December 31, 2016. Proceeds from the sale will be used to reduce outstanding borrowings under the Partnership's revolving credit facility. The Partnership has classified the CCCT Assets, and the related liabilities, as held for sale at September 30, 2016.

(2) New 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 and condensed 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 and condensed financial statements and related disclosures.

8

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2016

(Unaudited)

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 and condensed 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 evaluating the effect that ASU 2014-09 will have on its consolidated and condensed financial statements and related disclosures. The Partnership has not yet selected a transition method nor has it determined the effect of the standard on its ongoing financial reporting.

(3) Divestitures and discontinued operations

On October 14, 2016, the Partnership entered into a definitive agreement with NuStar to sell its CCCT Assets for gross consideration of $107,000 plus the reimbursement of certain capital expenditures and prepaid items. The Partnership expects to receive net proceeds of approximately $93,000 after transaction fees and expenses as well as the application of certain net cash payments previously received by the Partnership in conjunction with its mandated relocation of certain dockage assets to the purchase price in the amount of $13,400. The Partnership expects to close the transaction prior to December 31, 2016. Proceeds from the sale will be used to reduce outstanding borrowings under the Partnership's revolving credit facility. The Partnership expects to record a gain from the divestiture. The Partnership has classified the CCCT Assets, and the related liabilities, as held for sale at September 30, 2016, as follows:

	2016
Assets:
Other assets	$	4,333
Property, plant, and equipment	91,594
Accumulated depreciation	(25,091		)
Goodwill	2,361
Assets held for sale	$	73,197
Liabilities:
Current liabilities	$	23,400
Liabilities held for sale	$	23,400

The divestiture of the CCCT Assets does not qualify for discontinued operations presentation under the guidance of ASC 205-20.

Floating Storage Assets. On February 12, 2015, the Partnership sold all six of its 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 classified the Floating Storage Assets as held for sale at December 31, 2014 and has presented the results of operations and cash flows of the Floating Storage Assets as discontinued operations for the three and nine months ended September 30, 2016 and 2015. 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.

9

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2016

(Unaudited)

The Floating Storage Assets’ operating results, which are included in income from discontinued operations, were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Total revenues from third parties1	$	—	$	—	$	—	$	791
Total costs and expenses and other, net, excluding depreciation and amortization	—		—		—		1,038
Depreciation and amortization	—		—		—		—
Other operating income2	—		—		—		1,462
Income from discontinued operations before income taxes	—		—		—		1,215
Income tax expense	—		—		—		—
Income from discontinued operations, net of income taxes	$	—	$	—	$	—	$	1,215

¹ All revenues for the nine months ended September 30, 2015 were from third parties.

² Other operating income represents the gain on the disposition of the Floating Storage Assets.

(4) Inventories

Components of inventories at September 30, 2016 and December 31, 2015 were as follows: 

	September 30, 2016		December 31, 2015
Natural gas liquids	$	65,107	$	20,959
Sulfur	6,959		13,812
Sulfur based products	12,541		19,400
Lubricants	19,918		18,675
Other	2,951		3,024
	$	107,476	$	75,870

(5) Investment in West Texas LPG Pipeline L.P.

The Partnership owns a 19.8% general partnership and 0.2% limited partnership interest in West Texas LPG Pipeline L.P. ("WTLPG"). ONEOK Partners, L.P. is the operator of the assets. 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 20% interest in WTLPG as "Investment in WTLPG" on its Consolidated and Condensed Balance Sheets. The Partnership accounts for its ownership interest in WTLPG under the equity method of accounting.

10

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2016

(Unaudited)

Selected financial information for WTLPG is as follows:

	As of September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	Total Assets		Members' Equity		Revenues		Net Income		Revenues		Net Income
2016
WTLPG	$	815,700	$	791,762	$	21,849	$	5,515	$	66,870	$	18,240
	As of December 31,
2015
WTLPG	$	819,342	$	804,023	$	26,094	$	11,815	$	70,010	$	28,760

As of September 30, 2016 and December 31, 2015, the Partnership’s interest in cash of WTLPG was $1,189 and $1,060, respectively.

(6) 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 September 30, 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 net notional quantity of 441,000 barrels settling during the period from October 31, 2016 through March 31, 2017. These instruments settle against the applicable pricing source for each grade and location. Martin Energy Trading LLC ("MET"), an affiliate of Martin Resource Management, serves as the counterparty for all positions outstanding at September 30, 2016.

(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 its fixed rate senior unsecured notes. All derivatives and hedging instruments are included on the balance sheet as an asset or a liability measured at fair value and changes in fair value are recognized currently in earnings.

During the nine months ended September 30, 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") through September 30, 2016 and 2015, respectively. In connection with the interest rate swaption contracts, the Partnership received premiums of $0 and $630, which represented their fair value on the date the transactions were initiated and were initially recorded as derivative liabilities on the Partnership's Consolidated and Condensed Balance Sheets, during the three and nine months ended September 30, 2016, respectively. In connection with the interest rate swaption contracts, the Partnership received premiums of $750 and $2,495, which represented their fair value on the date the

11

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2016

(Unaudited)

transactions were initiated and were initially recorded as derivative liabilities on the Partnership's Consolidated and Condensed Balance Sheets, during the three and nine months ended September 30, 2015, respectively. Each of the interest rate swaptions was fully amortized as of September 30, 2016 and 2015. Interest rate swaption contract premiums received are amortized over the period from initiation of the contract through their termination date. For the three and nine months ended September 30, 2016, the Partnership recognized $0 and $630, respectively, of premiums in "Interest expense, net" on the Partnership's Consolidated and Condensed Statements of Operations related to the interest rate swaption contracts. For the three and nine months ended September 30, 2015, the Partnership recognized $750 and $2,495, respectively, of premiums in "Interest expense, net" on the Partnership's Consolidated and Condensed Statements of Operations related to the interest rate swaption contracts.

As of December 31, 2015, the Partnership had a fixed-to-variable interest rate swap agreement with a notional principal amount of $50,000 of fixed-to-variable interest rate swap agreements, 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 had a termination date that corresponded to the maturity date of the 2021 senior unsecured notes. This instrument was recorded on the Partnership's Consolidated and Condensed 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.

For information regarding gains and losses on interest rate derivative instruments, see "Tabular Presentation of Gains and Losses on Derivative Instruments" below.

(c)    Tabular Presentation of Gains and Losses on Derivative Instruments

The following table summarizes the fair value and classification of the Partnership’s derivative instruments in its Consolidated and Condensed Balance Sheets:

	Fair Values of Derivative Instruments in the Consolidated Balance Sheets
	Derivative Assets					Derivative Liabilities
		Fair Values					Fair Values
	Balance Sheet Location	September 30, 2016		December 31, 2015		Balance Sheet Location	September 30, 2016		December 31, 2015
Derivatives not designated as hedging instruments:	Current:
Commodity contracts	Fair value of derivatives	$	89	$	675	Fair value of derivatives	$	209	$	—
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		$	89	$	675		$	209	$	206

12

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2016

(Unaudited)

Effect of Derivative Instruments on the Consolidated and Condensed Statements of Operations

For the Three Months Ended September 30, 2016 and 2015

	Location of Gain (Loss) Recognized in Income on  Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives
		2016		2015
Derivatives not designated as hedging instruments:
Interest rate swaption contracts	Interest expense	$	—	$	750
Commodity contracts	Cost of products sold	742		(358		)
Total derivatives not designated as hedging instruments		$	742	$	392

Effect of Derivative Instruments on the Consolidated and Condensed Statements of Operations

For the Nine Months Ended September 30, 2016 and 2015

	Location of Gain (Loss) Recognized in Income on  Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives
		2016		2015
Derivatives not designated as hedging instruments:
Interest rate swaption contracts	Interest expense	$	630	$	2,495
Interest rate contracts	Interest expense	366		—
Commodity contracts	Cost of products sold	871		(358		)
Total derivatives not designated as hedging instruments		$	1,867	$	2,137

(7) 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
	September 30, 2016			December 31, 2015
Commodity derivative contracts, net	$	(120	)	$	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:

13

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2016

(Unaudited)

• 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.

	September 30, 2016				December 31, 2015
	Carrying Value		Fair Value		Carrying Value		Fair Value
Note receivable - MET	$	15,000	$	15,803	$	15,000	$	15,830
2021 Senior unsecured notes	372,144		359,184		371,861		318,000

(8) Supplemental Balance Sheet Information

Components of "Other assets, net" were as follows:

	September 30, 2016		December 31, 2015
Customer contracts and relationships, net	$	40,386	$	50,452
Other intangible assets	2,417		1,818
Other	6,148		6,044
	$	48,951	$	58,314

Accumulated amortization of intangible assets was $47,521 and $32,842 at September 30, 2016 and December 31, 2015, respectively.

Components of "Other accrued liabilities" were as follows:

	September 30, 2016		December 31, 2015
Accrued interest	$	3,721	$	10,365
Property and other taxes payable	8,535		6,668
Accrued payroll	2,505		1,389
Other	43		111
	$	14,804	$	18,533

14

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2016

(Unaudited)

(9) Long-Term Debt

At September 30, 2016 and December 31, 2015, long-term debt consisted of the following:

	September 30, 2016		December 31, 2015
$664,4443 Revolving credit facility at variable interest rate (3.53%1 weighted average at September 30, 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 $7,640 and $4,858, respectively2	$	541,360	$	493,142
$400,000 Senior notes, 7.25% interest, net of unamortized debt issuance costs of $2,994 and $3,507, respectively, including unamortized premium of $1,338 and $1,568, respectively, issued $250,000 February 2013 and $150,000 April 2014, $26,200 repurchased during 2015, due February 2021, unsecured2	372,144		371,861
Total long-term debt, net	$	913,504	$	865,003

¹ 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 September 30, 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 existing LIBOR borrowings at September 30, 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 Partnership's omnibus agreement with Martin Resource Management (the "Omnibus Agreement"). The Partnership is permitted to make quarterly distributions so long as no event of default exists.

² The Partnership is in compliance with all debt covenants as of September 30, 2016.

³ 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. In connection with the amendment, the Partnership expensed $820 of unamortized debt issuance costs determined not to have continuing benefit.

The Partnership paid cash interest, net of proceeds received from interest rate swaptions and capitalized interest, in the amount of $18,644 and $40,760 for the three and nine months ended September, 2016, respectively.  The Partnership paid cash interest, net of proceeds received from interest rate swaptions and capitalized interest, in the amount of $18,017 and $39,121 for the three and nine months ended September 30, 2015, respectively.  Capitalized interest was $229 and $911 for the three and nine months ended September 30, 2016, respectively. Capitalized interest was $427 and $1,522 for the three and nine months ended September 30, 2015, respectively.

(10) Partners' Capital

As of September 30, 2016, Partners’ capital consisted of 35,454,712 common limited partner units, representing a 98% partnership interest and a 2% general partner interest. Martin Resource Management, through subsidiaries, owns 6,264,532 of the Partnership's common limited partner units representing approximately 17.7% of the Partnership's outstanding common limited partner units. Martin Midstream GP LLC ("MMGP"), the Partnership's general partner, owns the 2% general partnership interest. Martin Resource Management controls the Partnership's general partner, by virtue of its 51% voting interest in MMGP Holdings, LLC ("Holdings"), the sole member of the Partnership's general partner.

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.

Incentive Distribution Rights

MMGP holds a 2% 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 general partner was allocated $0 and $7,786 in incentive distributions during the three and nine months ended September 30, 2016, respectively. The general partner was allocated $3,893 and $11,680 in incentive distributions during the three and nine months ended September 30, 2015, respectively.

The target distribution levels entitle the general partner to receive 2% of quarterly cash distributions from the minimum of $0.50 per unit 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.

15

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2016

(Unaudited)

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 income and 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 allocated to the general partner and limited partners for purposes of calculating net income attributable to limited partners per unit:

	Three Months Ended September 30,						Nine Months Ended September 30,
Continuing operations:	2016			2015			2016			2015
Income (loss) from continuing operations	$	(933	)	$	3,330		$	13,770		$	30,324
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	—			3,893			7,786			11,230
Distributions payable on behalf of general partner interest	361			667			1,696			1,925
General partner interest in undistributed earnings	(379		)	(601		)	(1,420		)	(1,319		)
Less income (loss) allocable to unvested restricted units	(3		)	16			36			122
Limited partners’ interest in income (loss) from continuing operations	$	(912	)	$	(645	)	$	5,672		$	18,366

16

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2016

(Unaudited)

	Three Months Ended September 30,				Nine Months Ended September 30,
Discontinued operations:	2016		2015		2016		2015
Income from discontinued operations	$	—	$	—	$	—	$	1,215
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	—		—		—		450
Distributions payable on behalf of general partner interest	—		—		—		77
General partner interest in undistributed earnings	—		—		—		(53		)
Less income allocable to unvested restricted units	—		—		—		5
Limited partners’ interest in income from discontinued operations	$	—	$	—	$	—	$	736

The following are the unit amounts used to compute the basic and diluted earnings per limited partner unit for the periods presented:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2016	2015	2016	2015
Basic weighted average limited partner units outstanding	35,346,412	35,307,583	35,358,217	35,308,990
Dilutive effect of restricted units issued	—	—	22,850	59,976
Total weighted average limited partner diluted units outstanding	35,346,412	35,307,583	35,381,067	35,368,966

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 periods presented. All common unit equivalents were antidilutive for the three months ended September 30, 2016 and 2015 because the limited partners were allocated a net loss in these periods.

(11) Related Party Transactions

As of September 30, 2016, Martin Resource Management owns 6,264,532 of the Partnership’s common units representing approximately 17.7% of the Partnership’s outstanding limited partner 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 IDRs.  The Partnership’s general partner’s ability, as general partner, to manage and operate the Partnership, and Martin Resource Management’s ownership as of September 30, 2016, of approximately 17.7% of the Partnership’s outstanding limited partner 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 and transactions:

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:

17

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2016

(Unaudited)

• 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 Alabama, Florida, Louisiana, Mississippi and Texas;

◦ 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 natural gas 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 of the board of directors of the general partner of the Partnership (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

18

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2016

(Unaudited)

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, 2016, through December 31, 2016, the Conflicts Committee approved an annual reimbursement amount for indirect expenses of $13,033.  The Partnership reimbursed Martin Resource Management for $3,258 and $9,775 of indirect expenses for the three and nine months ended September 30, 2016, respectively.  The Partnership reimbursed Martin Resource Management for $3,420 and $10,259 of indirect expenses for the three and nine months ended September 30, 2015, 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 the 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. These rates are subject to any adjustments which are mutually agreed upon 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, Inc. has indemnified the Partnership against all claims arising out of the negligence or willful misconduct of Martin Transport, Inc. and its officers, employees, agents, representatives and subcontractors. The

19

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2016

(Unaudited)

Partnership has indemnified Martin Transport, Inc. against all claims arising out of the negligence or willful misconduct of the Partnership and its officers, employees, agents, representatives and subcontractors. In the event a claim is the result of the joint negligence or misconduct of Martin Transport, Inc. and the Partnership, 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 the Platt’s U.S. Gulf Coast Index for #2 Fuel Oil.  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. This agreement replaced the prior agreement that was in place concerning the same services, which was dated January 1, 2015. The minimum throughput requirements were reduced under the new agreement. The per gallon throughput fee the Partnership charges under this agreement was increased and may be adjusted annually based on a price index.

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. Most of 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"), a wholly-owned subsidiary of Martin Resource Management, dated October 28, 2014, as amended, 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.

20

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2016

(Unaudited)

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 and Condensed 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 captions of the consolidated and condensed financial statements 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 and condensed financial statements as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Revenues:
Terminalling and storage	$	20,649	$	15,091	$	62,197	$	58,626
Marine transportation	4,861		6,552		17,308		19,919
Natural gas services	132		—		574		—
Product sales:
Natural gas services	—		479		—		779
Sulfur services	502		864		1,551		2,908
Terminalling and storage	221		388		840		1,392
	723		1,731		2,391		5,079
	$	26,365	$	23,374	$	82,470	$	83,624

The impact of related party cost of products sold is reflected in the consolidated and condensed financial statements as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Cost of products sold:
Natural gas services	$	2,946	$	6,470	$	10,829	$	20,198
Sulfur services	3,678		3,387		11,300		10,629
Terminalling and storage	3,766		3,227		11,232		14,261
	$	10,390	$	13,084	$	33,361	$	45,088

The impact of related party operating expenses is reflected in the consolidated and condensed financial statements as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Operating expenses:
Marine transportation	$	6,959	$	8,055	$	21,606	$	24,653
Natural gas services	2,329		2,218		6,955		6,373
Sulfur services	1,510		1,649		4,315		5,348
Terminalling and storage	7,012		7,368		20,379		22,231
	$	17,810	$	19,290	$	53,255	$	58,605

21

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2016

(Unaudited)

The impact of related party selling, general and administrative expenses is reflected in the consolidated and condensed financial statements as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Selling, general and administrative:
Marine transportation	$	9	$	6	$	22	$	22
Natural gas services	1,173		1,263		4,265		3,664
Sulfur services	678		661		2,089		2,099
Terminalling and storage	630		572		1,937		1,721
Indirect, including overhead allocation	3,258		3,420		9,778		10,259
	$	5,748	$	5,922	$	18,091	$	17,765

Other Related Party Transactions

The Partnership has a $15,000 note receivable from MET which 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 and Condensed Balance Sheets. Interest income for the three months ended September 30, 2016 and 2015 was $567 and $567, respectively, and is included in "Interest expense, net" in the Consolidated and Condensed Statements of Operations. Interest income for the nine months ended September 30, 2016 and 2015 was $1,689 and $1,683, respectively, and is included in "Interest expense, net" in the Consolidated and Condensed Statements of Operations.

As discussed in Note 6, the Partnership has certain derivative financial instruments through March 31, 2017 to protect a portion of its commodity price risk exposure related to NGLs. MET serves as counterparty to the outstanding positions at September 30, 2016.

(12) Income Taxes

The operations of the 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 included in income tax expense on the Consolidated and Condensed Statements of Operations. The Texas margin tax restructured the state business tax by replacing the taxable capital and earned surplus components of the existing franchise tax with a new "taxable margin" component. 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

22

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2016

(Unaudited)

immaterial.  State income taxes attributable to the Texas margin tax of $180 and $200 were recorded in income tax expense for the three months ended September 30, 2016 and 2015, respectively. State income taxes attributable to the Texas margin tax of $422 and $814 were recorded in income tax expense for the nine months ended September 30, 2016 and 2015, respectively.

(13) Business Segments

The Partnership has four reportable segments: terminalling and storage, natural gas services, sulfur services and marine transportation. 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 in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2015, filed with the SEC on February 29, 2016, as amended, by Amendment No. 1 on Form 10-K/A filed on March 30, 2016. The Partnership evaluates the performance of its reportable segments based on operating income. There is no allocation of administrative expenses or interest expense.    

Three Months Ended September 30, 2016	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures and Plant Turnaround Costs
Terminalling and storage	$	60,943	$	(1,344	)	$	59,599	$	10,828	$	5,748		$	2,929
Natural gas services	71,996		—			71,996		7,050		7,150			728
Sulfur services	29,096		—			29,096		1,997		(965		)	632
Marine transportation	14,920		(1,074		)	13,846		2,254		1,449			260
Indirect selling, general and administrative	—		—			—		—		(4,206		)	—
Total	$	176,955	$	(2,418	)	$	174,537	$	22,129	$	9,176		$	4,549

Three Months Ended September 30, 2015	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures and Plant Turnaround Costs
Terminalling and storage	$	68,473	$	(1,566	)	$	66,907	$	9,624	$	7,786		$	7,928
Natural gas services	103,834		—			103,834		8,522		6,265			3,784
Sulfur services	36,303		—			36,303		2,129		2,908			289
Marine transportation	19,522		(545		)	18,977		3,060		23			717
Indirect selling, general and administrative	—		—			—		—		(4,948		)	—
Total	$	228,132	$	(2,111	)	$	226,021	$	23,335	$	12,034		$	12,718

23

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2016

(Unaudited)

Nine Months Ended September 30, 2016	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures and Plant Turnaround Costs
Terminalling and storage	$	183,014	$	(4,100	)	$	178,914	$	30,904	$	19,773		$	18,059
Natural gas services	253,486		—			253,486		21,007		24,695			3,881
Sulfur services	113,559		—			113,559		5,978		17,506			4,425
Marine transportation	46,854		(2,323		)	44,531		8,377		(5,528		)	2,197
Indirect selling, general and administrative	—		—			—		—		(12,676		)	—
Total	$	596,913	$	(6,423	)	$	590,490	$	66,266	$	43,770		$	28,562

Nine Months Ended September 30, 2015	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures and Plant Turnaround Costs
Terminalling and storage	$	207,794	$	(4,065	)	$	203,729	$	29,030	$	20,771		$	25,810
Natural gas services	380,974		—			380,974		25,297		24,412			17,893
Sulfur services	137,814		—			137,814		6,360		18,174			650
Marine transportation	62,354		(2,398		)	59,956		8,050		7,267			1,913
Indirect selling, general and administrative	—		—			—		—		(14,258		)	—
Total	$	788,936	$	(6,463	)	$	782,473	$	68,737	$	56,366		$	46,266

The Partnership's assets by reportable segment as of September 30, 2016 and December 31, 2015, are as follows:

	September 30, 2016		December 31, 2015
Total assets:
Terminalling and storage	$	412,604	$	417,202
Natural gas services	687,579		694,333
Sulfur services	118,699		134,108
Marine transportation	121,462		134,830
Total assets	$	1,340,344	$	1,380,473

(14) Unit Based Awards

The Partnership recognizes compensation cost related to unit-based awards to employees in its consolidated financial statements in accordance with certain provisions of ASC 718. The Partnership recognizes compensation costs related to unit-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 and condensed financial statements with respect to these plans are as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2016		2015			2016		2015
Employees	$	204	$	333		$	614	$	985
Non-employee directors	22		(3		)	98		95
Total unit-based compensation expense	$	226	$	330		$	712	$	1,080

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 (the "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

24

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2016

(Unaudited)

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 nine months ended September 30, 2016 is provided below:

	Number of Units			Weighted Average Grant-Date Fair Value Per Unit
Non-vested, beginning of period	150,474			$	28.98
Granted	13,800			$	15.13
Vested	(55,474		)	$	30.57
Forfeited	(500		)	$	28.50
Non-Vested, end of period	108,300			$	27.03
Aggregate intrinsic value, end of period	$	2,170

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 nine months ended September 30, 2016 and 2015 is provided below:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Aggregate intrinsic value of units vested	$	—	$	—	$	1,183	$	110
Fair value of units vested	$	—	$	—	$	1,685	$	113

As of September 30, 2016, there was $1,358 of unrecognized compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 1.68 years.

