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 March 31, 2018

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, a smaller reporting company, or an emerging growth company. See definition of "large accelerated filer," "accelerated filer", "smaller reporting company", and "emerging growth company" in Rule 12b-2 of the Exchange Act.

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  

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 April 25, 2018, was 39,052,237.

	Page
PART I – FINANCIAL INFORMATION	2
Item 1. Financial Statements	2
Consolidated and Condensed Balance Sheets as of March 31, 2018 (unaudited) and December 31, 2017 (audited)	2
Consolidated and Condensed Statements of Operations for the Three Months Ended March 31, 2018 and 2017 (unaudited)	3
Consolidated and Condensed Statements of Capital for the Three Months Ended March 31, 2018 and 2017 (unaudited)	5
Consolidated and Condensed Statements of Cash Flows for the Three Months Ended March 31, 2018 and 2017 (unaudited)	6
Notes to Consolidated and Condensed Financial Statements	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 3. Quantitative and Qualitative Disclosures About Market Risk	44
Item 4. Controls and Procedures	45
PART II. OTHER INFORMATION	46
Item 1. Legal Proceedings	46
Item 1A. Risk Factors	46
Item 6. Exhibits	46

1

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED BALANCE SHEETS

(Dollars in thousands)

	March 31, 2018			December 31, 2017
	(Unaudited)			(Audited)
Assets
Cash	$	184		$	27
Accounts and other receivables, less allowance for doubtful accounts of $419 and $314, respectively	84,554			107,242
Product exchange receivables	75			29
Inventories (Note 6)	73,894			97,252
Due from affiliates	25,866			23,668
Fair value of derivatives (Note 10)	82			—
Other current assets	6,004			4,866
Assets held for sale (Note 4)	9,442			9,579
Total current assets	200,101			242,663
Property, plant and equipment, at cost	1,265,516			1,253,065
Accumulated depreciation	(432,275		)	(421,137		)
Property, plant and equipment, net	833,241			831,928
Goodwill	17,296			17,296
Investment in WTLPG (Note 7)	130,644			128,810
Other assets, net (Note 9)	29,779			32,801
Total assets	$	1,211,061		$	1,253,498
Liabilities and Partners’ Capital
Trade and other accounts payable	$	86,751		$	92,567
Product exchange payables	10,200			11,751
Due to affiliates	1,084			3,168
Income taxes payable	659			510
Fair value of derivatives (Note 10)	—			72
Other accrued liabilities (Note 9)	15,234			26,340
Total current liabilities	113,928			134,408
Long-term debt, net (Note 8)	795,139			812,632
Other long-term obligations	10,808			8,217
Total liabilities	919,875			955,257
Commitments and contingencies (Note 15)
Partners’ capital (Note 11)	291,186			298,241
Total partners’ capital	291,186			298,241
Total liabilities and partners' capital	$	1,211,061		$	1,253,498

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
	March 31,
	2018			2017
Revenues:
Terminalling and storage  *	$	24,064		$	24,658
Marine transportation  *	11,454			12,821
Natural gas services*	15,356			14,665
Sulfur services	2,787			2,850
Product sales: *
Natural gas services	159,163			126,657
Sulfur services	34,900			39,527
Terminalling and storage	36,480			32,147
	230,543			198,331
Total revenues	284,204			253,325
Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services *	142,957			108,179
Sulfur services *	23,896			24,483
Terminalling and storage *	31,413			26,446
	198,266			159,108
Expenses:
Operating expenses  *	33,001			35,057
Selling, general and administrative  *	9,668			9,921
Depreciation and amortization	19,210			25,336
Total costs and expenses	260,145			229,422
Other operating loss	(2		)	(155		)
Operating income	24,057			23,748
Other income (expense):
Equity in earnings of WTLPG	1,595			905
Interest expense, net	(12,685		)	(10,920		)
Other, net	—			30
Total other expense	(11,090		)	(9,985		)
Net income before taxes	12,967			13,763
Income tax expense	(149		)	(180		)
Net income	12,818			13,583
Less general partner's interest in net income	(256		)	(272		)
Less income allocable to unvested restricted units	(8		)	(35		)
Limited partners' interest in net income	$	12,554		$	13,276
Net income per unit attributable to limited partners - basic	$	0.33		$	0.36
Net income per unit attributable to limited partners - diluted	$	0.32		$	0.36
Weighted average limited partner units - basic	38,621			37,321
Weighted average limited partner units - diluted	38,630			37,367

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
	March 31,
	2018		2017
Revenues:*
Terminalling and storage	$	20,025	$	19,704
Marine transportation	3,613		4,325
Natural gas services	—		112
Product Sales	642		1,430
Costs and expenses:*
Cost of products sold: (excluding depreciation and amortization)
Natural gas services	4,318		8,894
Sulfur services	4,526		3,675
Terminalling and storage	6,558		5,067
Expenses:
Operating expenses	13,384		16,376
Selling, general and administrative	7,721		7,568

See accompanying notes to consolidated and condensed financial statements.

4

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, 2017	35,452,062		$	304,594		$	7,412		$	312,006
Net income	—		13,311			272			13,583
Issuance of common units, net	2,990,000		51,188			—			51,188
Issuance of restricted units	12,000		—			—			—
Forfeiture of restricted units	(1,500	)	—			—			—
General partner contribution	—		—			1,098			1,098
Cash distributions	—		(17,725		)	(362		)	(18,087		)
Unit-based compensation	—		186			—			186
Excess purchase price over carrying value of acquired assets	—		(7,887		)	—			(7,887		)
Reimbursement of excess purchase price over carrying value of acquired assets	—		1,125			—			1,125
Balances - March 31, 2017	38,452,562		$	344,792		$	8,420		$	353,212
Balances - January 1, 2018	38,444,612		$	290,927		$	7,314		$	298,241
Net income	—		12,562			256			12,818
Issuance of common units, net of issuance related costs	—		(101		)	—			(101		)
Issuance of restricted units	633,425		—			—			—
Forfeiture of restricted units	(7,000	)	—			—			—
Cash distributions	—		(19,213		)	(392		)	(19,605		)
Unit-based compensation	—		132			—			132
Excess purchase price over carrying value of acquired assets	—		(26		)	—			(26		)
Purchase of treasury units	(18,800	)	(273		)	—			(273		)
Balances - March 31, 2018	39,052,237		$	284,008		$	7,178		$	291,186

See accompanying notes to consolidated and condensed financial statements.

5

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED AND CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

(Dollars in thousands)

	Three Months Ended
	March 31,
	2018			2017
Cash flows from operating activities:
Net income	$	12,818		$	13,583
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	19,210			25,336
Amortization of deferred debt issuance costs	819			721
Amortization of premium on notes payable	(77		)	(77		)
Loss on sale of property, plant and equipment	2			155
Equity in earnings of WTLPG	(1,595		)	(905		)
Derivative (income) loss	(2,470		)	2,495
Net cash received (paid) for commodity derivatives	2,316			(6,332		)
Unit-based compensation	132			186
Cash distributions from WTLPG	1,500			1,200
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables	22,693			19,110
Product exchange receivables	(46		)	(90		)
Inventories	23,306			20,580
Due from affiliates	(2,203		)	(477		)
Other current assets	(1,232		)	(491		)
Trade and other accounts payable	(3,621		)	(2,560		)
Product exchange payables	(1,551		)	(100		)
Due to affiliates	(2,084		)	(5,186		)
Income taxes payable	149			180
Other accrued liabilities	(13,310		)	(11,083		)
Change in other non-current assets and liabilities	634			281
Net cash provided by operating activities	55,390			56,526
Cash flows from investing activities:
Payments for property, plant and equipment	(15,165		)	(6,477		)
Acquisitions	—			(19,533		)
Payments for plant turnaround costs	—			(1,394		)
Proceeds from sale of property, plant and equipment	(88		)	1,481
Contributions to WTLPG	(1,739		)	—
Net cash used in investing activities	(16,992		)	(25,923		)
Cash flows from financing activities:
Payments of long-term debt	(101,000		)	(133,000		)
Proceeds from long-term debt	84,000			75,000
Proceeds from issuance of common units, net of issuance related costs	(101		)	51,188
General partner contribution	—			1,098
Purchase of treasury units	(273		)	—
Payment of debt issuance costs	(1,236		)	(16		)
Excess purchase price over carrying value of acquired assets	(26		)	(7,887		)
Reimbursement of excess purchase price over carrying value of acquired assets	—			1,125
Cash distributions paid	(19,605		)	(18,087		)
Net cash used in financing activities	(38,241		)	(30,579		)
Net increase in cash	157			24
Cash at beginning of period	27			15
Cash at end of period	$	184		$	39
Non-cash additions to property, plant and equipment	$	1,905		$	3,262

See accompanying notes to consolidated and condensed financial statements.

6

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2018

(Unaudited)

NOTE 1. NATURE OF OPERATIONS AND BASIS OF PRESENTATION

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 U.S. 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, 2017, filed with the Securities and Exchange Commission (the "SEC") on February 16, 2018, as amended by Amendment No. 1 on Form 10-K/A for the year ended December 31, 2017 filed on March 29, 2018.

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.

NOTE 2. NEW ACCOUNTING PRONOUNCEMENTS

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 replaced most existing revenue recognition guidance in U.S. GAAP. 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 adopted the new standard utilizing the cumulative effect method which will result in the cumulative effect of the adoption being recorded as of January 1, 2018. The Partnership adopted ASU 2014-09 on January 1, 2018 and did not identify any significant changes in the timing of revenue recognition when considering the amended accounting guidance. Additional disclosures related to revenue recognition appear "Note 5. Revenue."

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.

7

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2018

(Unaudited)

NOTE 3. ACQUISITIONS

Acquisition of Terminalling Assets.    On February 22, 2017, the Partnership acquired 100% of the membership interests of MEH South Texas Terminals LLC ("MEH"), a subsidiary of Martin Resource Management, for a purchase price of $27,420 (the "Hondo Acquisition"), which was funded with borrowings under the Partnership's revolving credit facility. At the date of acquisition, MEH was in the process of constructing an asphalt terminal facility in Hondo, Texas (the "Hondo Terminal"), to serve the asphalt market in San Antonio, Texas and surrounding areas. This acquisition is considered a transfer of net assets between entities under common control. The acquisition of these assets was recorded at the historical carrying value of the assets at the acquisition date. The excess of the purchase price over the carrying value of the assets of $7,887 was recorded as an adjustment to "Partners' capital" during the three months ended March 31, 2017. During 2018, the Partnership paid an additional $26 related to a purchase price true-up, which was recorded as a further adjustment to "Partners' capital" for the three months ended March 31, 2018.

Original purchase price	$	27,420
Purchase price true-up	26
Historical carrying value of assets allocated to "Property, plant and equipment"	19,533
Excess purchase price over carrying value of acquired assets	$	7,913

As no individual line item of the historical financial statements of the acquired assets was in excess of 3% of the Partnership's relative consolidated financial statement captions, the Partnership elected not to retrospectively recast the historical financial information to include these assets.

NOTE 4. DIVESTITURES, ASSET IMPAIRMENTS, AND DISCONTINUED OPERATIONS

Long-Lived Assets Held for Sale

At March 31, 2018 and December 31, 2017, certain terminalling and storage and marine transportation assets met the criteria to be classified as held for sale in accordance with ASC 360-10 and are presented at the lower of the assets' carrying amount or fair value less cost to sell by segment in current assets as follows:

	March 31, 2018		December 31, 2017
Terminalling and storage	$	4,242	$	4,152
Marine transportation	5,200		5,427
Assets held for sale	$	9,442	$	9,579

These assets are considered non-core assets to the Partnership's operations and did not qualify for discontinued operations presentation under the guidance of ASC 205-20.

8

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2018

(Unaudited)

NOTE 5. REVENUE

The following table disaggregates our revenue by major source:

	Three Months Ended March 31,
	2018		2017
Terminalling and storage segment
Lubricant product sales	$	36,480	$	32,147
Throughput and storage	24,064		24,658
	$	60,544	$	56,805
Natural gas services segment
Natural gas liquids product sales	$	159,163	$	126,657
Natural gas storage	15,356		14,665
	$	174,519	$	141,322
Sulfur service segment
Sulfur product sales	$	11,837	$	13,080
Fertilizer product sales	23,063		26,447
Sulfur services	2,787		2,850
	$	37,687	$	42,377
Marine transportation segment
Inland transportation	$	9,692	$	11,291
Offshore transportation	1,762		1,530
	$	11,454	$	12,821

Revenue is measured based on a consideration specified in a contract with a customer and excludes amounts collected on behalf of third parties where the Partnership is acting as an agent. The Partnership recognizes revenue when the Partnership satisfies a performance obligation, which typically occurs when the Partnership transfers control over a product to a customer or as the Partnership delivers a service.

The following is a description of the principal activities - separated by reportable segments - from which the Partnership generates revenue.

Terminalling and Storage Segment

Revenue is recognized for storage contracts based on the contracted monthly tank fixed fee.  For throughput contracts, revenue is recognized based on the volume moved through the Partnership’s terminals at the contracted rate.  For the Partnership’s tolling agreement, revenue is recognized based on the contracted monthly reservation fee and throughput volumes moved through the facility.  When lubricants and drilling fluids are sold by truck or rail, revenue is recognized when title is transfered, which is either upon delivering product to the customer or when the product leaves the Partnership's facility, depending on the specific terms of the contract. Delivery of product is invoiced as the transaction occurs and is generally paid within a month.

Natural Gas Services Segment

Natural Gas Liquids ("NGL") distribution revenue is recognized when product is delivered by truck, rail, or pipeline to the Partnership's NGL customers. Revenue is recognized on title transfer of the product to the customer. Delivery of product is invoiced as the transaction occurs and are generally paid within a month. Natural gas storage revenue is recognized when the service is provided to the customer. The performance of the service is invoiced as the transaction occurs and is generally paid within a month.

9

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2018

(Unaudited)

Sulfur Services Segment

Revenue from sulfur product sales is recognized when the customer takes title to the product.  Delivery of product is invoiced as the transaction occurs and are generally paid within a month. Revenue from sulfur services is recognized as services are performed during each monthly period. The performance of the service is invoiced as the transaction occurs and is generally paid within a month.

Marine Transportation Segment

Revenue is recognized for time charters based on a per day rate. For contracted trips, revenue is recognized upon completion of the particular trip. The performance of the service is invoiced as the transaction occurs and is generally paid within a month.

The table includes estimated revenue expected to be recognized in the future related to performance obligations that are unsatisfied at the end of the reporting period. The Partnership applies the practical expedient in ASC 606-10-50-14(a) and does not disclose information about remaining performance obligations that have original expected durations of one year or less.

	2018		2019		2020		2021		2022		Thereafter		Total
Terminalling and storage
Storage and throughput	$	37,571	$	50,629	$	49,330	$	46,022	$	41,505	$	393,700	$	618,757
Natural gas services
Natural gas storage	$	31,309	$	32,932	$	27,011	$	25,134	$	24,615	$	12,068	$	153,069
Sulfur services
Sulfur product sales	$	12,597	$	16,796	$	4,898	$	1,181	$	295	$	—	$	35,767
Marine transportation
Offshore transportation	$	4,675	$	6,205	$	6,069	$	—	$	—	$	—	$	16,949
Total	$	86,152	$	106,562	$	87,308	$	72,337	$	66,415	$	405,768	$	824,542

NOTE 6. INVENTORIES

Components of inventories at March 31, 2018 and December 31, 2017 were as follows: 

	March 31, 2018		December 31, 2017
Natural gas liquids	$	18,922	$	47,462
Sulfur	11,299		8,436
Sulfur based products	19,107		18,674
Lubricants	21,874		20,086
Other	2,692		2,594
	$	73,894	$	97,252

NOTE 7. INVESTMENT IN WEST TEXAS LPG PIPELINE L.P.

The Partnership owns a 19.8% limited partnership and 0.2% general partnership interest in West Texas LPG Pipeline L.P. ("WTLPG"). A wholly-owned subsidiary of ONEOK, Inc. is the operator of the assets. WTLPG owns an approximate 2,300 mile common-carrier pipeline system that primarily 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)

March 31, 2018

(Unaudited)

Selected financial information for WTLPG is as follows:

	As of March 31,						Three Months Ended March 31,
	Total Assets		Long-Term Debt		Members' Equity		Revenues		Net Income
2018
WTLPG	$	870,691	$	—	$	839,028	$	23,041	$	7,706
	As of December 31,
2017
WTLPG	$	837,163	$	—	$	787,426	$	19,719	$	4,525

NOTE 8. LONG-TERM DEBT

At March 31, 2018 and December 31, 2017, long-term debt consisted of the following:

	March 31, 2018		December 31, 2017
$664,444 Revolving credit facility at variable interest rate (4.86%1 weighted average at March 31, 2018), 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 $5,573 and $4,986, respectively2,3	$	422,427	$	440,014
$400,000 Senior notes, 7.25% interest, net of unamortized debt issuance costs of $1,967 and $2,138, respectively, including unamortized premium of $879 and $956, respectively, issued $250,000 February 2013 and $150,000 April 2014, $26,200 repurchased during 2015, due February 2021, unsecured3,4	372,712		372,618
Total long-term debt, net	$	795,139	$	812,632

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 March 31, 2018 and December 31, 2017 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 March 31, 2018 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 On February 21, 2018, the Partnership amended its revolving credit facility to, among other things, (i) create an inventory financing sublimit tranche, which is a part of and not in addition to the already existing commitments under the revolving credit facility, under which availability is subject to a borrowing base calculated by reference to eligible petroleum products inventory, (ii) exclude the amount of loans under the inventory financing sublimit tranche from total outstanding indebtedness for purposes of determining leverage ratio covenants under the revolving credit facility, (iii) increase the maximum permitted leverage ratio (as defined in the credit agreement, being generally computed as the ratio of total funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) from 5.25 to 1.00, with a temporary springing provision to 5.50 to 1.00 under certain scenarios, to 5.75 to 1.00 for the first and second quarters of 2018, 5.50 to 1.00 for the next three quarters and 5.25 to 1.00, with the temporary springing provision to 5.50 to 1.00 going back into effect, thereafter and (iv) decrease the maximum permitted senior leverage ratio (as defined in the credit agreement, being generally computed as the ratio of total secured funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) from 3.50 to 1.00 to 3.25 to 1.00. The maximum amount of the inventory financing sublimit tranche is $10,000 during the period between March 1 and June 30 of each year, and $75,000 at all

11

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2018

(Unaudited)

other times during each year.

