10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

Mark One	Annual Report Pursuant to Section 13 or 15(d) of the
ý	Securities Exchange Act of 1934
	For the fiscal year ended December 31, 2017

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	(I.R.S. Employer Identification No.)

4200 Stone Road Kilgore, Texas  75662

(Address of principal executive offices)  (Zip Code)

903-983-6200

(Registrant’s telephone number, including area code)

_______________________

Securities Registered Pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Units representing limited partnership interests	NASDAQ Global Select Market

Securities Registered Pursuant to Section 12(g) of the Act:

NONE

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes  o                     No ý

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes o                        No ý

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 the past 90 days.

 Yes ý                        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 during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).

 Yes ý                        No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   ý

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of "large accelerated filer," "accelerated filer", "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	Smaller reporting company o
		(Do not check if a smaller reporting company)
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.  

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

Yes o                        No ý

As of June 30, 2017, 38,452,112 common units were outstanding.  The aggregate market value of the common units held by non-affiliates of the registrant as of such date approximated $564,892,029 based on the closing sale price on that date.  There were 38,425,812 of the registrant’s common units outstanding as of February 16, 2018.

DOCUMENTS INCORPORATED BY REFERENCE:         None.

TABLE OF CONTENTS

		Page
PART I		1
Item 1.	Business	1
Item 1A.	Risk Factors	19
Item 1B.	Unresolved Staff Comments	37
Item 2.	Properties	37
Item 3.	Legal Proceedings	37
Item 4.	Mine Safety Disclosures	37
PART II		38
Item 5.	Market for Our Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	38
Item 6.	Selected Financial Data	39
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	40
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	63
Item 8.	Financial Statements and Supplementary Data	64
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	100
Item 9A.	Controls and Procedures	100
Item 9B.	Other Information	101
PART III		102
Item 10.	Directors, Executive Officers and Corporate Governance	102
Item 11.	Executive Compensation	107
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	113
Item 13.	Certain Relationships and Related Transactions, and Director Independence	116
Item 14.	Principal Accounting Fees and Services	121
PART IV		122
Item 15.	Exhibits, Financial Statement Schedules	122

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PART I

Item 1. Business

References in this annual report to "we," "ours," "us" or like terms when used in a historical context refer to the assets and operations of Martin Resource Management's business contributed to us in connection with our initial public offering on November 6, 2002. References in this annual report to "Martin Resource Management" refer to Martin Resource Management Corporation and its subsidiaries, unless the context otherwise requires. References in this annual report to the "Partnership" refer to Martin Midstream Partners L.P. and its subsidiaries, unless the content otherwise requires. You should read the following discussion of our financial condition and results of operations in conjunction with the consolidated financial statements and the notes thereto included elsewhere in this annual report. For more detailed information regarding the basis for presentation for the following information, you should read the notes to the consolidated financial statements included elsewhere in this annual report.

Forward-Looking Statements

This annual report on Form 10-K 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 annual 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), 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 below in "Item 1A. Risk Factors - Risks Related to our Business."

Overview

We are a publicly traded limited partnership with a diverse set of operations focused primarily in the United States ("U.S.") Gulf Coast region. Our four primary business lines include:

• Terminalling and storage services for petroleum products and by-products, including the refining of naphthenic crude oil and the blending and packaging of finished lubricants;

• Natural gas liquids transportation and distribution services and natural gas storage;

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

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

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

We were formed in 2002 by Martin Resource Management, a privately-held company whose initial predecessor was incorporated in 1951 as a supplier of products and services to drilling rig contractors. Since then, Martin Resource Management has expanded its operations through acquisitions and internal expansion initiatives as its management identified

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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 December 31, 2017, Martin Resource Management owned 16.3% of our total outstanding common limited partner units. Furthermore, Martin Resource Management 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.

Primary Business Segments

Our primary business segments can be generally described as follows:

• Terminalling and Storage.  We own or operate 22 marine shore-based terminal facilities and 16 specialty terminal facilities located primarily in the U.S. Gulf Coast region that provide storage, refining, blending, packaging, and handling services for producers and suppliers of petroleum products and by-products, including the refining of naphthenic crude oil and the blending and packaging of various grades and quantities of industrial, commercial, and automotive lubricants and greases. Our facilities and resources provide us with the ability to handle various products that require specialized treatment, such as molten sulfur and asphalt. We also provide land rental to oil and gas companies along with storage and handling services for lubricants and fuels. We provide these terminalling and storage services on a fee basis primarily under long-term contracts. A significant portion of the contracts in this segment provide for minimum fee arrangements that are not based on the volumes handled.

• Natural Gas Services.  We distribute natural gas liquids ("NGLs"). We purchase NGLs primarily from refineries and natural gas processors. We store and transport NGLs for wholesale deliveries to refineries, industrial NGL users in Texas and the Southeastern U.S, and propane retailers. We own a NGL pipeline, which spans approximately 200 miles from Kilgore, Texas to Beaumont, Texas. We own approximately 2.4 million barrels of underground storage capacity for NGLs. Additionally, we own 100% of the interests in Cardinal Gas Storage Partners LLC ("Cardinal"), which is focused on the operation and management of natural gas storage facilities across northern Louisiana and Mississippi. We own a combined 20% interest in West Texas LPG Pipeline Limited Partnership ("WTLPG"). WTLPG is operated by ONEOK Inc. ("ONEOK"), which owns the remaining 80.0% interest. WTLPG owns an approximate 2,300 mile common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas, and to a lesser extent other markets, for fractionation. This asset enables us to participate in the transportation of NGL production originating in the Permian and other basins along the WTLPG pipeline route.

• Sulfur Services.  We have developed an integrated system of transportation assets and facilities relating to sulfur services. We process and distribute sulfur produced by oil refineries primarily located in the U.S. Gulf Coast region. We buy and sell molten sulfur on contracts that are tied to sulfur indices and tend to provide stable margins. We process molten sulfur into prilled or pelletized sulfur at our facilities in Port of Stockton, California and Beaumont, Texas on contracts that often provide guaranteed minimum fees. The sulfur we process and handle is primarily used in the production of fertilizers and industrial chemicals. We own and operate five sulfur-based fertilizer production plants and one emulsified sulfur blending plant that manufactures primarily sulfur-based fertilizer products for wholesale distributors and industrial users. These plants are located in Texas and Illinois. Demand for our sulfur products exist in both the domestic and foreign markets, and our asset base provides additional opportunities to handle increases in U.S. supply and access to foreign demand.

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• Marine Transportation.  We operate a fleet of 33 inland marine tank barges, 18 inland push boats and one offshore tug and barge unit that transport petroleum products and by-products largely in the U.S. Gulf Coast region. We provide these transportation services on a fee basis primarily under annual contracts, and many of our customers have long standing contractual relationships with us. Our modernized asset base is attractive both to our existing customers as well as potential new customers. In addition, our fleet contains several vessels that reflect our focus on specialty products.

Our Growth Strategy

The key components of our growth strategy are:

• Pursue Organic Growth Projects. We continually evaluate economically attractive organic expansion opportunities in new or existing areas of operation that will allow us to leverage our existing market position and increase the distributable cash flow from our existing assets through improved utilization and efficiency.

• Pursue Internal Organic Growth by Attracting New Customers and Expanding Services Provided to Existing Customers. Opportunities exist to expand our customer base and provide additional services and products to existing customers. We generally begin a relationship with a customer by transporting, storing or marketing a limited range of products and services. Expanding our customer base and our service and product offerings to existing customers is an efficient and cost effective method of achieving organic growth in revenues and cash flow.

• Pursue Strategic Acquisitions. We continually monitor the marketplace to identify and pursue accretive acquisitions that expand the services and products we offer or that expand our geographic presence. After acquiring other businesses, we attempt to utilize our industry knowledge, network of customers and suppliers and strategic asset base to operate the acquired businesses more efficiently and competitively, thereby increasing revenues and cash flow. Our diversified base of operations provides multiple platforms for strategic growth through acquisitions.

• Pursue Strategic Commercial Alliances. Many of our larger customers, which include major integrated energy companies, have established strategic alliances with midstream service providers such as us to address logistical and transportation problems or achieve operational synergies. We intend to pursue strategic commercial alliances with such customers in the future.

Competitive Strengths

Fee-Based Contracts. We generate a majority of our cash flow from fee-based contracts with our customers. A significant portion of the fee-based contracts consist of reservation charges or minimum fee arrangements, which reduce the volatility of our cash flows due to volume fluctuations.

Asset Base and Integrated Distribution Network. We operate a diversified asset base that enables us to offer our customers an integrated distribution network consisting of transportation, terminalling and storage and midstream logistical services for petroleum products and by-products.

Strategically Located Assets. A significant portion of our cash flow comes from providing various services to the oil refining industry.  Accordingly, a significant portion of our assets are located in proximity to refining operations along the U.S. Gulf Coast.  For example, we are one of the largest operators of marine service shore-based terminals in the U.S. Gulf Coast region providing broad geographic coverage and distribution capability of our products and services to our customers. Our natural gas storage and NGL distribution and storage assets are located in areas highly desirable for our customers. Finally, many of our sulfur services assets are strategically located to source sulfur from the largest refinery sources in the U.S.

Specialized Transportation Equipment and Storage Facilities. We have the assets and expertise to handle and transport certain petroleum products and by-products with unique requirements for transportation and storage. For example, we own facilities and resources to transport a variety of specialty products, including ammonia, molten sulfur and asphalt. Some of these specialty products require treatment across a wide range of temperatures ranging between approximately -30 to +400 degrees Fahrenheit to remain in liquid form, which our facilities are designed to accommodate. These capabilities help us enhance relationships with our customers by offering them services to handle their unique product requirements.

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Strong Industry Reputation and Established Relationships with Suppliers and Customers. We have established a reputation in our industry as a reliable and cost-effective supplier of services to our customers and have a track record of safe, efficient operation of our facilities. Our management has also established long-term relationships with many of our suppliers and customers. We benefit from our management's reputation and track record and from these long-term relationships.

Experienced Management Team and Operational Expertise. Members of our executive management team and the heads of our principal business lines have a significant amount of experience in the industries in which we operate. Our management team has a successful track record of creating internal growth and completing acquisitions. Our management team's experience and familiarity with our industry and businesses are important assets that assist us in implementing our business strategies.

Terminalling and Storage Segment

Industry Overview.  The U.S. petroleum distribution system moves petroleum products and by-products from oil refineries and natural gas processing facilities to end users. This distribution system is comprised of a network of terminals, storage facilities, pipelines, tankers, barges, railcars and trucks. Terminals play a key role in moving these products throughout the distribution system by providing storage, blending and other ancillary services.

Although many large energy and chemical companies own terminalling and storage facilities, these companies also use third-party terminalling and storage services. Major energy and chemical companies typically have a strong demand for terminals owned by independent operators when such terminals are strategically located at or near key transportation links, such as deep-water ports. Major energy and chemical companies also need independent terminal storage when their owned storage facilities are inadequate, either because of lack of capacity, the nature of the stored material or specialized handling requirements.

The Gulf Coast region is a major hub for petroleum refining. Approximately 50% of U.S. refining capacity exists in this region. Growth in the refining and natural gas processing industries has increased the volume of petroleum products and by-products that are transported within the Gulf Coast region, which consequently has increased the need for terminalling and storage services.

The marine and offshore oil and gas exploration and production industries use terminal facilities in the Gulf Coast region as shore bases that provide them logistical support services as well as provide a broad range of products, including fuel oil, lubricants, chemicals and supplies. The demand for these types of terminals, services and products is driven primarily by offshore exploration, development and production in the Gulf of Mexico. Offshore activity is greatly influenced by current and projected prices of oil and natural gas.

Specialty Petroleum Terminals.  We own or operate 16 terminalling facilities providing storage, handling and transportation of various petroleum products and by-products. The locations and capabilities of our terminals are structured to complement our other businesses and reflect our strategy to provide a broad range of integrated services in the storage, handling and transportation of products. We developed our terminalling and storage assets by acquisition and upgrades of existing facilities as well as developing our own properties strategically located near rail, waterways and pipelines. We anticipate further expansion of our terminalling facilities through both acquisition and organic growth.

The Tampa terminal is located on approximately 10 acres of land owned by the Tampa Port Authority that was leased to us under a 10-year lease that commenced on December 16, 2006. In December of 2016, this lease was extended to December of 2021 and may be extended at the option of the tenant for one additional option period of five years. The Stanolind terminal is located on approximately 11 acres of land owned by us located on the Neches River in Beaumont, Texas.  The Neches terminal is a deep water marine terminal located near Beaumont, Texas, on approximately 50 acres of land owned by us, and an additional 96 acres leased to us under terms of a 20-year lease commencing May 1, 2014 with three five-year options.

At the Neches and Stanolind terminals, our customers are primarily large oil refining companies. We charge either a fixed monthly fee or a throughput fee for the use of our facilities based on the capacity of the applicable tank. We conduct a substantial portion of our terminalling and storage operations under long-term contracts, which enhances the stability and predictability of our operations and cash flow. We attempt to balance our short-term and long-term terminalling contracts in order to allow us to maintain a consistent level of cash flow while maintaining flexibility to earn higher storage revenues when demand for storage space increases. In addition, a significant portion of the contracts for our specialty terminals provide for minimum fee arrangements that are not based on the volume handled.

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In Houston, Texas, we own and operate a terminal used for lubricant blending, storage, packaging and distribution. This terminal is used as our central hub for bulk lubricant distribution where we receive, package and ship lubricants to our terminals or directly to customers.

In Smackover, Arkansas, we own a refinery and terminal where we process crude oil into finished products that include naphthenic lubricants, distillates, asphalt and other intermediates.  This process is dedicated to an affiliate of Martin Resource Management through a long-term tolling agreement based on throughput rates and a monthly reservation fee.

In Smackover, Arkansas, we own and operate a terminal used for lubricant blending, processing, packaging, marketing and distribution. This terminal is used as our central hub for branded and private label packaged lubricants where we receive, package and ship heavy-duty, passenger car, and industrial lubricants to a network of retailers and distributors.

In Kansas City, Missouri, we lease and operate a plant that specializes in the processing and packaging of automotive, commercial and industrial greases.

In Houston, Texas, we own and operate a plant that specializes in the processing and packaging of post tension greases.

In Hondo, Texas, we own an asphalt terminal whose use is dedicated to an affiliate of Martin Resource Management through a terminalling service agreement based on throughput rates.

In South Houston, Texas, we own an asphalt terminal whose use is dedicated to an affiliate of Martin Resource Management through a terminalling service agreement based on throughput rates.

In Port Neches, Texas, we own an asphalt terminal whose use is dedicated to an affiliate of Martin Resource Management through a terminalling service agreement based upon throughput rates.

In Omaha, Nebraska, we own an asphalt terminal whose use is dedicated to an affiliate of Martin Resource Management through a terminalling service agreement based on throughput rates.

In Elko, Nevada, we lease and operate a sulfuric acid terminal whose use is dedicated to an affiliate of Martin Resource Management through a terminalling service agreement based on throughput rates.

In Beaumont, Texas we own a terminal where we receive natural gasoline via pipeline and then ship the product to our customers via other pipelines to which the facility is connected, referred to as the "Spindletop Terminal."  Our fees for the use of this facility are based on the volume of barrels shipped from the terminal.

In Jennings, Louisiana, we own a lubricant terminal whose use is dedicated to an affiliate of Martin Resource Management through a terminalling service agreement based on throughput rates.

The following is a summary description of our shore-based specialty terminals:

Terminal	Location	Aggregate Capacity (in barrels)	Products	Description
Tampa (1)	Tampa, Florida	719,000	Asphalt and fuel oil	Marine terminal, loading/unloading for vessels, barges, railcars and trucks
Stanolind	Beaumont, Texas	617,500	Asphalt, crude oil, sulfur, sulfuric acid and fuel oil	Marine terminal, marine dock for loading/unloading of vessels, barges, railcars and trucks
Neches	Beaumont, Texas	556,800	Molten sulfur, ammonia, asphalt, fuel oil, crude oil and sulfur-based fertilizer	Marine terminal, loading/unloading for vessels, barges, railcars and trucks

(1) This terminal is located on land owned by the Tampa Port Authority that was leased to us under a 10-year lease that expires in December 2021. This lease may be extended at the option of the tenant for one option period of five years.

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The following is a summary description of our non shore-based specialty terminals:

Terminal	Location	Aggregate Capacity	Products	Description
Channelview	Houston, Texas	39,800 barrels	Lubricants	Lubricants blending, storage, packaging and distribution
Smackover Refinery	Smackover, Arkansas	7,700 barrels per day	Naphthenic lubricants, distillates, asphalt	Crude refining facility
Smackover Refinery	Smackover, Arkansas	275,000 barrels of crude bulk storage; 641,000 barrels of lubricant storage	Crude oil, lubricants	Crude refining facility
Martin Lubricants	Smackover, Arkansas	3.9 million gallons bulk storage	Gard, SynGard, Unimark and Xtreme brands, and grease	Lubricants packaging facility
Martin Lubricants (1)	Kansas City, Missouri	0.2 million gallons bulk storage	Automotive, commercial and industrial greases	Grease manufacturing and packaging facility
Martin Lubricants	Houston, Texas	0.2 million gallons of bulk storage	Post tension greases	Grease manufacturing and packaging facility
Hondo Asphalt	Hondo, Texas	182,100 barrels	Asphalt	Asphalt processing and storage
South Houston Asphalt	Houston, Texas	95,500 barrels	Asphalt	Asphalt processing and storage
Port Neches Asphalt	Port Neches, Texas	30,100 barrels	Asphalt	Asphalt processing and storage
Omaha Asphalt	Omaha, Nebraska	113,900 barrels	Asphalt	Asphalt processing and storage
Dunphy (2)	Elko, Nevada	63,200 barrels	Sulfuric acid	Sulfuric acid storage
Spindletop	Beaumont, Texas	90,000 barrels	Natural gasoline	Pipeline receipts and shipments
Jennings Bulk Plant	Jennings, Louisiana	6,800 barrels	Lubricants, fuel	Lubricants and fuel storage

(1) This terminal contains a warehouse owned by third parties and leased under a lease that expires in December 2020 and can be extended by us for two successive five-year periods.

(2) This terminal is located on land owned by third parties and leased under a lease that expires in May 2024 and can be extended by us for two successive five-year periods.

Marine Shore-Based Terminals.  We own or operate 22 marine shore-based terminals along the Gulf Coast from Theodore, Alabama to Corpus Christi, Texas.   Our terminalling assets are located at strategic distribution points for the products we handle and are in close proximity to our customers. We are one of the largest operators of marine shore-based terminals in the Gulf Coast region. These terminals are used to distribute and market fuel and lubricants. Additionally, full service terminals also provide shore bases for companies that are operating in the offshore exploration and production industry. Customers are primarily oil and gas exploration and production companies and oilfield service companies, such as drilling fluid companies, marine transportation companies and offshore construction companies. Shore bases typically provide logistical support, including the storing and handling of tubular goods, loading and unloading bulk materials, providing facilities from which major and independent oil companies can communicate with and control offshore operations and leasing dockside facilities to companies which provide complementary products and services such as drilling fluids and cementing services. We generate revenues from our terminals that have shore bases by fees that we charge our customers under land rental contracts for the use of our terminal facility for these shore bases. These contracts generally provide us a fixed land rental fee and additional rental fees that are determined based on a percentage of the sales value of the products and services delivered from the shore base. In addition, Martin Resource Management, through terminalling service agreements, pays us for terminalling and storage of fuels and lubricants at these terminal facilities and includes a provision for minimum volume throughput requirements.

Our marine shore-based terminals are divided into two classes of terminals: (i) full service terminals and (ii) fuel and lubricant terminals.

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Full Service Terminals.  We own or operate 8 full service terminals. These facilities provide logistical support services and storage and handling services for fuel and lubricants.  The significant difference between our full service terminals and our fuel and lubricant terminals is that our full service terminals generate additional revenues by providing shore bases to support our customer’s operating activities related to the offshore exploration and production industry. One typical use for our shore bases is for drilling fluids manufacturers to manufacture and sell drilling fluids to the offshore drilling industry. Offshore drilling companies may also set up service facilities at these terminals to support their offshore operations. Customers of our full service terminals are primarily oil and gas exploration and production companies, oilfield service companies such as drilling fluids companies, marine transportation companies and offshore construction companies.

The following is a summary description of our full service terminals:

Terminal	Location	Aggregate Capacity (barrels)	End of Lease (Including Options)
Amelia	Amelia, Louisiana	13,000	August 2023
Cameron West (1)	Cameron, Louisiana	—	February 2033
Dock 193 (2)	Gueydan, Louisiana	11,000	May 2018
Fourchon 15	Fourchon, Louisiana	7,600	February 2047
Harbor Island (2)	Harbor Island, Texas	6,800	December 2039
Intracoastal City 2	Intracoastal City, Louisiana	17,700	December 2025
Pelican Island	Galveston, Texas	87,600	Own
Theodore	Theodore, Alabama	19,900	Own

(1) This terminal is currently in caretaker status and the lease will not be renewed at the end of the current term on February 28, 2018.

(2) A portion of these terminals are owned.

Fuel and Lubricant Terminals.  We own or operate 14 lubricant and fuel terminals located in the Gulf Coast region that provide storage and handling services for lubricants and fuel oil.