In conjunction with restricted unit issuances during the nine months ended September 30, 2015, the Partnership received $55 in capital contributions from its general partner to maintain its 2% general partnership interest in the Partnership.

Unit Options.  The plan currently permits the grant of options covering common units. As of September 30, 2016, the Partnership has not granted any common unit options to directors or employees of the Partnership's general partner, or its affiliates. In the future, the Compensation Committee may determine to make grants under the plan to employees and directors containing such terms as the Compensation Committee shall determine. Unit options will have an exercise price that, in the discretion of the Compensation Committee, may not be less than the fair market value of the units on the date of grant. In addition, the unit options will become exercisable upon a change in control of the Partnership's general partner, Martin Resource Management, or if the general partner ceases to be an affiliate of Martin Resource Management or upon the achievement of specified financial objectives.

(15) Condensed Consolidating Financial Information

The Partnership's operations are conducted by its operating subsidiaries as it has no independent assets or operations. Martin Operating Partnership L.P. (the "Operating Partnership"), the Partnership’s wholly-owned subsidiary, and the Partnership's other operating subsidiaries have issued in the past, and may issue in the future, unconditional guarantees of senior

25

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2016

(Unaudited)

or subordinated debt securities of the Partnership. The guarantees that have been issued are full, irrevocable and unconditional and joint and several. In addition, the Operating Partnership may also issue senior or subordinated debt securities which, if issued, will be fully, irrevocably and unconditionally guaranteed by the Partnership. Substantially all of the Partnership's operating subsidiaries are subsidiary guarantors of its outstanding senior unsecured notes and any subsidiaries other than the subsidiary guarantors are minor.

(16) 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 provides for purchase price reimbursements of up to $4,500 in 2016 in the event certain financial conditions are not met. Currently, the Partnership expects to be fully reimbursed for the 2016 amount of $4,500. For the three and nine months ended September 30, 2016, the Partnership received $1,125 and $3,000, respectively, related to the Purchase Price Reimbursement Agreement. For the each of the three and nine months ended September 30, 2015, the Partnership received $750 and $1,500 related to the Purchase Price Reimbursement Agreement.

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 is seeking to evict the Partnership from the leased property and to recover 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.

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 generally allege that the customer engaged in unlawful and deceptive business practices in connection with its marketing and advertising of its private label motor oil. The Partnership disputes that it has any obligation to defend or indemnify the customer for its conduct. Accordingly, on January 7, 2016, the Partnership filed a Complaint for Declaratory Judgment in the Chancery Court of Davidson County, Tennessee requesting a judicial determination that the Partnership does not owe the customer the demanded defense and indemnity obligations. Currently, we are unable to determine the exposure we may have in this matter, if any.

26

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

September 30, 2016

(Unaudited)

(17) Impairments and other charges

Marine Transportation Goodwill Impairment

Over the last two years, global oil and natural gas commodity prices, particularly crude oil, significantly decreased as compared to recent historical levels. This decrease in commodity prices has had, and is expected to continue to have, a negative impact on drilling and crude oil production in the areas served by the Partnership's marine transportation assets.  The Partnership performed its annual assessment of the recoverability of goodwill during the third quarter of 2015. The Partnership updated its internal business outlook of the Marine Transportation reporting unit to consider the current economic environment that affects its operations. As part of the first step of goodwill impairment testing, the Partnership updated its assessment of its future cash flows, applying expected long-term growth rates, discount rates, and terminal values that the Partnership considers reasonable. Fair value was determined based on weighted average of the discounted cash flow method, the guideline public company method and the guideline transaction method. As a result of the analysis, the Partnership determined that there was no impairment of goodwill as of its annual assessment date. At the August 31, 2015 annual assessment date, the percentage of the fair value of the Partnership's Marine Transportation reporting unit over its carrying value was 41%.

As of June 30, 2016, the Partnership determined that the state of market conditions, 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 impairment losses for goodwill during the nine months ended September 30, 2015.

Divestiture of Non-Core Marine Equipment

During the nine months ended September 30, 2016, the Partnership disposed of 8 inland tank barges and 2 inland push boats, which were deemed non-core assets to the Partnership's Marine Transportation business. The Partnership recognized a loss related to the disposition of these assets in the amount of $1,567, which is included in "Other operating loss" on the Partnership's Consolidated and Condensed Statements of Operations.

(18) Subsequent Events

Sale of CCCT Assets. As discussed in Note 3, on October 14, 2016, the Partnership entered into a definitive agreement with NuStar to sell the CCCT Assets for gross consideration of $107,000 plus the reimbursement of certain capital expenditures and prepaid items. The Partnership expects to receive net proceeds of approximately $93,000 after transaction fees and expenses as well as the application of certain net cash payments previously received by the Partnership in conjunction with its mandated relocation of certain dockage assets to the purchase price. Proceeds from the sale will be used to reduce outstanding borrowings under the Partnership's revolving credit facility.

Quarterly Distribution. On October 20, 2016, the Partnership declared a quarterly cash distribution of $0.50 per common unit for the third quarter of 2016, or $2.00 per common unit on an annualized basis, which will be paid on November 14, 2016 to unitholders of record as of November 7, 2016.

27

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

References in this quarterly report on Form 10-Q to "Martin Resource Management" refer to Martin Resource Management Corporation and its subsidiaries, unless the context otherwise requires. You should read the following discussion of our financial condition and results of operations in conjunction with the consolidated and condensed financial statements and the notes thereto included elsewhere in this quarterly report.

Forward-Looking Statements

This quarterly report on Form 10-Q includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Statements included in this quarterly report that are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions or forecasts related thereto), including, without limitation, the information set forth in Management’s Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements. These statements can be identified by the use of forward-looking terminology including "forecast," "may," "believe," "will," "expect," "anticipate," "estimate," "continue," or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other "forward-looking" information. We and our representatives may from time to time make other oral or written statements that are also forward-looking statements.

These forward-looking statements are made based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements.

Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed under "Item 1A. Risk Factors" of our Form 10-K for the year ended December 31, 2015, filed with the Securities and Exchange Commission (the "SEC") on February 29, 2016, as amended, by Amendment No. 1 on Form 10-K/A for the year ended December 31, 2015 filed on March 30, 2016, and in this report.

Overview

We are a publicly traded limited partnership with a diverse set of operations focused primarily in the United States ("U.S.") Gulf Coast region. Our 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 liquids transportation and distribution services and natural gas storage;

• Sulfur and sulfur-based products gathering, processing, marketing, manufacturing and distribution; and

• Marine transportation services for petroleum products and by-products.

The petroleum products and by-products we collect, transport, store and market are produced primarily by major and independent oil and gas companies who often turn to third parties, such as us, for the transportation and disposition of these products. In addition to these major and independent oil and gas companies, our primary customers include independent refiners, large chemical companies, fertilizer manufacturers and other wholesale purchasers of these products. We operate primarily in the U.S. Gulf Coast region. This region is a major hub for petroleum refining, natural gas gathering and processing, and support services for the exploration and production industry.

We were formed in 2002 by Martin Resource Management, a privately-held company whose initial predecessor was incorporated in 1951 as a supplier of products and services to drilling rig contractors. Since then, Martin Resource Management has expanded its operations through acquisitions and internal expansion initiatives as its management identified and capitalized on the needs of producers and purchasers of petroleum products and by-products and other bulk liquids. Martin Resource Management is an important supplier and customer of ours. As of September 30, 2016, Martin Resource Management owned 17.7% of our total outstanding common limited partner units. Furthermore, Martin Resource Management

28

controls Martin Midstream GP LLC ("MMGP"), our general partner, by virtue of its 51% voting interest in MMGP Holdings, LLC ("Holdings"), the sole member of MMGP. MMGP owns a 2.0% general partner interest in us and all of our incentive distribution rights. Martin Resource Management directs our business operations through its ownership interests in and control of our general partner.

We entered into an omnibus agreement dated November 1, 2002, with Martin Resource Management (the "Omnibus Agreement") 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 our use of certain of Martin Resource Management’s trade names and trademarks. Under the terms of the Omnibus Agreement, the employees of Martin Resource Management are responsible for conducting our business and operating our assets.

Martin Resource Management has operated our business since 2002.  Martin Resource Management began operating our natural gas services business in the 1950s and our sulfur business in the 1960s. It began our marine transportation business in the late 1980s. It entered into our fertilizer and terminalling and storage businesses in the early 1990s. In recent years, Martin Resource Management has increased the size of our asset base through expansions and strategic acquisitions.

Recent Developments

Over the past two years, commodity prices have declined substantially and experienced significant volatility. If commodity prices remain weak for a sustained period, our pipeline, terminalling throughput and NGL volumes may be negatively impacted, particularly as producers are curtailing or redirecting drilling. A sustained decline in commodity prices could result in a decrease in activity in the areas served by certain of our terminalling and storage and marine transportation assets resulting in reduced utilization of these assets. Drilling activity levels vary by geographic area, but in general, we have observed widespread decreases in drilling activity, particularly in the Gulf of Mexico, with lower commodity prices. The abundance of supply of inland marine tank barges in our predominantly Gulf Coast market has had a direct impact on our utilization as well a decreased transportation rates.

We continually adjust our business strategy to focus on maximizing liquidity; maintaining a stable asset base, which generates fee based revenues not sensitive to commodity prices; and improving profitability by increasing asset utilization and controlling costs, which includes force reductions and asset rationalization strategies. Given the current environment, we have altered and reduced our planned growth capital expenditures. We believe that controlling our spending in an effort to preserve liquidity is prudent and reduces our need for near-term access to the somewhat uncertain capital markets.

The following information highlights selected developments since January 1, 2016. 

West Texas LPG Pipeline L.P. ("WTLPG") 2015 Rate Complaints. Certain shippers filed complaints with the Railroad Commission of Texas (“RRC”) challenging the increased rates WTLPG implemented effective July 1, 2015.  The complaints request that the rate increase be suspended until the RRC has determined appropriate new rates.  On March 8, 2016, the RRC issued an order directing that WTLPG’s rates “in effect prior to July 1, 2015, are the lawful rates for the duration of this docket unless changed by Commission order.”  The RRC indicated that WTLPG’s rates should be reviewed on a market basis, without consideration of cost of service, if market information is available.  A hearing on the merits on the complaint has not occurred and is not currently scheduled.

Credit Facility Amendment. On April 27, 2016, we made certain strategic amendments to our revolving credit facility which, among other things, decreased our borrowing capacity from $700.0 million to $664.4 million and extended the maturity date of the facility from March 28, 2018 to March 28, 2020.

Subsequent Events

Divestiture of Terminalling Assets. On October 14, 2016, we entered into a definitive agreement with NuStar Logistics, L.P. (“NuStar”) to sell our 900,000 barrel crude oil storage terminal, its refined product barge terminal, certain pipelines and related easements as well as dockage and trans-loading assets located in Corpus Christi, Texas ("CCCT Assets") for gross consideration of $107.0 million plus the reimbursement of certain capital expenditures and prepaid items. We expect to receive net proceeds of approximately $93.0 million 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 $13.4 million. We expect to close the transaction prior to December 31, 2016. Proceeds from the sale will be used to reduce outstanding borrowings under the our revolving credit facility.

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Quarterly Distribution. On October 20, 2016, we declared a quarterly cash distribution of $0.50 per common unit for the third quarter of 2016, or $2.00 per common unit on an annualized basis, which will be paid on November 14, 2016 to unitholders of record as of November 7, 2016.

Critical Accounting Policies and Estimates    

Our discussion and analysis of our financial condition and results of operations are based on the historical consolidated and condensed financial statements included elsewhere herein. We prepared these financial statements in conformity with United States generally accepted accounting principles ("U.S. GAAP" or "GAAP"). The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. We base our estimates on historical experience and on various other assumptions we believe to be reasonable under the circumstances. We routinely evaluate these estimates, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Our results may differ from these estimates, and any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Changes in these estimates could materially affect our financial position, results of operations or cash flows. You should also read Note 2, "Significant Accounting Policies" in Notes to Consolidated Financial Statements included within our Annual Report on Form 10-K for the year ended December 31, 2015. The following table evaluates the potential impact of estimates utilized during the periods ended September 30, 2016 and 2015:

Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
Allowance for Doubtful Accounts
We evaluate our allowance for doubtful accounts on an ongoing basis and record adjustments when, in management's judgment, circumstances warrant. Reserves are recorded to reduce receivables to the amount ultimately expected to be collected.	We evaluate the collectability of our accounts receivable based on factors such as the customer's ability to pay, the age of the receivable and our historical collection experience. A deterioration in any of these factors could result in an increase in the allowance for doubtful accounts balance.	If actual collection results are not consistent with our judgments, we may experience an increase in uncollectible receivables. A 10% increase in our allowance for doubtful accounts would not significantly impact net income.
Depreciation
Depreciation expense is computed using the straight-line method over the useful life of the assets.	Determination of depreciation expense requires judgment regarding estimated useful lives and salvage values of property, plant and equipment. As circumstances warrant, estimates are reviewed to determine if any changes in the underlying assumptions are needed.	The lives of our fixed assets range from 3 - 50 years. If the depreciable lives of our assets were decreased by 10%, we estimate that annual depreciation expense would increase approximately $7.6 million, resulting in a corresponding reduction in net income.
Impairment of Long-Lived Assets
We periodically evaluate whether the carrying value of long-lived assets has been impaired when circumstances indicate the carrying value of the assets may not be recoverable. These evaluations are based on undiscounted cash flow projections over the remaining useful life of the asset. The carrying value is not recoverable if it exceeds the sum of the undiscounted cash flows. Any impairment loss is measured as the excess of the asset's carrying value over its fair value.	Our impairment analyses require management to use judgment in estimating future cash flows and useful lives, as well as assessing the probability of different outcomes.	No impairment of long-lived assets was recorded during the three or nine months ended September 30, 2016 or 2015.
Impairment of Goodwill

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Goodwill is subject to a fair-value based impairment test on an annual basis, or more frequently if events or changes in circumstances indicate that the fair value of any of our reporting units is less than its carrying amount.	We determine fair value using accepted valuation techniques, including discounted cash flow, the guideline public company method and the guideline transaction method. These analyses require management to make assumptions and estimates regarding industry and economic factors, future operating results and discount rates. We conduct impairment testing using present economic conditions, as well as future expectations.	During the three months ended June 30, 2016, we determined that based on a continued decrease in the demand for utilization and transportation day rates forecasted in our Marine Transportation reporting unit, an impairment of goodwill may exist. Based on the results of our impairment analysis, we determined that a $4.1 million impairment loss of all goodwill in the Marine Transportation reporting unit was incurred during the three months ended June 30, 2016. See note 17 for more information. We are in the process of completing the most recent annual review as of August 31, 2016. Based on preliminary results of the evaluation, no impairment exists with the remaining goodwill.
Purchase Price Allocations
We allocate the purchase price of an acquired business to its identifiable assets (including identifiable intangible assets) and liabilities based on their fair values at the date of acquisition. Any excess of purchase price in excess of amounts allocated to identifiable assets and liabilities is recorded as goodwill. As additional information becomes available, we may adjust the preliminary allocation for a period of up to one year.	The determination of fair values of acquired assets and liabilities requires a significant level of management judgment. Fair values are estimated using various methods as deemed appropriate. For significant transactions, third party assessments may be engaged to assist in the valuation process.	If subsequent factors indicate that estimates and assumptions used to allocate costs to acquired assets and liabilities differ from actual results, the allocation between goodwill, other intangible assets and fixed assets could significantly differ. Any such differences could impact future earnings through depreciation and amortization expense. Additionally, if estimated results supporting the valuation of goodwill or other intangible assets are not achieved, impairments could result.
Asset Retirement Obligations
Asset retirement obligations ("AROs") associated with a contractual or regulatory remediation requirement are recorded at fair value in the period in which the obligation can be reasonably estimated and depreciated over the life of the related asset or contractual term. The liability is determined using a credit-adjusted risk-free interest rate and is accreted over time until the obligation is settled.	Determining the fair value of AROs requires management judgment to evaluate required remediation activities, estimate the cost of those activities and determine the appropriate interest rate.	If actual results differ from judgments and assumptions used in valuing an ARO, we may experience significant changes in ARO balances. The establishment of an ARO has no initial impact on earnings.
Environmental Liabilities
We estimate environmental liabilities using both internal and external resources. Activities include feasibility studies and other evaluations management considers appropriate. Environmental liabilities are recorded in the period in which the obligation can be reasonably estimated.	Estimating environmental liabilities requires significant management judgment as well as possible use of third party specialists knowledgeable in such matters.	Environmental liabilities have not adversely affected our results of operations or financial condition in the past, and we do not anticipate that they will in the future.

Our Relationship with Martin Resource Management

Martin Resource Management is engaged in the following principal business activities:

• providing land transportation of various liquids using a fleet of trucks and road vehicles and road trailers;

• distributing fuel oil, ammonia, asphalt, sulfuric acid, marine fuel and other liquids;

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• providing marine bunkering and other shore-based marine services in Alabama, Louisiana, Florida, Mississippi and Texas;

• 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 our business;

• operating a natural gas optimization business;

• operating, for its account and our account, the docks, roads, loading and unloading facilities and other common use facilities or access routes at our Stanolind terminal; and

• operating, solely for our account, the asphalt facilities in Omaha, Nebraska, Port Neches, Texas and South Houston, Texas.

We are and will continue to be closely affiliated with Martin Resource Management as a result of the following relationships.

Ownership

Martin Resource Management owns approximately 17.7% of the outstanding limited partner units. In addition, Martin Resource Management controls MMGP, our general partner, by virtue of its 51% voting interest in Holdings, the sole member of MMGP. MMGP owns a 2% general partner interest in us and all of our incentive distribution rights.

Management

Martin Resource Management directs our business operations through its ownership interests in and control of our general partner. We benefit from our relationship with Martin Resource Management through access to a significant pool of management expertise and established relationships throughout the energy industry. We do not have employees. Martin Resource Management employees are responsible for conducting our business and operating our assets on our behalf.

Related Party Agreements

The Omnibus Agreement requires us to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes on our behalf or in connection with the operation of our business.  We reimbursed Martin Resource Management for $30.7 million of direct costs and expenses for the three months ended September 30, 2016 compared to $34.9 million for the three months ended September 30, 2015. We reimbursed Martin Resource Management for $94.9 million of direct costs and expenses for the nine months ended September 30, 2016 compared to $111.2 million for the nine months ended September 30, 2015. There is no monetary limitation on the amount we are required to reimburse Martin Resource Management for direct expenses.

In addition to the direct expenses, under the Omnibus Agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses.  For the three months ended September 30, 2016 and 2015, the Conflicts Committee approved reimbursement amounts of $3.3 million and $3.4 million, respectively. For the nine months ended September 30, 2016 and 2015, the Conflicts Committee approved reimbursement amounts of $9.8 million and $10.3 million, respectively. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.  These indirect expenses covered the centralized corporate functions Martin Resource Management provides for us, 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 we share with Martin Resource Management’s retained businesses.  The Omnibus Agreement also

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contains significant non-compete provisions and indemnity obligations.  Martin Resource Management also licenses certain of its trademarks and trade names to us under the Omnibus Agreement.

The agreements include, but are not limited to, motor carrier agreements, marine transportation agreements, terminal services agreements, a tolling agreement, a sulfuric acid agreement, and various other miscellaneous agreements. Pursuant to the terms of the Omnibus Agreement, we are prohibited from entering into certain material agreements with Martin Resource Management without the approval of the Conflicts Committee.

For a more comprehensive discussion concerning the Omnibus Agreement and the other agreements that we have entered into with Martin Resource Management, please refer to "Item 13. Certain Relationships and Related Transactions, and Director Independence" set forth in our Annual Report on Form 10-K for the year ended December 31, 2015, filed with the SEC on February 29, 2016, as amended by Amendment No. 1 on Form 10-K/A filed on March 30, 2016.

Commercial

We have been and anticipate that we will continue to be both a significant customer and supplier of products and services offered by Martin Resource Management. Our motor carrier agreement with Martin Resource Management provides us with access to Martin Resource Management’s fleet of road vehicles and road trailers to provide land transportation in the areas served by Martin Resource Management. Our ability to utilize Martin Resource Management’s land transportation operations is currently a key component of our integrated distribution network.

In the aggregate, the impact of related party transactions included in cost of products sold accounted for approximately 11% and 10% of our total cost of products sold during the three months ended September 30, 2016 and 2015, respectively. In the aggregate, the impact of related party transactions included in cost of products sold accounted for approximately 10% and 9% of our total cost of products sold during the nine months ended September 30, 2016 and 2015, respectively. We also purchase marine fuel from Martin Resource Management, which we account for as an operating expense.

Correspondingly, Martin Resource Management is one of our significant customers. Our sales to Martin Resource Management accounted for approximately 15% and 10% of our total revenues for the three months ended September 30, 2016 and 2015, respectively.  Our sales to Martin Resource Management accounted for approximately 14% and 11% of our total revenues for the nine months ended September 30, 2016 and 2015, respectively.  We have entered into certain agreements with Martin Resource Management pursuant to which we provide terminalling and storage and marine transportation services to its subsidiary, Martin Energy Services, LLC ("MES"), and MES provides terminal services to us to handle lubricants, greases and drilling fluids.  Additionally, we have entered into a long-term, fee for services-based tolling agreement with Martin Resource Management where Martin Resource Management agrees to pay us for the processing of its crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts.

For a more comprehensive discussion concerning the agreements that we have entered into with Martin Resource Management, please refer to "Item 13. Certain Relationships and Related Transactions, and Director Independence" set forth in our Annual Report on Form 10-K for the year ended December 31, 2015, filed with the SEC on February 29, 2016, as amended by Amendment No. 1 on Form 10-K/A filed on March 30, 2016.