³ The Partnership is in compliance with all debt covenants as of March 31, 2018 and December 31, 2017, respectively.

⁴ The 2021 indenture restricts the Partnership’s ability to sell assets; pay distributions or repurchase units or redeem or repurchase subordinated debt; make investments; incur or guarantee additional indebtedness or issue preferred units; and consolidate, merge or transfer all or substantially all of its assets.

The Partnership paid cash interest, net of capitalized interest, in the amount of $18,878 and $18,181 for the three months ended March 31, 2018 and 2017, respectively. Capitalized interest was $161 and $223 for the three months ended March 31, 2018 and 2017, respectively.

NOTE 9. SUPPLEMENTAL BALANCE SHEET INFORMATION

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

	March 31, 2018		December 31, 2017
Customer contracts and relationships, net	$	23,484	$	25,252
Other intangible assets	1,624		1,752
Other	4,671		5,797
	$	29,779	$	32,801

Accumulated amortization of intangible assets was $41,984 and $39,462 at March 31, 2018 and December 31, 2017, respectively.

Components of "Other accrued liabilities" were as follows:

	March 31, 2018		December 31, 2017
Accrued interest	$	4,952	$	11,726
Asset retirement obligations	3,360		5,429
Property and other taxes payable	3,279		5,638
Accrued payroll	3,636		3,385
Other	7		162
	$	15,234	$	26,340

12

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2018

(Unaudited)

The schedule below summarizes the changes in our asset retirement obligations:

	March 31, 2018
Beginning asset retirement obligations	$	13,512
Revisions to existing liabilities1	4,756
Accretion expense	147
Liabilities settled	(4,360		)
Ending asset retirement obligations	14,055
Current portion of asset retirement obligations2	(3,360		)
Long-term portion of asset retirement obligations3	$	10,695

¹Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, discount rates, and the estimated remaining useful life of the assets. The 2018 revisions reflect changes in removal cost estimates and the estimated remaining useful life of assets. 

²The current portion of asset retirement obligations is included in "Other current liabilities" on the Partnership's Consolidated and Condensed Balance Sheets.

³The non-current portion of asset retirement obligations is included in "Other long-term obligations" on the Partnership's Consolidated and Condensed Balance Sheets.

NOTE 10. 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 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. 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 March 31, 2018 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 gross notional quantity of 50 barrels settling during the period from May 1, 2018 through June 30, 2018. At December 31, 2017, the Partnership had instruments totaling a gross notional quantity of 145 barrels settling during the period from January 31, 2018 through February 28, 2018. These instruments settle against the applicable pricing source for each grade and location.

(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. From time to time, the Partnership enters into interest rate swaps to manage interest rate risk associated with the Partnership’s variable rate credit

13

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2018

(Unaudited)

facility and its fixed rate senior unsecured notes. At March 31, 2018 and 2017, the Partnership did not have any outstanding interest rate derivative instruments.

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 and Condensed Balance Sheets
	Derivative Assets					Derivative Liabilities
		Fair Values					Fair Values
	Balance Sheet Location	March 31, 2018		December 31, 2017		Balance Sheet Location	March 31, 2018		December 31, 2017
Derivatives not designated as hedging instruments:	Current:
Commodity contracts	Fair value of derivatives	$	82	$	—	Fair value of derivatives	$	—	$	72
Total derivatives not designated as hedging instruments		$	82	$	—		$	—	$	72

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

For the Three Months Ended March 31, 2018 and 2017

	Location of Gain (Loss) Recognized in Income on  Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives
		2018		2017
Derivatives not designated as hedging instruments:
Commodity contracts	Cost of products sold	$	2,470	$	(2,495	)
Total effect of derivatives not designated as hedging instruments		$	2,470	$	(2,495	)

NOTE 11. PARTNERS' CAPITAL

As of March 31, 2018, Partners’ capital consisted of 39,052,237 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 16.0% 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.

Issuance of Common Units

On February 22, 2017, the Partnership completed a public offering of 2,990,000 common units at a price of $18.00 per common unit, before the payment of underwriters' discounts, commissions and offering expenses (per unit value is in dollars,

14

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2018

(Unaudited)

not thousands). Total proceeds from the sale of the 2,990,000 common units, net of underwriters' discounts, commissions and offering expenses, were $51,188. Additionally, the Partnership's general partner contributed $1,098 in cash to the Partnership in conjunction with the issuance in order to maintain its 2.0% general partner interest in the Partnership. All of the net proceeds were used to pay down outstanding amounts under the Partnership's revolving credit facility.

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 no incentive distributions during the three months ended March 31, 2018 and 2017.

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:

15

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2018

(Unaudited)

	Three Months Ended March 31,
	2018			2017
Net income	$	12,818		$	13,583
Less general partner’s interest in net income (loss):
Distributions payable on behalf of IDRs	—			—
Distributions payable on behalf of general partner interest	392			392
General partner interest in undistributed loss	(136		)	(120		)
Less income allocable to unvested restricted units	8			35
Limited partners’ interest in net income (loss)	$	12,554		$	13,276

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 March 31,
	2018	2017
Basic weighted average limited partner units outstanding	38,621,375	37,321,263
Dilutive effect of restricted units issued	8,252	46,121
Total weighted average limited partner diluted units outstanding	38,629,627	37,367,384

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.

NOTE 12. 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 March 31,
	2018		2017
Employees	$	96	$	159
Non-employee directors	36		27
Total unit-based compensation expense	$	132	$	186

All of the Partnership's outstanding awards at March 31, 2018 met the criteria to be treated under equity classification.

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.

On May 26, 2017, the unitholders of the Partnership approved the Martin Midstream Partners L.P. 2017 Restricted Unit Plan (the "2017 LTIP"). The plan currently permits the grant of awards covering an aggregate of 3,000,000 common units, all of which can be awarded in the form of restricted units. The plan is administered by the compensation committee of the general partner’s board of directors (the "Compensation Committee").

16

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2018

(Unaudited)

 A restricted unit is a unit that is granted to grantees with certain vesting restrictions, which may be time-based and/or performance-based. Once these restrictions lapse, the grantee is entitled to full ownership of the unit without restrictions. The Compensation Committee may determine to make grants under the plan containing such terms as the Compensation Committee shall determine under the plan. With respect to time-based restricted units ("TBRU's", the Compensation Committee will determine the time period over which restricted units granted to employees and directors will vest. The Compensation Committee may also award a percentage of restricted units with vesting requirements based upon the achievement of specified pre-established performance targets ("Performance Based Restricted Units" or "PBRU's"). The performance targets may include, but are not limited to, the following: revenue and income measures, cash flow measures, net income before interest expense and income tax expense ("EBIT"), net income before interest expense, income tax expense, and depreciation and amortization ("EBITDA"), distribution coverage metrics, expense measures, liquidity measures, market measures, corporate sustainability metrics, and other measures related to acquisitions, dispositions, operational objectives and succession planning objectives. PBRU's are earned only upon our achievement of an objective performance measure for the performance period. PBRU's which vest are payable in common units.  Unvested units granted under the 2017 LTIP may or may not participate in cash distributions depending on the terms of each individual award agreement.

The restricted units issued to directors generally vest in equal annual installments over a four-year period. Restricted units issued to employees generally vest in equal annual installments over three years of service.

On February 20, 2018, the Partnership issued 4,650 TBRU's to each of the Partnership's three independent directors under the 2017 LTIP.  These restricted common units vest in equal installments of 1,550 units on January 24, 2019, 2020, 2021, and 2022.

On March 1, 2018, the Partnership issued 301,550 TBRU's and 317,925 PBRU's to certain employees of Martin Resource Management. The TBRU's vest in equal installments over a three-year service period. The PBRU's will vest at the conclusion of a three-performance period based on certain performance targets. In addition, the PBRU's awarded on March 1, 2018 that are achieved will only vest if the grantee is employed by Martin Resource Management on March 31, 2021.

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 three months ended March 31, 2018 is provided below:

	Number of Units			Weighted Average Grant-Date Fair Value Per Unit
Non-vested, beginning of period	98,750			$	24.80
Granted (TBRU)	315,500			$	13.89
Granted (PBRU)	317,925			$	13.89
Vested	(80,550		)	$	27.71
Forfeited	(7,000		)	$	13.90
Non-Vested, end of period	644,625			$	13.91
Aggregate intrinsic value, end of period	$	8,702

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 three months ended March 31, 2018 and 2017 is provided below:

	Three Months Ended March 31,
	2018		2017
Aggregate intrinsic value of units vested	$	1,188	$	125
Fair value of units vested	2,232		170

17

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2018

(Unaudited)

As of March 31, 2018, there was $4,431 of unrecognized compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 3.01 years.

NOTE 13. RELATED PARTY TRANSACTIONS

As of March 31, 2018, Martin Resource Management owns 6,264,532 of the Partnership’s common units representing approximately 16.0% 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 March 31, 2018, of approximately 16.0% 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, marine fuel and other liquids;

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

◦ operating a crude oil gathering business in Stephens, Arkansas;

18

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2018

(Unaudited)

◦ 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; and

◦ operating, solely for the Partnership's account, the asphalt facilities in Omaha, Nebraska, Port Neches, Texas, Hondo, 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, 2018, through December 31, 2018, the Conflicts Committee approved an annual reimbursement amount for indirect expenses of $16,416.  The Partnership reimbursed Martin Resource Management for $4,104 and $4,104 of indirect expenses for the three months ended March 31, 2018 and 2017, 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.

19

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2018

(Unaudited)

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.

20

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2018

(Unaudited)

Terminal Services Agreements

Diesel Fuel Terminal Services Agreement.  Effective January 1, 2016, the Partnership entered into a second amended and restated terminalling services agreement under which the Partnership provides terminal services to Martin Resource Management for marine fuel distribution.  At such time, the per gallon throughput fee the Partnership charged under this agreement was increased when compared to the previous agreement and may be adjusted annually based on a price index.  This agreement was further amended on January 1, 2017 and October 1, 2017 to modify its minimum throughput requirements and throughput fees. This agreement, as amended, continues until September 30, 2018 and thereafter on a month to month basis until terminated by either party by giving 60 days’ written notice.  

Miscellaneous Terminal Services Agreements.  The Partnership is currently party to several terminal services agreements and from time to time the Partnership may enter into other terminal service agreements for the purpose of providing terminal services to related parties. Individually, each of these agreements is immaterial but when considered in the aggregate they could be deemed material. These agreements are throughput based with a minimum volume commitment. Generally, the fees due under these agreements are adjusted annually based on a price index.

Other Agreements

 Cross Tolling Agreement. The Partnership is a party to an amended and restated tolling agreement with Cross Oil Refining and Marketing, Inc. ("Cross") dated October 28, 2014, under which the Partnership processes crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts for Cross.  The tolling agreement expires November 25, 2031.  Under this tolling agreement, Cross agreed to process a minimum of 6,500 barrels per day of crude oil at the facility at a fixed price per barrel.  Any additional barrels are processed at a modified price per barrel.  In addition, Cross agreed to pay a monthly reservation fee and a periodic fuel surcharge fee based on certain parameters specified in the tolling agreement.  All of these fees (other than the fuel surcharge) are subject to escalation annually based upon the greater of 3% or the increase in the Consumer Price Index for a specified annual period.  In addition, on the third, sixth and ninth anniversaries of the agreement, the parties can negotiate an upward or downward adjustment in the fees subject to their mutual agreement.

Sulfuric Acid Sales Agency Agreement. The Partnership is party to a third amended and restated sulfuric acid sales agency agreement dated August 2, 2017 but effective October 1, 2017, under which a successor in interest to the agreement from Martin Resource Management, Saconix LLC ("Saconix"), a limited liability company in which Martin Resource Management has a minority equity interest, 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 September 30, 2020 and shall automatically renew year to year thereafter until either party provides 90 days’ written notice of termination prior to the expiration of the then existing term.  Under this agreement, the Partnership sells all of its excess sulfuric acid to Saconix, who then markets and sells such acid to third-parties.  The Partnership shares in the profit of such sales.

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:

21

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2018

(Unaudited)

	Three Months Ended March 31,
	2018		2017
Revenues:
Terminalling and storage	$	20,025	$	19,704
Marine transportation	3,613		4,325
Natural gas services	—		112
Product sales:
Natural gas services	1		942
Sulfur services	386		431
Terminalling and storage	255		57
	642		1,430
	$	24,280	$	25,571

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

	Three Months Ended March 31,
	2018		2017
Cost of products sold:
Natural gas services	$	4,318	$	8,894
Sulfur services	4,526		3,675
Terminalling and storage	6,558		5,067
	$	15,402	$	17,636

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

	Three Months Ended March 31,
	2018		2017
Operating expenses:
Marine transportation	$	5,321	$	5,996
Natural gas services	2,199		2,235
Sulfur services	1,339		1,446
Terminalling and storage	4,525		6,699
	$	13,384	$	16,376

22

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2018

(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 March 31,
	2018		2017
Selling, general and administrative:
Marine transportation	$	8	$	8
Natural gas services	2,254		2,277
Sulfur services	659		636
Terminalling and storage	681		543
Indirect, including overhead allocation	4,119		4,104
	$	7,721	$	7,568

Other Related Party Transactions

The Partnership had a $15,000 note receivable from an affiliate of Martin Resource Management which previously bore an annual interest rate of 15% and had a maturity date of August 31, 2026, the balance of which could be prepaid on or after September 1, 2016. On February 14, 2017, the Partnership notified Martin Resource Management that it would be requesting voluntary repayment of the long-term Note Receivable plus accrued interest. During second quarter of 2017, the Note Receivable was fully repaid. The note has historically been recorded in "Note receivable - affiliates" on the Partnership's Consolidated and Condensed Balance Sheets. Interest income for the three months ended March 31, 2018 and 2017 was $0 and $555, respectively, and is included in "Interest expense, net" in the Consolidated and Condensed Statements of Operations.

NOTE 14. BUSINESS SEGMENTS

The Partnership has four reportable segments: natural gas services, terminalling and storage, 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, 2017, filed with the SEC on February 16, 2018, as amended, by Amendment No. 1 on Form 10-K/A filed on March 29, 2018. 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 March 31, 2018	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	$	61,983	$	(1,439	)	$	60,544	$	10,159	$	2,722		$	2,121
Natural gas services	174,519		—			174,519		5,301		17,411			1,009
Sulfur services	37,687		—			37,687		2,064		6,992			1,548
Marine transportation	12,028		(574		)	11,454		1,686		1,163			8,291
Indirect selling, general and administrative	—		—			—		—		(4,231		)	—
Total	$	286,217	$	(2,013	)	$	284,204	$	19,210	$	24,057		$	12,969

23

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2018

(Unaudited)

Three Months Ended March 31, 2017	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	$	58,578	$	(1,773	)	$	56,805	$	15,477	$	(2,101	)	$	7,463
Natural gas services	141,322		—			141,322		6,161		18,273			852
Sulfur services	42,377		—			42,377		2,033		10,767			305
Marine transportation	13,414		(593		)	12,821		1,665		1,229			694
Indirect selling, general and administrative	—		—			—		—		(4,420		)	—
Total	$	255,691	$	(2,366	)	$	253,325	$	25,336	$	23,748		$	9,314

The Partnership's assets by reportable segment as of March 31, 2018 and December 31, 2017, are as follows:

	March 31, 2018		December 31, 2017
Total assets:
Terminalling and storage	$	327,318	$	326,920
Natural gas services	647,193		704,524
Sulfur services	128,064		120,790
Marine transportation	108,486		101,264
Total assets	$	1,211,061	$	1,253,498

NOTE 15. COMMITTMENTS AND CONTINGENCIES

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 has reimbursed the Partnership $750 per quarter for four consecutive quarters as a reduction in the purchase price of the Redbird Class A interests.  These payments were the result of Cardinal Gas Storage Partners LLC ("Cardinal") not achieving certain financial targets set forth in the Purchase Price Reimbursement Agreement.  These payments were considered to be 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 were recorded as an adjustment to "Partners' capital" in each quarter in which the payments were made. The agreement further provided for purchase price reimbursements of up to $4,500 in 2016 in the event certain financial conditions were not met. For the three months ended March 31, 2017, the Partnership received $1,125, related to the Purchase Price Reimbursement Agreement. The amount received in the first quarter of 2017 represented the final payment under the Purchase Price Reimbursement Agreement.

Certain shippers filed complaints with the Railroad Commission of Texas ("RRC") challenging the increased rates WTLPG implemented effective July 1, 2015.  The complainants requested 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."  A hearing on the merits was held in front of a hearings examiner during the week of March 27, 2017.  The hearings examiner issued a Proposal for Decision on September 29, 2017. On December 5, 2017, this matter was brought before the RRC. After brief discussion, the RRC determined that more time was needed to review the proposal for decision and placed the matter on the agenda for the RRC’s January 23, 2018 meeting. At that meeting, the RRC voted to remand the case to the hearings examiner for the limited

24

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2018

(Unaudited)

purpose of admitting and considering additional relevant evidence on competition. The hearings examiner has scheduled the remand hearing for September 26-28, 2018.  