The following is a summary description of our fuel and lubricant terminals at:

Terminal	Location	Aggregate Capacity (barrels)	End of Lease (Including Options)
Dulac (1)	Dulac, Louisiana	15,400	December 2041
Fourchon	Fourchon, Louisiana	80,900	May 2027
Fourchon 16	Fourchon, Louisiana	16,400	March 2022
Fourchon 17	Fourchon, Louisiana	41,200	March 2023
Fourchon T	Fourchon, Louisiana	10,200	October 2038
Galveston T (2)	Galveston, Texas	1,400	Own
Intracoastal City (2)	Intracoastal City, Louisiana	—	Own
Lake Charles T	Lake Charles, Louisiana	1,000	April 2023
Morgan City DWC 31	Morgan City, Louisiana	7,100	December 2019
Pascagoula	Pascagoula, Mississippi	10,400	Own
Port Arthur	Port Arthur, Texas	16,300	November 2025
Port O'Connor (2)	Port O'Connor, Texas	6,800	March 2018
River Ridge (3)	River Ridge, Louisiana	—	February 2018
Sabine Pass (2)	Sabine Pass, Texas	16,500	September 2036

(1) This terminal is currently in caretaker status and the lease will not be renewed at the end of the term.

(2) These terminals are currently in caretaker status.

(3) This terminal is currently in caretaker status and the lease was terminated in February 2018.

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Competition.  We compete with independent terminal operators and major energy and chemical companies that own their own terminalling and storage facilities. Many customers prefer to contract with independent terminal operators rather than terminal operators owned by integrated energy and chemical companies that may have refining or marketing interests that compete with the customers.

Independent terminal owners generally compete on the basis of the location and versatility of terminals, service and price. A favorably located terminal has access to various cost effective transportation modes, both to and from the terminal, such as waterways, railroads, roadways and pipelines. Terminal versatility depends upon the operator’s ability to handle diverse products, some of which have complex or specialized handling and storage requirements. The service function of a terminal includes, among other things, the safe storage of product at specified temperature, moisture and other conditions and receiving and delivering product to and from the terminal. All of these services must be in compliance with applicable environmental and other regulations.

We successfully compete for terminal customers because of the strategic location of our terminals along the Gulf Coast, our integrated transportation services, our reputation, the prices we charge for our services and the quality and versatility of our services. Additionally, while some companies have significantly more terminalling and storage capacity than us, not all terminalling and storage facilities located in the markets we serve are equipped to properly handle specialty products such as asphalt, sulfur and anhydrous ammonia.

The principal competitive factors affecting our terminals, which provide fuel and lubricants distribution and marketing, as well as shore bases at certain terminals, are the locations of the facilities, availability of competing logistical support services and the experience of personnel and dependability of service. The distribution and marketing of our lubricant products is brand sensitive and we encounter brand loyalty competition. Shore base rental contracts are generally long-term contracts and provide more protection from competition. Our primary competitors for both lubricants and shore bases include several independent operations as well as major companies that maintain their own similarly equipped marine terminals, shore bases and fuel and lubricant supply sources.

Natural Gas Services Segment

Industry Overview.  NGLs are produced through natural gas processing and as a by-product of crude oil refining. NGLs include ethane, propane, normal butane, iso butane and natural gasoline.

Ethane is almost entirely used as a petrochemical feedstock in the production of ethylene and propylene.  Propane is used as a petrochemical feedstock in the production of ethylene and propylene, as a fuel for heating, for industrial applications, as motor fuel and as a refrigerant.  Normal butane is used as a petrochemical feedstock, as a blend stock for motor gasoline and as a component in aerosol propellants.  Normal butane can also be made into iso butane through isomerization.  Iso butane is used in the production of motor gasoline, alkylation and as a component in aerosol propellants.  Natural gasoline is used as a component of motor gasoline, as a petrochemical feedstock and as a diluent.

Facilities.  We purchase NGLs primarily from major domestic oil refiners and natural gas processors.  We transport NGLs using Martin Resource Management’s land transportation fleet or by contracting with common carriers, owner-operators and railroad tank cars. We typically enter into annual contracts with independent retail propane distributors to deliver their estimated annual volume requirements based on prevailing market prices. Dependable delivery is very important to these customers and in some cases may be more important than price. We ensure adequate supply of NGLs through:

• storage of NGLs purchased in off-peak months;

• efficient use of railroad tank cars and the transportation fleet of vehicles owned by Martin Resource Management; and

• product management expertise to obtain supplies when needed.

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The following is a summary description of our owned NGL facilities:

NGL Facility	Location	Capacity	Description
Wholesale terminals	Arcadia, Louisiana	2,400,000 barrels	Underground storage
Retail terminals	Kilgore, Texas	90,000 gallons	Retail propane distribution
	Longview, Texas	30,000 gallons	Retail propane distribution
	Henderson, Texas	12,000 gallons	Retail propane distribution
Rail terminal	Arcadia, Louisiana	24 railcars per day	NGL rail loading and unloading capabilities

In addition to the owned NGL facilities above, we lease underground storage capacity at four locations under short-term lease agreements.

Our NGL customers consist of refiners, industrial processors and retail propane distributors. The majority of our NGL volumes are sold to refiners and industrial processors.

We generally maintain consistent margins in our natural gas services business because we attempt to pass increases and decreases in the cost of NGLs directly to our customers. We generally try to coordinate our sales and purchases of NGLs based on the same daily price index of NGLs in order to decrease the impact of NGL price volatility on our profitability.

Natural Gas Storage. Natural gas storage facilities provide a staging and warehousing function for seasonal swings in demand relative to supply, as well as an essential reliability cushion against disruptions in natural gas supply, demand and transportation by allowing natural gas to be injected into, withdrawn from or warehoused in such storage facilities as dictated by market conditions. The long term demand for storage services in the U.S. is driven primarily by the long-term demand for natural gas and the overall lack of balance between the supply of and demand for natural gas on a seasonal, monthly, daily or other basis. In general and on a long-term basis, to the extent the overall demand for natural gas increases and such growth includes higher demand from seasonal or weather-sensitive end-users (such as gas-fired power generators and residential and commercial consumers), demand for natural gas storage services should also grow. In addition, any factors that contribute to more frequent and severe imbalances between the supply of and demand for natural gas, whether caused by supply or demand fluctuations, should increase the need for and the value of storage services. On a short term basis, storage demand and values are also significantly influenced by operational imbalances, near term seasonal spreads, shorter term spreads and basis differentials.

We own 100% of the interests in Cardinal, which is focused on the operation and management of natural gas storage facilities across northern Louisiana and Mississippi.

Cardinal facilities are summarized below:

Facility Name / Location	Facility Type	Working Storage Capacity	Percent of Capacity Contracted (1)	Weighted Average Life of Remaining Contract Term
Arcadia Gas Storage, LLC Bienville Parish, Louisiana	Salt dome	16.0 billion cubic feet (bcf)	97%	2.2 years
Cadeville Gas Storage, LLC Ouachita Parish, Louisiana	Depleted reservoir	17.0 bcf	100%	5.4 years
Perryville Gas Storage, LLC Franklin Parish, Louisiana	Salt dome	12.7 bcf	67%	1.7 years
Monroe Gas Storage Company, LLC Monroe County, Mississippi	Depleted reservoir	7.4 bcf	95%	2.6 years

(1) Contracted capacity refers specifically to firm contracted capacity.

These facilities were developed to provide producers, end users, local distribution companies, pipelines and energy marketers with high-deliverability storage services and hub services.

LPG Pipeline Investment. We own a 20% interest in WTLPG. WTLPG owns an approximate 2,300 mile common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas, and to a lesser extent other

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markets, for fractionation. This asset enables us to participate in the transportation of NGL production originating in the Permian and other basins along the WTLPG pipeline route.

Competition.  We compete with large integrated NGL producers and marketers, as well as small local independent marketers. The primary components of competition related to our natural gas storage operations are location, rates, terms and flexibility of service and supply. Our natural gas storage facilities compete with other storage providers and increased competition could result from newly developed storage facilities or expanded capacity from existing competitors.

Seasonality.  The level of NGL supply and demand is subject to changes in domestic production, weather, inventory levels and other factors. While production is not seasonal, residential, refinery, and wholesale demand is highly seasonal. This imbalance causes increases in inventories during summer months when consumption is low and decreases in inventories during winter months when consumption is high. Abnormally cold weather can put extra upward pressure on propane prices during the winter because there are less readily available sources of additional supply except for imports, which are less accessible and may take several weeks to arrive. General economic conditions and inventory levels have a greater impact on industrial and refinery use of NGLs than the weather.

Sulfur Services Segment

Industry Overview.  Sulfur is a natural element and is required to produce a variety of industrial products. In the U.S., approximately 9 million tons of sulfur are consumed annually with the Tampa, Florida area being the largest single market. Currently, all sulfur produced in the U.S. is "recovered sulfur," or sulfur that is a by-product from oil refineries and natural gas processing plants.  Sulfur production in the U.S. is principally located along the Gulf Coast, along major inland waterways and in some areas of the western U.S.

Sulfur is an important plant nutrient and is primarily used in the manufacture of phosphate fertilizers and other industrial purposes. The primary application of sulfur in fertilizers occurs in the form of sulfuric acid. Burning sulfur creates sulfur dioxide, which is subsequently oxidized and dissolved in water to create sulfuric acid. The sulfuric acid is then combined with phosphate rock to make phosphoric acid, the base material for most high-grade phosphate fertilizers.

Sulfur-based fertilizers are manufactured chemicals containing nutrients known to improve the fertility of soils. Nitrogen, phosphorus, potassium and sulfur are the four most important nutrients for crop growth.  These nutrients are found naturally in soils. However, soils used for agriculture become depleted of nutrients and require fertilizers rich in nutrients to restore fertility.

Industrial sulfur products (including sulfuric acid) are used in a wide variety of industries. For example, these products are used in power plants, paper mills, auto and tire manufacturing plants, food processing plants, road construction, cosmetics and pharmaceuticals.

Our Operations and Products.  We maintain an integrated system of transportation assets and facilities relating to our sulfur services.  We gather molten sulfur from refiners, primarily located on the Gulf Coast. We transport sulfur by inland and offshore barges, railcars and trucks.  In the U.S., recovered sulfur is mainly kept in liquid form from production to usage at a temperature of approximately 275 degrees Fahrenheit. Because of the temperature requirement, the sulfur industry uses specialized equipment to store and transport molten sulfur. We have the necessary assets and expertise to handle the unique requirements for transportation and storage of molten sulfur.

Terms for our standard purchase and sales contracts typically range from one to five years in length with prices that are usually tied to a published market indicator and fluctuate according to the price movement of the indicator. We also provide barge transportation and tank storage services to large producers and consumers of sulfur under contracts with remaining terms from one to five years in duration.

We operate sulfur forming assets in the Port of Stockton, California and Beaumont, Texas, which are used to convert molten sulfur into solid form (prills/granules). The Stockton facility is equipped with one wet prill unit capable of processing 1,000 metric tons of molten sulfur per day. The Beaumont facility is equipped with two wet prill units and one granulation unit capable of processing a combined 5,500 metric tons of molten sulfur per day. Formed sulfur at both facilities is stored in bulk until sold into local or international agricultural markets. Our forming services contracts are fee based and typically include minimum fee guarantees.

Our sulfuric acid production facility at our Plainview, Texas location processes molten sulfur to produce a dedicated supply of raw material sulfuric acid to our ammonium sulfate production plant.  The ammonium sulfate plant produces

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approximately 400 tons per day of quality ammonium sulfate and is marketed to our customers throughout the U.S.  The sulfuric acid produced and not consumed by the captive ammonium sulfate production is sold to Saconix LLC, a limited liability company in which Martin Resource Management has a minority equity interest, which markets the excess production to third parties.

Fertilizer and related sulfur products are a natural extension of our molten sulfur business because of our access to sulfur and our distribution capabilities. 

In the U.S., fertilizer is generally sold to farmers through local dealers.  These dealers are typically owned and supplied by much larger wholesale distributors. We sell to these wholesale distributors.  Our industrial sulfur products are marketed primarily in the southern U.S., where many paper manufacturers and power plants are located.  Our products are sold in accordance with price lists that vary from state to state. These price lists are updated periodically to reflect changes in seasonal or competitive prices.  We transport our fertilizer and industrial sulfur products to our customers using third-party common carriers.  We utilize rail shipments for large volume and long distance shipments where available.

We manufacture and market the following sulfur-based fertilizer and related sulfur products:

• Plant nutrient sulfur products.  We produce plant nutrient and agricultural ground sulfur products at our facilities in Odessa, Texas, Seneca, Illinois and Cactus, Texas. Our plant nutrient sulfur product is a 90% degradable sulfur product marketed under the Disper-Sul® trade name and sold throughout the U.S. to direct application agricultural markets.

• Ammonium sulfate products.  We produce various grades of ammonium sulfate including granular, coarse, standard, and 40% ammonium sulfate solution.  These products primarily serve direct application agricultural markets. We package these custom grade products under both proprietary and private labels and sell them to major retail distributors and other retail customers.

• Industrial sulfur products.  We produce industrial sulfur products such as elemental pastille sulfur, industrial ground sulfur products, and emulsified sulfur. We produce elemental pastille sulfur at our Odessa, Texas and Seneca, Illinois facilities. Elemental pastille sulfur is used to increase the efficiency of the coal-fired precipitators in the power industry. These industrial ground sulfur products are also used in a variety of dusting and wettable sulfur applications such as rubber manufacturing, fungicides, sugar and animal feeds. We produce emulsified sulfur at our Nash, Texas facility. Emulsified sulfur is primarily used to control the sulfur content in the pulp and paper manufacturing processes.

• Liquid sulfur products.  We produce ammonium thiosulfate at our Neches terminal facility in Beaumont, Texas. This agricultural sulfur product is a clear liquid containing 12% nitrogen and 26% sulfur. This product serves as a liquid plant nutrient used directly through spray rigs or irrigation systems. It is also blended with other nitrogen phosphorus potassium liquids or suspensions as well. Our market is predominantly the Mid-South U.S. and Coastal Bend area of Texas.

Our Sulfur Services Facilities. We own 26 railcars and lease 76 railcars equipped to transport molten sulfur. We own the following marine assets and use them to transport molten sulfur between U.S. Gulf Coast storage terminals (including our terminal in Beaumont, Texas) under third-party marine transportation agreements:

Asset	Class of Equipment	Capacity/Horsepower	Products Transported
Margaret Sue	Offshore tank barge	10,500 long tons	Molten sulfur
M/V Martin Explorer	Offshore tugboat	7,130 horsepower	N/A
M/V Martin Express	Inland push boat	1,200 horsepower	N/A
MGM 101	Inland tank barge	2,500 long tons	Molten sulfur
MGM 102	Inland tank barge	2,500 long tons	Molten sulfur

We operate the following sulfur forming facilities as part of our sulfur services business: 

Terminal	Location	Daily Production Capacity	Products Stored
Neches	Beaumont, Texas	5,500 metric tons per day	Molten, prilled and granulated sulfur
Stockton	Stockton, California	1,000 metric tons per day	Molten and prilled sulfur

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We lease 132 railcars to transport our fertilizer products.  We own the following manufacturing plants as part of our sulfur services business:

Facility	Location	Annual Capacity	Description
Fertilizer plant	Plainview, Texas	150,000 tons	Fertilizer production
Fertilizer plant	Beaumont, Texas	110,000 tons	Liquid sulfur fertilizer production
Fertilizer plants	Odessa, Texas	35,000 tons	Dry sulfur fertilizer production
Fertilizer plant	Seneca, Illinois	36,000 tons	Dry sulfur fertilizer production
Fertilizer plant	Cactus, Texas	20,000 tons	Dry sulfur fertilizer production
Industrial sulfur plant	Nash, Texas	18,000 tons	Emulsified sulfur production
Sulfuric acid plant	Plainview, Texas	150,000 tons	Sulfuric acid production

Competition.  The Martin Explorer/Margaret Sue articulated barge unit is one of four vessels currently used to transport molten sulfur between U.S. ports on the Gulf of Mexico and Tampa, Florida. Phosphate fertilizer manufacturers consume a majority of the sulfur produced in the U.S., which they purchase directly from both producers and resellers. As a reseller, we compete against producers and other resellers capable of accessing the required transportation and storage assets. Our sulfur-based fertilizer products compete with several large fertilizer and sulfur product manufacturers.  However, the close proximity of our manufacturing plants to our customer base is a competitive advantage for us in the markets we serve and allows us to minimize freight costs and respond quickly to customer requests. Our sulfuric acid products compete with regional producers and importers in the South and Southwest portion of the U.S. from Louisiana to California.  

Seasonality.  Sales of our agricultural fertilizer products are partly seasonal as a result of increased demand during the growing season.

Marine Transportation Segment

Industry Overview.  The inland waterway system is composed of a network of interconnected rivers and canals that serve as water highways and is used to transport vast quantities of products annually. This waterway system extends approximately 26,000 miles, of which 12,000 miles are generally considered significant for domestic commerce.

The Gulf Coast region is a major hub for petroleum refining. The petroleum refining process generates products and by-products that require transportation in large quantities from the refinery or processor. Convenient access to and use of this waterway system by the petroleum and petrochemical industry is a major reason for the current location of U.S. refineries and petrochemical facilities. The marine transportation industry uses push boats and tugboats as power sources and tank barges for freight capacity. The combination of the power source and tank barge freight capacity is called a tow.

Marine Fleet.  We utilize a fleet of inland and offshore tows that provide marine transportation of petroleum products and by-products produced in oil refining and natural gas processing. Our marine transportation business operates coastwise along the Gulf of Mexico and East Coast and on the U.S. inland waterway system, primarily between domestic ports along the Gulf of Mexico, Intracoastal Waterway, the Mississippi River system and the Tennessee-Tombigbee Waterway system.   Additionally, we participate in Caribbean, Central America, and South American transport.  Our inland tows generally consist of one push boat and one to three tank barges, depending upon the horsepower of the push boat, the river or canal capacity and conditions, and customer requirements. Our offshore tow consists of one tugboat, with much greater horsepower than an inland push boat, and one large tank barge. We transport asphalt, fuel oil, gasoline, sulfur and other bulk liquids.

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The following is a summary description of the marine vessels we use in our marine transportation business (excluding equipment classified as Assets Held for Sale):

Class of Equipment	Number in Class	Capacity/Horsepower	Description of Products Carried
Inland tank barges	7	Under 20,000 barrels	Asphalt, crude oil, fuel oil, gasoline and sulfur
Inland tank barges	26	20,000 - 31,000 barrels	Asphalt, crude oil, fuel oil and gasoline
Inland push boats	18	800 - 2,650 horsepower	N/A
Offshore tank barge	1	59,000 barrels	Diesel fuel
Offshore tugboat	1	5,100 horsepower	N/A

Our largest marine transportation customers include major and independent oil and gas refining companies, petroleum marketing companies and Martin Resource Management. We conduct our marine transportation services on a fee basis primarily under spot contracts.

We are a party to a marine transportation agreement under which we provide 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.

Competition.  We compete primarily with other marine transportation companies. Competition in this industry has historically been based primarily on price. However, customers are placing an increased emphasis on safety, environmental compliance, quality of service and the availability of a single source of supply of services. Specifically, customers are increasingly seeking suppliers that can offer marine, land, rail and terminal distribution services while providing a high level of flexibility, health, safety, environmental and financial responsibility, adequate insurance and quality of services consistent with the customer’s standards.

In addition to competitors that provide marine transportation services, we also compete with providers of other modes of transportation, such as rail, trucks and, to a lesser extent, pipelines. For example, a typical two inland barge unit carries a volume of product equal to approximately 80 railcars or 250 tanker trucks. Pipelines generally provide a less expensive form of transportation than marine transportation. However, pipelines are not able to transport most of the products we transport and are generally a less flexible form of transportation because they are limited to the fixed point-to-point distribution of commodities in high volumes over extended periods of time.

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;

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

• operating an environmental consulting company;

• operating an engineering services company;

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• supplying employees and services for the operation of our business;

• 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 16.3% 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 with Martin Resource Management 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 $129.5 million, $135.8 million and $149.3 million of direct costs and expenses for the years ended December 31, 2017, 2016 and 2015, respectively.  There is no monetary limitation on the amount we are required to reimburse Martin Resource Management for direct expenses.

In addition to the direct expenses, under the Omnibus Agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses.  For the years ended December 31, 2017, 2016, and 2015, the conflicts committee of our general partner ("Conflicts Committee") approved reimbursement amounts of $16.4 million, $13.0 million and $13.7 million, respectively, reflecting 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.  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, environmental and safety compliance, 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.

Other agreements include, but are not limited to, a motor carrier agreement, marine transportation agreements, terminal services agreements, a tolling agreement, and a sulfuric acid sales agency agreement.  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 see "Item 13. Certain Relationships and Related Transactions, and Director Independence."

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.

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In the aggregate, our purchases from Martin Resource Management accounted for approximately 8%, 11%, and 9% of our total cost of products sold during for the years ended December 31, 2017, 2016 and 2015, respectively.  We also purchase marine fuel from Martin Resource Management, which we account for as an operating expense.

Correspondingly, Martin Resource Management is one of our significant customers. Our sales to Martin Resource Management accounted for approximately 11%, 13%, 11% of our total revenues for each of the years ended December 31, 2017, 2016 and 2015, respectively.  We have entered into certain agreements with Martin Resource Management pursuant to which we provide terminalling and storage and marine transportation services to its subsidiary, Martin Energy Services LLC ("MES"), and MES provides terminal services to us to handle lubricants, greases and drilling fluids.  Additionally, we have entered into a long-term, fee for services-based tolling agreement with Martin Resource Management where Martin Resource Management agrees to pay us for the processing of its crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts.

For a more comprehensive discussion concerning the Omnibus Agreement and the other agreements that we have entered into with Martin Resource Management, please see "Item 13. Certain Relationships and Related Transactions, and Director Independence."

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 is involved in the approval process, it determines whether to refer the matter to the Conflicts Committee, as provided 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.