Approval and Review of Related Party Transactions

If we contemplate entering into a transaction, other than a routine or in the ordinary course of business transaction, in which a related person will have a direct or indirect material interest, the proposed transaction is submitted for consideration to the board of directors of our general partner or to our management, as appropriate. If the board of directors of our general partner is involved in the approval process, it determines whether to refer the matter to the Conflicts Committee of our general partner's board of directors, as constituted under our limited partnership agreement. If a matter is referred to the Conflicts Committee, it obtains information regarding the proposed transaction from management and determines whether to engage independent legal counsel or an independent financial advisor to advise the members of the committee regarding the transaction.  If the Conflicts Committee retains such counsel or financial advisor, it considers such advice and, in the case of a financial advisor, such advisor’s opinion as to whether the transaction is fair and reasonable to us and to our unitholders.

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How We Evaluate Our Operations

Our management uses a variety of financial and operational measurements other than our financial statements prepared in accordance with U.S. GAAP to analyze our performance. These include: (1) net income before interest expense, income tax expense, and depreciation and amortization ("EBITDA"), (2) adjusted EBITDA and (3) distributable cash flow. Our management views these measures as important performance measures of core profitability for our operations and the ability to generate and distribute cash flow, and as key components of our internal financial reporting. We believe investors benefit from having access to the same financial measures that our management uses.

EBITDA and Adjusted EBITDA. Certain items excluded from EBITDA and adjusted EBITDA are significant components in understanding and assessing an entity's financial performance, such as cost of capital and historical costs of depreciable assets. We have included information concerning EBITDA and adjusted EBITDA because they provide investors and management with additional information to better understand the following: financial performance of our assets without regard to financing methods, capital structure or historical cost basis; our operating performance and return on capital as compared to those of other similarly situated entities; and the viability of acquisitions and capital expenditure projects. Our method of computing adjusted EBITDA may not be the same method used to compute similar measures reported by other entities. The economic substance behind our use of adjusted EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make distributions to our unit holders.

Distributable Cash Flow. Distributable cash flow is a significant performance measure used by our management and by external users of our financial statements, such as investors, commercial banks and research analysts, to compare basic cash flows generated by us to the cash distributions we expect to pay our unitholders. Distributable cash flow is also an important financial measure for our unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships because the value of a unit of such an entity is generally determined by the unit's yield, which in turn is based on the amount of cash distributions the entity pays to a unitholder.

EBITDA, adjusted EBITDA and distributable cash flow should not be considered alternatives to, or more meaningful than, net income, cash flows from operating activities, or any other measure presented in accordance with U.S. GAAP. Our method of computing these measures may not be the same method used to compute similar measures reported by other entities.

Non-GAAP Financial Measures

The following table reconciles the non-GAAP financial measurements used by management to our most directly comparable GAAP measures for the three and nine months ended September 30, 2016 and 2015.

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Reconciliation of EBITDA, Adjusted EBITDA, and Distributable Cash Flow

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
	(in thousands)
Net income (loss)	$	(933	)	$	3,330		$	13,770		$	31,539
Less: Income from discontinued operations, net of income taxes	—			—			—			(1,215		)
Income (loss) from continuing operations	(933		)	3,330			13,770			30,324
Adjustments:
Interest expense	11,779			11,994			34,046			32,465
Income tax expense	180			200			422			814
Depreciation and amortization	22,129			23,335			66,266			68,737
EBITDA	33,155			38,859			114,504			132,340
Adjustments:
Equity in earnings of unconsolidated entities	(1,120		)	(2,363		)	(3,602		)	(5,752		)
(Gain) loss on sale of property, plant and equipment	(13		)	1,586			1,582			1,751
Loss on impairment of goodwill	—			—			4,145			—
Unrealized mark-to-market on commodity derivatives	(742		)	358			795			358
Gain on retirement of senior unsecured notes	—			(728		)	—			(728		)
Distributions from unconsolidated entities	1,800			3,400			6,100			7,800
Unit-based compensation	226			330			712			1,080
Adjusted EBITDA	33,306			41,442			124,236			136,849
Adjustments:
Interest expense	(11,779		)	(11,994		)	(34,046		)	(32,465		)
Income tax expense	(180		)	(200		)	(422		)	(814		)
Amortization of debt premium	(77		)	(82		)	(230		)	(246		)
Amortization of deferred debt issuance costs	718			2,400			2,965			4,142
Non-cash mark-to-market on interest rate derivatives	—			—			(206		)	—
Payments for plant turnaround costs	(430		)	—			(1,614		)	(1,754		)
Maintenance capital expenditures	(1,609		)	(2,438		)	(12,818		)	(7,621		)
Distributable Cash Flow	$	19,949		$	29,128		$	77,865		$	98,091

Results of Operations

The results of operations for the three and nine months ended September 30, 2016 and 2015 have been derived from our consolidated and condensed financial statements.

We evaluate segment performance on the basis of operating income, which is derived by subtracting cost of products sold, operating expenses, selling, general and administrative expenses, and depreciation and amortization expense from revenues.  The following table sets forth our operating revenues and operating income by segment for the three and nine months ended September 30, 2016 and 2015.  The results of operations for these interim periods are not necessarily indicative of the results of operations which might be expected for the entire year.

Our consolidated and condensed results of operations are presented on a comparative basis below.  There are certain items of income and expense which we do not allocate on a segment basis.  These items, including equity in earnings (loss) of unconsolidated entities, interest expense, and indirect selling, general and administrative expenses, are discussed following the comparative discussion of our results within each segment.

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Three Months Ended September 30, 2016 Compared to the Three Months Ended September 30, 2015

	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues  after Eliminations		Operating Income (Loss)			Operating Income (Loss) Intersegment Eliminations			Operating Income (Loss)  after Eliminations
Three Months Ended September 30, 2016	(in thousands)
Terminalling and storage	$	60,943	$	(1,344	)	$	59,599	$	6,513		$	(765	)	$	5,748
Natural gas services	71,996		—			71,996		6,455			695			7,150
Sulfur services	29,096		—			29,096		229			(1,194		)	(965		)
Marine transportation	14,920		(1,074		)	13,846		185			1,264			1,449
Indirect selling, general and administrative	—		—			—		(4,206		)	—			(4,206		)
Total	$	176,955	$	(2,418	)	$	174,537	$	9,176		$	—		$	9,176

Three Months Ended September 30, 2015
Terminalling and storage	$	68,473	$	(1,566	)	$	66,907	$	8,823		$	(1,037	)	$	7,786
Natural gas services	103,834		—			103,834		5,503			762			6,265
Sulfur services	36,303		—			36,303		3,573			(665		)	2,908
Marine transportation	19,522		(545		)	18,977		(917		)	940			23
Indirect selling, general and administrative	—		—			—		(4,948		)	—			(4,948		)
Total	$	228,132	$	(2,111	)	$	226,021	$	12,034		$	—		$	12,034

Nine Months Ended September 30, 2016 Compared to the Nine Months Ended September 30, 2015

	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues  after Eliminations		Operating Income (Loss)			Operating Income (Loss) Intersegment Eliminations			Operating Income (Loss)  after Eliminations
Nine Months Ended September 30, 2016	(in thousands)
Terminalling and storage	$	183,014	$	(4,100	)	$	178,914	$	22,239		$	(2,466	)	$	19,773
Natural gas services	253,486		—			253,486		22,543			2,152			24,695
Sulfur services	113,559		—			113,559		20,187			(2,681		)	17,506
Marine transportation	46,854		(2,323		)	44,531		(8,523		)	2,995			(5,528		)
Indirect selling, general and administrative	—		—			—		(12,676		)	—			(12,676		)
Total	$	596,913	$	(6,423	)	$	590,490	$	43,770		$	—		$	43,770

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	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues  after Eliminations		Operating Income (Loss)			Operating Income (Loss) Intersegment Eliminations			Operating Income (Loss)  after Eliminations
Nine Months Ended September 30, 2015	(in thousands)
Terminalling and storage	$	207,794	$	(4,065	)	$	203,729	$	22,736		$	(1,965	)	$	20,771
Natural gas services	380,974		—			380,974		22,739			1,673			24,412
Sulfur services	137,814		—			137,814		20,932			(2,758		)	18,174
Marine transportation	62,354		(2,398		)	59,956		4,217			3,050			7,267
Indirect selling, general and administrative	—		—			—		(14,258		)	—			(14,258		)
Total	$	788,936	$	(6,463	)	$	782,473	$	56,366		$	—		$	56,366

Terminalling and Storage Segment

Comparative Results of Operations for the Three Months Ended September 30, 2016 and 2015

	Three Months Ended September 30,				Variance			Percent Change
	2016		2015
	(In thousands, except BBL per day)
Revenues:
Services	$	32,114	$	35,144	$	(3,030	)	(9	)%
Products	28,829		33,329		(4,500		)	(14	)%
Total revenues	60,943		68,473		(7,530		)	(11	)%
Cost of products sold	24,118		28,765		(4,647		)	(16	)%
Operating expenses	18,299		20,268		(1,969		)	(10	)%
Selling, general and administrative expenses	1,439		995		444			45	%
Depreciation and amortization	10,828		9,624		1,204			13	%
	6,259		8,821		(2,562		)	(29	)%
Other operating income	254		2		252			12,600	%
Operating income	$	6,513	$	8,823	$	(2,310	)	(26	)%
Lubricant sales volumes (gallons)	5,196		5,974		(778		)	(13	)%
Shore-based throughput volumes (gallons)	25,313		36,383		(11,070		)	(30	)%
Smackover refinery throughput volumes (BBL per day)	5,924		6,205		(281		)	(5	)%
Corpus Christi crude terminal (BBL per day)	65,116		148,377		(83,261		)	(56	)%

Services revenues.  Services revenue decreased $3.0 million, primarily as a result of decreased throughput volumes and pass-through revenues at our Corpus Christi crude terminal.

Products revenues. A 21% decrease in sales volumes at our blending and packaging facilities resulted in a $3.6 million decrease to products revenues. The decline in volumes resulted primarily from increased price competition. A 5% decrease in sales prices resulted in a $0.9 million decrease to products revenues.

Cost of products sold.  A 21% decrease in sales volumes at our blending and packaging facilities resulted in a $2.6 million decrease in cost of products sold. The average price per gallon decreased 13%, resulting in a $2.0 million decrease in cost of products sold.

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Operating expenses. Operating expenses at our specialty terminals decreased $1.9 million, primarily due to decreases in repairs and maintenance of $1.0 million and decreased pass-through expenses at our Corpus Christi crude terminal of $0.9 million.

Selling, general and administrative expenses.  Selling, general and administrative expenses increased due to $0.2 million of higher advertising expense and $0.2 million related to increased legal fees.

Depreciation and amortization.  The increase in depreciation and amortization is due to the impact of recent capital expenditures.

Other operating income.  Other operating income represents gains from the disposition of property, plant and equipment.

Volumetric data. Actual volumes at our our Corpus Christi crude terminal for the quarter ended September 30, 2016 averaged 65,116 BBL per day, 19,884 BBL per day less than the contracted minimum throughput. 

Comparative Results of Operations for the Nine Months Ended September 30, 2016 and 2015

	Nine Months Ended September 30,					Variance			Percent Change
	2016		2015
	(In thousands, except BBL per day)
Revenues:
Services	$	97,663	$	104,893		$	(7,230	)	(7	)%
Products	85,351		102,901			(17,550		)	(17	)%
Total revenues	183,014		207,794			(24,780		)	(12	)%
Cost of products sold	71,939		90,076			(18,137		)	(20	)%
Operating expenses	54,740		62,947			(8,207		)	(13	)%
Selling, general and administrative expenses	3,546		2,806			740			26	%
Depreciation and amortization	30,904		29,030			1,874			6	%
	21,885		22,935			(1,050		)	(5	)%
Other operating income (loss)	354		(199		)	553			(278	)%
Operating income	$	22,239	$	22,736		$	(497	)	(2	)%
Lubricant sales volumes (gallons)	15,536		18,007			(2,471		)	(14	)%
Shore-based throughput volumes (gallons)	77,059		122,743			(45,684		)	(37	)%
Smackover refinery throughput volumes (BBL per day)	5,644		6,091			(447		)	(7	)%
Corpus Christi crude terminal (BBL per day)	77,394		166,129			(88,735		)	(53	)%

Services revenues. Services revenue decreased $7.2 million, primarily as a result of decreased throughput volumes and pass-through revenues at our Corpus Christi crude terminal.

Products revenues. A 24% decrease in sales volumes at our blending and packaging facilities resulted in a $13.2 million decrease to products revenues. The decline in volumes resulted primarily from the downturn in the energy industry, as well as increased price competition. Products revenues at our shore-based terminals decreased $3.7 million resulting from a 6% decrease in average sales price combined with a 2% decrease in sales volume.

Cost of products sold.  A 24% decrease in sales volumes at our blending and packaging facilities resulted in a $10.0 million decrease in cost of products sold. Average price per gallon decreased 10%, resulting in a $4.4 million decrease in cost of products sold. Cost of products sold at our shore-based terminals decreased $3.5 million resulting from a 6% decrease in average cost per gallon combined with a 2% decrease in sales volumes.

Operating expenses. Operating expenses at our specialty terminals decreased $5.9 million, primarily as a result of $2.8 million in decreased pass-through expenses at our Corpus Christi crude terminal, $2.2 million in decreased repairs and maintenance across our specialty terminals, and a $0.4 million decrease related to compensation expense across our specialty terminals. Operating expenses at our Smackover refinery decreased $1.6 million, primarily as a result of $1.3 million in decreased

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repairs and maintenance, $0.5 million in decreased compensation expense, $0.7 million in decreased utilities expense. These decreases were offset by an increase in property damage claims of $0.5 million and increased lease expense of $0.4 million. Operating expenses at our shore-based terminals decreased by $0.7 million primarily due to a decrease in contract labor of $0.3 million and lease expense of $0.1 million.

Selling, general and administrative expenses.   Selling, general and administrative expenses increased $0.7 million, of which $0.4 million is the result of increased compensation expense in our blending and packaging operations and $0.3 million is due to increased legal fees.

Depreciation and amortization.  The increase in depreciation and amortization is due to the impact of recent capital expenditures.

Other operating income (loss).  Other operating income (loss) represents gains and losses from the disposition of property, plant and equipment.

Volumetric data. Actual volumes at our Corpus Christi crude terminal for the nine months ended September 30, 2016 averaged 77,394 BBL per day, 7,606 BBL per day less than the contracted minimum throughput. 

Natural Gas Services Segment

Comparative Results of Operations for the Three Months Ended September 30, 2016 and 2015

	Three Months Ended September 30,					Variance			Percent Change
	2016			2015
	(In thousands)
Revenues:
Services	$	14,618		$	17,120	$	(2,502	)	(15	)%
Products	57,378			86,714		(29,336		)	(34	)%
Total revenues	71,996			103,834		(31,838		)	(31	)%
Cost of products sold	51,353			81,472		(30,119		)	(37	)%
Operating expenses	5,822			6,489		(667		)	(10	)%
Selling, general and administrative expenses	1,309			1,848		(539		)	(29	)%
Depreciation and amortization	7,050			8,522		(1,472		)	(17	)%
	6,462			5,503		959			17	%
Other operating loss	(7		)	—		(7		)
Operating income	$	6,455		$	5,503	$	952		17	%
Distributions from unconsolidated entities	$	1,800		$	3,400	$	(1,600	)	(47	)%
NGL sales volumes (Bbls)	1,592			3,138		(1,546		)	(49	)%

Services Revenues. The decrease in services revenue is primarily a result of decreased storage rates at our Arcadia and Monroe gas storage facilities.

Products Revenues. Our NGL average sales price per barrel increased $8.41, or 30%, resulting in an increase to products revenues of $26.4 million. The increase in average sales price per barrel was a result of an increase in market prices. Product sales volumes decreased 49%, decreasing products revenues $55.7 million.

Cost of products sold.  Our average cost per barrel excluding the effects of non-cash mark-to-market adjustments on derivative instruments increased $6.87, or 27%, increasing cost of products sold by $21.6 million.  The increase in average cost per barrel was a result of an increase in market prices.  The decrease in sales volume of 49% resulted in a $50.6 million decrease to cost of products sold. Our margins increased $1.54 per barrel, or 86%, during the period.

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Operating expenses.  Operating expenses decreased $0.7 million primarily due to a $0.5 million decrease in pipeline testing expense related to our East Texas NGL pipeline.

Selling, general and administrative expenses.  Selling, general and administrative expenses decreased primarily due to decreased compensation expense.

Depreciation and amortization. Depreciation and amortization decreased $1.5 million primarily due to a $1.7 million decrease in amortization related to contracts acquired during the purchase of Cardinal, offset by a $0.2 million increase in depreciation expense related to recent capital expenditures.

Other operating loss.  Other operating loss represents gains and losses from the disposition of property, plant and equipment.

Comparative Results of Operations for the Nine Months Ended September 30, 2016 and 2015

	Nine Months Ended September 30,						Variance			Percent Change
	2016			2015
	(In thousands)
Revenues:
Services	$	46,118		$	50,171		$	(4,053	)	(8	)%
Products	207,368			330,803			(123,435		)	(37	)%
Total revenues	253,486			380,974			(127,488		)	(33	)%
Cost of products sold	186,934			308,713			(121,779		)	(39	)%
Operating expenses	17,479			17,905			(426		)	(2	)%
Selling, general and administrative expenses	5,420			6,313			(893		)	(14	)%
Depreciation and amortization	21,007			25,297			(4,290		)	(17	)%
	22,646			22,746			(100		)	—	%
Other operating loss	(103		)	(7		)	(96		)	1,371	%
Operating income	$	22,543		$	22,739		$	(196	)	(1	)%
Distributions from unconsolidated entities	$	6,100		$	7,800		$	(1,700	)	(22	)%
NGL sales volumes (Bbls)	6,520			10,227			(3,707		)	(36	)%

Services Revenues. The decrease in services revenue is primarily a result of decreased storage rates at our Arcadia and Monroe gas storage facilities.

Products Revenues. Our NGL average sales price per barrel decreased $0.54, or 2%, resulting in a decrease to products revenues of $5.5 million. The decrease in average sales price per barrel was a result of a decline in market prices. Product sales volumes decreased 36%, decreasing products revenues by $117.9 million.

Cost of products sold.  Our average cost per barrel excluding the effects of non-cash mark-to-market adjustments on derivative instruments decreased $1.60, or 5%, decreasing cost of products sold by $16.4 million.  The decrease in average cost per barrel was a result of a decline in market prices.  The decrease in sales volume of 36% resulted in a $105.8 million decrease to cost of products sold. Our margins increased $1.06 per barrel, or 48%, during the period.

Operating expenses.  Operating expenses decreased $0.4 million primarily due to lower fuel expense of $0.6 million at our Cardinal Gas Storage facilities and a $0.5 million decrease in pipeline testing expense. These decreases are offset by a $0.7 million increase from our Arcadia rail facility put into service in June 2015.

Selling, general and administrative expenses.  Selling, general and administrative expenses decreased $0.9 million primarily due to a $0.2 million decrease in compensation expense, a $0.2 million decrease in consulting fees, a $0.1 million

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decrease in property taxes, and a $0.1 million decrease due to the 2015 period including the reserve for an uncollectible receivable.

Depreciation and amortization. Depreciation and amortization decreased $4.3 million primarily due to a $5.0 million decrease in amortization related to contracts acquired during the purchase of Cardinal, offset by a $0.7 million increase in depreciation expense related to recent capital expenditures.

Other operating loss.  Other operating loss represents gains and losses from the disposition of property, plant and equipment.

Sulfur Services Segment

Comparative Results of Operations for the Three Months Ended September 30, 2016 and 2015

	Three Months Ended September 30,						Variance			Percent Change
	2016			2015
	(In thousands)
Revenues:
Services	$	2,700		$	3,090		$	(390	)	(13	)%
Products	26,396			33,213			(6,817		)	(21	)%
Total revenues	29,096			36,303			(7,207		)	(20	)%
Cost of products sold	21,601			26,235			(4,634		)	(18	)%
Operating expenses	4,089			3,427			662			19	%
Selling, general and administrative expenses	946			934			12			1	%
Depreciation and amortization	1,997			2,129			(132		)	(6	)%
	463			3,578			(3,115		)	(87	)%
Other operating loss	(234		)	(5		)	(229		)	4,580	%
Operating income	$	229		$	3,573		$	(3,344	)	(94	)%
Sulfur (long tons)	241			203			38			19	%
Fertilizer (long tons)	47			51			(4		)	(8	)%
Total sulfur services volumes (long tons)	288			254			34			13	%

Services Revenues.  Services revenue decreased $0.4 million as a result of renegotiation of contract terms effective January 2016.

Products Revenues.  Products revenue decreased $9.9 million as a result of a 30% decline in average sales price. A 13% increase in sales volumes, primarily attributable to a 19% increase in sulfur volumes, resulted in an offsetting increase of $3.1 million.

Cost of products sold.  A 27% decrease in prices reduced cost of products sold by $7.2 million, resulting from a decline in commodity prices. A 13% increase in volumes resulted in an offsetting increase in cost of products sold of $2.6 million. Margin per ton decreased $10.82, or 39%.

Operating expenses.  Our operating expenses increased primarily as a result of increased outside towing as well as repairs and maintenance to railcars and marine vessels.

Selling, general and administrative expenses.  Selling, general and administrative expenses increased slightly as a result of increased compensation expense.

Depreciation and amortization.  The decrease in depreciation and amortization is due to asset dispositions in the fourth quarter of 2015 and third quarter of 2016.

Other Operating Loss.  Other operating loss represents losses from the disposition of property, plant and equipment.

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Comparative Results of Operations for the Nine Months Ended September 30, 2016 and 2015    

	Nine Months Ended September 30,						Variance			Percent Change
	2016			2015
	(In thousands)
Revenues:
Services	$	8,100		$	9,270		$	(1,170	)	(13	)%
Products	105,459			128,544			(23,085		)	(18	)%
Total revenues	113,559			137,814			(24,255		)	(18	)%
Cost of products sold	74,006			95,961			(21,955		)	(23	)%
Operating expenses	10,288			11,697			(1,409		)	(12	)%
Selling, general and administrative expenses	2,834			2,859			(25		)	(1	)%
Depreciation and amortization	5,978			6,360			(382		)	(6	)%
	20,453			20,937			(484		)	(2	)%
Other operating loss	(266		)	(5		)	(261		)	5,220	%
Operating income	$	20,187		$	20,932		$	(745	)	(4	)%
Sulfur (long tons)	579			641			(62		)	(10	)%
Fertilizer (long tons)	217			229			(12		)	(5	)%
Total sulfur services volumes (long tons)	796			870			(74		)	(9	)%

Services Revenues.  Services revenue decreased $1.2 million as a result of renegotiation of contract terms effective January 2016.