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 alleged that the Partnership breached a lease agreement by failing to perform work to the plaintiff's property as required under the lease agreement.  The plaintiff originally sought to evict the Partnership from the leased property and to recover damages.  Prior to trial, this matter was settled for a confidential amount in September of 2017. The Partnership's financial statements reflect the terms of the settlement and all amounts have been accrued as asset retirement obligations.

On December 31, 2015, the Partnership received a demand from a customer in its lubricants packaging business for defense and indemnity in connection with lawsuits filed against it in various 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.  The lawsuits against the customer have been transferred to the United States District Court for the Western District of Missouri for consolidated pretrial proceedings.  On March 1, 2017, at the request of the parties, the Chancery Court of Davidson County, Tennessee administratively closed the Partnership's lawsuit pending rulings in the United States District Court for the Western District of Missouri.  In the event that either party moves the Chancery Court of Davidson County, Tennessee to reopen the case, we expect the Court would grant such motion and reopen the case.  If the case is reopened, we are currently unable to determine the exposure we may have in this matter, if any.

Commitments

The Partnership has non-cancelable revenue arrangements that are not under the scope of ASC 606 whereby we have committed certain terminalling and storage assets in exchange for a minimum fee. Future minimum revenues the Partnership expects to receive under these non-cancelable arrangements as of March 31, 2018, are as follows: 2018 - $16,672; 2019 - $19,199; 2020 - $17,478; 2021 - $15,589; 2022 - $15,589; subsequent years - $72,872.

NOTE 16. 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
	March 31, 2018		December 31, 2017
Commodity derivative contracts, net	$	82	$	(72	)

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:

25

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED AND CONDENSED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

March 31, 2018

(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: 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 considered Level 1, as the fair value is based on quoted market prices in active markets.

	March 31, 2018				December 31, 2017
	Carrying Value		Fair Value		Carrying Value		Fair Value
2021 Senior unsecured notes	$	372,712	$	377,071	$	372,618	$	381,657

NOTE 17. CONDENSED CONSOLIDATED 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.

NOTE 18. SUBSEQUENT EVENTS

Quarterly Distribution. On April 19, 2018, the Partnership declared a quarterly cash distribution of $0.50 per common unit for the first quarter of 2018, or $2.00 per common unit on an annualized basis, which will be paid on May 15, 2018 to unitholders of record as of May 8, 2018.

26

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, 2017, filed with the Securities and Exchange Commission (the "SEC") on February 16, 2018, as amended, by Amendment No. 1 on Form 10-K/A for the year ended December 31, 2017 filed on March 29, 2018, 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:

• Natural gas 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 and the blending and packaging of finished lubricants;

• 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 March 31, 2018, Martin Resource Management owned 16.0% of our total outstanding common limited partner units. Furthermore, Martin Resource Management

27

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.

Significant Recent Developments

Credit Facility Amendment. On February 21, 2018, we amended our revolving credit facility in order to achieve two primary objectives, the first of which was to accommodate growth capital expenditures necessary for the previously announced WTLPG expansion project which is discussed in further detail below. Starting in the first quarter of 2018, the amendment will provide short-term (5 quarters) covenant relief by increasing the total leverage ratio to 5.75 to 1.00 (first and second quarters of 2018) with step downs to 5.50 to 1.00 (third and fourth quarters of 2018 and first quarter of 2019) and to 5.25 to 1.00 beginning in the second quarter of 2019. Additionally, the facility was amended to establish an inventory financing sublimit tranche for borrowings related to our NGL (butane) marketing business, which is a part of and not in addition to the already existing commitments under the revolving credit facility. This sublimit is not to exceed $75.0 million, with seasonal step downs to $10.0 million for the months of March through June of each fiscal year. The sublimit is subject to a monthly borrowing base not to exceed 90% of the value of forward sold/hedged inventory.

West Texas LPG Pipeline Limited Partnership Expansion. On October 23, 2017, we announced that the West Texas LPG Pipeline Limited Partnership ("WTLPG") joint venture (of which we own a 20% interest with ONEOK, Inc. owning and operating the other 80% interest) plans to invest approximately $200.0 million to expand its Natural Gas Liquids ("NGL") system into the prolific Delaware Basin, part of the larger Permian Basin and is expected to be in service by the third quarter of 2018. This project is supported by dedicated NGL production from two third-party planned natural gas processing plants in northern Reeves County, one of the most active areas in the Delaware Basin. The expansion will be supported by long-term volume dedications estimated to be up to 40,000 barrels per day. The Delaware Basin extension includes the construction of an approximately 120-mile, 16-inch pipeline lateral that will have an initial capacity of 110,000 bpd and the construction of two new pump stations and pipeline looping along the existing West Texas LPG system that will increase its capacity to handle the dedicated volume.

Subsequent Events

Quarterly Distribution. On April 19, 2018, we declared a quarterly cash distribution of $0.50 per common unit for the first quarter of 2018, or $2.00 per common unit on an annualized basis, which will be paid on May 15, 2018 to unitholders of record as of May 8, 2018.

28

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, 2017. The following table evaluates the potential impact of estimates utilized during the periods ended March 31, 2018 and 2017:

Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
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 months ended March 31, 2018 or 2017.
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. During the three months ended March 31, 2018, we made upward revisions to our asset retirement obligations in the amount of $4.8 million.

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, marine fuel and other liquids;

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

• operating a crude oil gathering business in Stephens, Arkansas;

• providing crude oil gathering, refining, and marketing services of base oils, asphalt, and distillate products in Smackover, Arkansas;

29

• 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; and

• operating, solely for our account, the asphalt facilities in Omaha, Nebraska, Port Neches, Texas, Hondo, 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 16.0% 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 $32.4 million of direct costs and expenses for the three months ended March 31, 2018 compared to $37.5 million for the three months ended March 31, 2017. 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 both the three months ended March 31, 2018 and 2017, the Conflicts Committee approved reimbursement amounts of $4.1 million. 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 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, 2017, filed with the SEC on February 16, 2018, as amended by Amendment No. 1 on Form 10-K/A filed on March 29, 2018.

30

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 8% and 11% of our total cost of products sold during the three months ended March 31, 2018 and 2017, 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 9% and 10% of our total revenues for the three months ended March 31, 2018 and 2017, 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, 2017, filed with the SEC on February 16, 2018, as amended by Amendment No. 1 on Form 10-K/A filed on March 29, 2018.

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.

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

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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 months ended March 31, 2018 and 2017.

Reconciliation of EBITDA, Adjusted EBITDA, and Distributable Cash Flow

	Three Months Ended
	March 31,
	2018			2017
	(in thousands)
Net income	$	12,818		$	13,583
Adjustments:
Interest expense, net	12,685			10,920
Income tax expense	149			180
Depreciation and amortization	19,210			25,336
EBITDA	44,862			50,019
Adjustments:
Equity in earnings of WTLPG	(1,595		)	(905		)
Loss on sale of property, plant and equipment	2			155
Unrealized mark-to-market on commodity derivatives	(154		)	(3,837		)
Distributions from WTLPG	1,500			1,200
Unit-based compensation	132			186
Adjusted EBITDA	44,747			46,818
Adjustments:
Interest expense, net	(12,685		)	(10,920		)
Income tax expense	(149		)	(180		)
Amortization of debt premium	(77		)	(77		)
Amortization of deferred debt issuance costs	819			721
Payments for plant turnaround costs	—			(1,394		)
Maintenance capital expenditures	(6,002		)	(4,668		)
Distributable Cash Flow	$	26,653		$	30,300

Results of Operations

The results of operations for the three months ended March 31, 2018 and 2017 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

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following table sets forth our operating revenues and operating income by segment for the three months ended March 31, 2018 and 2017.  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.

Three Months Ended March 31, 2018 Compared to the Three Months Ended March 31, 2017

	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 March 31, 2018	(in thousands)
Terminalling and storage	$	61,983	$	(1,439	)	$	60,544	$	3,619		$	(897	)	$	2,722
Natural gas services	174,519		—			174,519		16,620			791			17,411
Sulfur services	37,687		—			37,687		7,687			(695		)	6,992
Marine transportation	12,028		(574		)	11,454		362			801			1,163
Indirect selling, general and administrative	—		—			—		(4,231		)	—			(4,231		)
Total	$	286,217	$	(2,013	)	$	284,204	$	24,057		$	—		$	24,057

	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 March 31, 2017	(in thousands)
Terminalling and storage	$	58,578	$	(1,773	)	$	56,805	$	(893	)	$	(1,208	)	$	(2,101	)
Natural gas services	141,322		—			141,322		17,149			1,124			18,273
Sulfur services	42,377		—			42,377		11,480			(713		)	10,767
Marine transportation	13,414		(593		)	12,821		432			797			1,229
Indirect selling, general and administrative	—		—			—		(4,420		)	—			(4,420		)
Total	$	255,691	$	(2,366	)	$	253,325	$	23,748		$	—		$	23,748

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Terminalling and Storage Segment

Comparative Results of Operations for the Three Months Ended March 31, 2018 and 2017

	Three Months Ended March 31,					Variance			Percent Change
	2018		2017
	(In thousands, except BBL per day)
Revenues:
Services	$	25,503	$	26,431		$	(928	)	(4	)%
Products	36,480		32,147			4,333			13	%
Total revenues	61,983		58,578			3,405			6	%
Cost of products sold	31,955		27,011			4,944			18	%
Operating expenses	14,994		15,645			(651		)	(4	)%
Selling, general and administrative expenses	1,256		1,325			(69		)	(5	)%
Depreciation and amortization	10,159		15,477			(5,318		)	(34	)%
	3,619		(880		)	4,499			(511	)%
Other operating loss	—		(13		)	13			(100	)%
Operating income (loss)	$	3,619	$	(893	)	$	4,512		(505	)%
Lubricant sales volumes (gallons)	5,908		5,334			574			11	%
Shore-based throughput volumes (guaranteed minimum) (gallons)	20,000		41,667			(21,667		)	(52	)%
Smackover refinery throughput volumes (guaranteed minimum) (BBL per day)	6,500		6,500			—			—	%

Services revenues. Services revenue decreased $0.9 million, of which $2.2 million was a result of decreased throughput fees and $0.4 million related to consigned lubricants revenues at our shore-based terminals, offset by a $1.7 million increase primarily as a result of the Hondo asphalt plant being put into service.

Products revenues. A 32% increase in sales volumes combined with a 1% increase in average sales price at our blending and packaging facilities resulted in a $4.3 million increase to products revenues.

Cost of products sold.  A 32% increase in sales volumes combined with a 15% increase in average price per gallon at our blending and packaging facilities resulted in a $4.9 million increase in cost of products sold.

Operating expenses. Operating expenses at our shore-based terminals decreased by $0.9 million, primarily due to lease and other expenses related to facilities closed in 2017. Operating expenses at our specialty terminals increased $0.1 million, of which $0.5 million is a result of increased repairs and maintenance offset by a $0.3 million decrease in compensation expenses. Operating expenses at the Smackover refinery increased $0.1 million primarily due to an increase in utility costs associated with higher natural gas usage.

Selling, general and administrative expenses.   Selling, general and administrative expenses remained relatively consistent.

Depreciation and amortization.  The decrease in depreciation and amortization is due to the disposition of assets at several closed shore-based facilities, offset by recent capital expenditures.

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

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Natural Gas Services Segment

Comparative Results of Operations for the Three Months Ended March 31, 2018 and 2017

	Three Months Ended March 31,				Variance			Percent Change
	2018		2017
	(In thousands)
Revenues:
Services	$	15,356	$	14,665	$	691		5	%
Products	159,163		126,657		32,506			26	%
Total revenues	174,519		141,322		33,197			23	%
Cost of products sold	143,748		109,303		34,445			32	%
Operating expenses	5,780		5,658		122			2	%
Selling, general and administrative expenses	3,070		3,051		19			1	%
Depreciation and amortization	5,301		6,161		(860		)	(14	)%
Operating income	$	16,620	$	17,149	$	(529	)	(3	)%
Distributions from WTLPG	$	1,500	$	1,200	$	300		25	%
NGL sales volumes (Bbls)	3,441		2,810		631			22	%

Services Revenues. The increase in services revenue is primarily due to increased interruptible activity across our natural gas storage facilities, slightly higher re-contracting rates, and additional firm wheeling activity at our Monroe gas storage facility.

Products Revenues. Our average sales price per barrel increased $1.18, or 2.62%, resulting in an increase to products revenues of $3.3 million. The increase in average sales price per barrel was a result of an increase in market prices. Product sales volumes increased 22.5%, increasing products revenues by $29.2 million.

Cost of products sold.  Our average cost per barrel increased $2.88, or 7.4%, increasing cost of products sold by $8.1 million.  The increase in average cost per barrel was a result of an increase in market prices.  The increase in sales volume of 22.5% resulted in a $26.4 million increase to cost of products sold. Our margins decreased $1.70 per barrel, or 27.5%, during the period.

Operating expenses.  Operating expenses remained relatively consistent.

Selling, general and administrative expenses.  Selling, general and administrative expenses remained relatively consistent.

Depreciation and amortization. Depreciation and amortization decreased $0.9 million primarily due to a decrease in amortization related to contracts acquired as part of the purchase of Cardinal Gas Storage.

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Sulfur Services Segment

Comparative Results of Operations for the Three Months Ended March 31, 2018 and 2017    

	Three Months Ended March 31,						Variance			Percent Change
	2018			2017
	(In thousands)
Revenues:
Services	$	2,787		$	2,850		$	(63	)	(2	)%
Products	34,900			39,527			(4,627		)	(12	)%
Total revenues	37,687			42,377			(4,690		)	(11	)%
Cost of products sold	23,987			24,574			(587		)	(2	)%
Operating expenses	2,912			3,247			(335		)	(10	)%
Selling, general and administrative expenses	1,035			1,021			14			1	%
Depreciation and amortization	2,064			2,033			31			2	%
	7,689			11,502			(3,813		)	(33	)%
Other operating loss	(2		)	(22		)	20			(91	)%
Operating income	$	7,687		$	11,480		$	(3,793	)	(33	)%
Sulfur (long tons)	176			217			(41		)	(19	)%
Fertilizer (long tons)	88			94			(6		)	(6	)%
Total sulfur services volumes (long tons)	264			311			(47		)	(15	)%

Services revenues.  Services revenue remained relatively consistent.

Products revenues.  Products revenue decreased $6.2 million as a result of a 15% decline in sales volumes, primarily attributable to a 19% decrease in sulfur volumes. A 4% increase in average sales price resulted in an offsetting increase of $1.6 million.

Cost of products sold.  A 15% decrease in sales volumes reduced our cost of products sold by $4.3 million. Offsetting this decrease was an increase in cost of products sold of $3.7 million as a result of a 15% increase in average cost of products sold per ton. Margin per ton decreased $6.74, or 14%.

Operating expenses.  Operating expenses decreased $0.3 million due to a $0.4 million decline in compensation expense as well as a combined decrease of $0.1 million related to lease and utilities expenses. An offsetting increase of $0.2 million related to repairs and maintenance of marine vessels and railcars.

Selling, general and administrative expenses.   Selling, general and administrative expenses remained relatively consistent.

Other operating loss.  Other operating loss represents gains and 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 March 31, 2018 and 2017

	Three Months Ended March 31,					Variance			Percent Change
	2018		2017
	(In thousands)
Revenues	$	12,028	$	13,414		$	(1,386	)	(10)%
Operating expenses	9,904		11,093			(1,189		)	(11)%
Selling, general and administrative expenses	76		104			(28		)	(27)%
Depreciation and amortization	1,686		1,665			21			1%
	$	362	$	552		$	(190	)	(34)%
Other operating loss	—		(120		)	120			(100)%
Operating income	$	362	$	432		$	(70	)	(16)%

 

Inland revenues.  A decrease of $1.9 million is attributable to decreased utilization of the inland fleet resulting from regulatory downtime and the non-utilization of equipment that became idle and classified as held for sale.

Offshore revenues.  A $0.2 million increase in offshore revenues is primarily the result of increased utilization of our offshore tow.

Operating expenses.  The decrease in operating expenses is primarily a result of decreased compensation expense of $0.7 million, lease expense of $0.3 million, and repairs and maintenance of $0.2 million.

Selling, general and administrative expenses.  Selling, general and administrative expenses remained relatively consistent.

Depreciation and amortization.  Depreciation and amortization remained relatively consistent.

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

Equity in Earnings in and Distributions from WTLPG

Comparative Results for the Three Months Ended March 31, 2018 and 2017

	Three Months Ended March 31,				Variance		Percent Change
	2018		2017
	(In thousands)
Equity in earnings of WTLPG	$	1,595	$	905	$	690	76	%

	Three Months Ended March 31,				Variance		Percent Change
	2018		2017
	(In thousands)
Distributions from WTLPG	$	1,500	$	1,200	$	300	25	%

Equity in earnings from WTLPG increased primarily as a result of higher volumes as well as a decrease in repairs and maintenance. Offsetting this was an increase in pipeline lease expense, fuel and power expense, and property taxes. Distributions from WTLPG increased $0.3 million.      