Insurance

Our deductible for onshore physical damage resulting from named windstorms is 5% of the total value located at an individual location subject to an overall minimum deductible of $3.0 million for damage caused by the named windstorm at all locations. Our onshore program currently provides $40.0 million per occurrence for named windstorm events. For non-windstorm events, our deductible applicable to onshore physical damage is $0.5 million per occurrence. Business interruption coverage in connection with a windstorm event is subject to the same $40.0 million per occurrence and aggregate limit as the property damage coverage and a waiting period of 45 days. For non-windstorm events, our waiting period applicable to business interruption is 30 days.

We have various pollution liability policies which provide coverages ranging from remediation of our property to third party liability. The limits of these policies vary based on our assessments of exposure at each location.

Loss of, or damage to, our vessels and cargo is insured through hull and cargo insurance policies. Vessel operating liabilities such as collision, cargo, environmental and personal injury are insured primarily through our participation in mutual insurance associations and other reinsurance arrangements, pursuant to which we are potentially exposed to assessments in the event claims by us or other members exceed available funds and reinsurance. Protection and indemnity ("P&I") insurance coverage is provided by P&I associations and other insurance underwriters. Our vessels are entered in P&I associations that are parties to a pooling agreement, known as the International Group Pooling Agreement ("Pooling Agreement") through which approximately 90% of the world's ocean-going tonnage is reinsured through a group reinsurance policy. With regard to collision coverage, the first $1.0 million of coverage is insured by our hull policy and any excess is insured by a P&I association. We insure our owned cargo through a domestic insurance company. We insure cargo owned by third parties through our P&I coverage. As a member of P&I associations that are parties to the Pooling Agreement, we are subject to supplemental calls payable to the associations of which we are a member, based on our claims record and the other members of the other P&I associations that are parties to the Pooling Agreement. Except for our marine operations, we self-insure against liability exposure up to a predetermined amount, beyond which we are covered by catastrophe insurance coverage.

For marine claims, our insurance covers up to $1.0 billion of liability per accident or occurrence. We believe our current insurance coverage is adequate to protect us against most accident related risks involved in the conduct of our business.

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However, there can be no assurance that all risks are adequately insured against, that any particular claim will be paid by the insurer, or that we will be able to procure adequate insurance coverage at commercially reasonable rates in the future.

Environmental and Regulatory Matters

Our activities are subject to various federal, state and local laws and regulations, as well as orders of regulatory bodies, governing a wide variety of matters, including marketing, production, pricing, community right-to-know, protection of the environment, safety and other matters.

Environmental

We are subject to complex federal, state, and local environmental laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of human health, natural resources and the environment. These laws and regulations can impair our operations that affect the environment in many ways, such as requiring the acquisition of permits to conduct regulated activities; restricting the manner in which we can release materials into the environment; requiring remedial activities or capital expenditures to mitigate pollution from former or current operations; and imposing substantial liabilities on us for pollution resulting from our operations. Many environmental laws and regulations can impose joint and several, strict liability, and any failure to comply with environmental laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial obligations, and, in some circumstances, the issuance of injunctions that can limit or prohibit our operations.

The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and, thus, any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and financial position. Moreover, there is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum products and by-products, chemical substances, and wastes as well as the accidental release or spill of such materials into the environment. Consequently, we cannot provide assurance that we will not incur significant costs and liabilities as result of such handling practices, releases or spills, including those relating to claims for damage to property and persons. In the event of future increases in costs, we may be unable to pass on those increases to our customers. While we believe that we are in substantial compliance with current environmental laws and regulations and that continued compliance with existing requirements would not have a material adverse impact on us, we cannot provide any assurance that our environmental compliance expenditures will not have a material adverse effect on us in the future.

Superfund

The Federal Comprehensive Environmental Response, Compensation and Liability Act, as amended, ("CERCLA"), also known as the "Superfund" law, and similar state laws, impose liability without regard to fault or the legality of the original conduct, on certain classes of "responsible persons," including the owner or operator of a site where regulated hazardous substances have been released into the environment and companies that disposed or arranged for the disposal of the hazardous substances found at such site. Under CERCLA, these responsible persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances into the environment. Although certain hydrocarbons are not subject to CERCLA’s reach because "petroleum" is excluded from CERCLA’s definition of a "hazardous substance," in the course of our ordinary operations we will generate wastes that may fall within the definition of a "hazardous substance." In addition, some state counterparts to CERCLA tie liability to a broader set of substances than does CERCLA.

Solid Waste

We generate both hazardous and nonhazardous solid wastes, which are subject to requirements of the federal Resource Conservation and Recovery Act, as amended ("RCRA") and comparable state statutes. From time to time, the U.S. Environmental Protection Agency ("EPA") has considered making changes in nonhazardous waste standards that would result in stricter disposal requirements for these wastes. Furthermore, it is possible some wastes generated by us that are currently classified as nonhazardous may in the future be designated as "hazardous wastes," resulting in the wastes being subject to more rigorous and costly disposal requirements. Changes in applicable regulations may result in an increase in our capital expenditures or operating expenses.

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We currently own or lease, and have in the past owned or leased, properties that have been used for the manufacturing, processing, transportation and storage of petroleum products and by-products. Solid waste disposal practices within oil and gas related industries have improved over the years with the passage and implementation of various environmental laws and regulations. Nevertheless, a possibility exists that petroleum and other solid wastes may have been disposed of on or under various properties owned or leased by us during the operating history of those facilities. In addition, a number of these properties have been operated by third parties over whom we had no control as to such entities’ handling of petroleum, petroleum by-products or other wastes and the manner in which such substances may have been disposed of or released. State and federal laws and regulations applicable to oil and natural gas wastes and properties have gradually become more strict and, under such laws and regulations, we could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination, even under circumstances where such contamination resulted from past operations of third parties.

Clean Air Act

Our operations are subject to the federal Clean Air Act ("CAA"), as amended, and comparable state statutes. Amendments to the CAA adopted in 1990 contain provisions that may result in the imposition of increasingly stringent pollution control requirements with respect to air emissions from the operations of our terminal facilities, processing and storage facilities and fertilizer and related products manufacturing and processing facilities. Such air pollution control requirements may include specific equipment or technologies to control emissions, permits with emissions and operational limitations, pre-approval of new or modified projects or facilities producing air emissions, and similar measures. Failure to comply with applicable air statutes or regulations may lead to the assessment of administrative, civil or criminal penalties, and/or result in the limitation or cessation of construction or operation of certain air emission sources. We believe our operations, including our manufacturing, processing and storage facilities and terminals, are in substantial compliance with applicable requirements of the CAA and analogous state laws.

Global Warming and Climate Change.  Recent scientific studies have suggested that emissions of certain gases, commonly referred to as "greenhouse gases" and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere.  In response to such studies, the U.S. Congress has from time to time considered climate change-related legislation to restrict greenhouse gas emissions.  Many states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs.  Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007, in Massachusetts, et al. v. EPA, the EPA eventually concluded that it is required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases.  The Court's holding in Massachusetts that greenhouse gases fall under the federal CAA's definition of air pollutant has also led the EPA to determine that regulation of greenhouse gas emissions from stationary sources under various Clean Air Act programs is required.  To that end, EPA promulgated regulations, referred to as the Tailoring Rule, 75 Fed. Red. 31514, to begin gradually subjecting stationary greenhouse gas emission sources to various Clean Air Act programs, including permitting programs applicable to new and existing major sources of greenhouse gas emissions.  In reviewing the regulations at issue, the Supreme Court struck down EPA’s permitting requirements as applicable only to greenhouse gas emissions, although it upheld the EPA’s authority to control greenhouse gas emissions when a permit is required due to emissions of other pollutants.

On an international level, almost 200 nations agreed in December 2015 to an international climate change agreement in Paris, France that calls for countries to set their own greenhouse gas emissions targets and be transparent about the measures each country will use to achieve its emissions targets. Although the present administration has announced its intention to withdraw from the Paris accord, several states and local governments have stated their commitment to its principles in their effectuation of policy and regulations. To date, applicable requirements have not had a substantial effect upon our operations.  Still, new legislation or regulatory programs that restrict emissions of greenhouse gases in areas in which we conduct business could adversely affect our operations and demand for our services.

Moreover, in interpretative guidance on climate change disclosures, the SEC indicates that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, our operations have the potential to be adversely affected. Potential adverse effects could include disruption of our business activities, including, for example, damages to our facilities from powerful winds or floods, or increases in our costs of operation or reductions in the efficiency of our operations, as well as potentially increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process related services provided by companies or suppliers with whom we have a business relationship. In addition, the demand for and consumption of our products and services (due to change in both costs and weather patterns), and the economic health of the regions in which we operate, could have a material adverse effect on our business, financial condition, results of operations and

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cash flows. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change.

Clean Water Act

The Federal Water Pollution Control Act of 1972, as amended, also known as Clean Water Act and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including hydrocarbon-bearing wastes, into state waters and waters of the U.S.. Pursuant to the Clean Water Act and similar state laws, a National Pollutant Discharge Elimination System, or state permit, or both, must be obtained to discharge pollutants into federal and state waters. In addition, the Clean Water Act and comparable state laws require that individual permits or coverage under general permits be obtained by subject facilities for discharges of storm water runoff. Furthermore, the Clean Water Act potentially requires individual permits or qualification for nationwide permits for activities that involve the discharge of dredged or fill material into waters of the United States, the definition of which under EPA and Corps of Engineers rulemaking authority was expanded in 2015. The subject rules are currently the subject of litigation and proposed rescission. Nevertheless, the new “waters of the United States” rules, if they were to become effective and are not rescinded, could significantly expand federal control of land and water resources across the U.S., triggering substantial additional permitting and regulatory requirements to which our operations may be subject from time to time. We believe that we are in substantial compliance with Clean Water Act permitting requirements as well as the conditions imposed thereunder, and that our continued compliance with such existing permit conditions will not have a material adverse effect on our business, financial condition or results of operations.

Oil Pollution Act

The Oil Pollution Act of 1990, as amended ("OPA") imposes a variety of regulations on "responsible parties" related to the prevention of oil spills and liability for damages resulting from such spills in U.S. waters. A "responsible party" includes the owner or operator of a facility or vessel or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages including natural resource damages. Under the OPA, vessels and shore facilities handling, storing, or transporting oil are required to develop and implement oil spill response plans, and vessels greater than 300 tons in weight must provide to the U.S. Coast Guard evidence of financial responsibility to cover the costs of cleaning up oil spills from such vessels. The OPA also requires that all newly constructed tank barges engaged in oil transportation in the U.S. be double hulled effective January 1, 2016. We believe we are in substantial compliance with all of the oil spill-related and financial responsibility requirements. Nonetheless, in the aftermath of the Deepwater Horizon incident in 2010, Congress has from time to time considered oil spill related legislation that could have the effect of substantially increasing financial responsibility requirements and potential fines and damages for violations and discharges subject to the OPA, and similar legislation.  Any such changes in law affecting areas where we conduct business could materially affect our operations.

Safety Regulation

The Company’s marine transportation operations are subject to regulation by the U.S. Coast Guard, federal laws, state laws and certain international treaties. Tank ships, push boats, tugboats and barges are required to meet construction and repair standards established by the American Bureau of Shipping, a private organization, and the U.S. Coast Guard and to meet operational and safety standards presently established by the U.S. Coast Guard. We believe our marine operations and our terminals are in substantial compliance with current applicable safety requirements.

Occupational Health Regulations

The workplaces associated with our manufacturing, processing, terminal and storage facilities are subject to the requirements of the federal Occupational Safety and Health Act ("OSHA") and comparable state statutes. We believe we have conducted our operations in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances.  Our marine vessel operations are also subject to safety and operational standards established and monitored by the U.S. Coast Guard.

In general, we expect to increase our expenditures relating to compliance with likely higher industry and regulatory safety standards such as those described above. These expenditures cannot be accurately estimated at this time, but we do not expect them to have a material adverse effect on our business.

Jones Act

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The Jones Act is a federal law that restricts maritime transportation between locations in the U.S. to vessels built and registered in the U.S. and owned and manned by U.S. citizens. Since we engage in maritime transportation between locations in the U.S., we are subject to the provisions of the law. As a result, we are responsible for monitoring the ownership of our subsidiaries that engage in maritime transportation and for taking any remedial action necessary to ensure that no violation of the Jones Act ownership restrictions occurs. The Jones Act also requires that all U.S.-flagged vessels be manned by U.S. citizens. Foreign-flagged seamen generally receive lower wages and benefits than those received by U.S. citizen seamen. This requirement significantly increases operating costs of U.S.-flagged vessel operations compared to foreign-flagged vessel operations. Certain foreign governments subsidize their nations’ shipyards. This results in lower shipyard costs both for new vessels and repairs than those paid by U.S.-flagged vessel owners. The U.S. Coast Guard and American Bureau of Shipping maintain the most stringent regimen of vessel inspection in the world, which tends to result in higher regulatory compliance costs for U.S.-flagged operators than for owners of vessels registered under foreign flags of convenience.

Merchant Marine Act of 1936

The Merchant Marine Act of 1936 is a federal law that provides that, upon proclamation by the President of the U.S. of a national emergency or a threat to the national security, the U.S. Secretary of Transportation may requisition or purchase any vessel or other watercraft owned by U.S. citizens (including us, provided that we are considered a U.S. citizen for this purpose). If one of our push boats, tugboats or tank barges were purchased or requisitioned by the U.S. government under this law, we would be entitled to be paid the fair market value of the vessel in the case of a purchase or, in the case of a requisition, the fair market value of charter hire. However, if one of our push boats or tugboats is requisitioned or purchased and its associated tank barge is left idle, we would not be entitled to receive any compensation for the lost revenues resulting from the idled barge. We also would not be entitled to be compensated for any consequential damages we suffer as a result of the requisition or purchase of any of our push boats, tugboats or tank barges.

Employees

We do not have any employees.  Under our Omnibus Agreement with Martin Resource Management, Martin Resource Management provides us with corporate staff and support services.  These services include centralized corporate functions, such as accounting, treasury, engineering, information technology, insurance, administration of employee benefit plans and other corporate services.  Martin Resource Management employs approximately 748 individuals, including 51 employees represented by labor unions, who provide direct support to our operations as of December 31, 2017.

Financial Information about Segments

Information regarding our operating revenues and identifiable assets attributable to each of our segments is presented in Note 19 to our consolidated financial statements included in this annual report on Form 10-K.

Access to Public Filings

We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to these reports filed with the SEC under the Securities and Exchange Act of 1934.  These documents may be accessed free of charge on our website at the following address: www.martinmidstream.com.  These documents are provided as soon as is reasonably practicable after their filing with the SEC.  This website address is intended to be an inactive, textual reference only, and none of the material on this website is part of this report.  These documents may also be found at the SEC’s website at www.sec.gov.

Item 1A. Risk Factors

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a business similar to ours. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In this case, we might not be able to pay distributions on our common units, the trading price of our common units could decline and unitholders could lose all or part of their investment. These risk factors should be read in conjunction with the other detailed information concerning us set forth herein.

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Risks Relating to Our Business

Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the risks set forth below. The risks described below should not be considered to be comprehensive and all-inclusive. Many of such factors are beyond our ability to control or predict. Unitholders are cautioned not to put undue reliance on forward-looking statements. Additional risks that we do not yet know of or that we currently think are immaterial may also impair our business operations, financial condition and results of operations.

We may not have sufficient cash after the establishment of cash reserves and payment of our general partner's expenses to enable us to pay the minimum quarterly distribution each quarter.

We may not have sufficient available cash each quarter in the future to pay the minimum quarterly distributions on all our units. Under the terms of our partnership agreement, we must pay our general partner's expenses and set aside any cash reserve amounts before making a distribution to our unitholders. The amount of cash we can distribute on our common units principally depends upon the amount of net cash generated from our operations, which will fluctuate from quarter to quarter based on, among other things:

•the costs of acquisitions, if any;

• the prices of petroleum products and by-products;

• fluctuations in our working capital;

• the level of capital expenditures we make;

• restrictions contained in our debt instruments and our debt service requirements;

• our ability to make working capital borrowings under our credit facility; and

• the amount, if any, of cash reserves established by our general partner in its discretion.

Unitholders should also be aware that the amount of cash we have available for distribution depends primarily on our cash flow, including cash flow from working capital borrowings, and not solely on profitability, which will be affected by non-cash items. In addition, our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuances of additional partnership securities and the establishment of reserves, each of which can affect the amount of cash available for distribution to our unitholders. As a result, we may make cash distributions during periods when we record losses and may not make cash distributions during periods when we record net income.

Restrictions in our credit facility could prevent us from making distributions to our unitholders.

The payment of principal and interest on our indebtedness reduces the cash available for distribution to our unitholders. In addition, we are prohibited by our credit facility from making cash distributions during a default or an event of default under our credit facility or if the payment of a distribution would cause a default or an event of default thereunder. Our leverage and various limitations in our credit facility may reduce our ability to incur additional debt, engage in certain transactions, and capitalize on acquisition or other business opportunities that could increase cash flows and distributions to our unitholders.

Demand for a portion of our terminalling and storage services is substantially dependent on the level of offshore oil and gas exploration, development and production activity.

The level of offshore oil and gas exploration, development and production activity historically has been volatile and is likely to continue to be so in the future. The level of activity is subject to large fluctuations in response to relatively minor changes in a variety of factors that are beyond our control, including:

• prevailing oil and natural gas prices and expectations about future prices and price volatility;

• the ability of exploration and production companies to drill in other basins that have more attractive rates of return;

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• the cost of offshore exploration for and production and transportation of oil and natural gas;

• worldwide demand for oil and natural gas;

• consolidation of oil and gas and oil service companies operating offshore;

• availability and rate of discovery of new oil and natural gas reserves in offshore areas;

• local and international political and economic conditions and policies;

• technological advances affecting energy production and consumption;

• weather conditions;

• environmental regulation; and

• the ability of oil and gas companies to generate or otherwise obtain funds for exploration and production.

We expect levels of offshore oil and gas exploration, development and production activity to continue to be volatile and affect demand for our terminalling and storage services.

Debt we owe or incur in the future could limit our flexibility to obtain financing and to pursue other business opportunities.

                Our indebtedness could have important consequences, including the following:

• our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

• our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flows required to make interest payments on the debt;

• we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

• our flexibility in responding to changing business and economic conditions may be limited.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control.  If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital.  We may not be able to effect any of these actions on satisfactory terms or at all.

If we do not have sufficient capital resources for acquisitions or opportunities for expansion, our growth will be limited.

We intend to explore acquisition opportunities in order to expand our operations and increase our profitability. We may finance acquisitions through public and private financing, or we may use our limited partner interests for all or a portion of the consideration to be paid in acquisitions. Distributions of cash with respect to these equity securities or limited partner interests may reduce the amount of cash available for distribution to the common units. In addition, in the event our limited partner interests do not maintain a sufficient valuation, or potential acquisition candidates are unwilling to accept our limited partner interests as all or part of the consideration, we may be required to use our cash resources, if available, or rely on other financing arrangements to pursue acquisitions. If we use funds from operations, other cash resources or increased borrowings for an acquisition, the acquisition could adversely impact our ability to make our minimum quarterly distributions to our unitholders. Additionally, if we do not have sufficient capital resources or are not able to obtain financing on terms acceptable to us for acquisitions, our ability to implement our growth strategies may be adversely impacted.

A higher cost of capital relative to our peers could limit our ability to grow through acquisitions.

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In order to expand our operations and increase profitability, we explore acquisition opportunities.  When competing for acquisition targets, firms with a lower cost of capital will be in a stronger position to secure the acquisition.  A higher cost of capital relative to our peers could put us in a weaker position to grow through acquisitions.

We are exposed to counterparty risk in our credit facility and related interest rate protection agreements.

We rely on our credit facility to assist in financing a significant portion of our working capital, acquisitions and capital expenditures. Our ability to borrow under our credit facility may be impaired because:

• one or more of our lenders may be unable or otherwise fail to meet its funding obligations;

• the lenders do not have to provide funding if there is a default under the credit facility or if any of the representations or warranties included in the credit facility are false in any material respect; and

• if any lender refuses to fund its commitment for any reason, whether or not valid, the other lenders are not required to provide additional funding to make up for the unfunded portion.

If we are unable to access funds under our credit facility, we will need to meet our capital requirements, including some of our short-term capital requirements, using other sources. Alternative sources of liquidity may not be available on acceptable terms, if at all. If the cash generated from our operations or the funds we are able to obtain under our credit facility or other sources of liquidity are not sufficient to meet our capital requirements, then we may need to delay or abandon capital projects or other business opportunities, which could have a material adverse effect on our business, financial condition and results of operations.

In addition, we have from time to time entered into interest rate protection agreements to manage our interest rate risk exposure by fixing a portion of the interest expense we pay on our long-term debt under our credit facility. Uncertainty in the global economy and banking markets exists, which could affect whether the counterparties to such interest rate protection agreements are able to honor their agreements. If the counterparties fail to honor their commitments, we could experience higher interest rates, which could have a material adverse effect on our business, financial condition and results of operations. In addition, if the counterparties fail to honor their commitments, we also may be required to replace such interest rate protection agreements with new interest rate protection agreements, and such replacement interest rate protection agreements may be at higher rates than our current interest rate protection agreements, which could have a material adverse effect on our business, financial condition and results of operations.

The impacts of climate-related initiatives at the international, federal and state levels remain uncertain at this time.

Currently, there are numerous international, federal and state-level initiatives and proposals addressing domestic and global climate issues.  Within the U.S., most of these proposals would regulate and/or tax, in one fashion or another, the production of carbon dioxide and other "greenhouse gases" to facilitate the reduction of carbon compound emissions to the atmosphere and provide tax and other incentives to produce and use more "clean energy." Costs to comply with future climate-related initiatives could have a material impact on our business, financial condition and results of operations.