Products Revenues.  Products revenue decreased $13.3 million as a result of a 10% decline in average sales price. A 9% decrease in sales volumes, attributable primarily to a 10% decrease in sulfur volumes, decreased products revenue an additional $9.8 million.

Cost of products sold.  A 16% decrease in prices reduced our cost of products sold by $15.0 million. A 9% decrease in sales volumes decreased cost of products sold by $6.9 million. Margin per ton increased $2.06, or 6%.

Operating expenses.  Our operating expenses decreased primarily as a result of $0.9 million in lower fuel expense, terminal and thruput fees of $0.3 million, and compensation expense of $0.3 million.

Selling, general and administrative expenses.  Selling, general and administrative expenses decreased slightly due to decreased bad debt expense, advertising and dues and subscriptions.

Depreciation and amortization.  The decrease in depreciation and amortization is due to asset dispositions in the fourth quarter of 2015 and third quarter of 2016.

Other Operating Loss.  Other operating loss represents losses from the disposition of property, plant and equipment.

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Marine Transportation Segment

Comparative Results of Operations for the Three Months Ended September 30, 2016 and 2015

	Three Months Ended September 30,					Variance			Percent Change
	2016		2015
	(In thousands)
Revenues	$	14,920	$	19,522		$	(4,602	)	(24)%
Operating expenses	12,332		15,855			(3,523		)	(22)%
Selling, general and administrative expenses	149		(59		)	208			(353)%
Depreciation and amortization	2,254		3,060			(806		)	(26)%
	185		666			(481		)	(72)%
Other operating loss	—		(1,583		)	1,583			(100)%
Operating income (loss)	$	185	$	(917	)	$	1,102		(120)%

Inland revenues.  A $3.0 million decrease in inland revenues is primarily attributable to decreased utilization of the inland fleet resulting from an abundance of supply of marine equipment in our predominantly Gulf Coast market.

Offshore revenues.  A $1.6 million decrease in offshore revenue is the result of decreased utilization of the offshore fleet.

Operating expenses.  The decrease in operating expenses is a result of decreased compensation expense of $1.0 million, repairs and maintenance of $2.0 million, property taxes of $0.2 million, and outside labor of $0.2 million.

Selling, general and administrative expenses.  Selling, general and administrative expenses increased as a result of the revision of the classification of property taxes to operating expenses in the three month period ended September 30, 2015.

Depreciation and amortization.  Depreciation and amortization decreased as a result of the disposal of property, plant and equipment offset by recent capital expenditures.

Other operating loss.  Other operating loss represents gains and losses from the disposition of property, plant and equipment.

Comparative Results of Operations for the Nine Months Ended September 30, 2016 and 2015

	Nine Months Ended September 30,						Variance			Percent Change
	2016			2015
	(In thousands)
Revenues	$	46,854		$	62,354		$	(15,500	)	(25)%
Operating expenses	41,400			48,284			(6,884		)	(14)%
Selling, general and administrative expenses	(112		)	251			(363		)	(145)%
Loss on impairment of goodwill	4,145			—			4,145
Depreciation and amortization	8,377			8,050			327			4%
Operating income	$	(6,956	)	$	5,769		$	(12,725	)	(221)%
Other operating loss	(1,567		)	(1,552		)	(15		)	1%
Operating income (loss)	$	(8,523	)	$	4,217		$	(12,740	)	(302)%

 

Inland revenues.  An $8.0 million decrease in inland revenues is primarily attributable to decreased utilization of the inland fleet resulting from an abundance of supply of marine equipment in our predominantly Gulf Coast market.

Offshore revenues.  A $5.1 million decrease in offshore revenue is the result of decreased utilization of the offshore fleet, partially offset by the recognition of previously deferred revenues of $1.5 million.

Pass-through revenues.  A $2.7 million decrease in pass-through revenues was primarily related to fuel.

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Operating expenses.  The decrease in operating expenses is a result of decreased pass-through expenses (primarily fuel) of $2.6 million, compensation expense of $1.8 million, lower repairs and maintenance of $3.7 million and outside labor of $0.5 million. Offsetting these decreases were increases in claims expense of $0.5 million, property and liability premiums of $0.7 million, and outside towing of $0.6 million.

Selling, general and administrative expenses.  Selling, general and administrative expenses decreased due to the 2016 period including the collection of a previously deemed uncollectible receivable.

Loss on impairment of goodwill. This represents the loss on impairment of goodwill in the Marine Transportation reporting unit during the second quarter of 2016.

Depreciation and amortization.  Depreciation and amortization increased as a result of recent capital expenditures offset by the disposal of property, plant and equipment.

Other operating loss.  Other operating loss represents gains and losses from the disposition of property, plant and equipment.

Equity in Earnings of and Distributions from Unconsolidated Entities for the Three Months Ended September 30, 2016 and 2015

	Three Months Ended September 30,				Variance			Percent Change
	2016		2015
	(In thousands)
Equity in earnings of WTLPG	$	1,120	$	2,363	$	(1,243	)	(53)%

	Three Months Ended September 30,				Variance			Percent Change
	2016		2015
	(In thousands)
Distributions from WTLPG	$	1,800	$	3,400	$	(1,600	)	(47)%

Equity in earnings from West Texas LPG Pipeline L.P. ("WTLPG") decreased primarily due to a decrease in transportation rates combined with an increase in repairs and maintenance on the asset. Distributions from WTLPG decreased $1.6 million.

Equity in Earnings in and Distributions from Unconsolidated Entities for the Nine Months Ended September 30, 2016 and 2015

	Nine Months Ended September 30,				Variance			Percent Change
	2016		2015
	(In thousands)
Equity in earnings of WTLPG	$	3,602	$	5,752	$	(2,150	)	(37	)%

	Nine Months Ended September 30,				Variance			Percent Change
	2016		2015
	(In thousands)
Distributions from WTLPG	$	6,100	$	7,800	$	(1,700	)	(22	)%

Equity in earnings from WTLPG decreased primarily due to a decrease in transportation rates combined with an increase in repairs and maintenance on the asset. Distributions from WTLPG decreased $1.7 million.    

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Interest Expense, Net

Comparative Components of Interest Expense, Net for the Three Months Ended September 30, 2016 and 2015

	Three Months Ended September 30,						Variance			Percent Change
	2016			2015
	(In thousands)
Revolving loan facility	$	4,981		$	4,043		$	938		23%
7.25% Senior notes	6,775			7,253			(478		)	(7)%
Amortization of deferred debt issuance costs	718			2,400			(1,682		)	(70)%
Amortization of debt discount	(77		)	(82		)	5			(6)%
Impact of interest rate derivative activity, including cash settlements	—			(750		)	750			(100)%
Other	178			124			54			44%
Capitalized interest	(229		)	(427		)	198			(46)%
Interest income	(567		)	(567		)	—			—%
Total interest expense, net	$	11,779		$	11,994		$	(215	)	(2)%

Comparative Components of Interest Expense, Net for the Nine Months Ended September 30, 2016 and 2015

	Nine Months Ended September 30,						Variance			Percent Change
	2016			2015
	(In thousands)
Revolving loan facility	$	13,707		$	12,173		$	1,534		13%
7.25% Senior notes	20,401			21,753			(1,352		)	(6)%
Amortization of deferred debt issuance costs	2,965			4,142			(1,177		)	(28)%
Amortization of debt premium	(230		)	(246		)	16			(7)%
Impact of interest rate derivative activity, including cash settlements	(995		)	(2,495		)	1,500			(60)%
Other	798			343			455			133%
Capitalized interest	(911		)	(1,522		)	611			(40)%
Interest income	(1,689		)	(1,683		)	(6		)	—%
Total interest expense, net	$	34,046		$	32,465		$	1,581		5%

Indirect Selling, General and Administrative Expenses

	Three Months Ended September 30,				Variance			Percent Change	Nine Months Ended September 30,				Variance			Percent Change
	2016		2015						2016		2015
	(In thousands)								(In thousands)
Indirect selling, general and administrative expenses	$	4,206	$	4,948	$	(742	)	(15)%	$	12,676	$	14,258	$	(1,582	)	(11)%

Indirect selling, general and administrative expenses decreased for the three months ended September 30, 2016 due to a $0.4 million reduction in acquisition due diligence costs, $0.1 million in lower unit grant compensation expense, and a $0.2 million reduction in overhead expense allocated from Martin Resource Management.

For the nine months ended September 30, 2016, the decrease in indirect selling, general and administrative expenses is attributable to a $0.5 million reduction in overhead expense allocated from Martin Resource Management, $0.5 million in reduced acquisition due diligence costs, $0.4 million in lower unit grant compensation expense, and reduced audit fees of $0.2 million.

Martin Resource Management allocates to us a portion of its indirect selling, general and administrative expenses for services such as accounting, legal, treasury, clerical, billing, information technology, administration of insurance, engineering,

45

general office expense and employee benefit plans and other general corporate overhead functions we share with Martin Resource Management retained businesses. This allocation is based on the percentage of time spent by Martin Resource Management personnel that provide such centralized services. GAAP also permits other methods for allocation of these expenses, such as basing the allocation on the percentage of revenues contributed by a segment. The allocation of these expenses between Martin Resource Management and us is subject to a number of judgments and estimates, regardless of the method used. We can provide no assurances that our method of allocation, in the past or in the future, is or will be the most accurate or appropriate method of allocation for these expenses. Other methods could result in a higher allocation of selling, general and administrative expense to us, which would reduce our net income.

Under the Omnibus Agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. The Conflicts Committee of our general partner approved the following reimbursement amounts during the three months and nine months ended September 30, 2016 and 2015:

	Three Months Ended September 30,				Variance			Percent Change	Nine Months Ended September 30,				Variance			Percent Change
	2016		2015						2016		2015
	(In thousands)								(In thousands)
Conflicts Committee approved reimbursement amount	$	3,258	$	3,420	$	(162	)	(5)%	$	9,775	$	10,259	$	(484	)	(5)%

The amounts reflected above represent our allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.

Liquidity and Capital Resources

General

Our primary sources of liquidity to meet operating expenses, pay distributions to our unitholders and fund capital expenditures have historically been cash flows generated by our operations and access to debt and equity markets, both public and private.  Management believes that expenditures for our current capital projects will be funded with cash flows from operations, current cash balances and our current borrowing capacity under the revolving credit facility. Given the current environment, we have altered and reduced our planned growth capital expenditures.  We believe that controlling our spending in an effort to preserve liquidity is prudent and reduces our need for near-term access to the somewhat uncertain capital markets.

Recent Debt Financing Activity

Credit Facility Amendment. On April 27, 2016, we made certain strategic amendments to our revolving credit facility which, among other things, decreased our borrowing capacity from $700.0 million to $664.4 million and extended the maturity date of the facility from March 28, 2018 to March 28, 2020.

In 2015, we repurchased on the open market an aggregate $26.2 million of our outstanding 7.25% senior unsecured notes.

We believe that cash generated from operations and our borrowing capacity under our credit facility will be sufficient to meet our working capital requirements, anticipated maintenance capital expenditures and scheduled debt payments in 2016.

Finally, our ability to satisfy our working capital requirements, to fund planned capital expenditures and to satisfy our debt service obligations will also depend upon our future operating performance, which is subject to certain risks. Please read "Item 1A. Risk Factors" of our Form 10-K for the year ended December 31, 2015, filed with the SEC on February 29, 2016, as amended by Amendment No. 1 on Form 10-K/A filed on March 30, 2016, for a discussion of such risks.

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Cash Flows - Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015

The following table details the cash flow changes between the nine months ended September 30, 2016 and 2015:

	Nine Months Ended September 30,						Variance			Percent Change
	2016			2015
	(In thousands)
Net cash provided by (used in):
Operating activities	$	61,735		$	112,984		$	(51,249	)	(45)%
Investing activities	(10,074		)	1,358			(11,432		)	(842)%
Financing activities	(51,682		)	(114,371		)	62,689			(55)%
Net increase (decrease) in cash and cash equivalents	$	(21	)	$	(29	)	$	8		(28)%

The change in net cash provided by operating activities for the nine months ended September 30, 2016 includes a decrease in operating results plus other non-cash items of $13.5 million and a $38.1 million unfavorable variance in working capital. Net cash used in discontinued operating activities decreased $1.4 million in 2016.

Net cash provided by (used in) investing activities for the nine months ended September 30, 2016 decreased primarily as a result of the 2015 period including $41.3 million in cash proceeds from the disposition of certain floating storage assets classified as discontinued operations. The 2016 period included an acquisition of intangible assets of $2.2 million compared to no acquisitions in 2015. Payments for capital expenditures and plant turnaround costs decreased $8.6 million in 2016. Additionally, $23.4 million represents net proceeds from the involuntary conversion of property, plant and equipment.

The change in net cash used in financing activities for the nine months ended September 30, 2016 is due to a decrease in net repayments of long-term borrowings of $66.3 million. In 2016, we paid an additional $4.9 million in costs associated with our credit facility amendment compared to the previous period.

Capital Expenditures and Plant Turnaround Costs

Our operations require continual investment to upgrade or enhance operations and to ensure compliance with safety, operational, and environmental regulations. Our capital expenditures consist primarily of:

•expansion capital expenditures to acquire assets to grow our business, to expand existing facilities, such as projects that increase operating capacity, or to reduce operating costs;

•maintenance capital expenditures made to maintain existing assets and operations; and

•plant turnaround costs made at our refinery to perform maintenance, overhaul and repair operations and to inspect, test and replace process materials and equipment.

The following table summarizes our capital expenditure activity, excluding amounts paid for acquisitions, for the periods presented:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
	(In thousands)
Expansion capital expenditures	$	2,510	$	10,280	$	14,130	$	36,891
Maintenance capital expenditures	1,609		2,438		12,818		7,621
Plant turnaround costs	430		—		1,614		1,754
Total	$	4,549	$	12,718	$	28,562	$	46,266

Expansion capital expenditures were made primarily in our Terminalling and Storage segment during the three and nine months ended September 30, 2016. Within our Terminalling and Storage segment, expenditures were made primarily at our Smackover refinery and on certain organic growth projects ongoing in our specialty terminalling operations. Maintenance capital expenditures were made primarily in our Terminalling and Storage, Sulfur Services, and Marine Transportation

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segments to maintain our existing assets and operations during the three and nine months ended September 30, 2016. The increase is primarily related to tank repairs in our specialty terminalling business and a three-year regulatory coast guard inspection on our two marine vessels that operate in our sulfur business. For the three and nine months ended September 30, 2016 and 2015, plant turnaround costs relate to our Smackover refinery.

Expansion capital expenditures were made primarily in our Terminalling and Storage and Natural Gas Services segments during the three and nine months ended September 30, 2015. Within our Terminalling and Storage segment, expenditures were made primarily at our Smackover refinery and on certain organic growth projects ongoing in our specialty terminalling operations. Within our Natural Gas Services segment, expenditures were made on ongoing organic growth projects. Maintenance capital expenditures were made primarily in our Terminalling and Storage segment to maintain our existing assets and operations during the three and nine months ended September 30, 2015. For the three and nine months ended September 30, 2015, plant turnaround costs relate to our Smackover refinery.

Capital Resources

Historically, we have generally satisfied our working capital requirements and funded our capital expenditures with cash generated from operations and borrowings. We expect our primary sources of funds for short-term liquidity will be cash flows from operations and borrowings under our credit facility.

Total Contractual Cash Obligations.  A summary of our total contractual cash obligations as of September 30, 2016, is as follows: 

	Payments due by period
Type of Obligation	Total Obligation		Less than One Year		1-3 Years		3-5 Years		Due Thereafter
Revolving credit facility	$	549,000	$	—	$	—	$	549,000	$	—
2021 Senior unsecured notes	373,800		—		—		373,800		—
Throughput commitment	29,954		6,191		12,874		10,889		—
Exclusive right of use commitment	5,000		5,000		—		—		—
Operating leases	49,202		12,512		16,682		11,353		8,655
Interest payable on fixed long-term debt obligations	118,565		27,101		54,201		37,263		—
Total contractual cash obligations	$	1,125,521	$	50,804	$	83,757	$	982,305	$	8,655

The interest payable under our credit facility is not reflected in the above table because such amounts depend on the  outstanding balances and interest rates, which vary from time to time. 

Letters of Credit.  At September 30, 2016, we had outstanding irrevocable letters of credit in the amount of $0.9 million, which were issued under our revolving credit facility.

Off Balance Sheet Arrangements.  We do not have any off-balance sheet financing arrangements.

Description of Our Long-Term Debt

2021 Senior Notes

For a description of our 7.25% senior unsecured notes due 2021, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Description of Our Long-Term Debt" in our Annual Report on Form 10-K for the year ended December 31, 2015, as amended.

Revolving Credit Facility

At September 30, 2016, we maintained a $664.4 million credit facility. This facility was most recently amended on April 27, 2016, when we made certain strategic amendments to our revolving credit facility which, among other things, decreased our borrowing capacity from $700.0 million to $664.4 million and extended the maturity date of the facility from March 28, 2018 to March 28, 2020.

As of September 30, 2016, we had $549.0 million outstanding under the revolving credit facility and $0.9 million of letters of credit issued, leaving a maximum available to be borrowed under our credit facility for future revolving credit borrowings and letters of credit of $114.6 million. Subject to the financial covenants contained in our credit facility and based on our existing EBITDA (as defined in our credit facility) calculations, as of September 30, 2016, we have the ability to borrow approximately $8.0 million of that amount. While our current debt to EBITDA financial covenant calculation is near the maximum allowed under our credit facility at the September 30, 2016 evaluation, we expect to improve leverage during the fourth quarter through the impacts of selling inventory built during the second and third quarters in our seasonal NGL business. Additionally, we plan to further improve leverage with the $93.0 million in net proceeds we expect to receive upon the completion of the divestiture of the CCCT Assets. We expect to be in compliance with all financial covenants at December 31, 2016.

The revolving credit facility is used for ongoing working capital needs and general partnership purposes, and to finance permitted investments, acquisitions and capital expenditures.  During the nine months ended September 30, 2016, the level of outstanding draws on our credit facility has ranged from a low of $498.0 million to a high of $582.0 million.

The credit facility is guaranteed by substantially all of our subsidiaries. Obligations under the credit facility are secured by first priority liens on substantially all of our assets and those of the guarantors, including, without limitation, inventory, accounts receivable, bank accounts, marine vessels, equipment, fixed assets and the interests in our subsidiaries and certain of our equity method investees.

We may prepay all amounts outstanding under the credit facility at any time without premium or penalty (other than customary LIBOR breakage costs), subject to certain notice requirements. The credit facility requires mandatory prepayments of amounts outstanding thereunder with the net proceeds of certain asset sales, equity issuances and debt incurrences.

Indebtedness under the credit facility bears interest at our option at the Eurodollar Rate (the British Bankers Association LIBOR Rate) plus an applicable margin or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0%, or the administrative agent’s prime rate) plus an applicable margin. We pay a per annum fee on all letters of credit issued under the credit facility, and we pay a commitment fee per annum on the unused revolving credit availability under the credit facility. The letter of credit fee, the commitment fee and the applicable margins for our interest rate vary quarterly based on our leverage ratio (as defined in the credit facility, being generally computed as the ratio of total funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) and are as follows as of September 30, 2016:

Leverage Ratio	Base Rate Loans		Eurodollar Rate Loans		Letters of Credit
Less than 3.00 to 1.00	1.00	%	2.00	%	2.00	%
Greater than or equal to 3.00 to 1.00 and less than 3.50 to 1.00	1.25	%	2.25	%	2.25	%
Greater than or equal to 3.50 to 1.00 and less than 4.00 to 1.00	1.50	%	2.50	%	2.50	%
Greater than or equal to 4.00 to 1.00 and less than 4.50 to 1.00	1.75	%	2.75	%	2.75	%
Greater than or equal to 4.50 to 1.00	2.00	%	3.00	%	3.00	%

At September 30, 2016, 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 September 30, 2016 is 3.00%.  

The credit facility includes financial covenants that are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter. The maximum permitted leverage ratio is 5.25 to 1.00 with a temporary springing provision to 5.50 to 1.00 under certain scenarios. The maximum permitted senior leverage ratio (as defined in the credit facility but generally computed as the ratio of total secured funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) is 3.50 to 1.00. The minimum interest coverage ratio (as defined in the credit facility but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges to consolidated interest charges) is 2.50 to 1.00.

In addition, the credit facility contains various covenants, which, among other things, limit our and our subsidiaries’ ability to: (i) grant or assume liens; (ii) make investments (including investments in our joint ventures) and acquisitions; (iii) enter into certain types of hedging agreements; (iv) incur or assume indebtedness; (v) sell, transfer, assign or convey assets; (vi) repurchase our equity, make distributions and certain other restricted payments, but the credit facility permits us to make

48

quarterly distributions to unitholders so long as no default or event of default exists under the credit facility; (vii) change the nature of our business; (viii) engage in transactions with affiliates; (ix) enter into certain burdensome agreements; (x) make certain amendments to the Omnibus Agreement and our material agreements; (xi) make capital expenditures; and (xii) permit our joint ventures to incur indebtedness or grant certain liens.

The credit facility contains customary events of default, including, without limitation: (i) failure to pay any principal, interest, fees, expenses or other amounts when due; (ii) failure to meet the quarterly financial covenants; (iii) failure to observe any other agreement, obligation, or covenant in the credit facility or any related loan document, subject to cure periods for certain failures; (iv) the failure of any representation or warranty to be materially true and correct when made; (v) our, or any of our subsidiaries’ default under other indebtedness that exceeds a threshold amount; (vi) bankruptcy or other insolvency events involving us or any of our subsidiaries; (vii) judgments against us or any of our subsidiaries, in excess of a threshold amount; (viii) certain ERISA events involving us or any of our subsidiaries, in excess of a threshold amount; (ix) a change in control (as defined in the credit facility); and (x) the invalidity of any of the loan documents or the failure of any of the collateral documents to create a lien on the collateral.

The credit facility also contains certain default provisions relating to Martin Resource Management. If Martin Resource Management no longer controls our general partner, the lenders under the credit facility may declare all amounts outstanding thereunder immediately due and payable. In addition, an event of default by Martin Resource Management under its credit facility could independently result in an event of default under our credit facility if it is deemed to have a material adverse effect on us.