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Interest Expense, Net

Comparative Components of Interest Expense, Net for the Three Months Ended March 31, 2018 and 2017

	Three Months Ended March 31,						Variance		Percent Change
	2018			2017
	(In thousands)
Revolving loan facility	$	5,110		$	4,145		$	965	23%
7.25% Senior notes	6,474			6,474			—		—%
Amortization of deferred debt issuance costs	819			721			98		14%
Amortization of debt premium	(77		)	(77		)	—		—%
Other	520			435			85		20%
Capitalized interest	(161		)	(223		)	62		(28)%
Interest income	—			(555		)	555		(100)%
Total interest expense, net	$	12,685		$	10,920		$	1,765	16%

Indirect Selling, General and Administrative Expenses

	Three Months Ended March 31,				Variance			Percent Change
	2018		2017
	(In thousands)
Indirect selling, general and administrative expenses	$	4,231	$	4,420	$	(189	)	(4)%

Indirect selling, general and administrative expenses decreased for the three months ended March 31, 2018 compared to the three months ended March 31, 2017 primarily due to decreased audit fees.

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, 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 ended March 31, 2018 and 2017:

	Three Months Ended March 31,				Variance		Percent Change
	2018		2017
	(In thousands)
Conflicts Committee approved reimbursement amount	$	4,104	$	4,104	$	—	—%

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

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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 and are controlling our spending in an effort to preserve liquidity.

Recent Debt Financing Activity

Credit Facility Amendment. On February 21, 2018, we amended our revolving credit facility in order to achieve two primary objectives, the first of which was to accommodate growth capital expenditures necessary for the aforementioned WTLPG expansion project. Starting in the first quarter of 2018, the amendment will provide short-term (5 quarters) covenant relief by increasing the total leverage ratio to 5.75 to 1.00 (first and second quarters of 2018) with step downs to 5.50 to 1.00 (third and fourth quarters of 2018 and first quarter of 2019) and to 5.25 to 1.00 beginning in the second quarter of 2019. Additionally, the facility was amended to establish an inventory financing sublimit tranche for borrowings related to our NGL (butane) marketing business, which is a part of and not in addition to the already existing commitments under the revolving credit facility. This sublimit is not to exceed $75.0 million, with seasonal step downs to $10.0 million for the months of March through June of each fiscal year. The sublimit is subject to a monthly borrowing base not to exceed 90% of the value of forward sold/hedged inventory.

We believe that cash generated from operations and our borrowing capacity under our credit facility will be sufficient to meet our working capital requirements and anticipated maintenance capital expenditures in 2018.

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, 2017, filed with the SEC on February 16, 2018, as amended by Amendment No. 1 on Form 10-K/A filed on March 29, 2018, for a discussion of such risks.

Cash Flows - Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017

The following table details the cash flow changes between the three months ended March 31, 2018 and 2017:

	Three Months Ended March 31,						Variance			Percent Change
	2018			2017
	(In thousands)
Net cash provided by (used in):
Operating activities	$	55,390		$	56,526		$	(1,136	)	(2)%
Investing activities	(16,992		)	(25,923		)	8,931			(34)%
Financing activities	(38,241		)	(30,579		)	(7,662		)	25%
Net increase in cash and cash equivalents	$	157		$	24		$	133		554%

Net cash provided by operating activities. The decline in net cash provided by operating activities for the three months ended March 31, 2018 includes a decrease in operating results of $0.8 million and a $3.2 million decrease in other non-cash charges. Offsetting was a $2.2 million favorable variance in working capital and $0.4 million favorable variance in other non-current assets and liabilities. Further increases were due to increases in distributions received from WTLPG of $0.3 million.

Net cash used in investing activities. Net cash used in investing activities for the three months ended March 31, 2018 decreased primarily as a result of the acquisition of certain asphalt terminalling assets from Martin Resource Management of $19.5 million in 2017 compared to no acquisitions in 2018. Further, a decrease of $1.6 million resulted from a decline in proceeds from the sale of property, plant and equipment. An offsetting $7.3 million increase in net cash used in investing activities resulted from higher payments for capital expenditures and plant turnaround costs in 2018. Additionally, an increase of $1.7 million resulted from contributions to WTLPG.

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Net cash used in financing activities. Net cash used in financing activities increased for the three months ended March 31, 2018 as a result of a decrease in proceeds received from the issuance of common units (including the related general partner contribution) of $52.4 million. Also contributing was an increase in cash distributions paid of $1.5 million and an additional $1.2 million in costs associated with our credit facility amendment. Offsetting was a decrease in net repayments of long-term borrowings of $41.0 million and a decrease in cash used of $6.7 million related to excess purchase price over the carrying value of acquired assets in common control transactions.

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 March 31,
	2018		2017
	(In thousands)
Expansion capital expenditures	$	6,967	$	3,252
Maintenance capital expenditures	6,002		4,668
Plant turnaround costs	—		1,394
Total	$	12,969	$	9,314

Expansion capital expenditures were made primarily in our Marine Transportation and Terminalling and Storage segments during the three months ended March 31, 2018 on certain ongoing organic growth projects. Maintenance capital expenditures were made primarily in our Marine Transportation segment for the three months ended March 31, 2018 related to regulatory maintenance.

Expansion capital expenditures were made primarily in our Terminalling and Storage segment during the three months ended March 31, 2017. Within our Terminalling and Storage segment, expenditures were made primarily on project construction at our newly acquired asphalt terminal in Hondo, Texas, 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 and Marine Transportation segments to maintain our existing assets and operations during the three months ended March 31, 2017. For the three months ended March 31, 2017, 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.

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Total Contractual Cash Obligations.  A summary of our total contractual cash obligations as of March 31, 2018, 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	$	428,000	$	—	$	428,000	$	—	$	—
2021 Senior unsecured notes	373,800		—		373,800		—		—
Throughput commitment	19,914		6,072		12,636		1,206		—
Operating leases	26,556		8,121		7,723		3,126		7,586
Interest payable on fixed long-term debt obligations	77,914		27,101		50,813		—		—
Total contractual cash obligations	$	926,184	$	41,294	$	872,972	$	4,332	$	7,586

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 March 31, 2018, we had outstanding irrevocable letters of credit in the amount of $14.4 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, 2017, as amended.

Revolving Credit Facility

At March 31, 2018, we maintained a $664.4 million credit facility. This facility was most recently amended on February 21, 2018 when we amended our revolving credit facility in order to achieve two primary objectives, the first of which was to accommodate growth capital expenditures necessary for the aforementioned WTLPG expansion project. Starting in the first quarter of 2018, the amendment will provide short-term (5 quarters) covenant relief by increasing the total leverage ratio to 5.75 to 1.00 (first and second quarters of 2018) with step downs to 5.50 to 1.00 (third and fourth quarters of 2018 and first quarter of 2019) and to 5.25 to 1.00 beginning in the second quarter of 2019. Additionally, the facility was amended to establish an inventory financing sublimit tranche for borrowings related to our NGL (butane) marketing business, which is a part of and not in addition to the already existing commitments under the revolving credit facility. This sublimit is not to exceed $75.0 million, with seasonal step downs to $10.0 million for the months of March through June of each fiscal year. The sublimit is subject to a monthly borrowing base not to exceed 90% of the value of forward sold/hedged inventory.

As of March 31, 2018, we had $428.0 million outstanding under the revolving credit facility and $14.4 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 $222.0 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 March 31, 2018, we have the ability to borrow approximately $98.3 million of that amount.

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 three months ended March 31, 2018, the level of outstanding draws on our credit facility has ranged from a low of $428.0 million to a high of $458.0 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.

41

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 March 31, 2018:

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 March 31, 2018, 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 March 31, 2018 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. Based on the most recent amendment to our revolving credit facility on February 21, 2018, the maximum permitted leverage ratio (as defined in the credit agreement, being generally computed as the ratio of total funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) was revised from 5.25 to 1.00, with a temporary springing provision to 5.50 to 1.00 under certain scenarios, to 5.75 to 1.00 for the first and second quarters of 2018, 5.50 to 1.00 for the next three quarters and 5.25 to 1.00, with the temporary springing provision to 5.50 to 1.00 going back into effect, thereafter and (iv) decrease the maximum permitted senior leverage ratio (as defined in the credit agreement, being generally computed as the ratio of total secured funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) from 3.50 to 1.00 to 3.25 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 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

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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.

We are in compliance with all debt covenants as of March 31, 2018 and expect 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 three months ended March 31, 2018 or 2017.  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.

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 three months ended March 31, 2018 or 2017.

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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 March 31, 2018 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 gross notional quantity of 50,000 barrels settling during the period from May 1, 2018 through June 30, 2018. These instruments settle against the applicable pricing source for each grade and location. These instruments are recorded on our Consolidated and Condensed Balance Sheets at March 31, 2018 in "Fair value of derivatives" as a current asset of $0.1 million. Based on the current net notional volume hedged as of March 31, 2018, a $0.10 change in the expected settlement price of these contracts would result in a corresponding decrease in net income of approximately $0.2 million.

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 4.86% as of March 31, 2018.  Based on the amount of unhedged floating rate debt owed by us on March 31, 2018, 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 $4.3 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 $377.1 million as of March 31, 2018, based on market prices of similar debt at March 31, 2018.   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 not result in a change in fair value of our long-term debt at March 31, 2018.

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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.

During 2017 we began implementation of a new enterprise resource planning ("ERP") system. The new ERP system is expected to take several years to fully implement, and has and will continue to require significant capital and human resources to deploy. During the quarter ended March 31, 2018, we completed the implementation of certain functional areas of the ERP implementation project that affect the processes that constitute our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) and this initial deployment will require testing for effectiveness throughout 2018. Management has taken steps to ensure that appropriate controls are designed and implemented as each functional area of the new ERP system is enacted.

Beginning January 1, 2018, we implemented ASC 606, Revenue from Contracts with Customers.  Although the new revenue standard is expected to have an immaterial impact on our ongoing net income, we did implement changes to our processes related to revenue recognition and the control activities within them.  These included the development of new policies based on the five-step model provided in the new revenue standard, new training, ongoing contract review requirements, and gathering of information provided for disclosures.

Other than as described above, there were no changes in our internal control over financial reporting during the quarter ended March 31, 2018, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

Item 1. Legal Proceedings

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 15 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 16, 2018, as amended by Amendment No. 1 on Form 10-K/A filed on March 29, 2018.

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: 4/25/2018	By:	/s/ Robert D. Bondurant
		Robert D. Bondurant
		Executive Vice President, Treasurer, Chief Financial Officer, and Principal Accounting Officer

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INDEX TO EXHIBITS

Exhibit Number	Exhibit Name
10.1	Sixth Amendment to Third Amended and Restated Credit Agreement, dated February 21, 2018, among the Partnership, the Operating Partnership, certain of their subsidiaries, Royal Bank of Canada and the other Lenders as set forth therein (filed as exhibit 10.1 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed February 22, 2018, 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 March 31, 2018, 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: 4/25/2018

/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: 4/25/2018

/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 March 31, 2018, 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.

April 25, 2018

*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 March 31, 2018, 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.

April 25, 2018

*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	3 Months Ended
	Mar. 31, 2018	Apr. 25, 2018
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	Accelerated Filer
Document Type	10-Q
Document Period End Date	Mar. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding (in shares)		39,052,237

XML

CONSOLIDATED AND CONDENSED BALANCE SHEETS - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Assets
Cash	$ 184	$ 27
Accounts and other receivables, less allowance for doubtful accounts of $419 and $314, respectively	84,554	107,242
Product exchange receivables	75	29
Inventories (Note 6)	73,894	97,252
Due from affiliates	25,866	23,668
Fair value of derivatives (Note 10)	82	0
Other current assets	6,004	4,866
Assets held for sale (Note 4)	9,442	9,579
Total current assets	200,101	242,663
Property, plant and equipment, at cost	1,265,516	1,253,065
Accumulated depreciation	(432,275)	(421,137)
Property, plant and equipment, net	833,241	831,928
Goodwill	17,296	17,296
Investment in WTLPG (Note 7)	130,644	128,810
Other assets, net (Note 9)	29,779	32,801
Total assets	1,211,061	1,253,498
Liabilities and Partners’ Capital
Trade and other accounts payable	86,751	92,567
Product exchange payables	10,200	11,751
Due to affiliates	1,084	3,168
Income taxes payable	659	510
Fair value of derivatives (Note 10)	0	72
Other accrued liabilities (Note 9)	15,234	26,340
Total current liabilities	113,928	134,408
Long-term debt, net (Note 8)	795,139	812,632
Other long-term obligations	10,808	8,217
Total liabilities	919,875	955,257
Commitments and contingencies (Note 15)
Partners’ capital (Note 11)	291,186	298,241
Total partners’ capital	291,186	298,241
Total liabilities and partners' capital	$ 1,211,061	$ 1,253,498

XML

CONSOLIDATED AND CONDENSED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$ 419	$ 314

XML

CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Revenues:
Terminalling and storage	[1]	$ 24,064	$ 24,658
Marine transportation	[1]	11,454	12,821
Natural gas services	[1]	15,356	14,665
Sulfur services		2,787	2,850
Product sales:
Natural gas services	[1]	159,163	126,657
Sulfur services	[1]	34,900	39,527
Terminalling and storage	[1]	36,480	32,147
Total product sales	[1]	230,543	198,331
Total revenues		284,204	253,325
Cost of products sold: (excluding depreciation and amortization)
Natural gas services	[1]	142,957	108,179
Sulfur services	[1]	23,896	24,483
Terminalling and storage	[1]	31,413	26,446
Total cost of products sold (excluding depreciation and amortization)	[1]	198,266	159,108
Expenses:
Operating expenses	[1]	33,001	35,057
Selling, general and administrative	[1]	9,668	9,921
Depreciation and amortization		19,210	25,336
Total costs and expenses		260,145	229,422
Other operating loss		(2)	(155)
Operating income		24,057	23,748
Other income (expense):
Equity in earnings of WTLPG		1,595	905
Interest expense, net		(12,685)	(10,920)
Other, net		0	30
Total other expense		(11,090)	(9,985)
Net income before taxes		12,967	13,763
Income tax expense		(149)	(180)
Net income		12,818	13,583
Less general partner's interest in net income		(256)	(272)
Less income allocable to unvested restricted units		(8)	(35)
Limited partners' interest in net income		$ 12,554	$ 13,276
Net income per unit attributable to limited partners - basic (USD per share)		$ 0.33	$ 0.36
Net income per unit attributable to limited partners - diluted (USD per share)		$ 0.32	$ 0.36
Weighted average limited partner units - basic (in shares)		38,621,375	37,321,263
Weighted average limited partner units - diluted (in shares)		38,629,627	37,367,384

[1] Related Party Transactions Included Above     Three Months Ended     March 31,     2018   2017 Revenues:*         Terminalling and storage   $ 20,025
  $ 19,704
Marine transportation   3,613
  4,325
Natural gas services   —
  112
Product Sales   642
  1,430
Costs and expenses:*         Cost of products sold: (excluding depreciation and amortization)         Natural gas services   4,318
  8,894
Sulfur services   4,526
  3,675
Terminalling and storage   6,558
  5,067
Expenses:         Operating expenses   13,384
  16,376
Selling, general and administrative   7,721
  7,568

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CONSOLIDATED AND CONDENSED STATEMENTS OF OPERATIONS - Related Party Transactions - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Revenues:
Terminalling and storage	$ 20,025	$ 19,704
Marine transportation	3,613	4,325
Natural gas services	0	112
Product Sales	642	1,430
Cost of products sold: (excluding depreciation and amortization)
Natural gas services	4,318	8,894
Sulfur services	4,526	3,675
Terminalling and storage	6,558	5,067
Expenses:
Operating expenses	13,384	16,376
Selling, general and administrative	$ 7,721	$ 7,568

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CONSOLIDATED AND CONDENSED STATEMENTS OF CAPITAL - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Increase (Decrease) in Partners' Capital [Roll Forward]
Beginning balance	$ 298,241	$ 312,006
Net income	12,818	13,583
Issuance of common units, net	(101)	51,188
Issuance of restricted units	0	0
Forfeiture of restricted units	0	0
General partner contribution		1,098
Cash distributions	(19,605)	(18,087)
Unit-based compensation	132	186
Excess purchase price over carrying value of acquired assets	(26)	(7,887)
Reimbursement of excess purchase price over carrying value of acquired assets		1,125
Purchase of treasury units	(273)
Ending balance	$ 291,186	$ 353,212
Common Limited
Increase (Decrease) in Partners' Capital [Roll Forward]
Beginning balance (in shares)	38,444,612	35,452,062
Beginning balance	$ 290,927	$ 304,594
Net income	$ 12,562	$ 13,311
Issuance of common units, net (in shares)	0	2,990,000
Issuance of common units, net	$ (101)	$ 51,188
Issuance of restricted units (in shares)	633,425	12,000
Issuance of restricted units	$ 0	$ 0
Forfeiture of restricted units (in shares)	(7,000)	(1,500)
Forfeiture of restricted units	$ 0	$ 0
Cash distributions	(19,213)	(17,725)
Unit-based compensation	132	186
Excess purchase price over carrying value of acquired assets	$ (26)	(7,887)
Reimbursement of excess purchase price over carrying value of acquired assets		$ 1,125
Purchase of treasury units (in shares)	(18,800)
Purchase of treasury units	$ (273)
Ending balance (in shares)	39,052,237	38,452,562
Ending balance	$ 284,008	$ 344,792
General Partner Amount
Increase (Decrease) in Partners' Capital [Roll Forward]
Beginning balance	7,314	7,412
Net income	256	272
General partner contribution		1,098
Cash distributions	(392)	(362)
Ending balance	$ 7,178	$ 8,420

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CONSOLIDATED AND CONDENSED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Cash flows from operating activities:
Net income	$ 12,818	$ 13,583
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	19,210	25,336
Amortization of deferred debt issuance costs	819	721
Amortization of premium on notes payable	(77)	(77)
Loss on sale of property, plant and equipment	2	155
Equity in earnings of WTLPG	(1,595)	(905)
Derivative (income) loss	(2,470)	2,495
Net cash received (paid) for commodity derivatives	2,316	(6,332)
Unit-based compensation	132	186
Cash distributions from WTLPG	1,500	1,200
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables	22,693	19,110
Product exchange receivables	(46)	(90)
Inventories	23,306	20,580
Due from affiliates	(2,203)	(477)
Other current assets	(1,232)	(491)
Trade and other accounts payable	(3,621)	(2,560)
Product exchange payables	(1,551)	(100)
Due to affiliates	(2,084)	(5,186)
Income taxes payable	149	180
Other accrued liabilities	(13,310)	(11,083)
Change in other non-current assets and liabilities	634	281
Net cash provided by operating activities	55,390	56,526
Cash flows from investing activities:
Payments for property, plant and equipment	(15,165)	(6,477)
Acquisitions	0	(19,533)
Payments for plant turnaround costs	0	(1,394)
Proceeds from sale of property, plant and equipment	(88)	1,481
Contributions to WTLPG	(1,739)	0
Net cash used in investing activities	(16,992)	(25,923)
Cash flows from financing activities:
Payments of long-term debt	(101,000)	(133,000)
Proceeds from long-term debt	84,000	75,000
Proceeds from issuance of common units, net of issuance related costs	(101)	51,188
General partner contribution	0	1,098
Purchase of treasury units	(273)	0
Payment of debt issuance costs	(1,236)	(16)
Excess purchase price over carrying value of acquired assets	(26)	(7,887)
Reimbursement of excess purchase price over carrying value of acquired assets	0	1,125
Cash distributions paid	(19,605)	(18,087)
Net cash used in financing activities	(38,241)	(30,579)
Net increase in cash	157	24
Cash at beginning of period	27	15
Cash at end of period	184	39
Non-cash additions to property, plant and equipment	$ 1,905	$ 3,262

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Nature of Operations and Basis of Presentation

3 Months Ended

Mar. 31, 2018

Accounting Policies [Abstract]

Nature of Operations and Basis of Presentation

NATURE OF OPERATIONS AND BASIS OF PRESENTATION

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 U.S. 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, 2017, filed with the Securities and Exchange Commission (the "SEC") on February 16, 2018, as amended by Amendment No. 1 on Form 10-K/A for the year ended December 31, 2017 filed on March 29, 2018.