Our recent and future acquisitions may not be successful, may substantially increase our indebtedness and contingent liabilities and may create integration difficulties.

As part of our business strategy, we intend to acquire businesses or assets we believe complement our existing operations. We may not be able to successfully integrate recent or any future acquisitions into our existing operations or achieve the desired profitability from such acquisitions. These acquisitions may require substantial capital expenditures and the incurrence of additional indebtedness. If we make acquisitions, our capitalization and results of operations may change significantly. Further, any acquisition could result in:

• post-closing discovery of material undisclosed liabilities of the acquired business or assets;

• the unexpected loss of key employees or customers from the acquired businesses;

• difficulties resulting from our integration of the operations, systems and management of the acquired business; and

• an unexpected diversion of our management's attention from other operations.

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If recent or any future acquisitions are unsuccessful or result in unanticipated events or if we are unable to successfully integrate acquisitions into our existing operations, such acquisitions could adversely affect our results of operations, cash flow and ability to make distributions to our unitholders.

Adverse weather conditions, including droughts, hurricanes, tropical storms and other severe weather, could reduce our results of operations and ability to make distributions to our unitholders.

Our distribution network and operations are primarily concentrated in the Gulf Coast region and along the Mississippi River inland waterway. Weather in these regions is sometimes severe (including tropical storms and hurricanes) and can be a major factor in our day-to-day operations. Our marine transportation operations can be significantly delayed, impaired or postponed by adverse weather conditions, such as fog in the winter and spring months and certain river conditions. Additionally, our marine transportation operations and our assets in the Gulf of Mexico, including our barges, push boats, tugboats and terminals, can be adversely impacted or damaged by hurricanes, tropical storms, tidal waves or other related events. Demand for our lubricants and the diesel fuel we throughput in our Terminalling and Storage segment can be affected if offshore drilling operations are disrupted by weather in the Gulf of Mexico.

National weather conditions have a substantial impact on the demand for our products. Unusually warm weather during the winter months can cause a significant decrease in the demand for NGL products. Likewise, extreme weather conditions (either wet or dry) can decrease the demand for fertilizer. For example, an unusually wet spring can delay planting of seeds, which can leave insufficient time to apply fertilizer at the planting stage. Conversely, drought conditions can kill or severely stunt the growth of crops, thus eliminating the need to nurture plants with fertilizer. Any of these or similar conditions could result in a decline in our net income and cash flow, which would reduce our ability to make distributions to our unitholders.

If we incur material liabilities that are not fully covered by insurance, such as liabilities resulting from accidents on rivers or at sea, spills, fires or explosions, our results of operations and ability to make distributions to our unitholders could be adversely affected.

Our operations are subject to the operating hazards and risks incidental to terminalling and storage, marine transportation and the distribution of petroleum products and by-products and other industrial products. These hazards and risks, many of which are beyond our control, include:

• accidents on rivers or at sea and other hazards that could result in releases, spills and other environmental damages, personal injuries, loss of life and suspension of operations;

• leakage of NGLs, natural gas, and other petroleum products and by-products;

• fires and explosions;

• damage to transportation, terminalling and storage facilities and surrounding properties caused by natural disasters; and

• terrorist attacks or sabotage.

Our insurance coverage may not be adequate to protect us from all material expenses related to potential future claims for personal-injury and property damage, including various legal proceedings and litigation resulting from these hazards and risks. If we incur material liabilities that are not covered by insurance, our operating results, cash flow and ability to make distributions to our unitholders could be adversely affected.

Changes in the insurance markets attributable to the effects of hurricanes and their aftermath may make some types of insurance more difficult or expensive for us to obtain. As a result, we may be unable to secure the levels and types of insurance we would otherwise have secured prior to such events. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage.

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The price volatility of petroleum products and by-products could reduce our liquidity and results of operations and ability to make distributions to our unitholders.

We purchase petroleum products and by-products, such as molten sulfur, fuel oils, NGLs, lubricants, and other bulk liquids and sell these products to wholesale and bulk customers and to other end users. We also generate revenues through the terminalling and storage of certain products for third parties. The price and market value of petroleum products and by-products could be, and has recently been, volatile. Our liquidity and revenues have been adversely affected by this volatility during periods of decreasing prices because of the reduction in the value and resale price of our inventory. In addition, our liquidity and costs have been adversely affected during periods of increasing prices because of the increased costs associated with our purchase of petroleum products and by-products. Future price volatility could have an adverse impact on our liquidity and results of operations, cash flow and ability to make distributions to our unitholders.

Increasing energy prices could adversely affect our results of operations.

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 our results of operations including net income and cash flows. We cannot assure unitholders that we will be able to pass along increased operating expenses to our customers.

Decreasing energy prices could adversely affect our results of operations.

Decreasing energy prices could adversely affect our results of operations. If commodity prices remain weak for a sustained period, our pipeline, terminalling throughput and NGL volumes may be negatively impacted, particularly as producers are curtailing or redirecting drilling, adversely affecting our results of operations. A sustained decline in commodity prices could result in a decrease in activity in the areas served by certain of our terminalling and storage and marine transportation assets resulting in reduced utilization of these assets.

Increased competition from alternative natural gas transportation and storage options and alternative fuel sources could have a significant financial impact on us.

Our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows could be adversely affected by activities of other interstate and intrastate pipelines and storage facilities that may expand or construct competing transportation and storage systems. In addition, future pipeline transportation and storage capacity could be constructed in excess of actual demand and with lower fuel requirements, operating and maintenance costs than our facilities, which could reduce the demand for and the rates that we receive for our services in particular areas. Further, natural gas also competes with alternative energy sources available to our customers that are used to generate electricity, such as hydroelectric power, solar, wind, nuclear, coal and fuel oil.

Our NGL and sulfur-based fertilizer products are subject to seasonal demand and could cause our revenues to vary.

The demand for NGLs and natural gas is highest in the winter. Therefore, revenue from our natural gas services business is higher in the winter than in other seasons. Our sulfur-based fertilizer products experience an increase in demand during the spring, which increases the revenue generated by this business line in this period compared to other periods. The seasonality of the revenue from these products may cause our results of operations to vary on a quarter-to-quarter basis and thus could cause our cash available for quarterly distributions to fluctuate from period to period.

The highly competitive nature of our industry could adversely affect our results of operations and ability to make distributions to our unitholders.

We operate in a highly competitive marketplace in each of our primary business segments. Most of our competitors in each segment are larger companies with greater financial and other resources than we possess. We may lose customers and future business opportunities to our competitors and any such losses could adversely affect our results of operations and ability to make distributions to our unitholders.

Our business is subject to compliance with environmental laws and regulations that could expose us to significant costs and liabilities and adversely affect our results of operations and ability to make distributions to our unitholders.

Our business is subject to federal, state and local environmental laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of human health, natural resources and the environment.

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These laws and regulations may impose numerous obligations that are applicable to our operations, such as: requiring the acquisition of permits to conduct regulated activities; restricting the manner in which we can release materials into the environment; requiring remedial activities or capital expenditures to mitigate pollution from former or current operations; and imposing substantial liabilities on us for pollution resulting from our operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Many environmental laws and regulations can impose joint and several strict liability, and any failure to comply with environmental laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory and remedial obligations and, in some circumstances, the issuance of injunctions that can limit or prohibit our operations. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and, thus, any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial position.

The loss or insufficient attention of key personnel could negatively impact our results of operations and ability to make distributions to our unitholders.

Our success is largely dependent upon the continued services of members of the senior management team of Martin Resource Management. Those senior officers have significant experience in our businesses and have developed strong relationships with a broad range of industry participants. The loss of any of these executives could have a material adverse effect on our relationships with these industry participants, our results of operations and our ability to make distributions to our unitholders.

We do not have employees. We rely solely on officers and employees of Martin Resource Management to operate and manage our business. Martin Resource Management operates businesses and conducts activities of its own in which we have no economic interest. There could be competition for the time and effort of the officers and employees who provide services to our general partner. If these officers and employees do not or cannot devote sufficient attention to the management and operation of our business, our results of operations and ability to make distributions to our unitholders may be reduced.

Our loss of significant commercial relationships with Martin Resource Management could adversely impact our results of operations and ability to make distributions to our unitholders.

Martin Resource Management provides us with various services and products pursuant to various commercial contracts. The loss of any of these services and products provided by Martin Resource Management could have a material adverse impact on our results of operations, cash flow and ability to make distributions to our unitholders. Additionally, we provide terminalling and storage, processing and marine transportation services to Martin Resource Management to support its businesses under various commercial contracts. The loss of Martin Resource Management as a customer could have a material adverse impact on our results of operations, cash flow and ability to make distributions to our unitholders.

Our business could be adversely affected if operations at our transportation, terminalling and storage and distribution facilities experienced significant interruptions. Our business could also be adversely affected if the operations of our customers and suppliers experienced significant interruptions.

Our operations are dependent upon our terminalling and storage facilities and various means of transportation. We are also dependent upon the uninterrupted operations of certain facilities owned or operated by our suppliers and customers. Any significant interruption at these facilities or inability to transport products to or from these facilities or to or from our customers for any reason would adversely affect our results of operations, cash flow and ability to make distributions to our unitholders. Operations at our facilities and at the facilities owned or operated by our suppliers and customers could be partially or completely shut down, temporarily or permanently, as the result of any number of circumstances that are not within our control, such as:

• catastrophic events, including hurricanes;

• environmental remediation;

• labor difficulties; and

• disruptions in the supply of our products to our facilities or means of transportation.

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Additionally, terrorist attacks and acts of sabotage could target oil and gas production facilities, refineries, processing plants, terminals and other infrastructure facilities. Any significant interruptions at our facilities, facilities owned or operated by our suppliers or customers, or in the oil and gas industry as a whole caused by such attacks or acts could have a material adverse effect on our results of operations, cash flow and ability to make distributions to our unitholders.

NASDAQ does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements, and therefore, unitholders do not have the same protections afforded to shareholders of corporations subject to all NASDAQ requirements.

                Because we are a publicly traded partnership, the Nasdaq Global Select Market ("NASDAQ") does not require our general partner to have a majority of independent directors on its board of directors or to establish a compensation committee or nominating and corporate governance committee.  Accordingly, unitholders do not have the same protections afforded to certain corporations that are subject to all of NASDAQ corporate governance requirements.

Our marine transportation business could be adversely affected if we do not satisfy the requirements of the Jones Act or if the Jones Act were modified or eliminated.

The Jones Act is a federal law that restricts domestic marine transportation in the U.S. to vessels built and registered in the U.S. Furthermore, the Jones Act requires that the vessels be manned and owned by U.S. citizens. If we fail to comply with these requirements, our vessels lose their eligibility to engage in coastwise trade within U.S. Domestic waters.

The requirements that our vessels be U.S. built and manned by U.S. citizens, the crewing requirements and material requirements of the Coast Guard and the application of U.S. labor and tax laws significantly increase the costs of U.S. flagged vessels when compared with foreign-flagged vessels. During the past several years, certain interest groups have lobbied Congress to repeal the Jones Act to facilitate foreign flag competition for trades and cargoes reserved for U.S. flagged vessels under the Jones Act and cargo preference laws. If the Jones Act were to be modified to permit foreign competition that would not be subject to the same U.S. government imposed costs, we may need to lower the prices we charge for our services in order to compete with foreign competitors, which would adversely affect our cash flow and ability to make distributions to our unitholders.

Our marine transportation business could be adversely affected if the U.S. Government purchases or requisitions any of our vessels under the Merchant Marine Act.

We are subject to the Merchant Marine Act of 1936, which provides that, upon proclamation by the President of the U.S. of a national emergency or a threat to the national security, the U.S. Secretary of Transportation may requisition or purchase any vessel or other watercraft owned by U.S. citizens (including us, provided that we are considered a U.S. citizen for this purpose). If one of our push boats, tugboats or tank barges were purchased or requisitioned by the U.S. government under this law, we would be entitled to be paid the fair market value of the vessel in the case of a purchase or, in the case of a requisition, the fair market value of charter hire. However, if one of our push boats or tugboats is requisitioned or purchased and its associated tank barge is left idle, we would not be entitled to receive any compensation for the lost revenues resulting from the idled barge. We also would not be entitled to be compensated for any consequential damages we suffer as a result of the requisition or purchase of any of our push boats, tugboats or tank barges. If any of our vessels are purchased or requisitioned for an extended period of time by the U.S. government, such transactions could have a material adverse effect on our results of operations, cash flow and ability to make distributions to our unitholders.

Our interest rate swap activities could have a material adverse effect on our earnings, profitability, liquidity, cash flows and financial condition.

We enter into interest rate swap agreements from time to time to manage some of our exposure to interest rate volatility. These swap agreements involve risks, such as the risk that counterparties may fail to honor their obligations under these arrangements. In addition, these arrangements may not be effective in reducing our exposure to changes in interest rates. When we use forward-starting interest rate swaps, there is a risk that we will not complete the long-term borrowing against which the swap is intended to hedge. If such events occur, our results of operations may be adversely affected.

The industry in which we operate is highly competitive, and increased competitive pressure could adversely affect our business and operating results.

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We compete with similar enterprises in our respective areas of operation. Some of our competitors are large oil, natural gas and petrochemical companies that have greater financial resources and access to supplies of NGLs than we do. In addition, our customers who are significant producers of natural gas may develop their own gathering, processing and transportation systems in lieu of using ours. Likewise, our customers who produce NGLs may develop their own systems to transport NGLs in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

Information technology systems present potential targets for cyber security attacks, which could adversely affect our business.

                We are reliant on technology to improve efficiency in our business.  Information technology systems are critical to our operations.  These systems could be a potential target for a cyber security attack as they are used to store and process sensitive information regarding our operations, financial position, and information pertaining to our customers and vendors.  While we take the utmost precautions, we cannot guarantee safety from all threats and attacks.  Any successful breach of security could result in the spread of inaccurate or confidential information, disruption of operations, environmental harm, endangerment of employees, damage to our assets, and increased costs to respond.  Any of these instances could have a negative impact on cash flows, litigation status and/or our reputation, which could have a material adverse affect on our business, financial conditions and operations. 

If we are deemed an "investment company" under the Investment Company Act of 1940, it would adversely affect the price of our common units and could have a material adverse effect on our business.

Our assets include interests in joint ventures, specifically a 20.0% interest in WTLPG. This joint venture interest may be deemed to be "investment securities" within the meaning of the Investment Company Act of 1940, or the Investment Company Act. If a sufficient amount of our assets are deemed to be "investment securities" within the meaning of the Investment Company Act, and we are unable to rely on an exemption under the Investment Company Act, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates. The occurrence of some or all of these events may have a material adverse effect on our business.

Moreover, treatment of us as an investment company would prevent our qualification as a partnership for federal income tax purposes in which case we would be treated as a corporation for federal income tax purposes, and be subject to federal income tax at the corporate tax rate, significantly reducing the cash available for distributions. Additionally, distributions to the unitholders would be taxed again as corporate distributions and none of our income, gains, losses or deductions would flow through to the unitholders.

Additionally, as a result of our desire to avoid having to register as an investment company under the Investment Company Act, we may have to forego potential future acquisitions of interests in companies that may be deemed to be investment securities within the meaning of the Investment Company Act or dispose of our current interests in any of our assets that are deemed to be "investment securities."

Risks Relating to an Investment in the Common Units

Units available for future sales by us or our affiliates could have an adverse impact on the price of our common units or on any trading market that may develop.

Common units will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units held by an "affiliate" of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise.

Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders. Our general partner may also cause us to issue an unlimited number of additional common

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units or other equity securities of equal rank with the common units, without unitholder approval, in a number of circumstances such as:

• the issuance of common units in additional public offerings or in connection with acquisitions that increase cash flow from operations on a pro forma, per unit basis;

• the conversion of subordinated units into common units;

• the conversion of units of equal rank with the common units into common units under some circumstances; or

• the conversion of our general partner's general partner interest in us and its incentive distribution rights into common units as a result of the withdrawal of our general partner.

Our partnership agreement does not restrict our ability to issue equity securities ranking junior to the common units at any time. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding.

Under our partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow the general partner and its affiliates or their assignees holding any units to require registration of any of these units and to include any of these units in a registration by us of other units, including units offered by us or by any unitholder. Our general partner will continue to have these registration rights for two years following its withdrawal or removal as a general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. Except as described below, the general partner and its affiliates may sell their units in private transactions at any time, subject to compliance with applicable laws. Our general partner and its affiliates, with our concurrence, have granted comparable registration rights to their bank group to which their partnership units have been pledged.

The sale of any common or subordinated units could have an adverse impact on the price of the common units or on any trading market that may develop.

Unitholders have less power to elect or remove management of our general partner than holders of common stock in a corporation. It is unlikely that our common unitholders will have sufficient voting power to elect or remove our general partner without the consent of Martin Resource Management and its affiliates.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and therefore limited ability to influence management's decisions regarding our business. Unitholders did not elect our general partner or its directors and will have no right to elect our general partner or its directors on an annual or other continuing basis. Holdings, the sole member of MMGP, elects the board of directors of our general partner.

If unitholders are dissatisfied with the performance of our general partner, they will have a limited ability to remove our general partner. Our general partner generally may not be removed except upon the vote of the holders of at least 66 2/3% of the outstanding units voting together as a single class. As of December 31, 2017, Martin Resource Management owned 16.3% of our total outstanding common limited partner units.

Unitholders' voting rights are further restricted by our partnership agreement provision prohibiting any units held by a person owning 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of our general partner's directors, from voting on any matter. In addition, our partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management.

As a result of these provisions, it will be more difficult for a third party to acquire our partnership without first negotiating the acquisition with our general partner. Consequently, it is unlikely the trading price of our common units will ever reflect a takeover premium.

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Our general partner's discretion in determining the level of our cash reserves may adversely affect our ability to make cash distributions to our unitholders.

Our partnership agreement requires our general partner to deduct from operating surplus cash reserves that it determines in its reasonable discretion to be necessary to fund our future operating expenditures. In addition, our partnership agreement permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available for distribution to our unitholders.

Unitholders may not have limited liability if a court finds that we have not complied with applicable statutes or that unitholder action constitutes control of our business.

The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some states. The holder of one of our common units could be held liable in some circumstances for our obligations to the same extent as a general partner if a court were to determine that:

• we had been conducting business in any state without compliance with the applicable limited partnership statute; or

• the right or the exercise of the right by our unitholders as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted participation in the "control" of our business.

Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. In addition, under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of nine years from the date of the distribution.

Our partnership agreement contains provisions that reduce the remedies available to unitholders for actions that might otherwise constitute a breach of fiduciary duty by our general partner.

Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner to the unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions that would otherwise constitute breaches of our general partner's fiduciary duties. For example, our partnership agreement:

• permits our general partner to make a number of decisions in its "sole discretion." This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner;

• provides that our general partner is entitled to make other decisions in its "reasonable discretion," which may reduce the obligations to which our general partner would otherwise be held;

• generally provides that affiliated transactions and resolutions of conflicts of interest not involving a required vote of unitholders must be "fair and reasonable" to us and that, in determining whether a transaction or resolution is "fair and reasonable," our general partner may consider the interests of all parties involved, including its own; and

• provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for errors of judgment or for any acts or omissions if our general partner and those other persons acted in good faith.

Unitholders are treated as having consented to the various actions contemplated in our partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary duties under applicable state law.

We may issue additional common units without unitholder approval, which would dilute unitholder ownership interests.

Our general partner may also cause us to issue an unlimited number of additional common units or other equity securities of equal rank with the common units, without unitholder approval, in a number of circumstances such as:

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• the issuance of common units in additional public offerings or in connection with acquisitions that increase cash flow from operations on a pro forma, per unit basis;

• the conversion of subordinated units into common units;

• the conversion of units of equal rank with the common units into common units under some circumstances; or

• the conversion of our general partner's general partner interest in us and its incentive distribution rights into common units as a result of the withdrawal of our general partner.

We may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Our partnership agreement does not give our unitholders the right to approve our issuance of equity securities ranking junior to the common units at any time.

The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:

• our unitholders' proportionate ownership interest in us will decrease;

• the amount of cash available for distribution on a per unit basis may decrease;

• because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

• the relative voting strength of each previously outstanding unit will diminish;

• the market price of the common units may decline; and

• the ratio of taxable income to distributions may increase.

The control of our general partner may be transferred to a third party and that party could replace our current management team, without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the owner of our general partner to transfer its ownership interest in our general partner to a third party. A new owner of our general partner could replace the directors and officers of our general partner with its own designees and control the decisions taken by our general partner.

Our general partner has a limited call right that may require unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining common units held by unaffiliated persons at a price not less than the then-current market price. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units. No provision in our partnership agreement, or in any other agreement we have with our general partner or Martin Resource Management, prohibits our general partner or its affiliates from acquiring more than 80% of our common units. For additional information about this call right and unitholders' potential tax liability, please see "Risk Factors - Tax Risks - Tax gain or loss on the disposition of our common units could be different than expected."

Our common units have a limited trading volume compared to other publicly traded securities.

Our common units are quoted on the NASDAQ under the symbol "MMLP." However, daily trading volumes for our common units are, and may continue to be, relatively small compared to many other securities quoted on the NASDAQ. The price of our common units may, therefore, be volatile.

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Failure to achieve and maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act could have a material adverse effect on our unit price.