If an event of default relating to bankruptcy or other insolvency events occurs with respect to us or any of our subsidiaries, all indebtedness under our credit facility will immediately become due and payable. If any other event of default exists under our credit facility, the lenders may terminate their commitments to lend us money, accelerate the maturity of the indebtedness outstanding under the credit facility and exercise other rights and remedies. In addition, if any event of default exists under our credit facility, the lenders may commence foreclosure or other actions against the collateral.

We are subject to interest rate risk on our credit facility due to the variable interest rate and may enter into interest rate swaps to reduce this variable rate risk.

The Partnership is in compliance with all debt covenants as of September 30, 2016 and expects to be in compliance for the next twelve months.

Seasonality

A substantial portion of our revenues are dependent on sales prices of products, particularly NGLs and fertilizers, which fluctuate in part based on winter and spring weather conditions. The demand for NGLs is strongest during the winter heating season and the refinery blending season. The demand for fertilizers is strongest during the early spring planting season. However, our WTLPG and natural gas storage divisions of the Natural Gas Services segment each provide stable cash flows and are not generally subject to seasonal demand factors. Additionally, our Terminalling and Storage and Marine Transportation segments and the molten sulfur business are typically not impacted by seasonal fluctuations and a significant portion of our net income is derived from our terminalling and storage, sulfur and marine transportation businesses. Therefore, we do not expect that our overall net income will be impacted by seasonality factors.  However, extraordinary weather events, such as hurricanes, have in the past, and could in the future, impact our Terminalling and Storage and Marine Transportation segments.

Impact of Inflation

Inflation did not have a material impact on our results of operations for the nine months ended September 30, 2016 or 2015.  Although the impact of inflation has been insignificant in recent years, it is still a factor in the U.S. economy and may increase the cost to acquire or replace property, plant and equipment. It may also increase the costs of labor and supplies.  In the future, increasing energy prices could adversely affect our results of operations. Diesel fuel, natural gas, chemicals and other supplies are recorded in operating expenses.  An increase in price of these products would increase our operating expenses which could adversely affect net income. We cannot provide assurance that we will be able to pass along increased operating expenses to our customers.

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Environmental Matters

Our operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. We incurred no material environmental costs, liabilities or expenditures to mitigate or eliminate environmental contamination during the nine months ended September 30, 2016 or 2015.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

Commodity Risk. The Partnership from time to time uses 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.  We have established a hedging policy and monitor and manage the commodity market risk associated with potential commodity risk exposure.  In addition, we focus on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction.     

We have entered into hedging transactions as of September 30, 2016 to protect a portion of our commodity price risk exposure. These hedging arrangements are in the form of swaps for NGLs. We have instruments totaling a net notional quantity of 441,000 barrels settling during the period from October 31, 2016 through March 31, 2017. These instruments settle against OPIS Mont Belvieu (non-TET) monthly average price. These instruments are recorded on our Consolidated and Condensed Balance Sheets at September 30, 2016 in "Fair value of derivatives" as a current asset of $0.1 million and a current liability of $0.2 million. Based on the current net notional volume hedged as of September 30, 2016, a $0.10 change in the expected settlement price of these contracts would result in an impact of $1.9 million to the Partnership's net income.

Interest Rate Risk. We are exposed to changes in interest rates as a result of our credit facility, which had a weighted-average interest rate of 3.53% as of September 30, 2016.  Based on the amount of unhedged floating rate debt owed by us on September 30, 2016, the impact of a 100 basis point increase in interest rates on this amount of debt would result in an increase in interest expense and a corresponding decrease in net income of approximately $5.4 million annually.

We are not exposed to changes in interest rates with respect to our senior unsecured notes as these obligations are fixed rate.  The estimated fair value of the senior unsecured notes was approximately $359.2 million as of September 30, 2016, based on market prices of similar debt at September 30, 2016.   Market risk is estimated as the potential decrease in fair value of our long-term debt resulting from a hypothetical increase of a 100 basis point increase in interest rates. Such an increase in interest rates would result in approximately a $12.9 million decrease in fair value of our long-term debt at September 30, 2016.

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Item 4. Controls and Procedures

Evaluation of disclosure controls and procedures. In accordance with Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), we, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of our general partner, carried out an evaluation of the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) of the Exchange Act) as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of our general partner concluded that our disclosure controls and procedures were effective, as of the end of the period covered by this report, to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

There were no changes in our internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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PART II - OTHER INFORMATION

Item 1. Legal Proceedings

From time to time, we are subject to certain legal proceedings claims and disputes that arise in the ordinary course of our business. Although we cannot predict the outcomes of these legal proceedings, we do not believe these actions, in the aggregate, will have a material adverse impact on our financial position, results of operations or liquidity. Information regarding legal proceedings is set forth in Note 16 in Part I of this Form 10-Q.

Item 1A. Risk Factors

There have been no material changes to the risk factors disclosed in our annual report on Form 10-K filed with the SEC on February 29, 2016, as amended by Amendment No. 1 on Form 10-K/A filed on March 30, 2016.

Item 6. Exhibits

The information required by this Item 6 is set forth in the Index to Exhibits accompanying this quarterly report and is incorporated herein by reference.

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SIGNATURES

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

	Martin Midstream Partners L.P.
	By:	Martin Midstream GP LLC
		Its General Partner
Date: 10/26/2016	By:	/s/ Robert D. Bondurant
		Robert D. Bondurant
		Executive Vice President, Treasurer, Chief Financial Officer, and Principal Accounting Officer

54

INDEX TO EXHIBITS

Exhibit Number	Exhibit Name
10.1	Asset Purchase Agreement by and among Martin Operating Partnership L.P. and Nustar Logistics, L.P. dated October 14, 2016 (filed as Exhibit 10.1 to the Partnership's Current Report on Form 8-K (Reg. No. 000-50056), filed October 20, 2016, and incorporated herein by reference).
31.1*	Certifications of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certifications of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Chief Executive Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.  Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be "filed."
32.2*	Certification of Chief Financial Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.  Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be "filed."
101	Interactive Data: the following financial information from Martin Midstream Partners L.P.’s Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2016, formatted in Extensible Business Reporting Language: (1) the Consolidated and Condensed Balance Sheets; (2) the Consolidated and Condensed Statements of Income; (3) the Consolidated and Condensed Statements of Cash Flows; (4) the Consolidated and Condensed Statements of Capital; and (5) the Notes to Consolidated and Condensed Financial Statements.

* Filed or furnished herewith

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EX-31.1

Exhibit 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

Pursuant to 17 CFR 240.13a-14(a)/15d-14(a)

(Section 302 of the Sarbanes-Oxley Act of 2002)

I, Ruben S. Martin, certify that:

1.  I have reviewed this quarterly report on Form 10-Q of Martin Midstream Partners L.P.;

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

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

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

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

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

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

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

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

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

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

Date: 10/26/2016

/s/ Ruben S. Martin

Ruben S. Martin, President and

Chief Executive Officer of

Martin Midstream GP LLC,

the General Partner of Martin Midstream Partners L.P.

EX-31.2

Exhibit 31.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

Pursuant to 17 CFR 240.13a-14(a)/15d-14(a)

(Section 302 of the Sarbanes-Oxley Act of 2002)

I, Robert D. Bondurant, certify that:

1.  I have reviewed this quarterly report on Form 10-Q of Martin Midstream Partners L.P.;

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

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

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

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

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

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

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

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

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

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

Date: 10/26/2016

/s/ Robert D. Bondurant

Robert D. Bondurant, Executive Vice President, Treasurer, Chief Financial Officer and Principal Accounting Officer of

Martin Midstream GP LLC,

the General Partner of Martin Midstream Partners L.P.

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C.  SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002*

In connection with the Quarterly Report of Martin Midstream Partners L.P., a Delaware limited partnership (the “Partnership”), on Form 10-Q for the quarter ended September 30, 2016, as filed with the Securities and Exchange Commission (the “Report”), I, Ruben S. Martin, Chief Executive Officer of Martin Midstream GP LLC, the general partner of the Partnership, certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), that to my knowledge:

(1)          the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

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

/s/ Ruben S. Martin

Ruben S. Martin,

Chief Executive Officer

of Martin Midstream GP LLC,

the General Partner of Martin Midstream Partners L.P.

October 26, 2016

*A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO 18 U.S.C.  SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002*

In connection with the Quarterly Report of Martin Midstream Partners L.P., a Delaware limited partnership (the “Partnership”), on Form 10-Q for the quarter ended September 30, 2016 as filed with the Securities and Exchange Commission (the “Report”), I, Robert D. Bondurant, Chief Financial Officer of Martin Midstream GP LLC, the general partner of the Partnership, certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), that to my knowledge:

(1)           the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

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

/s/ Robert D. Bondurant

Robert D. Bondurant,

Chief Financial Officer

of Martin Midstream GP LLC,

the General Partner of Martin Midstream Partners L.P.

October 26, 2016

*A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Oct. 26, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	MARTIN MIDSTREAM PARTNERS LP
Entity Central Index Key	0001176334
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding (in shares)		35,454,462

XML

CONSOLIDATED AND CONDENSED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Assets
Cash	$ 10	$ 31
Accounts and other receivables, less allowance for doubtful accounts of $453 and $430, respectively	46,327	74,355
Product exchange receivables	159	1,050
Inventories	107,476	75,870
Due from affiliates	8,194	10,126
Fair value of derivatives	89	675
Other current assets	4,439	5,718
Assets held for sale	73,197	0
Total current assets	239,891	167,825
Property, plant and equipment, at cost	1,301,233	1,387,814
Accumulated depreciation	(411,821)	(404,574)
Property, plant and equipment, net	889,412	983,240
Goodwill	17,296	23,802
Investment in WTLPG	129,794	132,292
Note receivable - Martin Energy Trading LLC	15,000	15,000
Other assets, net	48,951	58,314
Total assets	1,340,344	1,380,473
Liabilities and Partners’ Capital
Trade and other accounts payable	60,462	81,180
Product exchange payables	10,188	12,732
Due to affiliates	3,879	5,738
Income taxes payable	550	985
Fair value of derivatives	209	0
Other accrued liabilities	14,804	18,533
Liabilities held for sale	23,400	0
Total current liabilities	113,492	119,168
Long-term debt, net	913,504	865,003
Fair value of derivatives	0	206
Other long-term obligations	2,435	2,217
Total liabilities	1,029,431	986,594
Commitments and contingencies (Note 16)
Partners’ capital	310,913	393,879
Total partners’ capital	310,913	393,879
Total liabilities and partners' capital	$ 1,340,344	$ 1,380,473

XML

CONSOLIDATED AND CONDENSED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$ 453	$ 430

XML

CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Revenues:
Terminalling and storage	$ 30,770	$ 33,578	$ 93,565	$ 100,828
Marine transportation	13,846	18,977	44,531	59,956
Natural gas services	14,618	17,120	46,118	50,171
Sulfur services	2,700	3,090	8,100	9,270
Product sales:
Natural gas services	57,378	86,714	207,368	330,803
Sulfur services	26,396	33,213	105,459	128,544
Terminalling and storage	28,829	33,329	85,349	102,901
Total product sales	112,603	153,256	398,176	562,248
Total revenues	174,537	226,021	590,490	782,473
Cost of products sold: (excluding depreciation and amortization)
Natural gas services	50,658	80,709	184,781	307,039
Sulfur services	21,510	26,144	73,734	95,685
Terminalling and storage	23,540	28,237	70,306	87,977
Total cost of products sold (excluding depreciation and amortization)	95,708	135,090	328,821	490,701
Expenses:
Operating expenses	39,488	45,310	121,542	138,399
Selling, general and administrative	8,049	8,666	24,364	26,507
Loss on impairment of goodwill	0	0	4,145	0
Depreciation and amortization	22,129	23,335	66,266	68,737
Total costs and expenses	165,374	212,401	545,138	724,344
Other operating income (loss)	13	(1,586)	(1,582)	(1,763)
Operating income	9,176	12,034	43,770	56,366
Other income (expense):
Equity in earnings of WTLPG	1,120	2,363	3,602	5,752
Interest expense, net	(11,779)	(11,994)	(34,046)	(32,465)
Gain on retirement of senior unsecured notes	0	728	0	728
Other, net	730	399	866	757
Total other expense	(9,929)	(8,504)	(29,578)	(25,228)
Net income (loss) before taxes	(753)	3,530	14,192	31,138
Income tax expense	(180)	(200)	(422)	(814)
Income (loss) from continuing operations	(933)	3,330	13,770	30,324
Income from discontinued operations, net of income taxes	0	0	0	1,215
Net income (loss)	(933)	3,330	13,770	31,539
Less general partner's interest in net (income) loss	18	(3,959)	(8,062)	(12,310)
Less (income) loss allocable to unvested restricted units	3	(16)	(36)	(127)
Limited partners' interest in net income (loss)	$ (912)	$ (645)	$ 5,672	$ 19,102

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CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS (Unaudited) - Allocation of Net Income - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Limited partner interest:
Continuing operations	$ (912)	$ (645)	$ 5,672	$ 18,366
Discontinued operations	0	0	0	736
Limited partners' interest in net income (loss)	(912)	(645)	5,672	19,102
General partner interest:
Continuing operations	(18)	3,959	8,062	11,836
Discontinued operations	0	0	0	474
General partners' interest in net income (loss)	$ (18)	$ 3,959	$ 8,062	$ 12,310
Basic:
Continuing operations (USD per share)	$ (0.03)	$ (0.02)	$ 0.16	$ 0.52
Discontinued operations (USD per share)	0	0	0	0.02
Net income (loss) per unit attributable to limited partners, basic (USD per share)	$ (0.03)	$ (0.02)	$ 0.16	$ 0.54
Weighted average limited partner units - basic (in shares)	35,346,412	35,307,583	35,358,217	35,308,990
Diluted:
Continuing operations (USD per share)	$ (0.03)	$ (0.02)	$ 0.16	$ 0.52
Discontinued operations (USD per share)	0	0	0	0.02
Net income (loss) per unit attributable to limited partners, diluted (USD per share)	$ (0.03)	$ (0.02)	$ 0.16	$ 0.54
Weighted average limited partner units - diluted (in shares)	35,346,412	35,307,583	35,381,067	35,368,966

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CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS (Unaudited) - Related Party Transactions - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Revenues:
Terminalling and storage	$ 20,649	$ 15,091	$ 62,197	$ 58,626
Marine transportation	4,861	6,552	17,308	19,919
Natural gas services	132	0	574	0
Product Sales	723	1,731	2,391	5,079
Cost of products sold: (excluding depreciation and amortization)
Natural gas services	2,946	6,470	10,829	20,198
Sulfur services	3,678	3,387	11,300	10,629
Terminalling and storage	3,766	3,227	11,232	14,261
Expenses:
Operating expenses	17,810	19,290	53,255	58,605
Selling, general and administrative	$ 5,748	$ 5,922	$ 18,091	$ 17,765

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CONSOLIDATED AND CONDENSED STATEMENTS OF CAPITAL (Unaudited) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Increase (Decrease) in Partners' Capital [Roll Forward]
Beginning Balance	$ 393,879	$ 485,671
Net income	13,770	31,539
Issuance of common units, net	(28)	(330)
General partner contribution		55
Cash distributions	(100,090)	(99,946)
Reimbursement of excess purchase price over carrying value of acquired assets	3,000	1,500
Unit-based compensation	712	1,080
Purchase of treasury units	(330)
Ending Balance	$ 310,913	$ 419,569
Limited Partner
Increase (Decrease) in Partners' Capital [Roll Forward]
Beginning Balance (in shares)	35,456,612	35,365,912
Beginning Balance	$ 380,845	$ 470,943
Net income	5,708	19,229
Issuance of common units, net	$ (28)	$ (330)
Issuance of restricted units (in shares)	13,800	91,950
Forfeiture of restricted units (in shares)	(500)	(1,250)
Cash distributions	$ (86,410)	$ (86,420)
Reimbursement of excess purchase price over carrying value of acquired assets	3,000	1,500
Unit-based compensation	$ 712	$ 1,080
Purchase of treasury units (in shares)	(15,200)
Purchase of treasury units	$ (330)
Ending Balance (in shares)	35,454,712	35,456,612
Ending Balance	$ 303,497	$ 406,002
General Partner
Increase (Decrease) in Partners' Capital [Roll Forward]
Beginning Balance	13,034	14,728
Net income	8,062	12,310
General partner contribution		55
Cash distributions	(13,680)	(13,526)
Ending Balance	$ 7,416	$ 13,567

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CONSOLIDATED AND CONDENSED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Cash flows from operating activities:
Net income	$ 13,770	$ 31,539
Less: Income from discontinued operations, net of income taxes	0	(1,215)
Net income from continuing operations	13,770	30,324
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	66,266	68,737
Amortization and write-off of deferred debt issuance costs	2,965	4,142
Amortization of premium on notes payable	(230)	(246)
Loss on sale of property, plant and equipment	1,582	1,751
Loss on impairment of goodwill	4,145	0
Gain on retirement of senior unsecured notes	0	(728)
Equity in earnings of unconsolidated entities	(3,602)	(5,752)
Derivative income	(1,867)	(2,137)
Net cash received for commodity derivatives	1,666	0
Net cash received for interest rate derivatives	160	0
Net premiums received on derivatives that settled during the year on interest rate swaption contracts	630	2,495
Unit-based compensation	712	1,080
Cash distributions from WTLPG	6,100	7,800
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables	28,028	69,967
Product exchange receivables	891	909
Inventories	(31,606)	(3,134)
Due from affiliates	1,932	3,348
Other current assets	(4,693)	354
Trade and other accounts payable	(15,782)	(59,124)
Product exchange payables	(2,544)	6,360
Due to affiliates	(1,859)	(1,935)
Income taxes payable	(435)	(386)
Other accrued liabilities	(3,729)	(8,490)
Change in other non-current assets and liabilities	(765)	(999)
Net cash provided by continuing operating activities	61,735	114,336
Net cash used in discontinued operating activities	0	(1,352)
Net cash provided by operating activities	61,735	112,984
Cash flows from investing activities:
Payments for property, plant and equipment	(31,884)	(40,123)
Acquisition of intangible assets	(2,150)	0
Payments for plant turnaround costs	(1,614)	(1,754)
Proceeds from sale of property, plant and equipment	2,174	1,985
Proceeds from involuntary conversion of property, plant and equipment	23,400	0
Net cash used in continuing investing activities	(10,074)	(39,892)
Net cash provided by discontinued investing activities	0	41,250
Net cash provided by (used in) investing activities	(10,074)	1,358
Cash flows from financing activities:
Payments of long-term debt	(219,700)	(224,310)
Proceeds from long-term debt	270,700	209,000
Proceeds from issuance of common units, net of issuance related costs	(28)	(330)
General partner contribution	0	55
Purchase of treasury units	(330)	0
Payment of debt issuance costs	(5,234)	(340)
Reimbursement of excess purchase price over carrying value of acquired assets	3,000	1,500
Cash distributions paid	(100,090)	(99,946)
Net cash used in financing activities	(51,682)	(114,371)
Net decrease in cash	(21)	(29)
Cash at beginning of period	31	42
Cash at end of period	10	13
Non-cash additions to property, plant and equipment	$ 1,068	$ 4,389

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General

9 Months Ended

Sep. 30, 2016

Accounting Policies [Abstract]

General

General

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:  natural gas services, including liquids transportation and distribution services and natural gas storage; terminalling and storage services for petroleum products and by-products including the refining of naphthenic crude oil, blending and packaging of finished lubricants; sulfur and sulfur-based products processing, manufacturing, marketing and distribution; and marine transportation services for petroleum products and by-products.

The Partnership’s unaudited consolidated and condensed financial statements have been prepared in accordance with the requirements of Form 10-Q and United States Generally Accepted Accounting Principles ("U.S. GAAP") for interim financial reporting. Accordingly, these financial statements have been condensed and do not include all of the information and footnotes required by U.S. GAAP for annual audited financial statements of the type contained in the Partnership’s annual reports on Form 10-K. 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 financial position, results of operations, and cash flows for the periods shown have been made. All such adjustments are of a normal recurring nature. Results for such interim periods are not necessarily indicative of the results of operations for the full year. These financial statements should be read in conjunction with the Partnership’s audited consolidated financial statements and notes thereto included in the Partnership’s annual report on Form 10-K for the year ended December 31, 2015, filed with the Securities and Exchange Commission (the "SEC") on February 29, 2016, as amended by Amendment No. 1 on Form 10-K/A for the year ended December 31, 2015 filed on March 30, 2016.

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 and condensed financial statements in conformity with U.S. GAAP.  Actual results could differ from those estimates.

As discussed further in Note 3, on October 14, 2016, the Partnership entered into a definitive agreement with NuStar Logistics, L.P. (“NuStar”) to sell its 900,000 barrel crude oil storage terminal, its refined product barge terminal, certain pipelines and related easements as well as dockage and trans-loading assets located in Corpus Christi, Texas ("CCCT Assets") for gross consideration of $107,000 plus the reimbursement of certain capital expenditures and prepaid items. The Partnership expects to receive net proceeds of approximately $93,000 after transaction fees and expenses as well as the application of certain net cash payments previously received by the Partnership in conjunction with its mandated relocation of certain dockage assets to the purchase price in the amount of $13,400. The Partnership expects to close the transaction prior to December 31, 2016. Proceeds from the sale will be used to reduce outstanding borrowings under the Partnership's revolving credit facility. The Partnership has classified the CCCT Assets, and the related liabilities, as held for sale at September 30, 2016.

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New Accounting Pronouncements

9 Months Ended

Sep. 30, 2016

Accounting Changes and Error Corrections [Abstract]

New Accounting Pronouncements

New 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 and condensed 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 and condensed 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 and condensed 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 evaluating the effect that ASU 2014-09 will have on its consolidated and condensed financial statements and related disclosures. The Partnership has not yet selected a transition method nor has it determined the effect of the standard on its ongoing financial reporting.