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.

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New Accounting Pronouncements

3 Months Ended

Mar. 31, 2018

Accounting Changes and Error Corrections [Abstract]

New Accounting Pronouncements

NEW ACCOUNTING PRONOUNCEMENTS

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 replaced most existing revenue recognition guidance in U.S. GAAP. 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 adopted the new standard utilizing the cumulative effect method which will result in the cumulative effect of the adoption being recorded as of January 1, 2018. The Partnership adopted ASU 2014-09 on January 1, 2018 and did not identify any significant changes in the timing of revenue recognition when considering the amended accounting guidance. Additional disclosures related to revenue recognition appear "Note 5. Revenue."

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.

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Acquisitions

3 Months Ended

Mar. 31, 2018

Business Combinations [Abstract]

Acquisitions

ACQUISITIONS

Acquisition of Terminalling Assets.    On February 22, 2017, the Partnership acquired 100% of the membership interests of MEH South Texas Terminals LLC ("MEH"), a subsidiary of Martin Resource Management, for a purchase price of $27,420 (the "Hondo Acquisition"), which was funded with borrowings under the Partnership's revolving credit facility. At the date of acquisition, MEH was in the process of constructing an asphalt terminal facility in Hondo, Texas (the "Hondo Terminal"), to serve the asphalt market in San Antonio, Texas and surrounding areas. This acquisition is considered a transfer of net assets between entities under common control. The acquisition of these assets was recorded at the historical carrying value of the assets at the acquisition date. The excess of the purchase price over the carrying value of the assets of $7,887 was recorded as an adjustment to "Partners' capital" during the three months ended March 31, 2017. During 2018, the Partnership paid an additional $26 related to a purchase price true-up, which was recorded as a further adjustment to "Partners' capital" for the three months ended March 31, 2018.

Original purchase price	$	27,420
Purchase price true-up	26
Historical carrying value of assets allocated to "Property, plant and equipment"	19,533
Excess purchase price over carrying value of acquired assets	$	7,913

As no individual line item of the historical financial statements of the acquired assets was in excess of 3% of the Partnership's relative consolidated financial statement captions, the Partnership elected not to retrospectively recast the historical financial information to include these assets.

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Divestitures, Asset Impairments, and Discontinued Operations

3 Months Ended

Mar. 31, 2018

Discontinued Operations and Disposal Groups [Abstract]

Divestitures, Asset Impairments, and Discontinued Operations

DIVESTITURES, ASSET IMPAIRMENTS, AND DISCONTINUED OPERATIONS

Long-Lived Assets Held for Sale

At March 31, 2018 and December 31, 2017, certain terminalling and storage and marine transportation assets met the criteria to be classified as held for sale in accordance with ASC 360-10 and are presented at the lower of the assets' carrying amount or fair value less cost to sell by segment in current assets as follows:

	March 31, 2018		December 31, 2017
Terminalling and storage	$	4,242	$	4,152
Marine transportation	5,200		5,427
Assets held for sale	$	9,442	$	9,579

These assets are considered non-core assets to the Partnership's operations and did not qualify for discontinued operations presentation under the guidance of ASC 205-20.

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Revenue

3 Months Ended

Mar. 31, 2018

Revenue from Contract with Customer [Abstract]

Revenue

REVENUE

The following table disaggregates our revenue by major source:

	Three Months Ended March 31,
	2018		2017
Terminalling and storage segment
Lubricant product sales	$	36,480	$	32,147
Throughput and storage	24,064		24,658
	$	60,544	$	56,805
Natural gas services segment
Natural gas liquids product sales	$	159,163	$	126,657
Natural gas storage	15,356		14,665
	$	174,519	$	141,322
Sulfur service segment
Sulfur product sales	$	11,837	$	13,080
Fertilizer product sales	23,063		26,447
Sulfur services	2,787		2,850
	$	37,687	$	42,377
Marine transportation segment
Inland transportation	$	9,692	$	11,291
Offshore transportation	1,762		1,530
	$	11,454	$	12,821

Revenue is measured based on a consideration specified in a contract with a customer and excludes amounts collected on behalf of third parties where the Partnership is acting as an agent. The Partnership recognizes revenue when the Partnership satisfies a performance obligation, which typically occurs when the Partnership transfers control over a product to a customer or as the Partnership delivers a service.

The following is a description of the principal activities - separated by reportable segments - from which the Partnership generates revenue.

Terminalling and Storage Segment

Revenue is recognized for storage contracts based on the contracted monthly tank fixed fee.  For throughput contracts, revenue is recognized based on the volume moved through the Partnership’s terminals at the contracted rate.  For the Partnership’s tolling agreement, revenue is recognized based on the contracted monthly reservation fee and throughput volumes moved through the facility.  When lubricants and drilling fluids are sold by truck or rail, revenue is recognized when title is transfered, which is either upon delivering product to the customer or when the product leaves the Partnership's facility, depending on the specific terms of the contract. Delivery of product is invoiced as the transaction occurs and is generally paid within a month.

Natural Gas Services Segment

Natural Gas Liquids ("NGL") distribution revenue is recognized when product is delivered by truck, rail, or pipeline to the Partnership's NGL customers. Revenue is recognized on title transfer of the product to the customer. Delivery of product is invoiced as the transaction occurs and are generally paid within a month. Natural gas storage revenue is recognized when the service is provided to the customer. The performance of the service is invoiced as the transaction occurs and is generally paid within a month.

Sulfur Services Segment

Revenue from sulfur product sales is recognized when the customer takes title to the product.  Delivery of product is invoiced as the transaction occurs and are generally paid within a month. Revenue from sulfur services is recognized as services are performed during each monthly period. The performance of the service is invoiced as the transaction occurs and is generally paid within a month.

Marine Transportation Segment

Revenue is recognized for time charters based on a per day rate. For contracted trips, revenue is recognized upon completion of the particular trip. The performance of the service is invoiced as the transaction occurs and is generally paid within a month.

The table includes estimated revenue expected to be recognized in the future related to performance obligations that are unsatisfied at the end of the reporting period. The Partnership applies the practical expedient in ASC 606-10-50-14(a) and does not disclose information about remaining performance obligations that have original expected durations of one year or less.

	2018		2019		2020		2021		2022		Thereafter		Total
Terminalling and storage
Storage and throughput	$	37,571	$	50,629	$	49,330	$	46,022	$	41,505	$	393,700	$	618,757
Natural gas services
Natural gas storage	$	31,309	$	32,932	$	27,011	$	25,134	$	24,615	$	12,068	$	153,069
Sulfur services
Sulfur product sales	$	12,597	$	16,796	$	4,898	$	1,181	$	295	$	—	$	35,767
Marine transportation
Offshore transportation	$	4,675	$	6,205	$	6,069	$	—	$	—	$	—	$	16,949
Total	$	86,152	$	106,562	$	87,308	$	72,337	$	66,415	$	405,768	$	824,542

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Inventories

3 Months Ended

Mar. 31, 2018

Inventory Disclosure [Abstract]

Inventories

INVENTORIES

Components of inventories at March 31, 2018 and December 31, 2017 were as follows: 

	March 31, 2018		December 31, 2017
Natural gas liquids	$	18,922	$	47,462
Sulfur	11,299		8,436
Sulfur based products	19,107		18,674
Lubricants	21,874		20,086
Other	2,692		2,594
	$	73,894	$	97,252

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Investment in West Texas LPG Pipeline L.P.

3 Months Ended

Mar. 31, 2018

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% limited partnership and 0.2% general partnership interest in West Texas LPG Pipeline L.P. ("WTLPG"). A wholly-owned subsidiary of ONEOK, Inc. is the operator of the assets. WTLPG owns an approximate 2,300 mile common-carrier pipeline system that primarily 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 March 31,						Three Months Ended March 31,
	Total Assets		Long-Term Debt		Members' Equity		Revenues		Net Income
2018
WTLPG	$	870,691	$	—	$	839,028	$	23,041	$	7,706
	As of December 31,
2017
WTLPG	$	837,163	$	—	$	787,426	$	19,719	$	4,525

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Long-Term Debt

3 Months Ended

Mar. 31, 2018

Debt Disclosure [Abstract]

Long-Term Debt

LONG-TERM DEBT

At March 31, 2018 and December 31, 2017, long-term debt consisted of the following:

	March 31, 2018		December 31, 2017
$664,444 Revolving credit facility at variable interest rate (4.86%1 weighted average at March 31, 2018), 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 $5,573 and $4,986, respectively2,3	$	422,427	$	440,014
$400,000 Senior notes, 7.25% interest, net of unamortized debt issuance costs of $1,967 and $2,138, respectively, including unamortized premium of $879 and $956, respectively, issued $250,000 February 2013 and $150,000 April 2014, $26,200 repurchased during 2015, due February 2021, unsecured3,4	372,712		372,618
Total long-term debt, net	$	795,139	$	812,632

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 March 31, 2018 and December 31, 2017 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 March 31, 2018 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 On February 21, 2018, the Partnership amended its revolving credit facility to, among other things, (i) create an inventory financing sublimit tranche, which is a part of and not in addition to the already existing commitments under the revolving credit facility, under which availability is subject to a borrowing base calculated by reference to eligible petroleum products inventory, (ii) exclude the amount of loans under the inventory financing sublimit tranche from total outstanding indebtedness for purposes of determining leverage ratio covenants under the revolving credit facility, (iii) increase the maximum permitted leverage ratio (as defined in the credit agreement, being generally computed as the ratio of total funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) from 5.25 to 1.00, with a temporary springing provision to 5.50 to 1.00 under certain scenarios, to 5.75 to 1.00 for the first and second quarters of 2018, 5.50 to 1.00 for the next three quarters and 5.25 to 1.00, with the temporary springing provision to 5.50 to 1.00 going back into effect, thereafter and (iv) decrease the maximum permitted senior leverage ratio (as defined in the credit agreement, being generally computed as the ratio of total secured funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) from 3.50 to 1.00 to 3.25 to 1.00. The maximum amount of the inventory financing sublimit tranche is $10,000 during the period between March 1 and June 30 of each year, and $75,000 at all

other times during each year.

³ The Partnership is in compliance with all debt covenants as of March 31, 2018 and December 31, 2017, respectively.

⁴ The 2021 indenture restricts the Partnership’s ability to sell assets; pay distributions or repurchase units or redeem or repurchase subordinated debt; make investments; incur or guarantee additional indebtedness or issue preferred units; and consolidate, merge or transfer all or substantially all of its assets.

The Partnership paid cash interest, net of capitalized interest, in the amount of $18,878 and $18,181 for the three months ended March 31, 2018 and 2017, respectively. Capitalized interest was $161 and $223 for the three months ended March 31, 2018 and 2017, respectively.

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Supplemental Balance Sheet Information

3 Months Ended

Mar. 31, 2018

Balance Sheet Related Disclosures [Abstract]

Supplemental Balance Sheet Information

SUPPLEMENTAL BALANCE SHEET INFORMATION

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

	March 31, 2018		December 31, 2017
Customer contracts and relationships, net	$	23,484	$	25,252
Other intangible assets	1,624		1,752
Other	4,671		5,797
	$	29,779	$	32,801

Accumulated amortization of intangible assets was $41,984 and $39,462 at March 31, 2018 and December 31, 2017, respectively.

Components of "Other accrued liabilities" were as follows:

	March 31, 2018		December 31, 2017
Accrued interest	$	4,952	$	11,726
Asset retirement obligations	3,360		5,429
Property and other taxes payable	3,279		5,638
Accrued payroll	3,636		3,385
Other	7		162
	$	15,234	$	26,340

The schedule below summarizes the changes in our asset retirement obligations:

	March 31, 2018
Beginning asset retirement obligations	$	13,512
Revisions to existing liabilities1	4,756
Accretion expense	147
Liabilities settled	(4,360		)
Ending asset retirement obligations	14,055
Current portion of asset retirement obligations2	(3,360		)
Long-term portion of asset retirement obligations3	$	10,695

¹Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, discount rates, and the estimated remaining useful life of the assets. The 2018 revisions reflect changes in removal cost estimates and the estimated remaining useful life of assets. 

²The current portion of asset retirement obligations is included in "Other current liabilities" on the Partnership's Consolidated and Condensed Balance Sheets.

³The non-current portion of asset retirement obligations is included in "Other long-term obligations" on the Partnership's Consolidated and Condensed Balance Sheets.

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Derivative Instruments and Hedging Activities

3 Months Ended

Mar. 31, 2018

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 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. 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 March 31, 2018 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 gross notional quantity of 50 barrels settling during the period from May 1, 2018 through June 30, 2018. At December 31, 2017, the Partnership had instruments totaling a gross notional quantity of 145 barrels settling during the period from January 31, 2018 through February 28, 2018. These instruments settle against the applicable pricing source for each grade and location.

(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. From time to time, 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. At March 31, 2018 and 2017, the Partnership did not have any outstanding interest rate derivative instruments.

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 and Condensed Balance Sheets
	Derivative Assets					Derivative Liabilities
		Fair Values					Fair Values
	Balance Sheet Location	March 31, 2018		December 31, 2017		Balance Sheet Location	March 31, 2018		December 31, 2017
Derivatives not designated as hedging instruments:	Current:
Commodity contracts	Fair value of derivatives	$	82	$	—	Fair value of derivatives	$	—	$	72
Total derivatives not designated as hedging instruments		$	82	$	—		$	—	$	72

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

For the Three Months Ended March 31, 2018 and 2017

	Location of Gain (Loss) Recognized in Income on  Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives
		2018		2017
Derivatives not designated as hedging instruments:
Commodity contracts	Cost of products sold	$	2,470	$	(2,495	)
Total effect of derivatives not designated as hedging instruments		$	2,470	$	(2,495	)

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Partners' Capital

3 Months Ended

Mar. 31, 2018

Partners' Capital Notes [Abstract]

Partners' Capital

PARTNERS' CAPITAL

As of March 31, 2018, Partners’ capital consisted of 39,052,237 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 16.0% 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.

Issuance of Common Units

On February 22, 2017, the Partnership completed a public offering of 2,990,000 common units at a price of $18.00 per common unit, before the payment of underwriters' discounts, commissions and offering expenses (per unit value is in dollars,

not thousands). Total proceeds from the sale of the 2,990,000 common units, net of underwriters' discounts, commissions and offering expenses, were $51,188. Additionally, the Partnership's general partner contributed $1,098 in cash to the Partnership in conjunction with the issuance in order to maintain its 2.0% general partner interest in the Partnership. All of the net proceeds were used to pay down outstanding amounts under the Partnership's revolving credit facility.

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 no incentive distributions during the three months ended March 31, 2018 and 2017.

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 March 31,
	2018			2017
Net income	$	12,818		$	13,583
Less general partner’s interest in net income (loss):
Distributions payable on behalf of IDRs	—			—
Distributions payable on behalf of general partner interest	392			392
General partner interest in undistributed loss	(136		)	(120		)
Less income allocable to unvested restricted units	8			35
Limited partners’ interest in net income (loss)	$	12,554		$	13,276

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 March 31,
	2018	2017
Basic weighted average limited partner units outstanding	38,621,375	37,321,263
Dilutive effect of restricted units issued	8,252	46,121
Total weighted average limited partner diluted units outstanding	38,629,627	37,367,384

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.

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Unit Based Awards

3 Months Ended

Mar. 31, 2018

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 March 31,
	2018		2017
Employees	$	96	$	159
Non-employee directors	36		27
Total unit-based compensation expense	$	132	$	186

All of the Partnership's outstanding awards at March 31, 2018 met the criteria to be treated under equity classification.