In order to comply with Section 404 of the Sarbanes-Oxley Act, we periodically document and test our internal control procedures. Section 404 of the Sarbanes-Oxley Act requires annual management assessments of the effectiveness of our internal controls over financial reporting addressing these assessments. During the course of our testing we may identify deficiencies, which we may not be able to address in time to meet the deadline imposed by the Sarbanes-Oxley Act for compliance with the requirements of Section 404. In addition, if we fail to maintain the adequacy of our internal controls, as such standards are modified, supplemented or amended from time to time, we may not be able to ensure that we can conclude on an ongoing basis that we have effective internal controls over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act. Failure to achieve and maintain an effective internal control environment could have a material adverse effect on the price of our common units.

Risks Relating to Our Relationship with Martin Resource Management

Cash reimbursements due to Martin Resource Management may be substantial and will reduce our cash available for distribution to our unitholders.

Under our Omnibus Agreement with Martin Resource Management, Martin Resource Management provides us with corporate staff and support services on behalf of our general partner that are substantially identical in nature and quality to the services it conducted for our business prior to our formation. The Omnibus Agreement requires us to reimburse Martin Resource Management for the costs and expenses it incurs in rendering these services, including an overhead allocation to us of Martin Resource Management's indirect general and administrative expenses from its corporate allocation pool. These payments may be substantial. Payments to Martin Resource Management will reduce the amount of available cash for distribution to our unitholders.

Martin Resource Management has conflicts of interest and limited fiduciary responsibilities, which may permit it to favor its own interests to the detriment of our unitholders.

As of December 31, 2017, Martin Resource Management owned 16.3% of our total outstanding common limited partner units and a 51% voting interest in Holdings, the sole member of MMGP. MMGP owns a 2.0% general partnership interest in us and all of our incentive distribution rights. Conflicts of interest may arise between Martin Resource Management and our general partner, on the one hand, and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of Martin Resource Management over the interests of our unitholders. Potential conflicts of interest between us, Martin Resource Management and our general partner could occur in many of our day-to-day operations including, among others, the following situations:

• Officers of Martin Resource Management who provide services to us also devote significant time to the businesses of Martin Resource Management and are compensated by Martin Resource Management for that time;

• Neither our partnership agreement nor any other agreement requires Martin Resource Management to pursue a business strategy that favors us or utilizes our assets or services. Martin Resource Management's directors and officers have a fiduciary duty to make these decisions in the best interests of the shareholders of Martin Resource Management without regard to the best interests of the unitholders;

• Martin Resource Management may engage in limited competition with us;

• Our general partner is allowed to take into account the interests of parties other than us, such as Martin Resource Management, in resolving conflicts of interest, which has the effect of reducing its fiduciary duty to our unitholders;

• Under our partnership agreement, our general partner may limit its liability and reduce its fiduciary duties, while also restricting the remedies available to our unitholders for actions that, without the limitations and reductions, might constitute breaches of fiduciary duty. As a result of purchasing units, our unitholders will be treated as having consented to some actions and conflicts of interest that, without such consent, might otherwise constitute a breach of fiduciary or other duties under applicable state law;

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• Our general partner determines which costs incurred by Martin Resource Management are reimbursable by us;

• Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or from entering into additional contractual arrangements with any of these entities on our behalf;

• Our general partner controls the enforcement of obligations owed to us by Martin Resource Management;

• Our general partner decides whether to retain separate counsel, accountants or others to perform services for us;

• The audit committee of our general partner retains our independent auditors;

• In some instances, our general partner may cause us to borrow funds to permit us to pay cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions; and

• Our general partner has broad discretion to establish financial reserves for the proper conduct of our business. These reserves also will affect the amount of cash available for distribution.

Martin Resource Management and its affiliates may engage in limited competition with us.

Martin Resource Management and its affiliates may engage in limited competition with us. For a discussion of the non-competition provisions of the Omnibus Agreement, please see "Item 13. Certain Relationships and Related Transactions, and Director Independence." If Martin Resource Management does engage in competition with us, we may lose customers or business opportunities, which could have an adverse impact on our results of operations, cash flow and ability to make distributions to our unitholders.

If Martin Resource Management were ever to file for bankruptcy or otherwise default on its obligations under its credit facility, amounts we owe under our credit facility may become immediately due and payable and our results of operations could be adversely affected.

If Martin Resource Management were ever to commence or consent to the commencement of a bankruptcy proceeding or otherwise default on its obligations under its credit facility, its lenders could foreclose on its pledge of the interests in our general partner and take control of our general partner. If Martin Resources Management no longer controls our general partner, the lenders under our credit facility may declare all amounts outstanding thereunder immediately due and payable. In addition, either a judgment against Martin Resource Management or a bankruptcy filing by or against Martin Resource Management could independently result in an event of default under our credit facility if it could reasonably be expected to have a material adverse effect on us. If our lenders do declare us in default and accelerate repayment, we may be required to refinance our debt on unfavorable terms, which could negatively impact our results of operations and our ability to make distributions to our unitholders. A bankruptcy filing by or against Martin Resource Management could also result in the termination or material breach of some or all of the various commercial contracts between us and Martin Resource Management, which could have a material adverse impact on our results of operations, cash flow and ability to make distributions to our unitholders.

Tax Risks

The U.S. Internal Revenue Service (“IRS”) could treat us as a corporation for tax purposes, which would substantially reduce the cash available for distribution to unitholders.

The anticipated after-tax economic benefit of an investment in us depends largely on our classification as a partnership for federal income tax purposes. We have not requested a ruling from the IRS on this matter.

Despite the fact that we are organized as a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. In order for us to be classified as a partnership for U.S. federal income tax purposes, more than 90% of our gross income each year must be "qualifying income" under Section 7704 of the U.S. Internal Revenue Code of 1986, as amended (the "Code"). "Qualifying income" includes income and gains derived from the exploration, development, mining or production, processing, refining, transportation, or marketing of minerals or natural resources, including crude oil, natural gas and products thereof. Other types

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of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income.

Although we intend to meet this gross income requirement, we may not find it possible, regardless of our efforts, to meet this gross income requirement or may inadvertently fail to meet this gross income requirement. If we do not meet this gross income requirement for any taxable year and the IRS does not determine that such failure was inadvertent, we would be treated as a corporation for such taxable year and each taxable year thereafter.

If we were treated as a corporation for federal income tax purposes, we would owe federal income tax on our income at the corporate tax rate, which is currently a maximum of 21%, and would likely owe state income tax at varying rates. Distributions would generally be taxed again to unitholders as corporate distributions and no income, gains, losses, or deductions would flow through to unitholders. Because a tax would be imposed upon us as an entity, cash available for distribution to unitholders would be reduced. Treatment of us as a corporation would result in a reduction in the anticipated cash flow and after-tax return to unitholders and therefore would likely result in a reduction in the value of the common units.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amount will be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative or judicial interpretation at any time.

At the federal level, members of Congress and the President of the United States have periodically considered substantive changes to the existing U.S. tax laws that would have affected certain publicly traded partnerships, including the elimination of partnership tax treatment for publicly traded partnerships. At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay a Texas margin tax at a maximum effective rate of 0.525% of our gross income apportioned to Texas in the prior year. Imposition of any such tax on us by any other state will reduce the cash available for distribution to you.

Any modification to the tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception pursuant to which we are treated as a partnership for U.S. federal income tax purposes that is not taxable as a corporation, affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our common units. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

On January 24, 2017, the U.S. Department of the Treasury issued final regulations (the “Final Regulations”) regarding qualifying income under Section 7704(d)(1)(E) of the Code which relates to the qualifying income exception upon which we rely for partnership tax treatment. The Final Regulations apply to income earned in a taxable year beginning on or after January 19, 2017. The Final Regulations include “reserved” paragraphs for fertilizer and hedging, which the U.S. Department of the Treasury plans to address in future proposed and final Treasury regulations (“Treasury regulations”). The Final Regulations provide for a ten year transition period during which certain taxpayers that either obtained a favorable private letter ruling or treated income under a reasonable interpretation of the statute or prior proposed regulations as qualifying income may continue to treat such income as qualifying income. We have obtained favorable private letter rulings from the IRS in the past as to what constitutes “qualifying income” within the meaning of Section 7704(d)(1)(E) of the Code and we expect to rely upon these private letter rulings for purposes of the ten year transition rule contained in the Final Regulations. With respect to some of these private letter rulings, the income that we derived from certain affected activities will be treated as qualifying income only until the end of the ten year transition period. Thus, at this time and through the transition period (and possibly beyond if not involving such affected activities), we believe that the Final Regulations will not significantly impact the amount of our gross income that we are able to treat as qualifying income.

The effects of the budget reconciliation act commonly referred to as the Tax Cuts and Jobs Act (hereinafter, “Tax Cuts and Jobs Act”) on our business have not yet been fully analyzed and could have an adverse effect on our net income.

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   On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”) that makes significant changes to the U.S. Internal Revenue Code. Among other changes, the Tax Act includes a reduction in the corporate and individual tax rates, a new deduction on certain pass-through income, a repeal of the partnership technical termination rule, and new limitations on certain deductions and credits, including interest expense deductions. The Tax Act is complex and far-reaching and we have not completed our analysis of the impact its enactment has on us. Certain of the changes made by the Tax Act could have a negative impact on our business, results of operations, financial condition, and cash flow.

A successful IRS contest of the federal income tax positions we take could adversely affect the market for our common units and the costs of any contest will be borne by our unitholders, debt security holders and our general partner.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take and our counsel's conclusions. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel's conclusions or the positions we take. A court may not agree with some or all our counsel's conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the prices at which they trade. In addition, the costs of any contest with the IRS will be borne directly or indirectly by all of our unitholders, debt security holders and our general partner.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.

Pursuant to the Bipartisan Budget Act of 2015 and recently issued proposed Treasury Regulations (the “Proposed Partnership Audit Regulations”), for taxable years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. Similarly, for such taxable years, if the IRS makes audit adjustments to income tax returns filed by an entity in which we are a member or partner, the IRS may assess and collect any taxes (including penalties and interest) resulting from such audit adjustment directly from such entity. Generally, we expect to elect to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, but there can be no assurance that such election will be effective in all circumstances. With respect to audit adjustments as to an entity in which we are a member or partner, the Joint Committee on Taxation has stated that we should not be able to have our unitholders take such audit adjustment into account. The Proposed Partnership Audit Regulations reserved on this issue and requested comments but noted that allowing a partnership, such as us, to have its unitholders take such audit adjustment into account would present complexities, challenges, and inefficiencies. If we are unable to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest as a result of audit adjustments cash available for distribution to our unitholders may be substantially reduced. These rules are not applicable to us for tax years beginning on or prior to December 31, 2017.

Additionally, pursuant to the Bipartisan Budget Act of 2015 and the Proposed Partnership Audit Regulations, we will no longer be required to designate a “tax matters partner.” Instead, for taxable years beginning after December 31, 2017, we will be required to designate a partner, or other person, with a substantial presence in the United States as the partnership representative (“Partnership Representative”). The Partnership Representative will have the sole authority to act on our behalf for purposes of, among other things, U.S. federal income tax audits and judicial review of administrative adjustments by the IRS. If we do not make such a designation, the IRS can select any person as the Partnership Representative. Any actions taken by us or by the Partnership Representative on our behalf with respect to, among other things, U.S. federal income tax audits and judicial review of administrative adjustments by the IRS, will be binding on us and all of the unitholders. We anticipate that our current tax matters partner will be designated the Partnership Representative.

Unitholders may be required to pay taxes on income from us, including their share of income from the cancellation of debt, even if they do not receive any cash distributions from us.

Unitholders may be required to pay federal income taxes and, in some cases, state, local and foreign income taxes on their share of our taxable income even if they receive no cash distributions from us. Unitholders may not receive cash

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distributions from us equal to their share of our taxable income or even the tax liability that results from the taxation of their share of our taxable income.

We may engage in transactions to delever the partnership and manage our liquidity that may result in income to our unitholders without a corresponding cash distribution. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, you may be allocated taxable income and gain resulting from the sale without receiving a cash distribution. Further, taking advantage of opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt could result in “cancellation of indebtedness income” (also referred to as “COD income”) being allocated to our unitholders as taxable income. Unitholders may be allocated COD income, and income tax liabilities arising therefrom may exceed cash distributions or the value of the units. The ultimate effect of any such allocations will depend on the unitholder's individual tax position with respect to its units. Unitholders are encouraged to consult their tax advisor with respect to the consequences to them of COD income.

Tax gain or loss on the disposition of our common units could be different than expected.

If our unitholders sell their common units, they will recognize gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions in excess of the total net taxable income unitholders were allocated for a common unit, which decreased unitholder tax basis in that common unit, will, in effect, become taxable income to our unitholders if the common unit is sold at a price greater than their tax basis in that common unit, even if the price they receive is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to our unitholders. Should the IRS successfully contest some positions we take, our unitholders could recognize more gain on the sale of units than would be the case under those positions without the benefit of decreased income in prior years. In addition, if our unitholders sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as employee benefit plans, individual retirement accounts (known as IRAs), Keogh plans and other retirement plans, regulated investment companies, real estate investment trusts, mutual funds and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. Tax-exempt entities, non-U.S. persons and other unique investors should consult their tax advisor regarding their investment in our common units.

We treat a purchaser of our common units as having the same tax benefits without regard to the seller's identity. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation positions that may not conform to all aspects of the Treasury regulations. Any position we take that is inconsistent with applicable Treasury regulations may have to be disclosed on our federal income tax return. This disclosure increases the likelihood that the IRS will challenge our positions and propose adjustments to some or all of our unitholders. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders' tax returns.

Unitholders may be subject to state, local and foreign taxes and return filing requirements as a result of investing in our common units.

In addition to federal income taxes, unitholders may be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. Unitholders may be required to file state, local and foreign income tax returns and pay state and local income taxes in some or all of the various jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. We own property and/or conduct business in Alabama, Arizona, Arkansas, California, Florida, Georgia, Illinois, Indiana, Kansas, Louisiana, Minnesota, Mississippi, Missouri, Nebraska, Nevada, New Mexico, Oklahoma, Pennsylvania, Tennessee, Texas, Utah, and West Virginia. We may do business or own property in other states or foreign countries in the future. It is the unitholder's responsibility to file all federal, state, local

35

and foreign tax returns. Our counsel has not rendered an opinion on the state, local or foreign tax consequences of an investment in our common units.

There are limits on the deductibility of our losses that may adversely affect our unitholders.

There are a number of limitations that may prevent unitholders from using their allocable share of our losses as a deduction against unrelated income. In cases when our unitholders are subject to the passive loss rules (generally, individuals and closely-held corporations), any losses generated by us will only be available to offset our future income and cannot be used to offset income from other activities, including other passive activities or investments. Unused losses may be deducted when the unitholder disposes of its entire investment in us in a fully taxable transaction with an unrelated party. A unitholder's share of our net passive income may be offset by unused losses from us carried over from prior years but not by losses from other passive activities, including losses from other publicly traded partnerships. Other limitations that may further restrict the deductibility of our losses by a unitholder include the at-risk rules and the prohibition against loss allocations in excess of the unitholder's tax basis in its units.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. Treasury regulations permit publicly traded partnerships to use a monthly simplifying convention that is similar to ours, but they do not specifically authorize all aspects of the proration method we have adopted. Therefore, the use of our proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of such method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

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Item 1B. Unresolved Staff Comments

None. 

Item 2. Properties

A description of our properties is contained in "Item 1.  Business" and is incorporated herein by reference. 

We believe we have satisfactory title to our assets.  Some of the easements, rights-of-way, permits, licenses or similar documents relating to the use of the properties that have been transferred to us in connection with our initial public offering and the assets we acquired in our acquisitions, required the consent of third parties, which in some cases is a governmental entity.  We believe we have obtained sufficient third-party consents, permits and authorizations for the transfer of assets necessary for us to operate our business in all material respects.  With respect to any third-party consents, permits or authorizations that have not been obtained, we believe the failure to obtain these consents, permits or authorizations will not have a material adverse effect on the operation of our business. Title to our property may be subject to encumbrances, including liens in favor of our secured lender.  We believe none of these encumbrances materially detract from the value of our properties or our interest in these properties or materially interfere with their use in the operation of our business.

Item 3. 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. A description of our legal proceedings is included in "Item 8. Financial Statements and Supplementary Data, Note 21. Commitments and Contingencies", and is incorporated herein by reference.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

Item 5. Market for Our Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

Market Information and Holders

Our common units are traded on the NASDAQ under the symbol "MMLP." As of January 26, 2018 there were approximately 280 holders of record and approximately 21,550 beneficial owners of our common units.  The following table sets forth the high and low sale prices of our common units for the periods indicated, based on the daily composite listing of stock transactions for NASDAQ during those periods:

	Year Ended December 31, 2017				Year Ended December 31, 2016
	High		Low		High		Low
First Quarter	$	20.10	$	17.50	$	22.22	$	14.05
Second Quarter	$	20.45	$	16.60	$	23.77	$	19.40
Third Quarter	$	19.85	$	15.55	$	25.12	$	18.99
Fourth Quarter	$	17.20	$	12.90	$	21.63	$	15.80

Cash Distributions

The following table sets forth the quarterly cash distribution declared and paid for our common units during the periods indicated:

Declared for Quarter Ended	Distribution Per Common Unit		Date Declared	Date Paid
December 31, 2017	$	0.5000	January 18, 2018	February 14, 2018
September 30, 2017	$	0.5000	October 19, 2017	November 14, 2017
June 30, 2017	$	0.5000	July 20, 2017	August 14, 2017
March 31, 2017	$	0.5000	April 20, 2017	May 15, 2017
December 31, 2016	$	0.5000	January 19, 2017	February 14, 2017
September 30, 2016	$	0.5000	October 20, 2016	November 14, 2016
June 30, 2016	$	0.8125	July 21, 2016	August 12, 2016
March 31, 2016	$	0.8125	April 21, 2016	May 13, 2016

Cash Distribution Policy

Within 45 days after the end of each quarter, we distribute all of our available cash, as defined in our partnership agreement, to unitholders of record on the applicable record date.  Our general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct our business.  These can include cash reserves for future capital and maintenance expenditures, reserves to stabilize distributions of cash to the unitholders and our general partner, reserves to reduce debt, or, as necessary, reserves to comply with the terms of any of our agreements or obligations.  Our distributions are effectively made 98% to unitholders and 2.0% to our general partner, subject to the payment of incentive distributions to our general partner if certain target cash distribution levels to common unitholders are achieved.  Distributions to our general partner increase to 15%, 25% and 50% based on incremental distribution thresholds as set forth in our partnership agreement.

Our ability to distribute available cash is contractually restricted by the terms of our credit facility.  Our credit facility contains covenants requiring us to maintain certain financial ratios.  We are prohibited from making any distributions to unitholders if the distribution would cause a default or an event of default, or a default or an event of default exists, under our credit facility.  Please read "Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Description of Our Credit Facility."

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Item 6. Selected Financial Data

The following table sets forth selected financial data and other operating data of the Partnership for the years ended December 31, 2017, 2016, 2015, 2014 and 2013 and is derived from the audited consolidated financial statements of the Partnership.

The following selected financial data are qualified by reference to and should be read in conjunction with the Partnership's Consolidated Financial Statements and Notes thereto and "Management’s Discussion and Analysis of Financial Condition and Results of Operations" included elsewhere in this document.

	2017		2016		2015		2014			2013
	(Dollars in thousands, except per unit amounts)
Revenues	$	946,116	$	827,391	$	1,036,844	$	1,642,141		$	1,612,739
Income (loss) from continuing operations	17,135		31,652		37,165		(6,367		)	(14,562		)
Income (loss) from discontinued operations, net of tax	—		—		1,215		(5,338		)	1,208
Net income (loss)	$	17,135	$	31,652	$	38,380	$	(11,705	)	$	(13,354	)
Net income (loss) attributable to limited partners	$	16,750	$	23,143	$	21,902	$	(15,176	)	$	(13,047	)
Net income (loss) per limited partner unit – continuing operations	0.44		0.65		0.60		(0.27		)	(0.54		)
Net income (loss) per limited partner unit – discontinued operations	—		—		0.02		(0.22		)	0.04
Net income (loss) per limited partner unit	$	0.44	$	0.65	$	0.62	$	(0.49	)	$	(0.50	)
Total assets	$	1,253,498	$	1,246,363	$	1,380,473	$	1,553,919		$	1,097,919
Long-term debt	812,632		808,107		865,003		902,005			658,695
Cash dividends per common unit (in dollars)	2.00		2.94		3.25		3.18			3.11

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Overview

We are a publicly traded limited partnership with a diverse set of operations focused primarily in the United States ("U.S.") Gulf Coast region. Our four primary business lines include:

• Terminalling and storage services for petroleum products and by-products, including the refining of naphthenic crude oil and the blending and packaging of finished lubricants;

• Natural gas liquids transportation and distribution services and natural gas storage;

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

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

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

We were formed in 2002 by Martin Resource Management, a privately-held company whose initial predecessor was incorporated in 1951 as a supplier of products and services to drilling rig contractors. Since then, Martin Resource Management has expanded its operations through acquisitions and internal expansion initiatives as its management identified and capitalized on the needs of producers and purchasers of petroleum products and by-products and other bulk liquids. Martin Resource Management is an important supplier and customer of ours. As of December 31, 2017, Martin Resource Management owned 16.3% of our total outstanding common limited partner units. Furthermore, Martin Resource Management 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. 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.

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

West Texas LPG Pipeline Limited Partnership Expansion. On October 23, 2017, we announced that the West Texas LPG Pipeline Limited Partnership 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 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

40

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.