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Divestitures and discontinued operations

9 Months Ended

Sep. 30, 2016

Discontinued Operations and Disposal Groups [Abstract]

Divestitures and discontinued operations

On October 14, 2016, the Partnership entered into a definitive agreement with NuStar to sell its CCCT Assets for gross consideration of $107,000 plus the reimbursement of certain capital expenditures and prepaid items. The Partnership expects to receive net proceeds of approximately $93,000 after transaction fees and expenses as well as the application of certain net cash payments previously received by the Partnership in conjunction with its mandated relocation of certain dockage assets to the purchase price in the amount of $13,400. The Partnership expects to close the transaction prior to December 31, 2016. Proceeds from the sale will be used to reduce outstanding borrowings under the Partnership's revolving credit facility. The Partnership expects to record a gain from the divestiture. The Partnership has classified the CCCT Assets, and the related liabilities, as held for sale at September 30, 2016, as follows:

	2016
Assets:
Other assets	$	4,333
Property, plant, and equipment	91,594
Accumulated depreciation	(25,091		)
Goodwill	2,361
Assets held for sale	$	73,197
Liabilities:
Current liabilities	$	23,400
Liabilities held for sale	$	23,400

The divestiture of the CCCT Assets does not qualify for discontinued operations presentation under the guidance of ASC 205-20.

Floating Storage Assets. On February 12, 2015, the Partnership sold all six of its 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 classified the Floating Storage Assets as held for sale at December 31, 2014 and has presented the results of operations and cash flows of the Floating Storage Assets as discontinued operations for the three and nine months ended September 30, 2016 and 2015. 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:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Total revenues from third parties1	$	—	$	—	$	—	$	791
Total costs and expenses and other, net, excluding depreciation and amortization	—		—		—		1,038
Depreciation and amortization	—		—		—		—
Other operating income2	—		—		—		1,462
Income from discontinued operations before income taxes	—		—		—		1,215
Income tax expense	—		—		—		—
Income from discontinued operations, net of income taxes	$	—	$	—	$	—	$	1,215

¹ All revenues for the nine months ended September 30, 2015 were from third parties.

² Other operating income represents the gain on the disposition of the Floating Storage Assets.

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Inventories

9 Months Ended

Sep. 30, 2016

Inventory Disclosure [Abstract]

Inventories

Inventories

Components of inventories at September 30, 2016 and December 31, 2015 were as follows: 

	September 30, 2016		December 31, 2015
Natural gas liquids	$	65,107	$	20,959
Sulfur	6,959		13,812
Sulfur based products	12,541		19,400
Lubricants	19,918		18,675
Other	2,951		3,024
	$	107,476	$	75,870

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Investment in West Texas LPG Pipeline L.P.

9 Months Ended

Sep. 30, 2016

Equity Method Investments and Joint Ventures [Abstract]

Investment in West Texas LPG Pipeline L.P.

Investment in West Texas LPG Pipeline L.P.

The Partnership owns a 19.8% general partnership and 0.2% limited partnership interest in West Texas LPG Pipeline L.P. ("WTLPG"). ONEOK Partners, L.P. is the operator of the assets. 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 20% interest in WTLPG as "Investment in WTLPG" on its Consolidated and Condensed Balance Sheets. The Partnership accounts for its ownership interest in WTLPG under the equity method of accounting.

Selected financial information for WTLPG is as follows:

	As of September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	Total Assets		Members' Equity		Revenues		Net Income		Revenues		Net Income
2016
WTLPG	$	815,700	$	791,762	$	21,849	$	5,515	$	66,870	$	18,240
	As of December 31,
2015
WTLPG	$	819,342	$	804,023	$	26,094	$	11,815	$	70,010	$	28,760

As of September 30, 2016 and December 31, 2015, the Partnership’s interest in cash of WTLPG was $1,189 and $1,060, respectively.

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Derivative Instruments and Hedging Activities

9 Months Ended

Sep. 30, 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 September 30, 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 net notional quantity of 441,000 barrels settling during the period from October 31, 2016 through March 31, 2017. These instruments settle against the applicable pricing source for each grade and location. Martin Energy Trading LLC ("MET"), an affiliate of Martin Resource Management, serves as the counterparty for all positions outstanding at September 30, 2016.

(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 its fixed rate senior unsecured notes. All derivatives and hedging instruments are included on the balance sheet as an asset or a liability measured at fair value and changes in fair value are recognized currently in earnings.

During the nine months ended September 30, 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") through September 30, 2016 and 2015, respectively. In connection with the interest rate swaption contracts, the Partnership received premiums of $0 and $630, which represented their fair value on the date the transactions were initiated and were initially recorded as derivative liabilities on the Partnership's Consolidated and Condensed Balance Sheets, during the three and nine months ended September 30, 2016, respectively. In connection with the interest rate swaption contracts, the Partnership received premiums of $750 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 and Condensed Balance Sheets, during the three and nine months ended September 30, 2015, respectively. Each of the interest rate swaptions was fully amortized as of September 30, 2016 and 2015. Interest rate swaption contract premiums received are amortized over the period from initiation of the contract through their termination date. For the three and nine months ended September 30, 2016, the Partnership recognized $0 and $630, respectively, of premiums in "Interest expense, net" on the Partnership's Consolidated and Condensed Statements of Operations related to the interest rate swaption contracts. For the three and nine months ended September 30, 2015, the Partnership recognized $750 and $2,495, respectively, of premiums in "Interest expense, net" on the Partnership's Consolidated and Condensed Statements of Operations related to the interest rate swaption contracts.

As of December 31, 2015, the Partnership had a fixed-to-variable interest rate swap agreement with a notional principal amount of $50,000 of fixed-to-variable interest rate swap agreements, 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 had a termination date that corresponded to the maturity date of the 2021 senior unsecured notes. This instrument was recorded on the Partnership's Consolidated and Condensed 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.

For information regarding gains and losses on interest rate derivative instruments, see "Tabular Presentation of Gains and Losses on Derivative Instruments" below.

(c)    Tabular Presentation of Gains and Losses on Derivative Instruments

The following table summarizes the fair value and classification of the Partnership’s derivative instruments in its Consolidated and Condensed Balance Sheets:

	Fair Values of Derivative Instruments in the Consolidated Balance Sheets
	Derivative Assets					Derivative Liabilities
		Fair Values					Fair Values
	Balance Sheet Location	September 30, 2016		December 31, 2015		Balance Sheet Location	September 30, 2016		December 31, 2015
Derivatives not designated as hedging instruments:	Current:
Commodity contracts	Fair value of derivatives	$	89	$	675	Fair value of derivatives	$	209	$	—
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		$	89	$	675		$	209	$	206

Effect of Derivative Instruments on the Consolidated and Condensed Statements of Operations

For the Three Months Ended September 30, 2016 and 2015

	Location of Gain (Loss) Recognized in Income on  Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives
		2016		2015
Derivatives not designated as hedging instruments:
Interest rate swaption contracts	Interest expense	$	—	$	750
Commodity contracts	Cost of products sold	742		(358		)
Total derivatives not designated as hedging instruments		$	742	$	392

Effect of Derivative Instruments on the Consolidated and Condensed Statements of Operations

For the Nine Months Ended September 30, 2016 and 2015

	Location of Gain (Loss) Recognized in Income on  Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives
		2016		2015
Derivatives not designated as hedging instruments:
Interest rate swaption contracts	Interest expense	$	630	$	2,495
Interest rate contracts	Interest expense	366		—
Commodity contracts	Cost of products sold	871		(358		)
Total derivatives not designated as hedging instruments		$	1,867	$	2,137

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Fair Value Measurements

9 Months Ended

Sep. 30, 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
	September 30, 2016			December 31, 2015
Commodity derivative contracts, net	$	(120	)	$	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.

	September 30, 2016				December 31, 2015
	Carrying Value		Fair Value		Carrying Value		Fair Value
Note receivable - MET	$	15,000	$	15,803	$	15,000	$	15,830
2021 Senior unsecured notes	372,144		359,184		371,861		318,000

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Supplemental Balance Sheet Information

9 Months Ended

Sep. 30, 2016

Balance Sheet Related Disclosures [Abstract]

Supplemental Balance Sheet Information

Supplemental Balance Sheet Information

Components of "Other assets, net" were as follows:

	September 30, 2016		December 31, 2015
Customer contracts and relationships, net	$	40,386	$	50,452
Other intangible assets	2,417		1,818
Other	6,148		6,044
	$	48,951	$	58,314

Accumulated amortization of intangible assets was $47,521 and $32,842 at September 30, 2016 and December 31, 2015, respectively.

Components of "Other accrued liabilities" were as follows:

	September 30, 2016		December 31, 2015
Accrued interest	$	3,721	$	10,365
Property and other taxes payable	8,535		6,668
Accrued payroll	2,505		1,389
Other	43		111
	$	14,804	$	18,533

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Long-Term Debt

9 Months Ended

Sep. 30, 2016

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt

At September 30, 2016 and December 31, 2015, long-term debt consisted of the following:

	September 30, 2016		December 31, 2015
$664,4443 Revolving credit facility at variable interest rate (3.53%1 weighted average at September 30, 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 $7,640 and $4,858, respectively2	$	541,360	$	493,142
$400,000 Senior notes, 7.25% interest, net of unamortized debt issuance costs of $2,994 and $3,507, respectively, including unamortized premium of $1,338 and $1,568, respectively, issued $250,000 February 2013 and $150,000 April 2014, $26,200 repurchased during 2015, due February 2021, unsecured2	372,144		371,861
Total long-term debt, net	$	913,504	$	865,003

¹ 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 September 30, 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 existing LIBOR borrowings at September 30, 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 Partnership's omnibus agreement with Martin Resource Management (the "Omnibus Agreement"). The Partnership is permitted to make quarterly distributions so long as no event of default exists.

² The Partnership is in compliance with all debt covenants as of September 30, 2016.

³ 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. In connection with the amendment, the Partnership expensed $820 of unamortized debt issuance costs determined not to have continuing benefit.

The Partnership paid cash interest, net of proceeds received from interest rate swaptions and capitalized interest, in the amount of $18,644 and $40,760 for the three and nine months ended September, 2016, respectively.  The Partnership paid cash interest, net of proceeds received from interest rate swaptions and capitalized interest, in the amount of $18,017 and $39,121 for the three and nine months ended September 30, 2015, respectively.  Capitalized interest was $229 and $911 for the three and nine months ended September 30, 2016, respectively. Capitalized interest was $427 and $1,522 for the three and nine months ended September 30, 2015, respectively.

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Partners' Capital

9 Months Ended

Sep. 30, 2016

Partners' Capital Notes [Abstract]

Partners' Capital

Partners' Capital

As of September 30, 2016, Partners’ capital consisted of 35,454,712 common limited partner units, representing a 98% partnership interest and a 2% general partner interest. Martin Resource Management, through subsidiaries, owns 6,264,532 of the Partnership's common limited partner units representing approximately 17.7% of the Partnership's outstanding common limited partner units. Martin Midstream GP LLC ("MMGP"), the Partnership's general partner, owns the 2% general partnership interest. Martin Resource Management controls the Partnership's general partner, by virtue of its 51% voting interest in MMGP Holdings, LLC ("Holdings"), the sole member of the Partnership's general partner.

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.

Incentive Distribution Rights

MMGP holds a 2% 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 general partner was allocated $0 and $7,786 in incentive distributions during the three and nine months ended September 30, 2016, respectively. The general partner was allocated $3,893 and $11,680 in incentive distributions during the three and nine months ended September 30, 2015, respectively.

The target distribution levels entitle the general partner to receive 2% of quarterly cash distributions from the minimum of $0.50 per unit 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.

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 income and 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 allocated to the general partner and limited partners for purposes of calculating net income attributable to limited partners per unit:

	Three Months Ended September 30,						Nine Months Ended September 30,
Continuing operations:	2016			2015			2016			2015
Income (loss) from continuing operations	$	(933	)	$	3,330		$	13,770		$	30,324
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	—			3,893			7,786			11,230
Distributions payable on behalf of general partner interest	361			667			1,696			1,925
General partner interest in undistributed earnings	(379		)	(601		)	(1,420		)	(1,319		)
Less income (loss) allocable to unvested restricted units	(3		)	16			36			122
Limited partners’ interest in income (loss) from continuing operations	$	(912	)	$	(645	)	$	5,672		$	18,366

	Three Months Ended September 30,				Nine Months Ended September 30,
Discontinued operations:	2016		2015		2016		2015
Income from discontinued operations	$	—	$	—	$	—	$	1,215
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	—		—		—		450
Distributions payable on behalf of general partner interest	—		—		—		77
General partner interest in undistributed earnings	—		—		—		(53		)
Less income allocable to unvested restricted units	—		—		—		5
Limited partners’ interest in income from discontinued operations	$	—	$	—	$	—	$	736

The following are the unit amounts used to compute the basic and diluted earnings per limited partner unit for the periods presented:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2016	2015	2016	2015
Basic weighted average limited partner units outstanding	35,346,412	35,307,583	35,358,217	35,308,990
Dilutive effect of restricted units issued	—	—	22,850	59,976
Total weighted average limited partner diluted units outstanding	35,346,412	35,307,583	35,381,067	35,368,966

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 periods presented. All common unit equivalents were antidilutive for the three months ended September 30, 2016 and 2015 because the limited partners were allocated a net loss in these periods.

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Related Party Transactions

9 Months Ended

Sep. 30, 2016

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

As of September 30, 2016, Martin Resource Management owns 6,264,532 of the Partnership’s common units representing approximately 17.7% of the Partnership’s outstanding limited partner 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 IDRs.  The Partnership’s general partner’s ability, as general partner, to manage and operate the Partnership, and Martin Resource Management’s ownership as of September 30, 2016, of approximately 17.7% of the Partnership’s outstanding limited partner 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 and transactions:

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 Alabama, Florida, Louisiana, Mississippi and Texas;

◦ 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 natural gas 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 of the board of directors of the general partner of the Partnership (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, 2016, through December 31, 2016, the Conflicts Committee approved an annual reimbursement amount for indirect expenses of $13,033.  The Partnership reimbursed Martin Resource Management for $3,258 and $9,775 of indirect expenses for the three and nine months ended September 30, 2016, respectively.  The Partnership reimbursed Martin Resource Management for $3,420 and $10,259 of indirect expenses for the three and nine months ended September 30, 2015, 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 the 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. These rates are subject to any adjustments which are mutually agreed upon 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, Inc. has indemnified the Partnership against all claims arising out of the negligence or willful misconduct of Martin Transport, Inc. and its officers, employees, agents, representatives and subcontractors. The

Partnership has indemnified Martin Transport, Inc. against all claims arising out of the negligence or willful misconduct of the Partnership and its officers, employees, agents, representatives and subcontractors. In the event a claim is the result of the joint negligence or misconduct of Martin Transport, Inc. and the Partnership, 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 the Platt’s U.S. Gulf Coast Index for #2 Fuel Oil.  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. This agreement replaced the prior agreement that was in place concerning the same services, which was dated January 1, 2015. The minimum throughput requirements were reduced under the new agreement. The per gallon throughput fee the Partnership charges under this agreement was increased and may be adjusted annually based on a price index.

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. Most of 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"), a wholly-owned subsidiary of Martin Resource Management, dated October 28, 2014, as amended, 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 and Condensed 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 captions of the consolidated and condensed financial statements 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 and condensed financial statements as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Revenues:
Terminalling and storage	$	20,649	$	15,091	$	62,197	$	58,626
Marine transportation	4,861		6,552		17,308		19,919
Natural gas services	132		—		574		—
Product sales:
Natural gas services	—		479		—		779
Sulfur services	502		864		1,551		2,908
Terminalling and storage	221		388		840		1,392
	723		1,731		2,391		5,079
	$	26,365	$	23,374	$	82,470	$	83,624

The impact of related party cost of products sold is reflected in the consolidated and condensed financial statements as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Cost of products sold:
Natural gas services	$	2,946	$	6,470	$	10,829	$	20,198
Sulfur services	3,678		3,387		11,300		10,629
Terminalling and storage	3,766		3,227		11,232		14,261
	$	10,390	$	13,084	$	33,361	$	45,088

The impact of related party operating expenses is reflected in the consolidated and condensed financial statements as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Operating expenses:
Marine transportation	$	6,959	$	8,055	$	21,606	$	24,653
Natural gas services	2,329		2,218		6,955		6,373
Sulfur services	1,510		1,649		4,315		5,348
Terminalling and storage	7,012		7,368		20,379		22,231
	$	17,810	$	19,290	$	53,255	$	58,605

The impact of related party selling, general and administrative expenses is reflected in the consolidated and condensed financial statements as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Selling, general and administrative:
Marine transportation	$	9	$	6	$	22	$	22
Natural gas services	1,173		1,263		4,265		3,664
Sulfur services	678		661		2,089		2,099
Terminalling and storage	630		572		1,937		1,721
Indirect, including overhead allocation	3,258		3,420		9,778		10,259
	$	5,748	$	5,922	$	18,091	$	17,765

Other Related Party Transactions

The Partnership has a $15,000 note receivable from MET which 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 and Condensed Balance Sheets. Interest income for the three months ended September 30, 2016 and 2015 was $567 and $567, respectively, and is included in "Interest expense, net" in the Consolidated and Condensed Statements of Operations. Interest income for the nine months ended September 30, 2016 and 2015 was $1,689 and $1,683, respectively, and is included in "Interest expense, net" in the Consolidated and Condensed Statements of Operations.

As discussed in Note 6, the Partnership has certain derivative financial instruments through March 31, 2017 to protect a portion of its commodity price risk exposure related to NGLs. MET serves as counterparty to the outstanding positions at September 30, 2016.

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Income Taxes

9 Months Ended

Sep. 30, 2016

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The operations of the 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 included in income tax expense on the Consolidated and Condensed Statements of Operations. The Texas margin tax restructured the state business tax by replacing the taxable capital and earned surplus components of the existing franchise tax with a new "taxable margin" component. 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 $180 and $200 were recorded in income tax expense for the three months ended September 30, 2016 and 2015, respectively. State income taxes attributable to the Texas margin tax of $422 and $814 were recorded in income tax expense for the nine months ended September 30, 2016 and 2015, respectively.

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Business Segments

9 Months Ended

Sep. 30, 2016

Segment Reporting [Abstract]

Business Segments

Business Segments

The Partnership has four reportable segments: terminalling and storage, natural gas services, sulfur services and marine transportation. 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 in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2015, filed with the SEC on February 29, 2016, as amended, by Amendment No. 1 on Form 10-K/A filed on March 30, 2016. The Partnership evaluates the performance of its reportable segments based on operating income. There is no allocation of administrative expenses or interest expense.    

Three Months Ended September 30, 2016	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures and Plant Turnaround Costs
Terminalling and storage	$	60,943	$	(1,344	)	$	59,599	$	10,828	$	5,748		$	2,929
Natural gas services	71,996		—			71,996		7,050		7,150			728
Sulfur services	29,096		—			29,096		1,997		(965		)	632
Marine transportation	14,920		(1,074		)	13,846		2,254		1,449			260
Indirect selling, general and administrative	—		—			—		—		(4,206		)	—
Total	$	176,955	$	(2,418	)	$	174,537	$	22,129	$	9,176		$	4,549

Three Months Ended September 30, 2015	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures and Plant Turnaround Costs
Terminalling and storage	$	68,473	$	(1,566	)	$	66,907	$	9,624	$	7,786		$	7,928
Natural gas services	103,834		—			103,834		8,522		6,265			3,784
Sulfur services	36,303		—			36,303		2,129		2,908			289
Marine transportation	19,522		(545		)	18,977		3,060		23			717
Indirect selling, general and administrative	—		—			—		—		(4,948		)	—
Total	$	228,132	$	(2,111	)	$	226,021	$	23,335	$	12,034		$	12,718

Nine Months Ended September 30, 2016	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures and Plant Turnaround Costs
Terminalling and storage	$	183,014	$	(4,100	)	$	178,914	$	30,904	$	19,773		$	18,059
Natural gas services	253,486		—			253,486		21,007		24,695			3,881
Sulfur services	113,559		—			113,559		5,978		17,506			4,425
Marine transportation	46,854		(2,323		)	44,531		8,377		(5,528		)	2,197
Indirect selling, general and administrative	—		—			—		—		(12,676		)	—
Total	$	596,913	$	(6,423	)	$	590,490	$	66,266	$	43,770		$	28,562

Nine Months Ended September 30, 2015	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures and Plant Turnaround Costs
Terminalling and storage	$	207,794	$	(4,065	)	$	203,729	$	29,030	$	20,771		$	25,810
Natural gas services	380,974		—			380,974		25,297		24,412			17,893
Sulfur services	137,814		—			137,814		6,360		18,174			650
Marine transportation	62,354		(2,398		)	59,956		8,050		7,267			1,913
Indirect selling, general and administrative	—		—			—		—		(14,258		)	—
Total	$	788,936	$	(6,463	)	$	782,473	$	68,737	$	56,366		$	46,266

The Partnership's assets by reportable segment as of September 30, 2016 and December 31, 2015, are as follows:

	September 30, 2016		December 31, 2015
Total assets:
Terminalling and storage	$	412,604	$	417,202
Natural gas services	687,579		694,333
Sulfur services	118,699		134,108
Marine transportation	121,462		134,830
Total assets	$	1,340,344	$	1,380,473

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Unit Based Awards

9 Months Ended

Sep. 30, 2016

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Unit Based Awards

Unit Based Awards

The Partnership recognizes compensation cost related to unit-based awards to employees in its consolidated financial statements in accordance with certain provisions of ASC 718. The Partnership recognizes compensation costs related to unit-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 and condensed financial statements with respect to these plans are as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2016		2015			2016		2015
Employees	$	204	$	333		$	614	$	985
Non-employee directors	22		(3		)	98		95
Total unit-based compensation expense	$	226	$	330		$	712	$	1,080

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 (the "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 nine months ended September 30, 2016 is provided below:

	Number of Units			Weighted Average Grant-Date Fair Value Per Unit
Non-vested, beginning of period	150,474			$	28.98
Granted	13,800			$	15.13
Vested	(55,474		)	$	30.57
Forfeited	(500		)	$	28.50
Non-Vested, end of period	108,300			$	27.03
Aggregate intrinsic value, end of period	$	2,170

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 nine months ended September 30, 2016 and 2015 is provided below:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Aggregate intrinsic value of units vested	$	—	$	—	$	1,183	$	110
Fair value of units vested	$	—	$	—	$	1,685	$	113

As of September 30, 2016, there was $1,358 of unrecognized compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 1.68 years.

In conjunction with restricted unit issuances during the nine months ended September 30, 2015, the Partnership received $55 in capital contributions from its general partner to maintain its 2% general partnership interest in the Partnership.