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.

On May 26, 2017, the unitholders of the Partnership approved the Martin Midstream Partners L.P. 2017 Restricted Unit Plan (the "2017 LTIP"). The plan currently permits the grant of awards covering an aggregate of 3,000,000 common units, all of which can be awarded in the form of restricted units. The plan is administered by the compensation committee of the general partner’s board of directors (the "Compensation Committee").

 A restricted unit is a unit that is granted to grantees with certain vesting restrictions, which may be time-based and/or performance-based. Once these restrictions lapse, the grantee is entitled to full ownership of the unit without restrictions. The Compensation Committee may determine to make grants under the plan containing such terms as the Compensation Committee shall determine under the plan. With respect to time-based restricted units ("TBRU's", the Compensation Committee will determine the time period over which restricted units granted to employees and directors will vest. The Compensation Committee may also award a percentage of restricted units with vesting requirements based upon the achievement of specified pre-established performance targets ("Performance Based Restricted Units" or "PBRU's"). The performance targets may include, but are not limited to, the following: revenue and income measures, cash flow measures, net income before interest expense and income tax expense ("EBIT"), net income before interest expense, income tax expense, and depreciation and amortization ("EBITDA"), distribution coverage metrics, expense measures, liquidity measures, market measures, corporate sustainability metrics, and other measures related to acquisitions, dispositions, operational objectives and succession planning objectives. PBRU's are earned only upon our achievement of an objective performance measure for the performance period. PBRU's which vest are payable in common units.  Unvested units granted under the 2017 LTIP may or may not participate in cash distributions depending on the terms of each individual award agreement.

The restricted units issued to directors generally vest in equal annual installments over a four-year period. Restricted units issued to employees generally vest in equal annual installments over three years of service.

On February 20, 2018, the Partnership issued 4,650 TBRU's to each of the Partnership's three independent directors under the 2017 LTIP.  These restricted common units vest in equal installments of 1,550 units on January 24, 2019, 2020, 2021, and 2022.

On March 1, 2018, the Partnership issued 301,550 TBRU's and 317,925 PBRU's to certain employees of Martin Resource Management. The TBRU's vest in equal installments over a three-year service period. The PBRU's will vest at the conclusion of a three-performance period based on certain performance targets. In addition, the PBRU's awarded on March 1, 2018 that are achieved will only vest if the grantee is employed by Martin Resource Management on March 31, 2021.

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 three months ended March 31, 2018 is provided below:

	Number of Units			Weighted Average Grant-Date Fair Value Per Unit
Non-vested, beginning of period	98,750			$	24.80
Granted (TBRU)	315,500			$	13.89
Granted (PBRU)	317,925			$	13.89
Vested	(80,550		)	$	27.71
Forfeited	(7,000		)	$	13.90
Non-Vested, end of period	644,625			$	13.91
Aggregate intrinsic value, end of period	$	8,702

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 three months ended March 31, 2018 and 2017 is provided below:

	Three Months Ended March 31,
	2018		2017
Aggregate intrinsic value of units vested	$	1,188	$	125
Fair value of units vested	2,232		170

As of March 31, 2018, there was $4,431 of unrecognized compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 3.01 years.

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Related Party Transactions

3 Months Ended

Mar. 31, 2018

Related Party Transactions [Abstract]

Related Party Transactions

RELATED PARTY TRANSACTIONS

As of March 31, 2018, Martin Resource Management owns 6,264,532 of the Partnership’s common units representing approximately 16.0% 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 March 31, 2018, of approximately 16.0% 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, marine fuel and other liquids;

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

◦ operating a crude oil gathering business in Stephens, Arkansas;

◦ providing crude oil gathering, refining, and marketing services of base oils, asphalt, and distillate products in Smackover, Arkansas;

◦ providing crude oil marketing and transportation from the well head to the end market;

◦ operating an environmental consulting company;

◦ operating an engineering services company;

◦ supplying employees and services for the operation of the Partnership's business; and

◦ operating, solely for the Partnership's account, the asphalt facilities in Omaha, Nebraska, Port Neches, Texas, Hondo, 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, 2018, through December 31, 2018, the Conflicts Committee approved an annual reimbursement amount for indirect expenses of $16,416.  The Partnership reimbursed Martin Resource Management for $4,104 and $4,104 of indirect expenses for the three months ended March 31, 2018 and 2017, 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 second amended and restated terminalling services agreement under which the Partnership provides terminal services to Martin Resource Management for marine fuel distribution.  At such time, the per gallon throughput fee the Partnership charged under this agreement was increased when compared to the previous agreement and may be adjusted annually based on a price index.  This agreement was further amended on January 1, 2017 and October 1, 2017 to modify its minimum throughput requirements and throughput fees. This agreement, as amended, continues until September 30, 2018 and thereafter on a month to month basis until terminated by either party by giving 60 days’ written notice.  

Miscellaneous Terminal Services Agreements.  The Partnership is currently party to several terminal services agreements and from time to time the Partnership may enter into other terminal service agreements for the purpose of providing terminal services to related parties. Individually, each of these agreements is immaterial but when considered in the aggregate they could be deemed material. These agreements are throughput based with a minimum volume commitment. Generally, the fees due under these agreements are adjusted annually based on a price index.

Other Agreements

 Cross Tolling Agreement. The Partnership is a party to an amended and restated tolling agreement with Cross Oil Refining and Marketing, Inc. ("Cross") dated October 28, 2014, under which the Partnership processes crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts for Cross.  The tolling agreement expires November 25, 2031.  Under this tolling agreement, Cross agreed to process a minimum of 6,500 barrels per day of crude oil at the facility at a fixed price per barrel.  Any additional barrels are processed at a modified price per barrel.  In addition, Cross agreed to pay a monthly reservation fee and a periodic fuel surcharge fee based on certain parameters specified in the tolling agreement.  All of these fees (other than the fuel surcharge) are subject to escalation annually based upon the greater of 3% or the increase in the Consumer Price Index for a specified annual period.  In addition, on the third, sixth and ninth anniversaries of the agreement, the parties can negotiate an upward or downward adjustment in the fees subject to their mutual agreement.

Sulfuric Acid Sales Agency Agreement. The Partnership is party to a third amended and restated sulfuric acid sales agency agreement dated August 2, 2017 but effective October 1, 2017, under which a successor in interest to the agreement from Martin Resource Management, Saconix LLC ("Saconix"), a limited liability company in which Martin Resource Management has a minority equity interest, 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 September 30, 2020 and shall automatically renew year to year thereafter until either party provides 90 days’ written notice of termination prior to the expiration of the then existing term.  Under this agreement, the Partnership sells all of its excess sulfuric acid to Saconix, who then markets and sells such acid to third-parties.  The Partnership shares in the profit of such sales.

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 March 31,
	2018		2017
Revenues:
Terminalling and storage	$	20,025	$	19,704
Marine transportation	3,613		4,325
Natural gas services	—		112
Product sales:
Natural gas services	1		942
Sulfur services	386		431
Terminalling and storage	255		57
	642		1,430
	$	24,280	$	25,571

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

	Three Months Ended March 31,
	2018		2017
Cost of products sold:
Natural gas services	$	4,318	$	8,894
Sulfur services	4,526		3,675
Terminalling and storage	6,558		5,067
	$	15,402	$	17,636

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

	Three Months Ended March 31,
	2018		2017
Operating expenses:
Marine transportation	$	5,321	$	5,996
Natural gas services	2,199		2,235
Sulfur services	1,339		1,446
Terminalling and storage	4,525		6,699
	$	13,384	$	16,376

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

	Three Months Ended March 31,
	2018		2017
Selling, general and administrative:
Marine transportation	$	8	$	8
Natural gas services	2,254		2,277
Sulfur services	659		636
Terminalling and storage	681		543
Indirect, including overhead allocation	4,119		4,104
	$	7,721	$	7,568

Other Related Party Transactions

The Partnership had a $15,000 note receivable from an affiliate of Martin Resource Management which previously bore an annual interest rate of 15% and had a maturity date of August 31, 2026, the balance of which could be prepaid on or after September 1, 2016. On February 14, 2017, the Partnership notified Martin Resource Management that it would be requesting voluntary repayment of the long-term Note Receivable plus accrued interest. During second quarter of 2017, the Note Receivable was fully repaid. The note has historically been recorded in "Note receivable - affiliates" on the Partnership's Consolidated and Condensed Balance Sheets. Interest income for the three months ended March 31, 2018 and 2017 was $0 and $555, respectively, and is included in "Interest expense, net" in the Consolidated and Condensed Statements of Operations.

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Business Segments

3 Months Ended

Mar. 31, 2018

Segment Reporting [Abstract]

Business Segments

BUSINESS SEGMENTS

The Partnership has four reportable segments: natural gas services, terminalling and storage, 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, 2017, filed with the SEC on February 16, 2018, as amended, by Amendment No. 1 on Form 10-K/A filed on March 29, 2018. 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 March 31, 2018	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	$	61,983	$	(1,439	)	$	60,544	$	10,159	$	2,722		$	2,121
Natural gas services	174,519		—			174,519		5,301		17,411			1,009
Sulfur services	37,687		—			37,687		2,064		6,992			1,548
Marine transportation	12,028		(574		)	11,454		1,686		1,163			8,291
Indirect selling, general and administrative	—		—			—		—		(4,231		)	—
Total	$	286,217	$	(2,013	)	$	284,204	$	19,210	$	24,057		$	12,969

Three Months Ended March 31, 2017	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	$	58,578	$	(1,773	)	$	56,805	$	15,477	$	(2,101	)	$	7,463
Natural gas services	141,322		—			141,322		6,161		18,273			852
Sulfur services	42,377		—			42,377		2,033		10,767			305
Marine transportation	13,414		(593		)	12,821		1,665		1,229			694
Indirect selling, general and administrative	—		—			—		—		(4,420		)	—
Total	$	255,691	$	(2,366	)	$	253,325	$	25,336	$	23,748		$	9,314

The Partnership's assets by reportable segment as of March 31, 2018 and December 31, 2017, are as follows:

	March 31, 2018		December 31, 2017
Total assets:
Terminalling and storage	$	327,318	$	326,920
Natural gas services	647,193		704,524
Sulfur services	128,064		120,790
Marine transportation	108,486		101,264
Total assets	$	1,211,061	$	1,253,498

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITTMENTS AND CONTINGENCIES

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 has reimbursed the Partnership $750 per quarter for four consecutive quarters as a reduction in the purchase price of the Redbird Class A interests.  These payments were the result of Cardinal Gas Storage Partners LLC ("Cardinal") not achieving certain financial targets set forth in the Purchase Price Reimbursement Agreement.  These payments were considered to be 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 were recorded as an adjustment to "Partners' capital" in each quarter in which the payments were made. The agreement further provided for purchase price reimbursements of up to $4,500 in 2016 in the event certain financial conditions were not met. For the three months ended March 31, 2017, the Partnership received $1,125, related to the Purchase Price Reimbursement Agreement. The amount received in the first quarter of 2017 represented the final payment under the Purchase Price Reimbursement Agreement.

Certain shippers filed complaints with the Railroad Commission of Texas ("RRC") challenging the increased rates WTLPG implemented effective July 1, 2015.  The complainants requested 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."  A hearing on the merits was held in front of a hearings examiner during the week of March 27, 2017.  The hearings examiner issued a Proposal for Decision on September 29, 2017. On December 5, 2017, this matter was brought before the RRC. After brief discussion, the RRC determined that more time was needed to review the proposal for decision and placed the matter on the agenda for the RRC’s January 23, 2018 meeting. At that meeting, the RRC voted to remand the case to the hearings examiner for the limited

purpose of admitting and considering additional relevant evidence on competition. The hearings examiner has scheduled the remand hearing for September 26-28, 2018.  

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 alleged that the Partnership breached a lease agreement by failing to perform work to the plaintiff's property as required under the lease agreement.  The plaintiff originally sought to evict the Partnership from the leased property and to recover damages.  Prior to trial, this matter was settled for a confidential amount in September of 2017. The Partnership's financial statements reflect the terms of the settlement and all amounts have been accrued as asset retirement obligations.

On December 31, 2015, the Partnership received a demand from a customer in its lubricants packaging business for defense and indemnity in connection with lawsuits filed against it in various 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.  The lawsuits against the customer have been transferred to the United States District Court for the Western District of Missouri for consolidated pretrial proceedings.  On March 1, 2017, at the request of the parties, the Chancery Court of Davidson County, Tennessee administratively closed the Partnership's lawsuit pending rulings in the United States District Court for the Western District of Missouri.  In the event that either party moves the Chancery Court of Davidson County, Tennessee to reopen the case, we expect the Court would grant such motion and reopen the case.  If the case is reopened, we are currently unable to determine the exposure we may have in this matter, if any.

Commitments

The Partnership has non-cancelable revenue arrangements that are not under the scope of ASC 606 whereby we have committed certain terminalling and storage assets in exchange for a minimum fee. Future minimum revenues the Partnership expects to receive under these non-cancelable arrangements as of March 31, 2018, are as follows: 2018 - $16,672; 2019 - $19,199; 2020 - $17,478; 2021 - $15,589; 2022 - $15,589; subsequent years - $72,872.

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Fair Value Measurements

3 Months Ended

Mar. 31, 2018

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
	March 31, 2018		December 31, 2017
Commodity derivative contracts, net	$	82	$	(72	)

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: 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 considered Level 1, as the fair value is based on quoted market prices in active markets.

	March 31, 2018				December 31, 2017
	Carrying Value		Fair Value		Carrying Value		Fair Value
2021 Senior unsecured notes	$	372,712	$	377,071	$	372,618	$	381,657

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Condensed Consolidated Financial Information

3 Months Ended

Mar. 31, 2018

Consolidating Financial Statements [Abstract]

Condensed Consolidated Financial Information

CONDENSED CONSOLIDATED FINANCIAL INFORMATIONThe 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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Subsequent Events

3 Months Ended

Mar. 31, 2018

Subsequent Events [Abstract]

Subsequent Events

SUBSEQUENT EVENTSQuarterly Distribution. On April 19, 2018, the Partnership declared a quarterly cash distribution of $0.50 per common unit for the first quarter of 2018, or $2.00 per common unit on an annualized basis, which will be paid on May 15, 2018 to unitholders of record as of May 8, 2018.

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New Accounting Pronouncements (Policies)

3 Months Ended

Mar. 31, 2018

Accounting Changes and Error Corrections [Abstract]

New Accounting Pronouncements

NEW ACCOUNTING PRONOUNCEMENTS

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 replaced most existing revenue recognition guidance in U.S. GAAP. 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 adopted the new standard utilizing the cumulative effect method which will result in the cumulative effect of the adoption being recorded as of January 1, 2018. The Partnership adopted ASU 2014-09 on January 1, 2018 and did not identify any significant changes in the timing of revenue recognition when considering the amended accounting guidance. Additional disclosures related to revenue recognition appear "Note 5. Revenue."

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.

Fair Value Measurement

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.

Fair Value of Financial Instruments

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: 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 considered Level 1, as the fair value is based on quoted market prices in active markets.

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Acquisitions (Tables)

3 Months Ended

Mar. 31, 2018

Business Combinations [Abstract]

Schedule of Business Acquisitions, by Acquisition

Original purchase price	$	27,420
Purchase price true-up	26
Historical carrying value of assets allocated to "Property, plant and equipment"	19,533
Excess purchase price over carrying value of acquired assets	$	7,913

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Divestitures, Asset Impairments, and Discontinued Operations (Tables)

3 Months Ended

Mar. 31, 2018

Discontinued Operations and Disposal Groups [Abstract]

Disclosure of Long Lived Assets Held-for-sale

At March 31, 2018 and December 31, 2017, certain terminalling and storage and marine transportation assets met the criteria to be classified as held for sale in accordance with ASC 360-10 and are presented at the lower of the assets' carrying amount or fair value less cost to sell by segment in current assets as follows:

	March 31, 2018		December 31, 2017
Terminalling and storage	$	4,242	$	4,152
Marine transportation	5,200		5,427
Assets held for sale	$	9,442	$	9,579

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Revenue (Tables)

3 Months Ended

Mar. 31, 2018

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

The following table disaggregates our revenue by major source:

	Three Months Ended March 31,
	2018		2017
Terminalling and storage segment
Lubricant product sales	$	36,480	$	32,147
Throughput and storage	24,064		24,658
	$	60,544	$	56,805
Natural gas services segment
Natural gas liquids product sales	$	159,163	$	126,657
Natural gas storage	15,356		14,665
	$	174,519	$	141,322
Sulfur service segment
Sulfur product sales	$	11,837	$	13,080
Fertilizer product sales	23,063		26,447
Sulfur services	2,787		2,850
	$	37,687	$	42,377
Marine transportation segment
Inland transportation	$	9,692	$	11,291
Offshore transportation	1,762		1,530
	$	11,454	$	12,821

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction

The table includes estimated revenue expected to be recognized in the future related to performance obligations that are unsatisfied at the end of the reporting period. The Partnership applies the practical expedient in ASC 606-10-50-14(a) and does not disclose information about remaining performance obligations that have original expected durations of one year or less.