Hurricane Impact. On August 25, 2017, Hurricane Harvey made landfall as a Category 4 hurricane. The storm lingered over Texas and Louisiana for days producing over 50 inches of rain in some areas, resulting in widespread flooding and damage. We experienced an impact from Hurricane Harvey in our Terminalling and Storage and Sulfur Services segments, where damages were suffered to our property, plant, and equipment at our Neches, Stanolind, Galveston, and Harbor Island terminals located along the Texas gulf coast. The damage incurred did not exceed the insurance deductible at these locations and therefore we do not expect to receive any insurance proceeds resulting from the damage from Hurricane Harvey. For the year ended December 31, 2017, we spent $3.8 million related to actual repairs and improvements made to assets damaged by Hurricane Harvey. Additionally, we recorded an accrual for $0.7 million in estimated repairs to be made to assets damaged by Hurricane Harvey. As a result of the damage sustained, we recorded a write-off in the amount of $0.2 million related to assets damaged. Hurricane Harvey impacted our operations primarily in our Terminalling and Storage and Sulfur Services segments, where we experienced an estimated reduction in net income and cash flow of approximately $1.1 million from lost volume and downtime due to the hurricane.

2017 Restricted Unit Plan. On May 26, 2017, our unitholders approved the Martin Midstream Partners L.P. 2017 Restricted Unit Plan (the “New LTIP”), which authorizes 3,000,000 common units to be available for delivery with respect to awards under the plan. A summary of the New LTIP is set forth under the caption “Proposal to Approve the Martin Midstream Partners L.P. 2017 Restricted Unit Plan” in our definitive proxy statement filed with the SEC on April 21, 2017 (the “Proxy Statement”).

Equity Offering. On February 22, 2017, we 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. Total proceeds from the sale of the 2,990,000 common units, net of underwriters' discounts, commissions and offering expenses, were $51.1 million. Additionally, our general partner contributed $1.1 million in cash to us in conjunction with the issuance in order to maintain its 2.0% general partner interest in us. All of the net proceeds were used to pay down outstanding amounts under our revolving credit facility.

Acquisition of Terminalling Assets.  On February 22, 2017, we acquired certain asphalt terminalling assets located in Hondo, Texas for a purchase price of $27.4 million (the “Hondo Acquisition”).  At the date of acquisition, Martin Resource Management was in the process of constructing an asphalt terminal facility in Hondo, Texas, which will serve the asphalt market in San Antonio, Texas and surrounding areas.  This terminal will have 178,000 barrels of asphalt storage with processing and blending capabilities.  We spent $8.6 million to finalize construction of the terminal.  The terminal is supported by long-term contractual agreements with Martin Resource Management whereby we expect to receive cash flow of approximately $5.0 million annually.

Repayment of Note Receivable.  On February 14, 2017, we notified Martin Resource Management that we would be requesting voluntary repayment of the long-term Note Receivable - Affiliate of $15.0 million plus accrued interest. During the second quarter of 2017, the Note Receivable - Affiliate was fully repaid.

West Texas LPG Pipeline Limited Partnership ("WTLPG") 2015 Rate Complaints. Certain shippers filed complaints with the Railroad Commission of Texas (“RRC”) challenging the increased rates WTLPG implemented effective July 1, 2015.  The 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.

Subsequent Events

Quarterly Distribution. On January 18, 2018, we declared a quarterly cash distribution of $0.50 per common unit for the fourth quarter of 2017, or $2.00 per common unit on an annualized basis, which was paid on February 14, 2018 to unitholders of record as of February 7, 2018.

Critical Accounting Policies and Estimates    

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Our discussion and analysis of our financial condition and results of operations are based on the historical consolidated 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 required 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 based 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. The following table evaluates the potential impact of estimates utilized during the periods ended December 31, 2017 and 2016:

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.	Applying this impairment review methodology, in 2017 we recorded an impairment charge of $1.6 million in our Marine Transportation segment and $0.6 million in our Terminalling and Storage segment. In 2016 we recorded an impairment charge of $15.3 million in our Terminalling and Storage segment and $11.7 million in our Marine Transportation segment. In 2015 we recorded an impairment charge of $9.3 million in our Terminalling and Storage segment and $1.3 million in our Marine Transportation segment.
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 the related asset is depreciated over its useful life 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.

Our Relationship with Martin Resource Management

Martin Resource Management directs our business operations through its ownership and control of our general partner and under the Omnibus Agreement. In addition to the direct expenses, under the Omnibus Agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. For the years ended December 31, 2017, 2016 and 2015, the conflicts committee of our general partner ("Conflicts Committee") approved reimbursement amounts of $16.4 million, $13.0 million and $13.7 million, respectively, reflecting 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.

We are required 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. Martin Resource Management also licenses certain of its trademarks and trade names to us under the Omnibus Agreement.

We are both an important supplier to and customer of Martin Resource Management. Among other things, we provide marine transportation and terminalling and storage services to Martin Resource Management. We purchase land transportation

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services and marine fuel from Martin Resource Management. All of these services and goods are purchased and sold pursuant to the terms of a number of agreements between us and Martin Resource Management.

For a more comprehensive discussion concerning the Omnibus Agreement and the other agreements that we have entered into with Martin Resource Management, please see "Item 13. Certain Relationships and Related Transactions, and Director Independence."

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

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

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

Non-GAAP Financial Measures

The following table reconciles the non-GAAP financial measurements used by management to our most directly comparable GAAP measures for the years ended December 31, 2017, 2016, and 2015, which represents EBITDA, Adjusted EBITDA and Distributable Cash Flow from continuing operations.

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Reconciliation of EBITDA, Adjusted EBITDA, and Distributable Cash Flow

	Year Ended December 31,
	2017			2016			2015
Net income	$	17,135		$	31,652		$	38,380
Less: Income from discontinued operations, net of income taxes	—			—			(1,215		)
Income from continuing operations	17,135			31,652			37,165
Adjustments:
Interest expense	47,743			46,100			43,292
Income tax expense	352			726			1,048
Depreciation and amortization	85,195			92,132			92,250
EBITDA	150,425			170,610			173,755
Adjustments:
Equity in earnings of unconsolidated entities	(4,314		)	(4,714		)	(8,986		)
(Gain) loss on sale of property, plant and equipment	(523		)	(33,400		)	2,149
Gain on retirement of senior unsecured notes	—			—			(1,242		)
Impairment of long-lived assets	2,225			26,953			10,629
Impairment of goodwill	—			4,145			—
Unrealized mark-to-market on commodity derivatives	(3,832		)	4,579			(675		)
Hurricane damage repair accrual	657			—			—
Asset retirement obligation revision	5,547			—			—
Distributions from unconsolidated entities	5,400			7,500			11,200
Unit-based compensation	650			904			1,429
Adjusted EBITDA	156,235			176,577			188,259
Adjustments:
Interest expense	(47,743		)	(46,100		)	(43,292		)
Income tax expense	(352		)	(726		)	(1,048		)
Amortization of deferred debt issuance costs	2,897			3,684			4,859
Amortization of debt premium	(306		)	(306		)	(324		)
Non-cash mark-to-market on interest rate derivatives	—			(206		)	206
Payments for plant turnaround costs	(1,583		)	(2,061		)	(1,908		)
Maintenance capital expenditures	(18,080		)	(17,163		)	(12,902		)
Distributable Cash Flow	$	91,068		$	113,699		$	133,850

Results of Operations

The results of operations for the years ended December 31, 2017, 2016, and 2015 have been derived from our consolidated financial statements.

We evaluate segment performance on the basis of operating income, which is derived by subtracting cost of products sold, operating expenses, selling, general and administrative expenses, and depreciation and amortization expense from revenues.  The following table sets forth our operating revenues and operating income by segment for the years ended December 31, 2017, 2016, and 2015.  

Our consolidated 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 after the comparative discussion of our results within each segment.

The Natural Gas Services segment information below excludes the discontinued operations of the Floating Storage Assets disposed of on February 12, 2015 for the year ended December 31, 2015. See Item 8, Note 5.

44

	Operating Revenues		Revenues Intersegment Eliminations			Operating Revenues  after Eliminations		Operating Income (loss)			Operating Income Intersegment Eliminations			Operating Income (loss)  after Eliminations
	(In thousands)
Year Ended December 31, 2017:
Terminalling and storage	$	236,169	$	(5,998	)	$	230,171	$	3,305		$	(2,676	)	$	629
Natural gas services	532,908		(226		)	532,682		49,191			2,472			51,663
Sulfur services	134,684		—			134,684		25,862			(2,657		)	23,205
Marine transportation	51,915		(3,336		)	48,579		(1,211		)	2,861			1,650
Indirect selling, general and administrative	—		—			—		(17,332		)	—			(17,332		)
Total	$	955,676	$	(9,560	)	$	946,116	$	59,815		$	—		$	59,815
Year Ended December 31, 2016:
Terminalling and storage	$	242,363	$	(5,653	)	$	236,710	$	44,143		$	(3,483	)	$	40,660
Natural gas services	391,333		—			391,333		38,382			3,056			41,438
Sulfur services	141,058		—			141,058		26,815			(3,422		)	23,393
Marine transportation	61,233		(2,943		)	58,290		(19,888		)	3,849			(16,039		)
Indirect selling, general and administrative	—		—			—		(16,794		)	—			(16,794		)
Total	$	835,987	$	(8,596	)	$	827,391	$	72,658		$	—		$	72,658
Year Ended December 31, 2015:
Terminalling and storage	$	270,440	$	(5,670	)	$	264,770	$	18,750		$	(3,046	)	$	15,704
Natural gas services	523,160		—			523,160		38,611			2,609			41,220
Sulfur services	170,161		—			170,161		27,113			(3,509		)	23,604
Marine transportation	81,784		(3,031		)	78,753		4,630			3,946			8,576
Indirect selling, general and administrative	—		—			—		(18,951		)	—			(18,951		)
Total	$	1,045,545	$	(8,701	)	$	1,036,844	$	70,153		$	—		$	70,153

45

Terminalling and Storage Segment

Comparative Results of Operations for the Twelve Months Ended December 31, 2017 and 2016

	Year Ended December 31,				Variance			Percent Change
	2017		2016
	(In thousands)
Revenues:
Services	$	105,703	$	128,783	$	(23,080	)	(18)%
Products	130,466		113,580		16,886			15%
Total revenues	236,169		242,363		(6,194		)	(3)%
Cost of products sold	112,135		96,344		15,791			16%
Operating expenses	69,888		71,831		(1,943		)	(3)%
Selling, general and administrative expenses	5,832		4,677		1,155			25%
Impairment of long-lived assets	600		15,252		(14,652		)	(96)%
Depreciation and amortization	45,160		45,484		(324		)	(1)%
	2,554		8,775		(6,221		)	(71)%
Other operating income, net	751		35,368		(34,617		)	(98)%
Operating income	$	3,305	$	44,143	$	(40,838	)	(93)%
Lubricant sales volumes (gallons)	21,897		17,995		3,902			22%
Shore-based throughput volumes (guaranteed minimum) (gallons)	144,998		200,000		(55,002		)	(28)%
Smackover refinery throughput volumes (guaranteed minimum BBL per day)	6,500		6,500		—			—%
Corpus Christi crude terminal throughput volumes (barrels per day)	—		66,167		(66,167		)	(100)%

Services revenues. Services revenue decreased primarily as a result of decreased throughput volumes and pass-through revenues at our Corpus Christi crude terminal, which was sold on December 21, 2016.

Products revenues. An 11% increase in sales volumes offset by a 1% decrease in average sales price at our blending and packaging facilities resulted in a $5.9 million increase to products revenues. Products revenues at our shore-based terminals increased $11.0 million resulting from an 18% increase in average sales price and a 1% increase in sales volume.

Cost of products sold.  An 11% increase in sales volumes at our blending and packaging facilities resulted in a $4.9 million increase in cost of products sold. Average cost per gallon increased 2%, resulting in a $0.8 million increase in cost of products sold. Cost of products sold at our shore-based terminals increased $10.1 million resulting from an 19% increase in average cost per gallon and a 1% increase in sales volumes.

Operating expenses. Operating expenses at our specialty terminals decreased $4.8 million, primarily as a result of the disposition of the Corpus Christi crude terminalling assets in the fourth quarter 2016 of $7.6 million, offset by hurricane expenses of $2.5 million. Operating expenses at our shore-based terminals increased by $3.2 million, primarily due to a $5.5 million increase in the accrual related to asset retirement obligations at leased terminal facilities and hurricane expenses of $0.3 million, offset by $2.7 million decrease associated with closed facilities.

Selling, general and administrative expenses.   Selling, general and administrative expenses increased primarily due to increased legal fees of $0.6 million and compensation expense of $0.5 million.

Depreciation and amortization.  The decrease in depreciation and amortization is due to the impact of the disposition of assets and assets being fully depreciated, offset by capital expenditures.

Other operating income, net.  Other operating income, net represents gains and losses from the disposition of property, plant and equipment. The 2016 period includes the gain on the disposition of the Corpus Christi crude terminalling assets of $37.3 million.

46

Comparative Results of Operations for the Twelve Months Ended December 31, 2016 and 2015

	Year Ended December 31,					Variance			Percent Change
	2016		2015
	(In thousands)
Revenues:
Services	$	128,783	$	138,614		$	(9,831	)	(7)%
Products	113,580		131,826			(18,246		)	(14)%
Total revenues	242,363		270,440			(28,077		)	(10)%
Cost of products sold	96,344		115,460			(19,116		)	(17)%
Operating expenses	71,831		83,917			(12,086		)	(14)%
Selling, general and administrative expenses	4,677		3,804			873			23%
Impairment of long-lived assets	15,252		9,305			5,947			64%
Depreciation and amortization	45,484		38,731			6,753			17%
	8,775		19,223			(10,448		)	(54)%
Other operating income (loss), net	35,368		(473		)	35,841			(7,577)%
Operating income	$	44,143	$	18,750		$	25,393		135%
Lubricant sales volumes (gallons)	17,995		23,045			(5,050		)	(22)%
Shore-based throughput volumes (guaranteed minimum) (gallons)	200,000		275,000			(75,000		)	(27)%
Smackover refinery throughput volumes (guaranteed minimum BBL per day)	6,500		6,500			—			—%
Corpus Christi crude terminal (barrels per day)	66,167		154,381			(88,214		)	(57)%

Services revenues. Services revenue decreased primarily as a result of decreased throughput volumes and pass-through revenues at our Corpus Christi crude terminal, which was sold on December 21, 2016.

Products revenues. A 22% decrease in sales volumes at our blending and packaging facilities resulted in a $15.6 million decrease to products revenues. The decline in volumes resulted primarily from the downturn in the energy industry, as well as increased price competition. Products revenues at our shore-based terminals decreased $2.3 million resulting from a 7% decrease in average sales price offset by a 3% increase in sales volume.

Cost of products sold.  A 22% decrease in sales volumes at our blending and packaging facilities resulted in an $11.9 million decrease in cost of products sold. Average cost per gallon decreased 8%, resulting in a $4.6 million decrease in cost of products sold. Cost of products sold at our shore-based terminals decreased $2.6 million resulting from a 7% decrease in average cost per gallon offset by a 3% increase in sales volumes.

Operating expenses. Operating expenses at our specialty terminals decreased $9.0 million, primarily as a result of $3.9 million in decreased pass-through expenses at our Corpus Christi crude terminal, $4.2 million in decreased repairs and maintenance across our specialty terminals, and a $0.6 million decrease related to compensation expense across our specialty terminals. Operating expenses at our Smackover refinery decreased $1.8 million, primarily as a result of $1.8 million in decreased repairs and maintenance, $0.5 million in decreased compensation expense, $0.6 million in decreased utilities expense. These decreases were offset by an increase in property damage claims of $0.5 million and increased lease expense of $0.4 million. Operating expenses at our shore-based terminals decreased by $1.3 million primarily due to a decrease in freight expense of $0.4 million, compensation expense of $0.4 million, property tax expense of $0.3 million, and repairs and maintenance of $0.2 million.

Selling, general and administrative expenses.   Selling, general and administrative expenses increased $0.9 million, of which $0.3 million is the result of increased compensation expense and $0.2 million is the result of increased advertising in our blending and packaging operations and $0.4 million is due to increased legal fees at our shore-based terminals.

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

47

Other operating income (loss), net.  Other operating income (loss), net represents gains and losses from the disposition of property, plant and equipment. The 2016 period includes the gain on the disposition of the CCCT Assets of $37.3 million.

Natural Gas Services Segment

Comparative Results of Operations for the Twelve Months Ended December 31, 2017 and 2016

	Year Ended December 31,						Variance			Percent Change
	2017			2016
	(In thousands)
Revenues:
Services	$	58,817		$	61,133		$	(2,316	)	(4)%
Products	474,091			330,200			143,891			44%
Total revenues	532,908			391,333			141,575			36%
Cost of products sold	425,073			292,573			132,500			45%
Operating expenses	22,347			23,152			(805		)	(3)%
Selling, general and administrative expenses	11,292			9,035			2,257			25%
Depreciation and amortization	24,916			28,081			(3,165		)	(11)%
	49,280			38,492			10,788			28%
Other operating loss, net	(89		)	(110		)	21			(19)%
Operating income	$	49,191		$	38,382		$	10,809		28%
Distributions from unconsolidated entities	$	5,400		$	7,500		$	(2,100	)	(28)%
NGLs Volumes (barrels)	10,487			9,532			955			10%

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

Products Revenues. Our NGL average sales price per barrel increased $10.57, or 31%, resulting in an increase to products revenues of $100.7 million. The increase in average sales price per barrel was a result of an increase in market prices. Product sales volumes increased 10%, increasing revenues $43.2 million.

Cost of products sold.   Our average cost per barrel increased $9.84, or 32%, increasing cost of products sold by $93.8 million.  The increase in average cost per barrel was a result of an increase in market prices.  The increase in sales volume of 10% resulted in a $38.7 million increase to cost of products sold. Our margins increased $0.73 per barrel, or 18% during the period.

Operating expenses.  Operating expenses decreased $0.8 million due to $0.3 million of decreased maintenance expense at our NGL East Texas pipeline, decreased compensation expense of $0.3 million, and decreased repairs and maintenance at our underground NGL storage facility of $0.2 million.

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

Depreciation and amortization. Depreciation and amortization decreased primarily due to a $3.7 million decrease in amortization related to contracts acquired during the purchase of Cardinal Gas Storage Partners, LLC (“Cardinal”), offset by a $0.6 million increase in depreciation expense related to recent capital expenditures.

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

48

Comparative Results of Operations for the Twelve Months Ended December 31, 2016 and 2015

	Year Ended December 31,						Variance			Percent Change
	2016			2015
	(In thousands)
Revenues:
Services	$	61,133		$	64,858		$	(3,725	)	(6)%
Products	330,200			458,302			(128,102		)	(28)%
Total revenues	391,333			523,160			(131,827		)	(25)%
Cost of products sold	292,573			416,404			(123,831		)	(30)%
Operating expenses	23,152			23,979			(827		)	(3)%
Selling, general and administrative expenses	9,035			9,791			(756		)	(8)%
Depreciation and amortization	28,081			34,072			(5,991		)	(18)%
	38,492			38,914			(422		)	(1)%
Other operating loss, net	(110		)	(303		)	193			(64)%
Operating income	$	38,382		$	38,611		$	(229	)	(1)%
Distributions from unconsolidated entities	$	7,500		$	11,200		$	(3,700	)	(33)%
NGLs Volumes (barrels)	9,532			14,340			(4,808		)	(34)%

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

Products Revenues. Our NGL average sales price per barrel increased $2.68, or 8%, resulting in an increase to products revenues of $38.5 million. The increase in average sales price per barrel was a result of an increase in market prices. Product sales volumes decreased 34%, decreasing revenues $166.6 million.

Cost of products sold.   Our average cost per barrel increased $1.66, or 6%, increasing cost of products sold by $23.7 million.  The increase in average cost per barrel was a result of an increase in market prices.  The decrease in sales volume of 34% resulted in a $147.6 million decrease to cost of products sold. Our margins increased $1.03 per barrel, or 35% during the period.

Operating expenses.  Operating expenses decreased primarily due to a $0.6 million decrease in pipeline testing expense, $0.4 million in lower fuel expense at our gas storage facilities, $0.3 million decrease in maintenance expense at our gas storage facilities, $0.1 million decrease in NGLs employment expense and a $0.1 million decrease in utility expense related to our East Texas NGL pipeline. These decreases are offset by a $0.8 million increase from our Arcadia rail facility put into service in June 2015.

Selling, general and administrative expenses.  Selling, general and administrative expenses decreased primarily due to a $0.3 million decrease in professional fees, $0.2 million decrease in bad debt expense, and a $0.2 million decrease in property tax expense.

Depreciation and amortization. Depreciation and amortization decreased primarily due to a $6.8 million decrease in amortization related to contracts acquired during the purchase of Cardinal, offset by a $0.8 million increase in depreciation expense related to recent capital expenditures.

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

49

Sulfur Services Segment

Comparative Results of Operations for the Twelve Months Ended December 31, 2017 and 2016

	Year Ended December 31,						Variance			Percent Change
	2017			2016
	(In thousands)
Revenues:
Services	$	10,952		$	10,800		$	152		1%
Products	123,732			130,258			(6,526		)	(5)%
Total revenues	134,684			141,058			(6,374		)	(5)%
Cost of products sold	82,760			88,325			(5,565		)	(6)%
Operating expenses	13,783			13,771			12			—%
Selling, general and administrative expenses	4,136			3,861			275			7%
Depreciation and amortization	8,117			7,995			122			2%
	25,888			27,106			(1,218		)	(4)%
Other operating loss, net	(26		)	(291		)	265			(91)%
Operating income	$	25,862		$	26,815		$	(953	)	(4)%
Sulfur (long tons)	807.0			797.0			10.0			1%
Fertilizer (long tons)	276.0			262.0			14.0			5%
Sulfur services volumes (long tons)	1,083.0			1,059.0			24.0			2%

Services Revenues.  Services revenues increased as a result of a contractually prescribed index based fee adjustment.