Unit Options.  The plan currently permits the grant of options covering common units. As of September 30, 2016, the Partnership has not granted any common unit options to directors or employees of the Partnership's general partner, or its affiliates. In the future, the Compensation Committee may determine to make grants under the plan to employees and directors containing such terms as the Compensation Committee shall determine. Unit options will have an exercise price that, in the discretion of the Compensation Committee, may not be less than the fair market value of the units on the date of grant. In addition, the unit options will become exercisable upon a change in control of the Partnership's general partner, Martin Resource Management, or if the general partner ceases to be an affiliate of Martin Resource Management or upon the achievement of specified financial objectives.

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Condensed Consolidating Financial Information

9 Months Ended

Sep. 30, 2016

Consolidating Financial Statements [Abstract]

Condensed Consolidating Financial Information

Condensed Consolidating Financial Information

The Partnership's operations are conducted by its operating subsidiaries as it has no independent assets or operations. Martin Operating Partnership L.P. (the "Operating Partnership"), the Partnership’s wholly-owned subsidiary, and the Partnership's other operating subsidiaries have issued in the past, and may issue in the future, unconditional guarantees of senior

or subordinated debt securities of the Partnership. The guarantees that have been issued are full, irrevocable and unconditional and joint and several. In addition, the Operating Partnership may also issue senior or subordinated debt securities which, if issued, will be fully, irrevocably and unconditionally guaranteed by the Partnership. Substantially all of the Partnership's operating subsidiaries are subsidiary guarantors of its outstanding senior unsecured notes and any subsidiaries other than the subsidiary guarantors are minor.

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Commitments and Contingencies

9 Months Ended

Sep. 30, 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 provides for purchase price reimbursements of up to $4,500 in 2016 in the event certain financial conditions are not met. Currently, the Partnership expects to be fully reimbursed for the 2016 amount of $4,500. For the three and nine months ended September 30, 2016, the Partnership received $1,125 and $3,000, respectively, related to the Purchase Price Reimbursement Agreement. For the each of the three and nine months ended September 30, 2015, the Partnership received $750 and $1,500 related to the Purchase Price Reimbursement Agreement.

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 is seeking to evict the Partnership from the leased property and to recover 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.

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 generally allege that the customer engaged in unlawful and deceptive business practices in connection with its marketing and advertising of its private label motor oil. The Partnership disputes that it has any obligation to defend or indemnify the customer for its conduct. Accordingly, on January 7, 2016, the Partnership filed a Complaint for Declaratory Judgment in the Chancery Court of Davidson County, Tennessee requesting a judicial determination that the Partnership does not owe the customer the demanded defense and indemnity obligations. Currently, we are unable to determine the exposure we may have in this matter, if any.

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Impairment and other charges

9 Months Ended

Sep. 30, 2016

Goodwill and Intangible Assets Disclosure [Abstract]

Impairment and other charges

Impairments and other charges

Marine Transportation Goodwill Impairment

Over the last two years, global oil and natural gas commodity prices, particularly crude oil, significantly decreased as compared to recent historical levels. This decrease in commodity prices has had, and is expected to continue to have, a negative impact on drilling and crude oil production in the areas served by the Partnership's marine transportation assets.  The Partnership performed its annual assessment of the recoverability of goodwill during the third quarter of 2015. The Partnership updated its internal business outlook of the Marine Transportation reporting unit to consider the current economic environment that affects its operations. As part of the first step of goodwill impairment testing, the Partnership updated its assessment of its future cash flows, applying expected long-term growth rates, discount rates, and terminal values that the Partnership considers reasonable. Fair value was determined based on weighted average of the discounted cash flow method, the guideline public company method and the guideline transaction method. As a result of the analysis, the Partnership determined that there was no impairment of goodwill as of its annual assessment date. At the August 31, 2015 annual assessment date, the percentage of the fair value of the Partnership's Marine Transportation reporting unit over its carrying value was 41%.

As of June 30, 2016, the Partnership determined that the state of market conditions, 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 impairment losses for goodwill during the nine months ended September 30, 2015.

Divestiture of Non-Core Marine Equipment

During the nine months ended September 30, 2016, the Partnership disposed of 8 inland tank barges and 2 inland push boats, which were deemed non-core assets to the Partnership's Marine Transportation business. The Partnership recognized a loss related to the disposition of these assets in the amount of $1,567, which is included in "Other operating loss" on the Partnership's Consolidated and Condensed Statements of Operations.

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Subsequent Events

9 Months Ended

Sep. 30, 2016

Subsequent Events [Abstract]

Subsequent Events

Subsequent Events

Sale of CCCT Assets. As discussed in Note 3, on October 14, 2016, the Partnership entered into a definitive agreement with NuStar to sell the CCCT Assets for gross consideration of $107,000 plus the reimbursement of certain capital expenditures and prepaid items. The Partnership expects to receive net proceeds of approximately $93,000 after transaction fees and expenses as well as the application of certain net cash payments previously received by the Partnership in conjunction with its mandated relocation of certain dockage assets to the purchase price. Proceeds from the sale will be used to reduce outstanding borrowings under the Partnership's revolving credit facility.

Quarterly Distribution. On October 20, 2016, the Partnership declared a quarterly cash distribution of $0.50 per common unit for the third quarter of 2016, or $2.00 per common unit on an annualized basis, which will be paid on November 14, 2016 to unitholders of record as of November 7, 2016.

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New Accounting Pronouncements (Policies)

9 Months Ended

Sep. 30, 2016

Accounting Changes and Error Corrections [Abstract]

New 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 and condensed 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 and condensed 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 and condensed 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 evaluating the effect that ASU 2014-09 will have on its consolidated and condensed financial statements and related disclosures. The Partnership has not yet selected a transition method nor has it determined the effect of the standard on its ongoing financial reporting.

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Divestitures and discontinued operations (Tables)

9 Months Ended

Sep. 30, 2016

Discontinued Operations and Disposal Groups [Abstract]

Schedule Of Disposal Groups Including Discontinued Operations

The Floating Storage Assets’ operating results, which are included in income from discontinued operations, were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Total revenues from third parties1	$	—	$	—	$	—	$	791
Total costs and expenses and other, net, excluding depreciation and amortization	—		—		—		1,038
Depreciation and amortization	—		—		—		—
Other operating income2	—		—		—		1,462
Income from discontinued operations before income taxes	—		—		—		1,215
Income tax expense	—		—		—		—
Income from discontinued operations, net of income taxes	$	—	$	—	$	—	$	1,215

¹ All revenues for the nine months ended September 30, 2015 were from third parties.

² Other operating income represents the gain on the disposition of the Floating Storage Assets.

The Partnership has classified the CCCT Assets, and the related liabilities, as held for sale at September 30, 2016, as follows:

	2016
Assets:
Other assets	$	4,333
Property, plant, and equipment	91,594
Accumulated depreciation	(25,091		)
Goodwill	2,361
Assets held for sale	$	73,197
Liabilities:
Current liabilities	$	23,400
Liabilities held for sale	$	23,400

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Inventories (Tables)

9 Months Ended

Sep. 30, 2016

Inventory Disclosure [Abstract]

Components of inventory

Components of inventories at September 30, 2016 and December 31, 2015 were as follows: 

	September 30, 2016		December 31, 2015
Natural gas liquids	$	65,107	$	20,959
Sulfur	6,959		13,812
Sulfur based products	12,541		19,400
Lubricants	19,918		18,675
Other	2,951		3,024
	$	107,476	$	75,870

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Investment in West Texas LPG Pipeline L.P. (Tables)

9 Months Ended

Sep. 30, 2016

Equity Method Investments and Joint Ventures [Abstract]

Select financial information for significant unconsolidated equity-method investees

Selected financial information for WTLPG is as follows:

	As of September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	Total Assets		Members' Equity		Revenues		Net Income		Revenues		Net Income
2016
WTLPG	$	815,700	$	791,762	$	21,849	$	5,515	$	66,870	$	18,240
	As of December 31,
2015
WTLPG	$	819,342	$	804,023	$	26,094	$	11,815	$	70,010	$	28,760

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Derivative Instruments and Hedging Activities (Tables)

9 Months Ended

Sep. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Effect of derivative instruments on the Consolidated Balance Sheets

The following table summarizes the fair value and classification of the Partnership’s derivative instruments in its Consolidated and Condensed Balance Sheets:

	Fair Values of Derivative Instruments in the Consolidated Balance Sheets
	Derivative Assets					Derivative Liabilities
		Fair Values					Fair Values
	Balance Sheet Location	September 30, 2016		December 31, 2015		Balance Sheet Location	September 30, 2016		December 31, 2015
Derivatives not designated as hedging instruments:	Current:
Commodity contracts	Fair value of derivatives	$	89	$	675	Fair value of derivatives	$	209	$	—
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		$	89	$	675		$	209	$	206

Effect of derivative instruments on the Consolidated Statement of Operations

Effect of Derivative Instruments on the Consolidated and Condensed Statements of Operations

For the Three Months Ended September 30, 2016 and 2015

	Location of Gain (Loss) Recognized in Income on  Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives
		2016		2015
Derivatives not designated as hedging instruments:
Interest rate swaption contracts	Interest expense	$	—	$	750
Commodity contracts	Cost of products sold	742		(358		)
Total derivatives not designated as hedging instruments		$	742	$	392

Effect of Derivative Instruments on the Consolidated and Condensed Statements of Operations

For the Nine Months Ended September 30, 2016 and 2015

	Location of Gain (Loss) Recognized in Income on  Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives
		2016		2015
Derivatives not designated as hedging instruments:
Interest rate swaption contracts	Interest expense	$	630	$	2,495
Interest rate contracts	Interest expense	366		—
Commodity contracts	Cost of products sold	871		(358		)
Total derivatives not designated as hedging instruments		$	1,867	$	2,137

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 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
	September 30, 2016			December 31, 2015
Commodity derivative contracts, net	$	(120	)	$	675
Interest rate derivative contracts	—			(206		)

	September 30, 2016				December 31, 2015
	Carrying Value		Fair Value		Carrying Value		Fair Value
Note receivable - MET	$	15,000	$	15,803	$	15,000	$	15,830
2021 Senior unsecured notes	372,144		359,184		371,861		318,000

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Supplemental Balance Sheet Information (Tables)

9 Months Ended

Sep. 30, 2016

Balance Sheet Related Disclosures [Abstract]

Schedule of Other Assets

Components of "Other assets, net" were as follows:

	September 30, 2016		December 31, 2015
Customer contracts and relationships, net	$	40,386	$	50,452
Other intangible assets	2,417		1,818
Other	6,148		6,044
	$	48,951	$	58,314

Schedule of Other Accrued Liabilities

Components of "Other accrued liabilities" were as follows:

	September 30, 2016		December 31, 2015
Accrued interest	$	3,721	$	10,365
Property and other taxes payable	8,535		6,668
Accrued payroll	2,505		1,389
Other	43		111
	$	14,804	$	18,533

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Long-Term Debt (Tables)

9 Months Ended

Sep. 30, 2016

Debt Disclosure [Abstract]

Schedule of long-term debt

At September 30, 2016 and December 31, 2015, long-term debt consisted of the following:

	September 30, 2016		December 31, 2015
$664,4443 Revolving credit facility at variable interest rate (3.53%1 weighted average at September 30, 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 $7,640 and $4,858, respectively2	$	541,360	$	493,142
$400,000 Senior notes, 7.25% interest, net of unamortized debt issuance costs of $2,994 and $3,507, respectively, including unamortized premium of $1,338 and $1,568, respectively, issued $250,000 February 2013 and $150,000 April 2014, $26,200 repurchased during 2015, due February 2021, unsecured2	372,144		371,861
Total long-term debt, net	$	913,504	$	865,003

¹ 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 September 30, 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 existing LIBOR borrowings at September 30, 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 Partnership's omnibus agreement with Martin Resource Management (the "Omnibus Agreement"). The Partnership is permitted to make quarterly distributions so long as no event of default exists.

² The Partnership is in compliance with all debt covenants as of September 30, 2016.

³ 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. In connection with the amendment, the Partnership expensed $820 of unamortized debt issuance costs determined not to have continuing benefit.

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Partners' Capital (Tables)

9 Months Ended

Sep. 30, 2016

Partners' Capital Notes [Abstract]

Reconciliation of net income to partners interest in net income

The following is a reconciliation of net income allocated to the general partner and limited partners for purposes of calculating net income attributable to limited partners per unit:

	Three Months Ended September 30,						Nine Months Ended September 30,
Continuing operations:	2016			2015			2016			2015
Income (loss) from continuing operations	$	(933	)	$	3,330		$	13,770		$	30,324
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	—			3,893			7,786			11,230
Distributions payable on behalf of general partner interest	361			667			1,696			1,925
General partner interest in undistributed earnings	(379		)	(601		)	(1,420		)	(1,319		)
Less income (loss) allocable to unvested restricted units	(3		)	16			36			122
Limited partners’ interest in income (loss) from continuing operations	$	(912	)	$	(645	)	$	5,672		$	18,366

	Three Months Ended September 30,				Nine Months Ended September 30,
Discontinued operations:	2016		2015		2016		2015
Income from discontinued operations	$	—	$	—	$	—	$	1,215
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	—		—		—		450
Distributions payable on behalf of general partner interest	—		—		—		77
General partner interest in undistributed earnings	—		—		—		(53		)
Less income allocable to unvested restricted units	—		—		—		5
Limited partners’ interest in income from discontinued operations	$	—	$	—	$	—	$	736

The following are the unit amounts used to compute the basic and diluted earnings per limited partner unit for the periods presented:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2016	2015	2016	2015
Basic weighted average limited partner units outstanding	35,346,412	35,307,583	35,358,217	35,308,990
Dilutive effect of restricted units issued	—	—	22,850	59,976
Total weighted average limited partner diluted units outstanding	35,346,412	35,307,583	35,381,067	35,368,966

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Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 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 and condensed financial statements as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Revenues:
Terminalling and storage	$	20,649	$	15,091	$	62,197	$	58,626
Marine transportation	4,861		6,552		17,308		19,919
Natural gas services	132		—		574		—
Product sales:
Natural gas services	—		479		—		779
Sulfur services	502		864		1,551		2,908
Terminalling and storage	221		388		840		1,392
	723		1,731		2,391		5,079
	$	26,365	$	23,374	$	82,470	$	83,624

The impact of related party cost of products sold is reflected in the consolidated and condensed financial statements as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Cost of products sold:
Natural gas services	$	2,946	$	6,470	$	10,829	$	20,198
Sulfur services	3,678		3,387		11,300		10,629
Terminalling and storage	3,766		3,227		11,232		14,261
	$	10,390	$	13,084	$	33,361	$	45,088

The impact of related party operating expenses is reflected in the consolidated and condensed financial statements as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Operating expenses:
Marine transportation	$	6,959	$	8,055	$	21,606	$	24,653
Natural gas services	2,329		2,218		6,955		6,373
Sulfur services	1,510		1,649		4,315		5,348
Terminalling and storage	7,012		7,368		20,379		22,231
	$	17,810	$	19,290	$	53,255	$	58,605

The impact of related party selling, general and administrative expenses is reflected in the consolidated and condensed financial statements as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Selling, general and administrative:
Marine transportation	$	9	$	6	$	22	$	22
Natural gas services	1,173		1,263		4,265		3,664
Sulfur services	678		661		2,089		2,099
Terminalling and storage	630		572		1,937		1,721
Indirect, including overhead allocation	3,258		3,420		9,778		10,259
	$	5,748	$	5,922	$	18,091	$	17,765

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Business Segments (Tables)

9 Months Ended

Sep. 30, 2016

Segment Reporting [Abstract]

Segment reporting by segment

Three Months Ended September 30, 2016	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures and Plant Turnaround Costs
Terminalling and storage	$	60,943	$	(1,344	)	$	59,599	$	10,828	$	5,748		$	2,929
Natural gas services	71,996		—			71,996		7,050		7,150			728
Sulfur services	29,096		—			29,096		1,997		(965		)	632
Marine transportation	14,920		(1,074		)	13,846		2,254		1,449			260
Indirect selling, general and administrative	—		—			—		—		(4,206		)	—
Total	$	176,955	$	(2,418	)	$	174,537	$	22,129	$	9,176		$	4,549

Three Months Ended September 30, 2015	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures and Plant Turnaround Costs
Terminalling and storage	$	68,473	$	(1,566	)	$	66,907	$	9,624	$	7,786		$	7,928
Natural gas services	103,834		—			103,834		8,522		6,265			3,784
Sulfur services	36,303		—			36,303		2,129		2,908			289
Marine transportation	19,522		(545		)	18,977		3,060		23			717
Indirect selling, general and administrative	—		—			—		—		(4,948		)	—
Total	$	228,132	$	(2,111	)	$	226,021	$	23,335	$	12,034		$	12,718

Nine Months Ended September 30, 2016	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures and Plant Turnaround Costs
Terminalling and storage	$	183,014	$	(4,100	)	$	178,914	$	30,904	$	19,773		$	18,059
Natural gas services	253,486		—			253,486		21,007		24,695			3,881
Sulfur services	113,559		—			113,559		5,978		17,506			4,425
Marine transportation	46,854		(2,323		)	44,531		8,377		(5,528		)	2,197
Indirect selling, general and administrative	—		—			—		—		(12,676		)	—
Total	$	596,913	$	(6,423	)	$	590,490	$	66,266	$	43,770		$	28,562

Nine Months Ended September 30, 2015	Operating Revenues		Intersegment Revenues Eliminations			Operating Revenues after Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures and Plant Turnaround Costs
Terminalling and storage	$	207,794	$	(4,065	)	$	203,729	$	29,030	$	20,771		$	25,810
Natural gas services	380,974		—			380,974		25,297		24,412			17,893
Sulfur services	137,814		—			137,814		6,360		18,174			650
Marine transportation	62,354		(2,398		)	59,956		8,050		7,267			1,913
Indirect selling, general and administrative	—		—			—		—		(14,258		)	—
Total	$	788,936	$	(6,463	)	$	782,473	$	68,737	$	56,366		$	46,266

Assets by segment

The Partnership's assets by reportable segment as of September 30, 2016 and December 31, 2015, are as follows:

	September 30, 2016		December 31, 2015
Total assets:
Terminalling and storage	$	412,604	$	417,202
Natural gas services	687,579		694,333
Sulfur services	118,699		134,108
Marine transportation	121,462		134,830
Total assets	$	1,340,344	$	1,380,473

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Unit Based Awards (Tables)

9 Months Ended

Sep. 30, 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 and condensed financial statements with respect to these plans are as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2016		2015			2016		2015
Employees	$	204	$	333		$	614	$	985
Non-employee directors	22		(3		)	98		95
Total unit-based compensation expense	$	226	$	330		$	712	$	1,080

Summary of restricted unit activity

A summary of the restricted unit activity for the nine months ended September 30, 2016 is provided below:

	Number of Units			Weighted Average Grant-Date Fair Value Per Unit
Non-vested, beginning of period	150,474			$	28.98
Granted	13,800			$	15.13
Vested	(55,474		)	$	30.57
Forfeited	(500		)	$	28.50
Non-Vested, end of period	108,300			$	27.03
Aggregate intrinsic value, end of period	$	2,170

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 nine months ended September 30, 2016 and 2015 is provided below:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Aggregate intrinsic value of units vested	$	—	$	—	$	1,183	$	110
Fair value of units vested	$	—	$	—	$	1,685	$	113

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General (Details) bbl in Millions		9 Months Ended
	Oct. 14, 2016 USD ($) bbl	Sep. 30, 2016 segment
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of primary business lines (in segments) | segment		4
Subsequent Event | CCCT Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from dock relocation	$ 13,400
Disposal Group, Held-for-sale, Not Discontinued Operations | Subsequent Event | CCCT Assets
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	0.9
Gross consideration	$ 107,000
Net proceeds	93,000
Proceeds from dock relocation	$ 13,400

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Divestitures and discontinued operations - Narrative (Details)	Oct. 14, 2016 USD ($)	Feb. 12, 2015 barge bbl
Floating Storage Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of pressure barges disposed of (in barges) | barge		6
Volume of pressure barges disposed of (in bbl) | bbl		16,101
Subsequent Event | CCCT Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from dock relocation	$ 13,400
Disposal Group, Held-for-sale, Not Discontinued Operations | Subsequent Event | CCCT Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gross consideration	107,000
Net proceeds	93,000
Proceeds from dock relocation	$ 13,400

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Divestitures and discontinued operations Divestitures and discontinued operations - CCCT Assets (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Assets:
Accumulated depreciation	$ (411,821)	$ (404,574)
Liabilities:
Liabilities held for sale	23,400	$ 0
CCCT Assets | Discontinued Operations, Held-for-sale
Assets:
Other assets	4,333
Property, plant, and equipment	91,594
Accumulated depreciation	(25,091)
Goodwill	2,361
Assets held for sale	73,197
Liabilities:
Current liabilities	23,400
Liabilities held for sale	$ 23,400

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Divestitures and discontinued operations - Operating Results (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income from discontinued operations, net of income taxes	$ 0	$ 0	$ 0	$ 1,215
Discontinued Operations, Disposed of by Sale | 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
Total costs and expenses and other, net, excluding depreciation and amortization	0	0
Depreciation and amortization	0	0
Other operating income	0	0
Income from discontinued operations before income taxes	0	0
Income tax expense	0	0
Income from discontinued operations, net of income taxes	$ 0	$ 0
Discontinued Operations, Held-for-sale | 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
Total costs and expenses and other, net, excluding depreciation and amortization			0	1,038
Depreciation and amortization			0	0
Other operating income			0	1,462
Income from discontinued operations before income taxes			0	1,215
Income tax expense			0	0
Income from discontinued operations, net of income taxes			$ 0	$ 1,215

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Inventories (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Inventory Disclosure [Abstract]
Natural gas liquids	$ 65,107	$ 20,959
Sulfur	6,959	13,812
Sulfur based products	12,541	19,400
Lubricants	19,918	18,675
Other	2,951	3,024
Inventories	$ 107,476	$ 75,870