	2018		2019		2020		2021		2022		Thereafter		Total
Terminalling and storage
Storage and throughput	$	37,571	$	50,629	$	49,330	$	46,022	$	41,505	$	393,700	$	618,757
Natural gas services
Natural gas storage	$	31,309	$	32,932	$	27,011	$	25,134	$	24,615	$	12,068	$	153,069
Sulfur services
Sulfur product sales	$	12,597	$	16,796	$	4,898	$	1,181	$	295	$	—	$	35,767
Marine transportation
Offshore transportation	$	4,675	$	6,205	$	6,069	$	—	$	—	$	—	$	16,949
Total	$	86,152	$	106,562	$	87,308	$	72,337	$	66,415	$	405,768	$	824,542

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Inventories (Tables)

3 Months Ended

Mar. 31, 2018

Inventory Disclosure [Abstract]

Components of inventory

Components of inventories at March 31, 2018 and December 31, 2017 were as follows: 

	March 31, 2018		December 31, 2017
Natural gas liquids	$	18,922	$	47,462
Sulfur	11,299		8,436
Sulfur based products	19,107		18,674
Lubricants	21,874		20,086
Other	2,692		2,594
	$	73,894	$	97,252

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

3 Months Ended

Mar. 31, 2018

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 March 31,						Three Months Ended March 31,
	Total Assets		Long-Term Debt		Members' Equity		Revenues		Net Income
2018
WTLPG	$	870,691	$	—	$	839,028	$	23,041	$	7,706
	As of December 31,
2017
WTLPG	$	837,163	$	—	$	787,426	$	19,719	$	4,525

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Long-Term Debt (Tables)

3 Months Ended

Mar. 31, 2018

Debt Disclosure [Abstract]

Schedule of Long-Term Debt

At March 31, 2018 and December 31, 2017, long-term debt consisted of the following:

	March 31, 2018		December 31, 2017
$664,444 Revolving credit facility at variable interest rate (4.86%1 weighted average at March 31, 2018), 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 $5,573 and $4,986, respectively2,3	$	422,427	$	440,014
$400,000 Senior notes, 7.25% interest, net of unamortized debt issuance costs of $1,967 and $2,138, respectively, including unamortized premium of $879 and $956, respectively, issued $250,000 February 2013 and $150,000 April 2014, $26,200 repurchased during 2015, due February 2021, unsecured3,4	372,712		372,618
Total long-term debt, net	$	795,139	$	812,632

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 March 31, 2018 and December 31, 2017 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 March 31, 2018 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 On February 21, 2018, the Partnership amended its revolving credit facility to, among other things, (i) create an inventory financing sublimit tranche, which is a part of and not in addition to the already existing commitments under the revolving credit facility, under which availability is subject to a borrowing base calculated by reference to eligible petroleum products inventory, (ii) exclude the amount of loans under the inventory financing sublimit tranche from total outstanding indebtedness for purposes of determining leverage ratio covenants under the revolving credit facility, (iii) increase the maximum permitted leverage ratio (as defined in the credit agreement, being generally computed as the ratio of total funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) from 5.25 to 1.00, with a temporary springing provision to 5.50 to 1.00 under certain scenarios, to 5.75 to 1.00 for the first and second quarters of 2018, 5.50 to 1.00 for the next three quarters and 5.25 to 1.00, with the temporary springing provision to 5.50 to 1.00 going back into effect, thereafter and (iv) decrease the maximum permitted senior leverage ratio (as defined in the credit agreement, being generally computed as the ratio of total secured funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) from 3.50 to 1.00 to 3.25 to 1.00. The maximum amount of the inventory financing sublimit tranche is $10,000 during the period between March 1 and June 30 of each year, and $75,000 at all

other times during each year.

³ The Partnership is in compliance with all debt covenants as of March 31, 2018 and December 31, 2017, respectively.

⁴ The 2021 indenture restricts the Partnership’s ability to sell assets; pay distributions or repurchase units or redeem or repurchase subordinated debt; make investments; incur or guarantee additional indebtedness or issue preferred units; and consolidate, merge or transfer all or substantially all of its assets.

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Supplemental Balance Sheet Information (Tables)

3 Months Ended

Mar. 31, 2018

Balance Sheet Related Disclosures [Abstract]

Schedule of Other Assets

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

	March 31, 2018		December 31, 2017
Customer contracts and relationships, net	$	23,484	$	25,252
Other intangible assets	1,624		1,752
Other	4,671		5,797
	$	29,779	$	32,801

Schedule of Other Accrued Liabilities

Components of "Other accrued liabilities" were as follows:

	March 31, 2018		December 31, 2017
Accrued interest	$	4,952	$	11,726
Asset retirement obligations	3,360		5,429
Property and other taxes payable	3,279		5,638
Accrued payroll	3,636		3,385
Other	7		162
	$	15,234	$	26,340

Schedule of Asset Retirement Obligations

The schedule below summarizes the changes in our asset retirement obligations:

	March 31, 2018
Beginning asset retirement obligations	$	13,512
Revisions to existing liabilities1	4,756
Accretion expense	147
Liabilities settled	(4,360		)
Ending asset retirement obligations	14,055
Current portion of asset retirement obligations2	(3,360		)
Long-term portion of asset retirement obligations3	$	10,695

¹Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, discount rates, and the estimated remaining useful life of the assets. The 2018 revisions reflect changes in removal cost estimates and the estimated remaining useful life of assets. 

²The current portion of asset retirement obligations is included in "Other current liabilities" on the Partnership's Consolidated and Condensed Balance Sheets.

³The non-current portion of asset retirement obligations is included in "Other long-term obligations" on the Partnership's Consolidated and Condensed Balance Sheets.

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Derivative Instruments and Hedging Activities (Tables)

3 Months Ended

Mar. 31, 2018

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 and Condensed Balance Sheets
	Derivative Assets					Derivative Liabilities
		Fair Values					Fair Values
	Balance Sheet Location	March 31, 2018		December 31, 2017		Balance Sheet Location	March 31, 2018		December 31, 2017
Derivatives not designated as hedging instruments:	Current:
Commodity contracts	Fair value of derivatives	$	82	$	—	Fair value of derivatives	$	—	$	72
Total derivatives not designated as hedging instruments		$	82	$	—		$	—	$	72

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 March 31, 2018 and 2017

	Location of Gain (Loss) Recognized in Income on  Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives
		2018		2017
Derivatives not designated as hedging instruments:
Commodity contracts	Cost of products sold	$	2,470	$	(2,495	)
Total effect of derivatives not designated as hedging instruments		$	2,470	$	(2,495	)

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Partners' Capital (Tables)

3 Months Ended

Mar. 31, 2018

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 March 31,
	2018			2017
Net income	$	12,818		$	13,583
Less general partner’s interest in net income (loss):
Distributions payable on behalf of IDRs	—			—
Distributions payable on behalf of general partner interest	392			392
General partner interest in undistributed loss	(136		)	(120		)
Less income allocable to unvested restricted units	8			35
Limited partners’ interest in net income (loss)	$	12,554		$	13,276

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 March 31,
	2018	2017
Basic weighted average limited partner units outstanding	38,621,375	37,321,263
Dilutive effect of restricted units issued	8,252	46,121
Total weighted average limited partner diluted units outstanding	38,629,627	37,367,384

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Unit Based Awards (Tables)

3 Months Ended

Mar. 31, 2018

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 March 31,
	2018		2017
Employees	$	96	$	159
Non-employee directors	36		27
Total unit-based compensation expense	$	132	$	186

Summary of Restricted Unit Activity

A summary of the restricted unit activity for the three months ended March 31, 2018 is provided below:

	Number of Units			Weighted Average Grant-Date Fair Value Per Unit
Non-vested, beginning of period	98,750			$	24.80
Granted (TBRU)	315,500			$	13.89
Granted (PBRU)	317,925			$	13.89
Vested	(80,550		)	$	27.71
Forfeited	(7,000		)	$	13.90
Non-Vested, end of period	644,625			$	13.91
Aggregate intrinsic value, end of period	$	8,702

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 three months ended March 31, 2018 and 2017 is provided below:

	Three Months Ended March 31,
	2018		2017
Aggregate intrinsic value of units vested	$	1,188	$	125
Fair value of units vested	2,232		170

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Related Party Transactions (Tables)

3 Months Ended

Mar. 31, 2018

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 March 31,
	2018		2017
Revenues:
Terminalling and storage	$	20,025	$	19,704
Marine transportation	3,613		4,325
Natural gas services	—		112
Product sales:
Natural gas services	1		942
Sulfur services	386		431
Terminalling and storage	255		57
	642		1,430
	$	24,280	$	25,571

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

	Three Months Ended March 31,
	2018		2017
Cost of products sold:
Natural gas services	$	4,318	$	8,894
Sulfur services	4,526		3,675
Terminalling and storage	6,558		5,067
	$	15,402	$	17,636

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

	Three Months Ended March 31,
	2018		2017
Operating expenses:
Marine transportation	$	5,321	$	5,996
Natural gas services	2,199		2,235
Sulfur services	1,339		1,446
Terminalling and storage	4,525		6,699
	$	13,384	$	16,376

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

	Three Months Ended March 31,
	2018		2017
Selling, general and administrative:
Marine transportation	$	8	$	8
Natural gas services	2,254		2,277
Sulfur services	659		636
Terminalling and storage	681		543
Indirect, including overhead allocation	4,119		4,104
	$	7,721	$	7,568

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Business Segments (Tables)

3 Months Ended

Mar. 31, 2018

Segment Reporting [Abstract]

Segment Reporting by Segment

Three Months Ended March 31, 2018	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	$	61,983	$	(1,439	)	$	60,544	$	10,159	$	2,722		$	2,121
Natural gas services	174,519		—			174,519		5,301		17,411			1,009
Sulfur services	37,687		—			37,687		2,064		6,992			1,548
Marine transportation	12,028		(574		)	11,454		1,686		1,163			8,291
Indirect selling, general and administrative	—		—			—		—		(4,231		)	—
Total	$	286,217	$	(2,013	)	$	284,204	$	19,210	$	24,057		$	12,969

Three Months Ended March 31, 2017	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	$	58,578	$	(1,773	)	$	56,805	$	15,477	$	(2,101	)	$	7,463
Natural gas services	141,322		—			141,322		6,161		18,273			852
Sulfur services	42,377		—			42,377		2,033		10,767			305
Marine transportation	13,414		(593		)	12,821		1,665		1,229			694
Indirect selling, general and administrative	—		—			—		—		(4,420		)	—
Total	$	255,691	$	(2,366	)	$	253,325	$	25,336	$	23,748		$	9,314

Assets by Segment

The Partnership's assets by reportable segment as of March 31, 2018 and December 31, 2017, are as follows:

	March 31, 2018		December 31, 2017
Total assets:
Terminalling and storage	$	327,318	$	326,920
Natural gas services	647,193		704,524
Sulfur services	128,064		120,790
Marine transportation	108,486		101,264
Total assets	$	1,211,061	$	1,253,498

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2018

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis

	March 31, 2018				December 31, 2017
	Carrying Value		Fair Value		Carrying Value		Fair Value
2021 Senior unsecured notes	$	372,712	$	377,071	$	372,618	$	381,657

Assets and liabilities measured at fair value on a recurring basis are summarized below:

	Level 2
	March 31, 2018		December 31, 2017
Commodity derivative contracts, net	$	82	$	(72	)

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Nature of Operations and Basis of Presentation (Details)	3 Months Ended
	Mar. 31, 2018 segment
Accounting Policies [Abstract]
Number of primary business lines	4

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Acquisitions - Narrative (Details) - USD ($) $ in Thousands		3 Months Ended
	Feb. 22, 2017	Mar. 31, 2018	Mar. 31, 2017
Business Acquisition [Line Items]
Excess purchase price over carrying value of acquired assets		$ 26	$ 7,887
MEH South Texas Terminals LLC
Business Acquisition [Line Items]
Percentage of voting interests acquired	100.00%
Purchase price	$ 27,420	27,420
Excess purchase price over carrying value of acquired assets	$ 7,887	7,913
Purchase price true-up		$ 26
Excess purchase price over carrying value of acquired assets, percentage	3.00%

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Acquisitions - Purchase Price (Details) - USD ($) $ in Thousands		3 Months Ended
	Feb. 22, 2017	Mar. 31, 2018	Mar. 31, 2017
Business Acquisition [Line Items]
Excess purchase price over carrying value of acquired assets		$ 26	$ 7,887
MEH South Texas Terminals LLC
Business Acquisition [Line Items]
Original purchase price	$ 27,420	27,420
Purchase price true-up		26
Historical carrying value of assets allocated to Property, plant and equipment		19,533
Excess purchase price over carrying value of acquired assets	$ 7,887	$ 7,913

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Divestitures, Asset Impairments, and Discontinued Operations - (Long-Lived Assets Held-for-Sale) (Details) - Disposal Group, Held-for-sale, Not Discontinued Operations - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long lived assets held-for-sale fair value disclosure	$ 9,442	$ 9,579
Terminalling and storage
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long lived assets held-for-sale fair value disclosure	4,242	4,152
Marine transportation
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long lived assets held-for-sale fair value disclosure	$ 5,200	$ 5,427

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Revenue - Dissagregation of Revenue (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Terminalling and storage segment
Disaggregation of Revenue [Line Items]
Revenue	$ 60,544	$ 56,805
Terminalling and storage segment | Lubricant product sales
Disaggregation of Revenue [Line Items]
Revenue	36,480	32,147
Terminalling and storage segment | Throughput and storage
Disaggregation of Revenue [Line Items]
Revenue	24,064	24,658
Natural gas services segment
Disaggregation of Revenue [Line Items]
Revenue	174,519	141,322
Natural gas services segment | Natural gas liquids product sales
Disaggregation of Revenue [Line Items]
Revenue	159,163	126,657
Natural gas services segment | Natural gas storage
Disaggregation of Revenue [Line Items]
Revenue	15,356	14,665
Sulfur service segment
Disaggregation of Revenue [Line Items]
Revenue	37,687	42,377
Sulfur service segment | Sulfur product sales
Disaggregation of Revenue [Line Items]
Revenue	11,837	13,080
Sulfur service segment | Fertilizer product sales
Disaggregation of Revenue [Line Items]
Revenue	23,063	26,447
Sulfur service segment | Sulfur services
Disaggregation of Revenue [Line Items]
Revenue	2,787	2,850
Marine transportation segment
Disaggregation of Revenue [Line Items]
Revenue	11,454	12,821
Marine transportation segment | Inland transportation
Disaggregation of Revenue [Line Items]
Revenue	9,692	11,291
Marine transportation segment | Offshore transportation
Disaggregation of Revenue [Line Items]
Revenue	$ 1,762	$ 1,530

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Revenue - Estimated Revenue Expected to be Recognized in Future (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2018 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 86,152
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-01-01 | Storage and throughput | Terminalling and storage
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 37,571
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-01-01 | Natural gas storage | Natural gas services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 31,309
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-01-01 | Sulfur product sales | Sulfur services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 12,597
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-01-01 | Offshore transportation | Marine transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 4,675
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 106,562
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01 | Storage and throughput | Terminalling and storage
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 50,629
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01 | Natural gas storage | Natural gas services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 32,932
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01 | Sulfur product sales | Sulfur services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 16,796
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01 | Offshore transportation | Marine transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 6,205
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 87,308
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | Storage and throughput | Terminalling and storage
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 49,330
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | Natural gas storage | Natural gas services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 27,011
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | Sulfur product sales | Sulfur services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 4,898
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | Offshore transportation | Marine transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 6,069
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 72,337
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Storage and throughput | Terminalling and storage
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 46,022
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Natural gas storage | Natural gas services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 25,134
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Sulfur product sales | Sulfur services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 1,181
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Offshore transportation | Marine transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 0
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 66,415
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Storage and throughput | Terminalling and storage
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 41,505
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Natural gas storage | Natural gas services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 24,615
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Sulfur product sales | Sulfur services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 295
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Offshore transportation | Marine transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 0
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 405,768
Revenue, remaining performance obligation, expected timing of satisfaction, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Storage and throughput | Terminalling and storage
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 393,700
Revenue, remaining performance obligation, expected timing of satisfaction, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Natural gas storage | Natural gas services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 12,068
Revenue, remaining performance obligation, expected timing of satisfaction, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Sulfur product sales | Sulfur services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 0
Revenue, remaining performance obligation, expected timing of satisfaction, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Offshore transportation | Marine transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 0
Revenue, remaining performance obligation, expected timing of satisfaction, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 824,542
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | Storage and throughput | Terminalling and storage
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	618,757
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | Natural gas storage | Natural gas services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	153,069
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | Sulfur product sales | Sulfur services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	35,767
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | Offshore transportation | Marine transportation
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 16,949

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Inventories (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Inventory Disclosure [Abstract]
Natural gas liquids	$ 18,922	$ 47,462
Sulfur	11,299	8,436
Sulfur based products	19,107	18,674
Lubricants	21,874	20,086
Other	2,692	2,594
Inventories	$ 73,894	$ 97,252

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Investment in West Texas LPG Pipeline L.P. - Narrative (Details) - West Texas LPG Pipeline L.P.	Mar. 31, 2018 mi
Schedule of Equity Method Investments [Line Items]
Ownership percentage	20.00%
Length of common-carrier pipeline system (in miles)	2,300
Common Limited
Schedule of Equity Method Investments [Line Items]
Ownership percentage	19.80%
General Partner
Schedule of Equity Method Investments [Line Items]
Ownership percentage	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
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Schedule of Equity Method Investments [Line Items]
Total Assets	$ 870,691		$ 837,163
Long-Term Debt	0		0
Members' Equity	839,028		$ 787,426
Revenues	23,041	$ 19,719
Net Income	$ 7,706	$ 4,525