Products Revenues.  Products revenues decreased $9.3 million as a result of a 7% decline in average sales price. Offsetting, products revenues increased $2.8 million due to a 2% increase in sales volumes, primarily related to a 5% increase in fertilizer volumes.

Cost of products sold.  An 8% decrease in prices reduced cost of products sold by $7.4 million, resulting from a decline in commodity prices. A 2% increase in sales volumes caused an offsetting increase in cost of products sold of $1.9 million. Margin per ton decreased $1.78, or 4%.

Selling, general and administrative expenses.  Our selling, general and administrative expenses increased $0.3 million due to increased compensation expense offset slightly by a decrease of $0.1 million in bad debt expense.

Depreciation and amortization.  Depreciation expense increased $0.1 million due to capital projects being completed and placed in service during the second half of 2016.

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

50

Comparative Results of Operations for the Twelve Months Ended December 31, 2016 and 2015

	Year Ended December 31,						Variance			Percent Change
	2016			2015
	(In thousands)
Revenues:
Services	$	10,800		$	12,270		$	(1,470	)	(12)%
Products	130,258			157,891			(27,633		)	(18)%
Total revenues	141,058			170,161			(29,103		)	(17)%
Cost of products sold	88,325			115,133			(26,808		)	(23)%
Operating expenses	13,771			15,279			(1,508		)	(10)%
Selling, general and administrative expenses	3,861			3,805			56			1%
Depreciation and amortization	7,995			8,455			(460		)	(5)%
	27,106			27,489			(383		)	(1)%
Other operating loss, net	(291		)	(376		)	85			(23)%
Operating income	$	26,815		$	27,113		$	(298	)	(1)%
Sulfur (long tons)	797.0			856.0			(59.0		)	(7)%
Fertilizer (long tons)	262.0			274.0			(12.0		)	(4)%
Sulfur services volumes (long tons)	1,059.0			1,130.0			(71.0		)	(6)%

Services Revenues.  Services revenues decreased $1.5 million as a result of renegotiation of contract terms effective January 2016.

Products Revenues.  Products revenues decreased $18.9 million as a result of a 12% decline in average sales price. Further, products revenues decreased an additional $8.7 million due to a 6% decrease in sales volumes, primarily related to a 7% decrease in sulfur volumes.

Cost of products sold.  An 18% decrease in prices reduced cost of products sold by $20.9 million, resulting from a decline in commodity prices. A 6% decrease in sales volumes decreased cost of products sold by $5.9 million. Margin per ton increased $1.76, or 5%.

Operating expenses.  Our operating expenses decreased primarily as a result of $0.8 million in lower fuel expense, $0.4 million in compensation expense, $0.3 million in terminal and throughput fees, $0.2 million in property taxes, $0.2 million in wharfage fees, and $0.2 million in other marine operating expenses (i.e. tug assist, waste disposal, harbor fees). Offsetting this decrease was an increase of $0.4 million in railcar repairs and maintenance and $0.2 million in outside towing.

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

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

51

Marine Transportation Segment

Comparative Results of Operations for the Twelve Months Ended December 31, 2017 and 2016

	Year Ended December 31,						Variance			Percent Change
	2017			2016
	(In thousands)
Revenues	$	51,915		$	61,233		$	(9,318	)	(15)%
Operating expenses	44,028			53,118			(9,090		)	(17)%
Selling, general and administrative expenses	358			18			340			1,889%
Impairment of long-lived assets	1,625			11,701			(10,076		)	(86)%
Impairment of goodwill	—			4,145			(4,145		)	(100)%
Depreciation and amortization	7,002			10,572			(3,570		)	(34)%
	(1,098		)	(18,321		)	17,223			(94)%
Other operating loss, net	(113		)	(1,567		)	1,454			(93)%
Operating loss	$	(1,211	)	$	(19,888	)	$	18,677		(94)%

Inland revenues.  A decrease of $7.2 million is primarily attributable to decreased transportation rates and decreased utilization of the inland fleet resulting from an abundance of supply of marine equipment in our predominantly Gulf Coast market.

Offshore revenues.  A $2.4 million decrease in offshore revenues is primarily the result of the 2016 period including the recognition of previously deferred revenues of $1.5 million and decreased utilization of the offshore fleet due to downtime associated with regulatory inspections of $0.7 million.

Operating expenses.  The decrease in operating expenses is primarily a result of decreased labor and burden of $3.9 million, repairs and maintenance of $1.3 million, Jones Act claims of $0.8 million, pass-through expenses (primarily barge tank cleaning) of $0.7 million, outside towing of $0.4 million, barge rental expense of $0.4 million, property taxes of $0.3 million, operating supplies of $0.3 million, and property insurance premiums of $0.2 million.

Selling, general and administrative expenses.  Selling, general and administrative expenses increased primarily due to the 2016 period including the collection of a previously deemed uncollectible receivable of $0.5 million, offset by decreased legal fees of $0.1 million.

Impairment of long-lived assets. This represents the loss on impairment of non-core operating assets.

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

Depreciation and amortization.  Depreciation and amortization decreased as a result of the disposal of property, plant and equipment combined with the impairment of long-lived assets recognized in the fourth quarter of 2016, offset by recent capital expenditures.

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

52

Comparative Results of Operations for the Twelve Months Ended December 31, 2016 and 2015

	Year Ended December 31,						Variance			Percent Change
	2016			2015
	(In thousands)
Revenues	$	61,233		$	81,784		$	(20,551	)	(25)%
Operating expenses	53,118			63,412			(10,294		)	(16)%
Selling, general and administrative expenses	18			417			(399		)	(96)%
Impairment of long lived assets	11,701			1,324			10,377			784%
Impairment of goodwill	4,145			—			4,145
Depreciation and amortization	10,572			10,992			(420		)	(4)%
	(18,321		)	5,639			(23,960		)	(425)%
Other operating loss, net	(1,567		)	(1,009		)	(558		)	55%
Operating income (loss)	$	(19,888	)	$	4,630		$	(24,518	)	(530)%

Inland revenues.  An $11.1 million decrease in inland revenues is primarily attributable to decreased utilization of the inland fleet resulting from an abundance of supply of marine equipment in our predominantly Gulf Coast market.

Offshore revenues.  A $6.8 million decrease in offshore revenue is the result of decreased utilization of the offshore fleet, partially offset by the recognition of previously deferred revenues of $1.5 million.

Pass-through revenues.  A $3.1 million decrease in pass-through revenues was primarily related to fuel.

Operating expenses.  The decrease in operating expenses is a result of decreased pass-through expenses (primarily fuel) of $3.0 million, labor and burden of $3.2 million, lower repairs and maintenance of $5.3 million and operating supplies of $0.5 million. Offsetting these decreases were increases in claims expense of $0.5 million, fuel of $0.5 million, and outside towing of $0.8 million.

Selling, general and administrative expenses.  Selling, general and administrative expenses decreased due to a $0.2 million reduction in legal fees and a $0.2 million reduction in consulting fees.

Impairment of long-lived assets. This represents the loss on impairment of non-core operating assets.

Impairment of goodwill. This represents the loss on impairment of goodwill in the Marine Transportation segment during the second quarter of 2016.

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

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

53

Equity in Earnings of and Distributions from Unconsolidated Entities for the Twelve Months Ended December 31, 2017 and 2016

	Year Ended December 31,				Variance		Percent Change
	2017		2016
	(In thousands)
Equity in earnings of WTLPG	$	4,314	$	4,714	(400	)	(8)%

	Year Ended December 31,				Variance		Percent Change
	2017		2016
	(In thousands)
Distributions from WTLPG	$	5,400	$	7,500	(2,100	)	(28)%

Equity in earnings from WTLPG declined primarily due to lower volumes as well as increased pipeline lease expense, fuel and power expense, and environmental expense. Offsetting this was a decrease in repairs and maintenance, legal fees, and other outside services. Distributions from WTLPG decreased $2.1 million.

Equity in Earnings of and Distributions from Unconsolidated Entities for the Twelve Months Ended December 31, 2016 and 2015    

	Year Ended December 31,				Variance			Percent Change
	2016		2015
	(In thousands)
Equity in earnings of WTLPG	$	4,714	$	8,986	$	(4,272	)	(48)%

	Year Ended December 31,				Variance			Percent Change
	2016		2015
	(In thousands)
Distributions from WTLPG	$	7,500	$	11,200	$	(3,700	)	(33)%

Equity in earnings from WTLPG decreased primarily due to a decrease in transportation rates combined with an increase in repairs and maintenance on the asset. Distributions from WTLPG decreased $3.7 million.

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Interest Expense

Comparative Components of Interest Expense, Net for the Twelve Months Ended December 31, 2017 and 2016    

	Year Ended December 31,						Variance			Percent Change
	2017			2016
	(In thousands)
Revolving loan facility	$	18,192		$	19,482		$	(1,290	)	(7)%
7.250 % senior unsecured notes	27,101			27,326			(225		)	(1)%
Amortization of deferred debt issuance costs	2,897			3,684			(787		)	(21)%
Amortization of debt discount and premium	(306		)	(306		)	—			—%
Impact of interest rate derivative activity, including cash settlements	—			(995		)	995			(100)%
Other	1,532			291			1,241			426%
Capitalized interest	(730		)	(1,126		)	396			(35)%
Interest income	(943		)	(2,256		)	1,313			(58)%
Total interest expense, net	$	47,743		$	46,100		$	1,643		4%

Comparative Components of Interest Expense, Net for the Twelve Months Ended December 31, 2016 and 2015

	Year Ended December 31,						Variance			Percent Change
	2016			2015
	(In thousands)
Revolving loan facility	$	19,482		$	16,270		$	3,212		20%
7.250 % senior unsecured notes	27,326			28,583			(1,257		)	(4)%
Amortization of deferred debt issuance costs	3,684			4,859			(1,175		)	(24)%
Amortization of debt discount and premium	(306		)	(324		)	18			(6)%
Impact of interest rate derivative activity, including cash settlements	(995		)	(2,289		)	1,294			(57)%
Other	291			387			(96		)	(25)%
Capitalized interest	(1,126		)	(1,944		)	818			(42)%
Interest income	(2,256		)	(2,250		)	$	(6	)	—%
Total interest expense, net	$	46,100		$	43,292		$	2,808		6%

Indirect Selling, General and Administrative Expenses

	Year Ended December 31,				Variance		Percent Change	Year Ended December 31,				Variance			Percent Change
	2017		2016					2016		2015
	(In thousands)							(In thousands)
Indirect selling, general and administrative expenses	$	17,332	$	16,795	$	537	3%	$	16,795	$	18,951	$	(2,156	)	(11)%

The increase in indirect selling, general and administrative expenses from 2016 to 2017 is primarily a result of a $0.6 million increase in audit, consulting and other professional fees.

The decrease in indirect selling, general and administrative expenses from 2015 to 2016 is primarily a result of a $1.1 million reduction in legal, audit and other professional fees. Also contributing to this decrease was a $0.6 million reduction in allocated overhead expenses from Martin Resource Management as well as a $0.6 million decrease in employee related expenses.

Martin Resource Management allocates to us a portion of its indirect selling, general and administrative expenses for services 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 retained businesses. This allocation is based on the percentage of time spent by Martin Resource

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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 approved the following reimbursement amounts:

	Year Ended December 31,				Variance		Percent Change	Year Ended December 31,				Variance			Percent Change
	2017		2016					2016		2015
	(In thousands)							(In thousands)
Conflicts Committee approved reimbursement amount	$	16,416	$	13,033	$	3,383	26%	$	13,033	$	13,679	$	(646	)	(5)%

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

Liquidity and Capital Resources

General

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

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 - Risks related to Our Business" for a discussion of such risks.

Recent Capital Markets Activity

On February 22, 2017, we 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. Total proceeds from the sale of the 2,990,000 common units, net of underwriters' discounts, commissions and offering expenses, were $51.1 million. Additionally, our general partner contributed $1.1 million in cash to us in conjunction with the issuance in order to maintain its 2.0% general partner interest in us. All of the net proceeds were used to pay down outstanding amounts under our revolving credit facility.

Recent Debt Financing Activity

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

Due to the foregoing, 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 depend upon our future operating performance, which is subject to certain risks.  Please read "Item 1A. Risk Factors - Risks Relating to Our Business" for a discussion of such risks.

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Cash Flows - Twelve Months Ended December 31, 2017 Compared to Twelve Months Ended December 31, 2016

The following table details the cash flow changes between the twelve months ended December 31, 2017 and 2016:

	Years Ended December 31,						Variance			Percent Change
	2017			2016
	(In thousands)
Net cash provided by (used in):
Operating activities	$	67,506		$	110,848		$	(43,342	)	(39)%
Investing activities	(37,878		)	63,839			(101,717		)	159%
Financing activities	(29,616		)	(174,703		)	145,087			(83)%
Net increase (decrease) in cash and cash equivalents	$	12		$	(16	)	$	28		(175)%

Net cash provided by operating activities. The decline in net cash provided by operating activities includes a decrease in operating results from continuing operations of $14.5 million and a $29.6 million unfavorable variance in working capital. Further decreases were due to an $11.8 million decrease in other non-cash charges and a decrease in distributions received from WTLPG of $2.1 million. Offsetting was an increase of $14.6 million attributable to a favorable variance in other non-current assets and liabilities.

Net cash (used in) provided by investing activities. Net cash from investing activities decreased as a result of a decrease of $100.1 million in net proceeds from the sale of property, plant and equipment. The 2017 period also included an acquisition of $19.5 million compared to an acquisition of $2.2 million in 2016, resulting in a $17.4 million decrease in cash. Offsetting these decreases was an increase of $15.0 million for proceeds received from repayment of the Note receivable - affiliate and a decrease in payments for capital expenditures and plant turnaround costs of $1.2 million.

Net cash used in financing activities. Net cash used in financing activities decreased for the year ended December 31, 2017 as a result of a decrease in net repayments of long-term borrowings of $57.0 million. Proceeds received from the issuance of common units (including the related general partner contribution) increased net cash by $52.2 million. Also contributing was a decrease in cash distributions paid of $41.2 million and $5.2 million less in costs associated with our credit facility amendment. Offsetting was an increase of $10.9 million related to excess purchase price over the carrying value of acquired assets in common control transactions.

Cash Flows - Twelve Months Ended December 31, 2016 Compared to Twelve Months Ended December 31, 2015

The following table details the cash flow changes between the twelve months ended December 31, 2016 and 2015:

	Years Ended December 31,						Variance			Percent Change
	2016			2015
	(In thousands)
Net cash provided by (used in):
Operating activities	$	110,848		$	182,572		$	(71,724	)	(39)%
Investing activities	63,839			(23,805		)	87,644			368%
Financing activities	(174,703		)	(158,778		)	(15,925		)	(10)%
Net decrease in cash and cash equivalents	$	(16	)	$	(11	)	$	(5	)	45%

Net cash provided by operating activities. The change in net cash provided by operating activities includes a decrease in operating results from continuing operations of $12.0 million, a decrease in distributions from WTLPG of $3.7 million, and a $57.4 million unfavorable variance in working capital and other non-current assets and liabilities. Offsetting was a decrease in cash used in discontinued operations of $1.4 million in 2016.

Net cash provided by (used in) investing activities. Net cash increased as a result of an increase of $105.9 million in net proceeds from the sale of property, plant and equipment in 2016. Payments for capital expenditures and plant turnaround costs decreased $25.2 million in 2016. Offsetting these increases was a decrease due to the 2015 period including $41.3 million in cash proceeds from the disposition of certain floating storage assets classified as discontinued operations. The 2016 period also included an acquisition of intangible assets of $2.2 million compared to no acquisitions in 2015.

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Net cash used in financing activities. Net cash used in financing activities increased for the year ended December 31, 2016 as a result of an increase in net repayments of long-term borrowings of $28.2 million. In 2016, we paid an additional $4.9 million in costs associated with our credit facility amendment compared to the previous period. Offsetting was a reduction of $15.1 million in quarterly cash distributions as well as an increase of $1.9 million related to excess purchase price over the carrying value of acquired assets in common control transactions.

Capital Expenditures

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:

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

•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; 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 maintenance and expansion capital expenditures, excluding amounts paid for acquisitions, for the periods presented:

	Three Months Ended December 31,				Years Ended December 31,
	2017		2016		2017		2016
	(In thousands)				(In thousands)
Expansion capital expenditures	$	6,883	$	4,977	$	23,951	$	19,107
Maintenance capital expenditures	5,586		4,345		18,080		17,163
Plant turnaround costs	—		447		1,583		2,061
Total	$	12,469	$	9,769	$	43,614	$	38,331

Expansion capital expenditures were made primarily in our Terminalling and Storage and Natural Gas Services segments during the twelve months ended December 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. Within our Natural Gas Services segment, expenditures were made primarily on certain organic growth projects ongoing in our Natural Gas Services operations. Expansion capital expenditures were made primarily in our Terminalling and Storage and Marine Transportation segments during the three months ended December 31, 2017. These expenditures were primarily made on certain organic growth projects ongoing in our Terminalling and Storage and Marine Transportation operations. Maintenance capital expenditures were made primarily in our Terminalling and Storage segment to maintain our existing assets and operations during the three and twelve months ended December 31, 2017.

Expansion capital expenditures were made primarily in our Terminalling and Storage and Natural Gas Services segments during the three and twelve months ended December 31, 2016. Within our Terminalling and Storage segment, expenditures were made primarily at our Smackover refinery and on certain organic growth projects ongoing in our specialty terminalling operations. Within our Natural Gas Services segment, expenditures were made primarily on certain organic growth projects ongoing in our Natural Gas Services operations. Maintenance capital expenditures were made primarily in our Terminalling and Storage, Sulfur Services, and Natural Gas Services segments to maintain our existing assets and operations during the three and twelve months ended December 31, 2016.

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 December 31, 2017, is as follows (dollars in thousands):

 

	Payments due by period
Type of Obligation	Total Obligation		Less than One Year		1-3 Years		3-5 Years		Due Thereafter
Revolving credit facility	$	445,000	$	—	$	445,000	$	—	$	—
2021 senior unsecured notes	373,800		—		—		373,800		—
Throughput commitment	21,946		6,184		12,866		2,896		—
Operating leases	26,189		6,841		8,274		3,324		7,750
Interest payable on fixed long-term obligations	84,690		27,101		54,201		3,388		—
Total contractual cash obligations	$	951,625	$	40,126	$	520,341	$	383,408	$	7,750

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. 

Letter of Credit.  At December 31, 2017, 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

We and Martin Midstream Finance Corp., a subsidiary of us (collectively, the "Issuers"), entered into (i) an Indenture, dated as of February 11, 2013 (the "2021 Indenture") among the Issuers, certain subsidiary guarantors (the "2021 Guarantors") and Wells Fargo Bank, National Association, as trustee (the "2021 Trustee") and (ii) a Registration Rights Agreement, dated as of February 11, 2013 (the "2021 Registration Rights Agreement"), among the Issuers, the 2021 Guarantors and Wells Fargo Securities, LLC, RBC Capital Markets, LLC, RBS Securities Inc., SunTrust Robinson Humphrey, Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representatives of a group of initial purchasers, in connection with a private placement to eligible purchasers of $250.0 million in aggregate principal amount of the Issuers' 7.25% senior unsecured notes due 2021 (the "2021 Notes"). On April 1, 2014, we completed a private placement add-on of $150.0 million of the 2021 Notes. In 2015, we repurchased on the open market and subsequently retired an aggregate $26.2 million of our outstanding 2021 Notes.

Interest and Maturity. The Issuers issued the 2021 Notes pursuant to the 2021 Indenture in transactions exempt from registration requirements under the Securities Act of 1933, as amended (the "Securities Act"). The 2021 Notes were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. The 2021 Notes will mature on February 15, 2021. The interest payment dates are February 15 and August 15.

Optional Redemption. Prior to February 15, 2017, the Issuers may on any one or more occasions redeem all or a part of the 2021 Notes at the redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. On or after February 15, 2017, the Issuers may on any one or more occasions redeem all or a part of the 2021 Notes at the redemption prices (expressed as percentages of principal amount) equal to 103.625% for the twelve-month period beginning on February 15, 2017, 101.813% for the twelve-month period beginning on February 15, 2018 and 100.00% for the twelve-month period beginning on February 15, 2019 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the 2021 Notes.

Certain Covenants. The 2021 Indenture restricts our ability and the ability of certain of our subsidiaries to: (i) sell assets including equity interests in our subsidiaries; (ii) pay distributions on, redeem or repurchase our units or redeem or repurchase our subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us; (vii) consolidate, merge or transfer all or substantially all of our assets; (viii) engage in transactions with affiliates; (ix) create unrestricted subsidiaries; (x) enter into sale and leaseback transactions; or (xi) engage in certain business activities. These covenants are subject to a number of important exceptions and qualifications. If the 2021 Notes achieve an

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investment grade rating from each of Moody's Investors Service, Inc. and Standard & Poor's Ratings Services and no Default (as defined in the 2021 Indenture) has occurred and is continuing, many of these covenants will terminate.