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Investment in West Texas LPG Pipeline L.P. - Narrative (Details) $ in Thousands	Sep. 30, 2016 USD ($) mi	Dec. 31, 2015 USD ($)
Schedule of Equity Method Investments [Line Items]
Partnership's interest in cash of the unconsolidated equity-method investees | $	$ 1,189	$ 1,060
West Texas LPG Pipeline L.P.
Schedule of Equity Method Investments [Line Items]
Length of common-carrier pipeline system (in miles) | mi	2,300
Unconsolidated interest ownership (percentage)	20.00%
West Texas LPG Pipeline L.P. | General Partner
Schedule of Equity Method Investments [Line Items]
Remaining ownership percentage in investment	19.80%
West Texas LPG Pipeline L.P. | Limited Partner
Schedule of Equity Method Investments [Line Items]
Remaining ownership percentage in investment	0.20%

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Investment in West Texas LPG Pipeline L.P. (Selected Financial Information for Equity Method Investees) (Details) - West Texas LPG Pipeline L.P. - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
Total Assets	$ 815,700		$ 815,700		$ 819,342
Members' Equity	791,762		791,762		$ 804,023
Revenues	21,849	$ 26,094	66,870	$ 70,010
Net Income	$ 5,515	$ 11,815	$ 18,240	$ 28,760

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Derivative Instruments and Hedging Activities - Narrative (Details)		3 Months Ended		9 Months Ended
	Jan. 07, 2016 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)	Sep. 30, 2016 USD ($) bbl	Sep. 30, 2015 USD ($)	Dec. 31, 2015 USD ($)
Commodity contracts
Derivatives, Fair Value [Line Items]
Notional quantity (in bbl) | bbl				441,000,000
Interest Rate Swaption
Derivatives, Fair Value [Line Items]
Premiums received		$ 0	$ 750,000	$ 630,000	$ 2,495,000
Interest Rate Swaption | Interest expense
Derivatives, Fair Value [Line Items]
Premiums received		$ 0	$ 750,000	$ 630,000	$ 2,495,000
Interest Rate Swap
Derivatives, Fair Value [Line Items]
Notional principal amount						$ 50,000,000
Fair value of derivatives | Interest Rate Swap
Derivatives, Fair Value [Line Items]
Derivative Liabilities						$ 206,000
Benefit from termination of position	$ 160,000

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Derivative Instruments and Hedging Activities - Balance Sheet Derivatives (Details) - Derivatives not designated as hedging instruments: - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Derivative Assets	$ 89	$ 675
Derivative Liabilities	209	206
Commodity contracts | Fair value of derivatives
Derivatives, Fair Value [Line Items]
Derivative Assets	89	675
Derivative Liabilities	209	0
Interest rate contracts | Fair value of derivatives
Derivatives, Fair Value [Line Items]
Derivative Assets	0	0
Derivative Liabilities	$ 0	$ 206

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Derivative Instruments and Hedging Activities - Statement of Operations Derivatives (Details) - Derivatives not designated as hedging instruments: - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	$ 742	$ 392	$ 1,867	$ 2,137
Interest rate swaption contracts | Interest expense
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	0	750	630	2,495
Commodity contracts | Cost of products sold
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	$ 742	$ (358)	871	(358)
Interest rate contracts | Interest expense
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives			$ 366	$ 0

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Fair Value Measurements (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Recurring | Level 2 | Commodity contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value, net asset (liability)	$ (120)	$ 675
Recurring | Level 2 | Interest rate contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value, net asset (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 | Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Note receivable - MET	15,803	15,830
Nonrecurring | 2021 Senior unsecured notes | Carrying Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
2021 Senior unsecured notes	372,144	371,861
Nonrecurring | 2021 Senior unsecured notes | Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
2021 Senior unsecured notes	$ 359,184	$ 318,000

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Supplemental Balance Sheet Information - Other Assets (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Balance Sheet Related Disclosures [Abstract]
Customer contracts and relationships, net	$ 40,386	$ 50,452
Other intangible assets	2,417	1,818
Other	6,148	6,044
Other assets, net	48,951	58,314
Accumulated amortization of intangible assets	$ 47,521	$ 32,842

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Supplemental Balance Sheet Information - Other Accrued Liabilities (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Balance Sheet Related Disclosures [Abstract]
Accrued interest	$ 3,721	$ 10,365
Property and other taxes payable	8,535	6,668
Accrued payroll	2,505	1,389
Other	43	111
Total Other Accrued Liabilities	$ 14,804	$ 18,533

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Long-Term Debt (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Apr. 27, 2016	Apr. 26, 2016	Dec. 31, 2015	Apr. 30, 2014	Feb. 28, 2013
Debt Instrument [Line Items]
Total long-term debt, net	$ 913,504,000		$ 913,504,000				$ 865,003,000
Debt issuance costs					$ 820,000
Cash paid for interest	18,644,000	$ 18,017,000	40,760,000	$ 39,121,000
Capitalized interest	229,000	$ 427,000	911,000	$ 1,522,000
Revolving Loan Facility
Debt Instrument [Line Items]
Total long-term debt, net	541,360,000		541,360,000				493,142,000
Face amount	$ 664,444,000		$ 664,444,000		$ 664,444,000	$ 700,000,000
Weighted average interest rate	3.53%		3.53%
Unamortized debt issuance costs	$ 7,640,000		$ 7,640,000				4,858,000
Revolving Loan Facility | LIBOR
Debt Instrument [Line Items]
Applicable margins			3.00%
Revolving Loan Facility | LIBOR | Minimum
Debt Instrument [Line Items]
Applicable margins			2.00%
Revolving Loan Facility | LIBOR | Maximum
Debt Instrument [Line Items]
Applicable margins			3.00%
Revolving Loan Facility | Prime Rate | Minimum
Debt Instrument [Line Items]
Applicable margins			1.00%
Revolving Loan Facility | Prime Rate | Maximum
Debt Instrument [Line Items]
Applicable margins			2.00%
Senior Notes | Senior Notes 7.250%
Debt Instrument [Line Items]
Total long-term debt, net	372,144,000		$ 372,144,000				371,861,000
Face amount	400,000,000		400,000,000					$ 150,000,000	$ 250,000,000
Unamortized debt issuance costs	$ 2,994,000		$ 2,994,000				3,507,000
Stated interest rate	7.25%		7.25%
Unamortized premium	$ 1,338,000		$ 1,338,000				1,568,000
Repurchase amount							$ 26,200,000

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Partners' Capital (Details) - shares	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Limited Partners' Capital Account [Line Items]
Common limited partner units (in shares)	35,454,712
Ownership percentage	98.00%
General partner interest percentage	2.00%	2.00%
Martin Resource Management
Limited Partners' Capital Account [Line Items]
Voting interest percentage	51.00%
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%
Voting interest percentage	17.70%

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Partners' Capital - Incentive Distribution Rights and Distributions of Available Cash (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Limited Partners' Capital Account [Line Items]
General partner interest percentage			2.00%	2.00%
Distribution period			45 days
Martin Midstream GP LLC
Limited Partners' Capital Account [Line Items]
General partner interest percentage			2.00%
Incentive distribution	$ 0	$ 3,893	$ 7,786	$ 11,680
Martin Midstream GP LLC | Target Level 1
Limited Partners' Capital Account [Line Items]
Target cash distribution, percent	2.00%		2.00%
Target cash distribution (USD per share)	$ 0.55		$ 0.55
Martin Midstream GP LLC | Target Level 2
Limited Partners' Capital Account [Line Items]
Target cash distribution, percent	15.00%		15.00%
Target cash distribution (USD per share)	$ 0.625		$ 0.625
Martin Midstream GP LLC | Target Level 3
Limited Partners' Capital Account [Line Items]
Target cash distribution, percent	25.00%		25.00%
Target cash distribution (USD per share)	$ 0.75		$ 0.75
Martin Midstream GP LLC | Target Level 4
Limited Partners' Capital Account [Line Items]
Target cash distribution, percent	50.00%		50.00%
Minimum | Martin Midstream GP LLC | Target Level 1
Limited Partners' Capital Account [Line Items]
Target cash distribution (USD per share)	$ 0.50		$ 0.50
Maximum | Martin Midstream GP LLC | Target Level 1
Limited Partners' Capital Account [Line Items]
Target cash distribution (USD per share)	$ 0.55		$ 0.55

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Partners' Capital - Net Income Per Unit (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Reconciliation of Net Income from Continuing and Discontinued Operations [Line Items]
Income from operations	$ (933)	$ 3,330	$ 13,770	$ 31,539
Less general partner’s interest in net income:
Less income (loss) allocable to unvested restricted units	3	(16)	(36)	(127)
Limited partners' interest in net income (loss)	$ (912)	$ (645)	$ 5,672	$ 19,102
Basic weighted average limited partner units outstanding (in shares)	35,346,412	35,307,583	35,358,217	35,308,990
Dilutive effect of restricted units issued (in shares)	0	0	22,850	59,976
Total weighted average limited partner diluted units outstanding (in shares)	35,346,412	35,307,583	35,381,067	35,368,966
Continuing operations:
Reconciliation of Net Income from Continuing and Discontinued Operations [Line Items]
Income from operations	$ (933)	$ 3,330	$ 13,770	$ 30,324
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	0	3,893	7,786	11,230
Distributions payable on behalf of general partner interest	361	667	1,696	1,925
General partner interest in undistributed earnings	(379)	(601)	(1,420)	(1,319)
Less income (loss) allocable to unvested restricted units	(3)	16	36	122
Limited partners' interest in net income (loss)	(912)	(645)	5,672	18,366
Discontinued operations:
Reconciliation of Net Income from Continuing and Discontinued Operations [Line Items]
Income from operations	0	0	0	1,215
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	0	0	0	450
Distributions payable on behalf of general partner interest	0	0	0	77
General partner interest in undistributed earnings	0	0	0	(53)
Less income (loss) allocable to unvested restricted units	0	0	0	5
Limited partners' interest in net income (loss)	$ 0	$ 0	$ 0	$ 736

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Related Party Transactions - Other Related Party Transactions (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Related Party Transaction [Line Items]
General partner interest percentage			2.00%	2.00%
Note receivable - Martin Energy Trading LLC	$ 15,000		$ 15,000		$ 15,000
Martin Energy Trading LLC
Related Party Transaction [Line Items]
Due from related parties, annual interest rate			15.00%
Martin Energy Trading LLC | Interest expense
Related Party Transaction [Line Items]
Interest Income, Related Party	567	$ 567	$ 1,689	$ 1,683
Martin Energy Trading LLC | Notes Receivable
Related Party Transaction [Line Items]
Note receivable - Martin Energy Trading LLC	$ 15,000		$ 15,000
Martin Resource Management
Related Party Transaction [Line Items]
Number of shares owned (in shares)	6,264,532		6,264,532
Ownership percentage	17.70%		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%

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Related Party Transactions - Omnibus Agreement (Details) - Omnibus Agreement - Martin Resource Management - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Related Party Transaction [Line Items]
Noncompete restriction threshold	$ 5,000,000		$ 5,000,000
Noncompete restriction ownership option opportunity threshold minimum	5,000,000		5,000,000
Noncompete restriction ownership option opportunity threshold minimum with equity limitation	$ 5,000,000		$ 5,000,000
Equity limitation on ownership restriction percentage	20.00%		20.00%
Approved annual reimbursements for indirect expenses			$ 13,033,000
Indirect expenses reimbursed	$ 3,258,000	$ 3,420,000	$ 9,775,000	$ 10,259,000

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Related Party Transactions - Motor Carrier Agreement (Details) - Motor Carrier Agreement - Martin Resource Management	9 Months Ended
	Sep. 30, 2016
Related Party Transaction [Line Items]
Automatic consecutive term renewal period (in years)	1 year
Termination written notice, minimum (in days)	30 days
Partnership notice period to terminate agreement (in days)	90 days

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Related Party Transactions - Marine Agreements (Details) - Marine Transportation Agreement - Martin Resource Management	9 Months Ended
	Sep. 30, 2016
Related Party Transaction [Line Items]
Automatic consecutive term renewal period (in years)	1 year
Termination written notice, minimum (in days)	60 days

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Related Party Transactions - Other Agreements (Details) - Martin Resource Management	9 Months Ended
	Sep. 30, 2016 bbl
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

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Related Party Transactions (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Revenues:
Terminalling and storage	$ 20,649	$ 15,091	$ 62,197	$ 58,626
Marine transportation	4,861	6,552	17,308	19,919
Natural gas services	132	0	574	0
Product sales:
Product Sales Related Party	723	1,731	2,391	5,079
Cost of products sold:
Natural gas services	2,946	6,470	10,829	20,198
Sulfur services	3,678	3,387	11,300	10,629
Terminalling and storage	3,766	3,227	11,232	14,261
Operating expenses:
Operating expenses	17,810	19,290	53,255	58,605
Related Party
Product sales:
Product Sales Related Party	723	1,731	2,391	5,079
Revenue from Related Parties	26,365	23,374	82,470	83,624
Cost of products sold:
Cost of products sold	10,390	13,084	33,361	45,088
Operating expenses:
Operating expenses	17,810	19,290	53,255	58,605
Selling, general and administrative:
Selling, general and administrative	5,748	5,922	18,091	17,765
Related Party | Terminalling and storage
Revenues:
Terminalling and storage	20,649	15,091	62,197	58,626
Product sales:
Product Sales Related Party	221	388	840	1,392
Cost of products sold:
Terminalling and storage	3,766	3,227	11,232	14,261
Operating expenses:
Operating expenses	7,012	7,368	20,379	22,231
Selling, general and administrative:
Selling, general and administrative	630	572	1,937	1,721
Related Party | Marine transportation
Revenues:
Marine transportation	4,861	6,552	17,308	19,919
Operating expenses:
Operating expenses	6,959	8,055	21,606	24,653
Selling, general and administrative:
Selling, general and administrative	9	6	22	22
Related Party | Natural gas services
Revenues:
Natural gas services	132	0	574	0
Product sales:
Product Sales Related Party	0	479	0	779
Cost of products sold:
Natural gas services	2,946	6,470	10,829	20,198
Operating expenses:
Operating expenses	2,329	2,218	6,955	6,373
Selling, general and administrative:
Selling, general and administrative	1,173	1,263	4,265	3,664
Related Party | Sulfur services
Product sales:
Product Sales Related Party	502	864	1,551	2,908
Cost of products sold:
Sulfur services	3,678	3,387	11,300	10,629
Operating expenses:
Operating expenses	1,510	1,649	4,315	5,348
Selling, general and administrative:
Selling, general and administrative	678	661	2,089	2,099
Related Party | Indirect, including overhead allocation
Selling, general and administrative:
Selling, general and administrative	$ 3,258	$ 3,420	$ 9,778	$ 10,259

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Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
State and Local Jurisdiction | Texas
Income Tax Contingency [Line Items]
State income taxes	$ 180	$ 200	$ 422	$ 814

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Business Segments (Details) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)	Sep. 30, 2016 USD ($) segment	Sep. 30, 2015 USD ($)	Dec. 31, 2015 USD ($)
Segment Reporting [Abstract]
Number of reportable segments (in segments) | segment			4
Segment Reporting Information [Line Items]
Total revenue	$ 174,537	$ 226,021	$ 590,490	$ 782,473
Depreciation and amortization	22,129	23,335	66,266	68,737
Operating Income (Loss) after Eliminations	9,176	12,034	43,770	56,366
Capital Expenditures and Plant Turnaround Costs	4,549	12,718	28,562	46,266
Total assets:
Total assets	1,340,344		1,340,344		$ 1,380,473
Terminalling and storage
Segment Reporting Information [Line Items]
Total revenue	59,599	66,907	178,914	203,729
Depreciation and amortization	10,828	9,624	30,904	29,030
Operating Income (Loss) after Eliminations	5,748	7,786	19,773	20,771
Capital Expenditures and Plant Turnaround Costs	2,929	7,928	18,059	25,810
Total assets:
Total assets	412,604		412,604		417,202
Natural gas services
Segment Reporting Information [Line Items]
Total revenue	71,996	103,834	253,486	380,974
Depreciation and amortization	7,050	8,522	21,007	25,297
Operating Income (Loss) after Eliminations	7,150	6,265	24,695	24,412
Capital Expenditures and Plant Turnaround Costs	728	3,784	3,881	17,893
Total assets:
Total assets	687,579		687,579		694,333
Sulfur services
Segment Reporting Information [Line Items]
Total revenue	29,096	36,303	113,559	137,814
Depreciation and amortization	1,997	2,129	5,978	6,360
Operating Income (Loss) after Eliminations	(965)	2,908	17,506	18,174
Capital Expenditures and Plant Turnaround Costs	632	289	4,425	650
Total assets:
Total assets	118,699		118,699		134,108
Marine transportation
Segment Reporting Information [Line Items]
Total revenue	13,846	18,977	44,531	59,956
Depreciation and amortization	2,254	3,060	8,377	8,050
Operating Income (Loss) after Eliminations	1,449	23	(5,528)	7,267
Capital Expenditures and Plant Turnaround Costs	260	717	2,197	1,913
Total assets:
Total assets	121,462		121,462		$ 134,830
Operating segments
Segment Reporting Information [Line Items]
Total revenue	176,955	228,132	596,913	788,936
Operating segments | Terminalling and storage
Segment Reporting Information [Line Items]
Total revenue	60,943	68,473	183,014	207,794
Operating segments | Natural gas services
Segment Reporting Information [Line Items]
Total revenue	71,996	103,834	253,486	380,974
Operating segments | Sulfur services
Segment Reporting Information [Line Items]
Total revenue	29,096	36,303	113,559	137,814
Operating segments | Marine transportation
Segment Reporting Information [Line Items]
Total revenue	14,920	19,522	46,854	62,354
Intersegment Eliminations
Segment Reporting Information [Line Items]
Total revenue	(2,418)	(2,111)	(6,423)	(6,463)
Intersegment Eliminations | Terminalling and storage
Segment Reporting Information [Line Items]
Total revenue	(1,344)	(1,566)	(4,100)	(4,065)
Intersegment Eliminations | Natural gas services
Segment Reporting Information [Line Items]
Total revenue	0	0	0	0
Intersegment Eliminations | Sulfur services
Segment Reporting Information [Line Items]
Total revenue	0	0	0	0
Intersegment Eliminations | Marine transportation
Segment Reporting Information [Line Items]
Total revenue	(1,074)	(545)	(2,323)	(2,398)
Indirect selling, general, and administrative
Segment Reporting Information [Line Items]
Depreciation and amortization	0	0	0	0
Operating Income (Loss) after Eliminations	(4,206)	(4,948)	(12,676)	(14,258)
Capital Expenditures and Plant Turnaround Costs	$ 0	$ 0	$ 0	$ 0

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Unit Based Awards - Schedule of Compensation Costs (Details) - Selling, General and Administrative Expenses - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total unit-based compensation expense	$ 226	$ 330	$ 712	$ 1,080
Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total unit-based compensation expense	204	333	614	985
Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total unit-based compensation expense	$ 22	$ (3)	$ 98	$ 95

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Unit Based Awards - Narrative (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2016 USD ($) plan_component shares	Sep. 30, 2015 USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of plan components (in plan components) | plan_component	2
Number of shares authorized (in shares)	725,000
General partner capital contributions | $		$ 55
General partner interest percentage	2.00%	2.00%
Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized (in shares)	241,667
Unrecognized compensation cost related to non-vested restricted units | $	$ 1,358
Weighted average period for recognition (in years)	1 year 8 months 4 days
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

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Unit Based Awards - Restricted Unit Activity (Details) - Restricted Units $ / shares in Units, $ in Thousands	9 Months Ended
	Sep. 30, 2016 USD ($) $ / shares shares
Number of Units
Non-vested, beginning of period, Number of Units (in shares) | shares	150,474
Granted, Number of Units (in shares) | shares	13,800
Vested, Number of Units (in shares) | shares	(55,474)
Forfeited, Number of Units (in shares) | shares	(500)
Non-vested, end of period, Number of Units (in shares) | shares	108,300
Weighted Average Grant-Date Fair Value Per Unit
Non-vested, beginning of period, Weighted Average Grant-Date Fair Value Per Unit (USD per share) | $ / shares	$ 28.98
Granted, Weighted Average Grant-Date Fair Value Per Unit (USD per share) | $ / shares	15.13
Vested, Weighted Average Grant-Date Fair Value Per Unit (USD per share) | $ / shares	30.57
Forfeited, Weighted Average Grant-Date Fair Value Per Unit (USD per share) | $ / shares	28.50
Non-vested, end of period, Weighted Average Grant-Date Fair Value Per Unit (USD per share) | $ / shares	$ 27.03
Aggregate intrinsic value, end of period | $	$ 2,170

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Unit Based Awards - Intrinsic and Fair Value (Details) - Restricted Units - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate intrinsic value of units vested	$ 0	$ 0	$ 1,183	$ 110
Fair value of units vested	$ 0	$ 0	$ 1,685	$ 113

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Commitments and Contingencies (Details)			3 Months Ended		9 Months Ended
	Dec. 31, 2015 lawsuit	Oct. 02, 2012 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)
Martin Resource Management
Loss Contingencies [Line Items]
Quarterly purchase price reimbursement for non compliance		$ 750,000	$ 1,125,000	$ 750,000	$ 3,000,000	$ 1,500,000
Maximum purchase price reimbursement for non compliance					$ 4,500,000
Lubricants Packaging Business for Defense and Indemnity
Loss Contingencies [Line Items]
Number of lawsuits filed (in lawsuits) | lawsuit	5

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Impairment and other charges (Details)	3 Months Ended			9 Months Ended
	Sep. 30, 2016 USD ($) barge push_boat	Jun. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)	Aug. 31, 2015
Goodwill [Line Items]
Loss on impairment of goodwill	$ 0		$ 0	$ 4,145,000	$ 0
Marine transportation
Goodwill [Line Items]
Loss on impairment of goodwill		$ 4,145,000	$ 0		$ 0
Reporting unit, percentage of fair value in excess of carrying amount						41.00%
Number of Inland Tank Barges Disposed Of | barge	8
Number of Inland Push Boats Disposed Of | push_boat	2
Gain (loss) on disposition of assets	$ 1,567,000

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Subsequent Events (Details) - Subsequent Event - USD ($)	Oct. 20, 2016	Oct. 14, 2016
Subsequent Event [Line Items]
Dividends declared (USD per share)	$ 0.50
Estimated annualized dividends (USD per share)	$ 2.00
Disposal Group, Held-for-sale, Not Discontinued Operations | CCCT Assets
Subsequent Event [Line Items]
Gross consideration		$ 107,000
Net proceeds		$ 93,000