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Long-Term Debt (Details)	3 Months Ended
	Mar. 31, 2018 USD ($)	Mar. 31, 2017 USD ($)	Feb. 21, 2018 USD ($)	Feb. 20, 2018	Dec. 31, 2017 USD ($)	Dec. 31, 2015 USD ($)	Apr. 30, 2014 USD ($)	Feb. 28, 2013 USD ($)
Debt Instrument [Line Items]
Total long-term debt, net	$ 795,139,000				$ 812,632,000
Cash paid for interest	18,878,000	$ 18,181,000
Capitalized interest	161,000	$ 223,000
Revolving Loan Facility
Debt Instrument [Line Items]
Total long-term debt, net	422,427,000				440,014,000
Face amount	$ 664,444,000
Weighted average interest rate	4.86%
Unamortized debt issuance costs	$ 5,573,000				4,986,000
Debt instrument, covenant, leverage ratio, maximum				5.25
Debt instrument, covenant, leverage ratio with temporary springing provision, maximum				5.50
Debt instrument, covenant, senior leverage ratio, maximum			3.25	3.50
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 7.25%
Debt Instrument [Line Items]
Total long-term debt, net	$ 372,712,000				372,618,000
Face amount	400,000,000						$ 150,000,000	$ 250,000,000
Unamortized debt issuance costs	$ 1,967,000				2,138,000
Stated interest rate	7.25%
Unamortized premium	$ 879,000				$ 956,000
Repurchase amount						$ 26,200,000
January 1, 2018 to June 30, 2018 | Revolving Loan Facility
Debt Instrument [Line Items]
Debt instrument, covenant, leverage ratio, maximum			5.75
July 1, 2018 to March 31, 2019 | Revolving Loan Facility
Debt Instrument [Line Items]
Debt instrument, covenant, leverage ratio, maximum			5.50
Subsequent to March 31, 2019 | Revolving Loan Facility
Debt Instrument [Line Items]
Debt instrument, covenant, leverage ratio, maximum			5.25
Debt instrument, covenant, leverage ratio with temporary springing provision, maximum			5.50
March 1 to June 30 of each year | Revolving Loan Facility
Debt Instrument [Line Items]
Debt instrument, covenant, inventory financing sublimit tranche, maximum			$ 10,000,000
Periods excluding March 1 to June 30 of each year | Revolving Loan Facility
Debt Instrument [Line Items]
Debt instrument, covenant, inventory financing sublimit tranche, maximum			$ 75,000,000

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Supplemental Balance Sheet Information - Other Assets (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Balance Sheet Related Disclosures [Abstract]
Customer contracts and relationships, net	$ 23,484	$ 25,252
Other intangible assets	1,624	1,752
Other	4,671	5,797
Other assets, net	29,779	32,801
Accumulated amortization of intangible assets	$ 41,984	$ 39,462

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Supplemental Balance Sheet Information - Other Accrued Liabilities (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Balance Sheet Related Disclosures [Abstract]
Accrued interest	$ 4,952	$ 11,726
Asset retirement obligations	3,360	5,429
Property and other taxes payable	3,279	5,638
Accrued payroll	3,636	3,385
Other	7	162
Total other accrued liabilities	$ 15,234	$ 26,340

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Supplemental Balance Sheet Information - Asset Retirement Obligations (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning asset retirement obligations	$ 13,512
Revisions to existing liabilities	4,756
Accretion expense	147
Liabilities settled	(4,360)
Ending asset retirement obligations	14,055
Current portion of asset retirement obligations	(3,360)	$ (5,429)
Long-term portion of asset retirement obligations	$ 10,695

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Derivative Instruments and Hedging Activities - Narrative (Details) - bbl	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Commodity contracts
Derivatives, Fair Value [Line Items]
Notional quantity (in bbl)	50	145

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Derivative Instruments and Hedging Activities - Balance Sheet Derivatives (Details) - Derivatives not designated as hedging instruments - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Derivative Assets	$ 82	$ 0
Derivative Liabilities	0	72
Commodity contracts | Fair value of derivatives
Derivatives, Fair Value [Line Items]
Derivative Assets	82	0
Derivative Liabilities	$ 0	$ 72

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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
	Mar. 31, 2018	Mar. 31, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	$ 2,470	$ (2,495)
Commodity contracts | Cost of products sold
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivatives	$ 2,470	$ (2,495)

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Partners' Capital (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended
	Feb. 22, 2017	Mar. 31, 2018	Mar. 31, 2017
Limited Partners' Capital Account [Line Items]
Common limited partner units (in shares)		39,052,237
Ownership percentage		98.00%
General partner interest percentage		2.00%
Common units sold in public offering (in shares)	2,990,000
Share price (USD per share)	$ 18.00
Proceeds from the sale of common units, net of offering costs	$ 51,188
General partner contribution	$ 1,098	$ 0	$ 1,098
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		16.00%
General partner interest percentage		2.00%
Voting interest percentage		16.00%

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Partners' Capital - Incentive Distribution Rights and Distributions of Available Cash (Details) - USD ($)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Limited Partners' Capital Account [Line Items]
General partner interest percentage	2.00%
Incentive distribution	$ 0	$ 0
Distribution period	45 days
Martin Midstream GP LLC
Limited Partners' Capital Account [Line Items]
General partner interest percentage	2.00%
Incentive distribution	$ 0	$ 0
Martin Midstream GP LLC | Target Level 1
Limited Partners' Capital Account [Line Items]
Target cash distribution, percent	2.00%
Target cash distribution (USD per share)	$ 0.55
Martin Midstream GP LLC | Target Level 2
Limited Partners' Capital Account [Line Items]
Target cash distribution, percent	15.00%
Target cash distribution (USD per share)	$ 0.625
Martin Midstream GP LLC | Target Level 3
Limited Partners' Capital Account [Line Items]
Target cash distribution, percent	25.00%
Target cash distribution (USD per share)	$ 0.75
Martin Midstream GP LLC | Target Level 4
Limited Partners' Capital Account [Line Items]
Target cash distribution, percent	50.00%
Minimum | Martin Midstream GP LLC | Target Level 1
Limited Partners' Capital Account [Line Items]
Target cash distribution (USD per share)	$ 0.50
Maximum | Martin Midstream GP LLC | Target Level 1
Limited Partners' Capital Account [Line Items]
Target cash distribution (USD per share)	$ 0.55

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Partners' Capital - Net Income Per Unit (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Partners' Capital Notes [Abstract]
Net income	$ 12,818	$ 13,583
Less general partner’s interest in net income (loss):
Distributions payable on behalf of IDRs	0	0
Distributions payable on behalf of general partner interest	392	392
General partner interest in undistributed loss	(136)	(120)
Less income allocable to unvested restricted units	8	35
Limited partners’ interest in net income (loss)	$ 12,554	$ 13,276
Basic weighted average limited partner units outstanding (in shares)	38,621,375	37,321,263
Dilutive effect of restricted units issued (in shares)	8,252	46,121
Total weighted average limited partner diluted units outstanding (in shares)	38,629,627	37,367,384

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Unit Based Awards - Schedule of Compensation Costs (Details) - Selling, General and Administrative Expenses - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total unit-based compensation expense	$ 132	$ 186
Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total unit-based compensation expense	96	159
Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total unit-based compensation expense	$ 36	$ 27

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Unit Based Awards - Narrative (Details) - USD ($) $ in Thousands							3 Months Ended
	Jan. 24, 2022	Jan. 24, 2021	Jan. 24, 2020	Jan. 24, 2019	Mar. 01, 2018	Feb. 20, 2018	Mar. 31, 2018	May 26, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized (in shares)								3,000,000
Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vested, number of units (in shares)							80,550
Unrecognized compensation cost related to non-vested restricted units							$ 4,431
Weighted average period for recognition (in years)							3 years 3 days
Restricted Units | Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)							3 years
Restricted Units | Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)							4 years
Time Based Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)							3 years
Granted, number of units (in shares)							315,500
Time Based Restricted Units | Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted, number of units (in shares)					301,550
Time Based Restricted Units | Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted, number of units (in shares)						4,650
Performance Based Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)							3 years
Granted, number of units (in shares)							317,925
Performance Based Restricted Units | Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted, number of units (in shares)					317,925
Scenario, Forecast | Time Based Restricted Units | Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vested, number of units (in shares)	1,550	1,550	1,550	1,550

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Unit Based Awards - Restricted Unit Activity (Details) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2018 USD ($) $ / shares shares
Restricted Units
Number of Units
Non-vested, beginning of period, number of units (in shares) | shares	98,750
Vested, number of units (in shares) | shares	(80,550)
Forfeited, number of units (in shares) | shares	(7,000)
Non-vested, end of period, number of units (in shares) | shares	644,625
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	$ 24.80
Vested, weighted average grant-date fair value per unit (USD per share) | $ / shares	27.71
Forfeited, weighted average grant-date fair value per unit (USD per share) | $ / shares	13.90
Non-vested, end of period, weighted average grant-date fair value per unit (USD per share) | $ / shares	$ 13.91
Aggregate intrinsic value, end of period | $	$ 8,702
Time Based Restricted Units
Number of Units
Granted, number of units (in shares) | shares	315,500
Weighted Average Grant-Date Fair Value Per Unit
Granted, weighted average grant-date fair value per unit (USD per share) | $ / shares	$ 13.89
Performance Based Restricted Units
Number of Units
Granted, number of units (in shares) | shares	317,925
Weighted Average Grant-Date Fair Value Per Unit
Granted, weighted average grant-date fair value per unit (USD per share) | $ / shares	$ 13.89

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Unit Based Awards - Intrinsic and Fair Value (Details) - Restricted Units - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate intrinsic value of units vested	$ 1,188	$ 125
Fair value of units vested	$ 2,232	$ 170

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Related Party Transactions (Details)	3 Months Ended
	Mar. 31, 2018 shares
Related Party Transaction [Line Items]
General partner interest percentage	2.00%
Martin Resource Management
Related Party Transaction [Line Items]
Number of shares owned (in shares)	6,264,532
Ownership percentage	16.00%
General partner interest percentage	2.00%
MMGP Holdings, LLC | Martin Resource Management
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
	Mar. 31, 2018	Mar. 31, 2017
Related Party Transaction [Line Items]
Noncompete restriction threshold	$ 5,000,000
Noncompete restriction ownership option opportunity threshold minimum	5,000,000
Noncompete restriction ownership option opportunity threshold minimum with equity limitation	$ 5,000,000
Equity limitation on ownership restriction percentage	20.00%
Approved annual reimbursements for indirect expenses	$ 16,416,000
Indirect expenses reimbursed	$ 4,104,000	$ 4,104,000

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Related Party Transactions - Motor Carrier Agreement (Details) - Motor Carrier Agreement - Martin Resource Management	3 Months Ended
	Mar. 31, 2018
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	3 Months Ended
	Mar. 31, 2018
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 - Terminal Services Agreements (Details)	3 Months Ended
	Mar. 31, 2018
Martin Resource Management
Related Party Transaction [Line Items]
Termination written notice, minimum (in days)	60 days

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Related Party Transactions - Other Agreements (Details) - Martin Resource Management	3 Months Ended
	Mar. 31, 2018 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)	90 days

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Related Party Transactions - Schedule of the impact of Related Party Transactions (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Revenues:
Terminalling and storage	$ 20,025	$ 19,704
Marine transportation	3,613	4,325
Natural gas services	0	112
Product sales:
Product sales related party	642	1,430
Cost of products sold:
Natural gas services	4,318	8,894
Sulfur services	4,526	3,675
Terminalling and storage	6,558	5,067
Operating expenses:
Operating expenses	13,384	16,376
Related Party
Product sales:
Product sales related party	642	1,430
Revenue from related parties	24,280	25,571
Cost of products sold:
Cost of products sold	15,402	17,636
Operating expenses:
Operating expenses	13,384	16,376
Selling, general and administrative:
Selling, general and administrative	7,721	7,568
Related Party | Terminalling and storage
Revenues:
Terminalling and storage	20,025	19,704
Product sales:
Product sales related party	255	57
Cost of products sold:
Terminalling and storage	6,558	5,067
Operating expenses:
Operating expenses	4,525	6,699
Selling, general and administrative:
Selling, general and administrative	681	543
Related Party | Marine transportation
Revenues:
Marine transportation	3,613	4,325
Operating expenses:
Operating expenses	5,321	5,996
Selling, general and administrative:
Selling, general and administrative	8	8
Related Party | Natural gas services
Revenues:
Natural gas services	0	112
Product sales:
Product sales related party	1	942
Cost of products sold:
Natural gas services	4,318	8,894
Operating expenses:
Operating expenses	2,199	2,235
Selling, general and administrative:
Selling, general and administrative	2,254	2,277
Related Party | Sulfur services
Product sales:
Product sales related party	386	431
Cost of products sold:
Sulfur services	4,526	3,675
Operating expenses:
Operating expenses	1,339	1,446
Selling, general and administrative:
Selling, general and administrative	659	636
Related Party | Indirect, including overhead allocation
Selling, general and administrative:
Selling, general and administrative	$ 4,119	$ 4,104

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Related Party Transactions - Other Related Party Transactions (Details) - Martin Energy Trading LLC - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Related Party Transaction [Line Items]
Due from related parties, annual interest rate	15.00%
Interest expense
Related Party Transaction [Line Items]
Interest income, related party	$ 0	$ 555
Notes Receivable
Related Party Transaction [Line Items]
Note receivable - affiliate	$ 15,000

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Business Segments (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2018 USD ($) segment	Mar. 31, 2017 USD ($)	Dec. 31, 2017 USD ($)
Segment Reporting [Abstract]
Number of reportable segments | segment	4
Segment Reporting Information [Line Items]
Total revenue	$ 284,204	$ 253,325
Depreciation and amortization	19,210	25,336
Operating Income (Loss) after Eliminations	24,057	23,748
Capital Expenditures and Plant Turnaround Costs	12,969	9,314
Total assets:
Total assets	1,211,061		$ 1,253,498
Terminalling and storage
Segment Reporting Information [Line Items]
Total revenue	60,544	56,805
Depreciation and amortization	10,159	15,477
Operating Income (Loss) after Eliminations	2,722	(2,101)
Capital Expenditures and Plant Turnaround Costs	2,121	7,463
Total assets:
Total assets	327,318		326,920
Natural gas services
Segment Reporting Information [Line Items]
Total revenue	174,519	141,322
Depreciation and amortization	5,301	6,161
Operating Income (Loss) after Eliminations	17,411	18,273
Capital Expenditures and Plant Turnaround Costs	1,009	852
Total assets:
Total assets	647,193		704,524
Sulfur services
Segment Reporting Information [Line Items]
Total revenue	37,687	42,377
Depreciation and amortization	2,064	2,033
Operating Income (Loss) after Eliminations	6,992	10,767
Capital Expenditures and Plant Turnaround Costs	1,548	305
Total assets:
Total assets	128,064		120,790
Marine transportation
Segment Reporting Information [Line Items]
Total revenue	11,454	12,821
Depreciation and amortization	1,686	1,665
Operating Income (Loss) after Eliminations	1,163	1,229
Capital Expenditures and Plant Turnaround Costs	8,291	694
Total assets:
Total assets	108,486		$ 101,264
Operating Revenues
Segment Reporting Information [Line Items]
Total revenue	286,217	255,691
Operating Revenues | Terminalling and storage
Segment Reporting Information [Line Items]
Total revenue	61,983	58,578
Operating Revenues | Natural gas services
Segment Reporting Information [Line Items]
Total revenue	174,519	141,322
Operating Revenues | Sulfur services
Segment Reporting Information [Line Items]
Total revenue	37,687	42,377
Operating Revenues | Marine transportation
Segment Reporting Information [Line Items]
Total revenue	12,028	13,414
Intersegment Revenues Eliminations
Segment Reporting Information [Line Items]
Total revenue	(2,013)	(2,366)
Intersegment Revenues Eliminations | Terminalling and storage
Segment Reporting Information [Line Items]
Total revenue	(1,439)	(1,773)
Intersegment Revenues Eliminations | Natural gas services
Segment Reporting Information [Line Items]
Total revenue	0	0
Intersegment Revenues Eliminations | Sulfur services
Segment Reporting Information [Line Items]
Total revenue	0	0
Intersegment Revenues Eliminations | Marine transportation
Segment Reporting Information [Line Items]
Total revenue	(574)	(593)
Indirect selling, general and administrative
Segment Reporting Information [Line Items]
Depreciation and amortization	0	0
Operating Income (Loss) after Eliminations	(4,231)	(4,420)
Capital Expenditures and Plant Turnaround Costs	$ 0	$ 0

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Commitments and Contingencies (Details) - USD ($) $ in Thousands		3 Months Ended	12 Months Ended
	Oct. 02, 2012	Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2018
Loss Contingencies [Line Items]
Non-cancelable revenue arrangements, future minimum revenues, 2018				$ 16,672
Non-cancelable revenue arrangements, future minimum revenues, 2019				19,199
Non-cancelable revenue arrangements, future minimum revenues, 2020				17,478
Non-cancelable revenue arrangements, future minimum revenues, 2021				15,589
Non-cancelable revenue arrangements, future minimum revenues, 2022				15,589
Non-cancelable revenue arrangements, future minimum revenues, subsequent years				$ 72,872
Martin Resource Management
Loss Contingencies [Line Items]
Quarterly purchase price reimbursement for non compliance	$ 750	$ 1,125
Maximum purchase price reimbursement for non compliance			$ 4,500

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Fair Value Measurements (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Recurring | Level 2 | Commodity contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	$ 82	$ (72)
Nonrecurring | 2021 Senior unsecured notes | Carrying Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
2021 Senior unsecured notes	372,712	372,618
Nonrecurring | 2021 Senior unsecured notes | Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
2021 Senior unsecured notes	$ 377,071	$ 381,657

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Subsequent Events (Details) - Subsequent Event	Apr. 19, 2018 $ / shares
Subsequent Event [Line Items]
Dividends declared (USD per share)	$ 0.50
Estimated annualized dividends (USD per share)	$ 2.00