Events of Default. The 2021 Indenture provides that each of the following is an Event of Default: (i) default for 30 days in the payment when due of interest on the 2021 Notes; (ii) default in payment when due of the principal of, or premium, if any, on the 2021 Notes; (iii) failure by us to comply with certain covenants relating to asset sales, repurchases of the 2021 Notes upon a change of control and mergers or consolidations; (iv) failure by us for 180 days after notice to comply with our reporting obligations under the Securities Exchange Act of 1934; (v) failure by us for 60 days after notice to comply with any of the other agreements in the 2021 Indenture; (vi) default under any mortgage, indenture or instrument governing any indebtedness for money borrowed or guaranteed by us or any of our restricted subsidiaries, whether such indebtedness or guarantee now exists or is created after the date of the 2021 Indenture, if such default: (a) is caused by a payment default; or (b) results in the acceleration of such indebtedness prior to its stated maturity, and, in each case, the principal amount of the indebtedness, together with the principal amount of any other such indebtedness under which there has been a payment default or acceleration of maturity, aggregates $20.0 million or more, subject to a cure provision; (vii) failure by us or any of our restricted subsidiaries to pay final judgments aggregating in excess of $20.0 million, which judgments are not paid, discharged or stayed for a period of 60 days; (viii) except as permitted by the 2021 Indenture, any subsidiary guarantee is held in any judicial proceeding to be unenforceable or invalid or ceases for any reason to be in full force or effect, or any 2021 Guarantor, or any person acting on behalf of any Guarantor, denies or disaffirms its obligations under its subsidiary guarantee; and (ix) certain events of bankruptcy, insolvency or reorganization described in the 2021 Indenture with respect to the Issuers or any of our restricted subsidiaries that is a significant subsidiary or any group of restricted subsidiaries that, taken together, would constitute a significant subsidiary of us. Upon a continuing Event of Default, the 2021 Trustee, by notice to the Issuers, or the holders of at least 25% in principal amount of the then outstanding 2021 Notes, by notice to the Issuers and the 2021 Trustee, may declare the 2021 Notes immediately due and payable, except that an Event of Default resulting from entry into a bankruptcy, insolvency or reorganization with respect to the Issuers, any restricted subsidiary of us that is a significant subsidiary or any group of its restricted subsidiaries that, taken together, would constitute a significant subsidiary of us, will automatically cause the 2021 Notes to become due and payable.

Revolving Credit Facility

At December 31, 2017, we maintained a $664.4 million credit facility. This facility was most recently amended on April 27, 2016, when we made certain strategic amendments to our revolving credit facility which, among other things, decreased our borrowing capacity from $700.0 million to $664.4 million and extended the maturity date of the facility from March 28, 2018 to March 28, 2020.

As of December 31, 2017, we had $445.0 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 $205.0 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 December 31, 2017, we have the ability to borrow approximately $7.1 million of that amount. We were in compliance with all financial covenants at December 31, 2017. While our current debt to EBITDA financial covenant calculation is near the maximum allowed under our credit facility at the December 31, 2017 evaluation, we expect to improve leverage during the first quarter of 2018 through the impacts of selling inventory built during the second and third quarters in our seasonal NGL business. 

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 year ended December 31, 2017, the level of outstanding draws on our credit facility has ranged from a low of $382.0 million to a high of $497.0 million.

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

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

Indebtedness under the credit facility bears interest at our option at the Eurodollar Rate (the British Bankers Association LIBOR Rate) plus an applicable margin or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0%, or the administrative agent’s prime rate) plus an applicable margin. We pay a per annum fee

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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 December 31, 2017:

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 December 31, 2017, the applicable margin for revolving loans that are LIBOR loans ranges from 2.00% to 3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 1.00% to 2.00%. The applicable margin for LIBOR borrowings at December 31, 2017 is 3.00%.  

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

In addition, the credit facility contains various covenants, which, among other things, limit our and our subsidiaries’ ability to: (i) grant or assume liens; (ii) make investments (including investments in our joint ventures) and acquisitions; (iii) enter into certain types of hedging agreements; (iv) incur or assume indebtedness; (v) sell, transfer, assign or convey assets; (vi) repurchase our equity, make distributions and certain other restricted payments, but the credit facility permits us to make quarterly distributions to unitholders so long as no default or event of default exists under the credit facility; (vii) change the nature of our business; (viii) engage in transactions with affiliates; (ix) enter into certain burdensome agreements; (x) make certain amendments to the Omnibus Agreement and our material agreements; (xi) make capital expenditures; and (xii) permit our joint ventures to incur indebtedness or grant certain liens.

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

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

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

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

The Partnership is in compliance with all debt covenants as of December 31, 2017 and expects to be in compliance for the next twelve months.

Seasonality

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

Impact of Inflation

Inflation did not have a material impact on our results of operations in 2017, 2016 or 2015.  Although the impact of inflation has been insignificant in recent years, it is still a factor in the U.S. economy and may increase the cost to acquire or replace property, plant and equipment. It may also increase the costs of labor and supplies.  In the future, increasing energy prices could adversely affect our results of operations. Diesel fuel, natural gas, chemicals and other supplies are recorded in operating expenses.  An increase in price of these products would increase our operating expenses which could adversely affect net income. We cannot provide assurance that we will be able to pass along increased operating expenses to our customers.

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 2017, 2016 or 2015.

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Item 7A. 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 December 31, 2017 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 145,000 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. These instruments are recorded on our Consolidated Balance Sheets at December 31, 2017 in "Fair value of derivatives" as a current liability of $0.1 million. Based on the current net notional volume hedged as of December 31, 2017, a $0.10 change in the expected settlement price of these contracts would result in an impact of $0.6 million to the Partnership's net income.

Interest Rate Risk. We are exposed to changes in interest rates as a result of our credit facility, which had a weighted-average interest rate of 4.55% as of December 31, 2017.  Based on the amount of unhedged floating rate debt owed by us on December 31, 2017, 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 $4.5 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 $381.7 million as of December 31, 2017, based on market prices of similar debt at December 31, 2017.   Market risk is estimated as the potential decrease in fair value of our long-term debt resulting from a hypothetical increase of a 100 basis point increase in interest rates. Such an increase in interest rates would result in approximately a $3.0 million decrease in fair value of our long-term debt at December 31, 2017.

63

Item 8. Financial Statements and Supplementary Data

The following financial statements of Martin Midstream Partners L.P. (Partnership) are listed below:

	Page
Reports of Independent Registered Public Accounting Firm	65
Consolidated Balance Sheets as of December 31, 2017 and 2016	67
Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015	68
Consolidated Statements of Changes in Capital for the years ended December 31, 2017, 2016 and 2015	71
Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015	72
Notes to Consolidated Financial Statements	73

64

Report of Independent Registered Public Accounting Firm

To the Unitholders and Board of Directors

Martin Midstream Partners LP and Martin Midstream GP LLC:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Martin Midstream Partners LP and subsidiaries (the “Partnership”) as of December 31, 2017 and 2016, the related consolidated statements of operations, changes in capital, and cash flows for each of the years in the three‑year period ended December 31, 2017,and the related notes collectively, the “consolidated financial statements”. In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Partnership’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 16, 2018 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ KPMG LLP 

We have served as the Partnership’s auditor since 1981

Dallas, Texas

February 16, 2018

65

Report of Independent Registered Public Accounting Firm

To the Unitholders and Board of Directors

Martin Midstream Partners LP and Martin Midstream GP LLC:

Opinion on Internal Control Over Financial Reporting

We have audited Martin Midstream Partners LP and subsidiaries' (the “Partnership”) internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Partnership as of December 31, 2017 and 2016, the related consolidated statements of operations, changes in capital, and cash flows for each of the years in the three‑year period ended December 31, 2017,and the related notes (collectively, the “consolidated financial statements”), and our report dated February 16, 2018, expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ KPMG LLP 

Dallas, Texas

February 16, 2018

66

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

	December 31,
	2017			2016
Assets
Cash	$	27		$	15
Trade and accrued accounts receivable, less allowance for doubtful accounts of $314 and $372 respectively	107,242			80,508
Product exchange receivables	29			207
Inventories	97,252			82,631
Due from affiliates	23,668			11,567
Other current assets	4,866			3,296
Assets held for sale	9,579			15,779
Total current assets	242,663			194,003
Property, plant and equipment, at cost	1,253,065			1,224,277
Accumulated depreciation	(421,137		)	(378,593		)
Property, plant and equipment, net	831,928			845,684
Goodwill	17,296			17,296
Investment in unconsolidated entities	128,810			129,506
Notes receivable - Martin Energy Trading LLC	—			15,000
Intangibles and other assets, net	32,801			44,874
	$	1,253,498		$	1,246,363
Liabilities and Partners’ Capital
Trade and other accounts payable	$	92,567		$	70,249
Product exchange payables	11,751			7,360
Due to affiliates	3,168			8,474
Income taxes payable	510			870
Fair value of derivatives	72			3,904
Other accrued liabilities	26,340			26,717
Total current liabilities	134,408			117,574
Long-term debt, net	812,632			808,107
Other long-term obligations	8,217			8,676
Total liabilities	955,257			934,357
Commitments and contingencies
Partners’ capital	298,241			312,006
Total partners’ capital	298,241			312,006
	$	1,253,498		$	1,246,363

See accompanying notes to consolidated financial statements.

67

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands, except per unit amounts)

	Year Ended December 31,
	2017			2016			2015
Revenues:
Terminalling and storage *	$	99,705		$	123,132		$	132,945
Marine transportation *	48,579			58,290			78,753
Natural gas storage services *	58,817			61,133			64,858
Sulfur services	10,952			10,800			12,270
Product sales: *
Natural gas services	473,865			330,200			458,302
Sulfur services	123,732			130,258			157,891
Terminalling and storage	130,466			113,578			131,825
	728,063			574,036			748,018
Total revenues	946,116			827,391			1,036,844
Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services *	421,444			289,516			413,795
Sulfur services *	82,338			87,963			114,766
Terminalling and storage *	109,798			94,175			112,836
	613,580			471,654			641,397
Expenses:
Operating expenses *	146,874			158,864			183,466
Selling, general and administrative *	38,950			34,385			36,788
Impairment of long-lived assets	2,225			26,953			10,629
Impairment of goodwill	—			4,145			—
Depreciation and amortization	85,195			92,132			92,250
Total costs and expenses	886,824			788,133			964,530
Other operating income (loss), net	523			33,400			(2,161		)
Operating income	59,815			72,658			70,153
Other income (expense):
Equity in earnings of unconsolidated entities	4,314			4,714			8,986
Interest expense, net	(47,743		)	(46,100		)	(43,292		)
Gain on retirement of senior unsecured notes	—			—			1,242
Other, net	1,101			1,106			1,124
Total other income (expense)	(42,328		)	(40,280		)	(31,940		)
Net income before taxes	17,487			32,378			38,213
Income tax expense	(352		)	(726		)	(1,048		)
Income from continuing operations	17,135			31,652			37,165
Income from discontinued operations, net of income taxes	—			—			1,215
Net income	17,135			31,652			38,380
Less general partner's interest in net income	(343		)	(8,419		)	(16,338		)
Less income allocable to unvested restricted units	(42		)	(90		)	(140		)
Limited partner's interest in net income	$	16,750		$	23,143		$	21,902

*Related Party Transactions Shown Below

See accompanying notes to consolidated financial statements.

68

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands, except per unit amounts)

*Related Party Transactions Included Above

	Year Ended December 31,
	2017		2016		2015
Revenues:
Terminalling and storage	$	82,205	$	82,437	$	78,233
Marine transportation	16,801		21,767		27,724
Natural gas services	122		699		878
Product sales	3,578		3,034		5,671
Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services	18,946		22,886		25,797
Sulfur services	15,564		15,339		16,579
Terminalling and storage	17,612		13,838		17,718
Expenses:
Operating expenses	64,344		70,841		77,871
Selling, general and administrative	29,416		25,890		24,968

See accompanying notes to consolidated financial statements.

69

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands, except per unit amounts)

	Year Ended December 31,
	2017		2016		2015
Allocation of net income attributable to:
Limited partner interest:
Continuing operations	$	16,750	$	23,143	$	21,208
Discontinued operations	—		—		694
	$	16,750	$	23,143	$	21,902
General partner interest:
Continuing operations	$	343	$	8,419	$	15,821
Discontinued operations	—		—		517
	$	343	$	8,419	$	16,338
Net income per unit attributable to limited partners:
Basic:
Continuing operations	$	0.44	$	0.65	$	0.60
Discontinued operations	—		—		0.02
	$	0.44	$	0.65	$	0.62
Weighted average limited partner units - basic	38,102		35,347		35,309
Diluted:
Continuing operations	$	0.44	$	0.65	$	0.60
Discontinued operations	—		—		0.02
	$	0.44	$	0.65	$	0.62
Weighted average limited partner units - diluted	38,165		35,375		35,372

See accompanying notes to consolidated financial statements.

70

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CHANGES IN CAPITAL

(Dollars in thousands)

	Partners’ Capital
	Common					General Partner
	Units		Amount			Amount			Total
Balances – December 31, 2014	35,365,912		$	470,943		$	14,728		$	485,671
Net income	—		22,042			16,338			38,380
Issuance of common units, net	—		(590		)	—			(590		)
Issuance of restricted units	91,950		—			—			—
Forfeiture of restricted units	(1,250	)	—			—			—
General partner contribution	—		—			55			55
Cash distributions	—		(115,229		)	(18,087		)	(133,316		)
Reimbursement of excess purchase price over carrying value of acquired assets	—		2,250			—			2,250
Unit-based compensation	—		1,429			—			1,429
Balances – December 31, 2015	35,456,612		380,845			13,034			393,879
Net income	—		23,233			8,419			31,652
Issuance of common units, net	—		(29		)	—			(29		)
Issuance of restricted units	13,800		—			—			—
Forfeiture of restricted units	(2,250	)	—			—			—
Cash distributions	—		(104,137		)	(14,041		)	(118,178		)
Reimbursement of excess purchase price over carrying value of acquired assets	—		4,125			—			4,125
Unit-based compensation	—		904			—			904
Purchase of treasury units	(16,100	)	(347		)	—			(347		)
Balances – December 31, 2016	35,452,062		304,594			7,412			312,006
Net income	—		16,792			343			17,135
Issuance of common units, net	2,990,000		51,056			—			51,056
Issuance of restricted units	12,000		—			—			—
Forfeiture of restricted units	(9,250	)	—			—			—
General partner contribution	—		—			1,098			1,098
Cash distributions	—		(75,399		)	(1,539		)	(76,938		)
Reimbursement of excess purchase price over carrying value of acquired assets	—		1,125			—			1,125
Excess purchase price over carrying value of acquired assets	—		(7,887		)	—			(7,887		)
Unit-based compensation	—		650			—			650
Purchase of treasury units	(200	)	(4		)	—			(4		)
Balances – December 31, 2017	38,444,612		$	290,927		$	7,314		$	298,241

See accompanying notes to consolidated financial statements.

71

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

	Year Ended December 31,
	2017			2016			2015
Cash flows from operating activities:
Net income	$	17,135		$	31,652		$	38,380
Less: Income from discontinued operations	—			—			(1,215		)
Net income from continuing operations	17,135			31,652			37,165
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	85,195			92,132			92,250
Amortization of deferred debt issue costs	2,897			3,684			4,859
Amortization of premium on notes payable	(306		)	(306		)	(324		)
(Gain) loss on disposition or sale of property, plant, and equipment	(523		)	(33,400		)	2,149
Gain on retirement of senior unsecured notes	—			—			(1,242		)
Impairment of long lived assets	2,225			26,953			10,629
Impairment of goodwill	—			4,145			—
Equity in earnings unconsolidated entities	(4,314		)	(4,714		)	(8,986		)
Derivative (income) loss	1,304			4,133			(3,107		)
Net cash (paid) received for commodity derivatives	(5,136		)	(550		)	143
Net cash received for interest rate derivatives	—			160			—
Net premiums received on derivatives that settled during the year on interest rate swaption contracts	—			630			2,495
Unit-based compensation	650			904			1,429
Return on investment	5,400			7,500			11,200
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables	(26,739		)	(6,153		)	59,479
Product exchange receivables	178			843			1,996
Inventories	(14,656		)	(6,761		)	12,799
Due from affiliates	(12,096		)	(1,441		)	4,386
Other current assets	(1,699		)	2,478			891
Trade and other accounts payable	20,037			3,254			(44,153		)
Product exchange payables	4,391			(5,372		)	2,336
Due to affiliates	(5,306		)	2,736			866
Income taxes payable	(360		)	(115		)	(189		)
Other accrued liabilities	(3,187		)	686			(2,802		)
Change in other non-current assets and liabilities	2,416			(12,230		)	(345		)
Net cash provided by continuing operating activities	67,506			110,848			183,924
Net cash used in discontinued operating activities	—			—			(1,352		)
Net cash provided by operating activities	67,506			110,848			182,572
Cash flows from investing activities:
Payments for property, plant, and equipment	(39,749		)	(40,455		)	(65,791		)
Acquisitions, net of cash acquired	(19,533		)	(2,150		)	—
Payments for plant turnaround costs	(1,583		)	(2,061		)	(1,908		)
Proceeds from sale of property, plant, and equipment	8,377			108,505			2,644
Proceeds from repayment of Note receivable - affiliate	15,000			—			—
Contributions to unconsolidated entities for operations	(390		)	—			—
Net cash provided by (used in) continuing investing activities	(37,878		)	63,839			(65,055		)
Net cash provided by discontinued investing activities	—			—			41,250
Net cash provided by (used in) investing activities	(37,878		)	63,839			(23,805		)
Cash flows from financing activities:
Payments of long-term debt	(339,000		)	(386,700		)	(308,836		)
Proceeds from long-term debt	341,000			331,700			282,000
Net proceeds from issuance of common units	51,056			(29		)	(590		)
General partner contributions	1,098			—			55
Excess purchase price over carrying value of acquired assets	(7,887		)	—			—
Reimbursement of excess purchase price over carrying value of acquired assets	1,125			4,125			2,250
Purchase of treasury units	(4		)	(347		)	—
Payments of debt issuance costs	(66		)	(5,274		)	(341		)
Cash distributions paid	(76,938		)	(118,178		)	(133,316		)
Net cash used in financing activities	(29,616		)	(174,703		)	(158,778		)
Net increase (decrease) in cash	12			(16		)	(11		)
Cash at beginning of year	15			31			42
Cash at end of year	$	27		$	15		$	31

See accompanying notes to consolidated financial statements.

72

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

(1) Organization and Description of Business

Martin Midstream Partners L.P. (the "Partnership") is a publicly traded limited partnership with a diverse set of operations focused primarily in the United States ("U.S.") Gulf Coast region. Its four primary business lines include:  terminalling and storage services for petroleum products and by-products including the refining of naphthenic crude oil and the blending and packaging of finished lubricants; natural gas services, including liquids transportation and distribution services and natural gas storage; sulfur and sulfur-based products processing, manufacturing, marketing and distribution; and marine transportation services for petroleum products and by-products.

The petroleum products and by-products the Partnership collects, transports, stores and distributes are produced primarily by major and independent oil and gas companies who often turn to third parties, such as the Partnership, for the transportation and disposition of these products.  In addition to these major and independent oil and gas companies, the Partnership's primary customers include independent refiners, large chemical companies, fertilizer manufacturers and other wholesale purchasers of these products. The Partnership operates primarily in the U.S. Gulf Coast region, which is a major hub for petroleum refining, natural gas gathering and processing and support services for the oil and gas exploration and production industry.

On August 30, 2013, Martin Resource Management completed the sale of a 49% non-controlling voting interest (50% economic interest) in MMGP Holdings, LLC ("Holdings"), a newly-formed sole member of Martin Midstream GP LLC ("MMGP"), the general partner of the Partnership, to certain affiliated investment funds managed by Alinda Capital Partners ("Alinda"). Upon closing the transaction, Alinda appointed two representatives to serve on the board of directors of the general partner of the Partnership.

(2) Significant Accounting Policies

(a)       Principles of Presentation and Consolidation

The consolidated financial statements include the financial statements of the Partnership and its wholly-owned subsidiaries and equity method investees.  In the opinion of the management of the Partnership’s general partner, all adjustments and elimination of significant intercompany balances necessary for a fair presentation of the Partnership’s results of operations, financial position and cash flows for the periods shown have been made.  All such adjustments are of a normal recurring nature.  In addition, the Partnership evaluates its relationships with other entities to identify whether they are variable interest entities under certain provisions of the Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC"), 810-10 and to assess whether it is the primary beneficiary of such entities.  If the determination is made that the Partnership is the primary beneficiary, then that entity is included in the consolidated financial statements in accordance with ASC 810-10.  No such variable interest entities exist as of December 31, 2017 or 2016.

As discussed in Note 5, on February 12, 2015, the Partnership sold all six 16,101 barrel liquefied petroleum gas ("LPG") pressure barges, collectively referred to as the "Floating Storage Assets." These assets were acquired on February 28, 2013. On December 19, 2014, the Partnership made the decision to dispose of the Floating Storage Assets. As a result, the Partnership has presented the results of operations and cash flows of the Floating Storage Assets as discontinued operations for the year ended December 31, 2015.

(b)       Product Exchanges

The Partnership enters into product exchange agreements with third parties, whereby the Partnership agrees to exchange natural gas liquids ("NGLs") and sulfur with third parties.  The Partnership records the balance of exchange products due to other companies under these agreements at quoted market product prices and the balance of exchange products due from other companies at the lower of cost or market.  Cost is determined using the first-in, first-out ("FIFO") method.  Product exchanges with the same counterparty are entered into in contemplation of one another and are combined. The net amount related to location differentials is reported in "Product sales" or "Cost of products sold" in the Consolidated Statements of Operations.

73

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

(c)       Inventories

Inventories are stated at the lower of cost or market.  Cost is generally determined by using the FIFO method for all inventories except lubricants and lubricants packaging inventories. Lubricants and lubricants packaging inventories cost is determined using standard cost, which approximates actual cost, computed on a FIFO basis.

(d)      Revenue Recognition

Terminalling and Storage – Revenue is recognized for storage contracts based on the contracted monthly tank fixed fee.  For throughput contracts, revenue is recognized based on the volume moved through the Partnership’s terminals at the contracted rate.  For the Partnership’s tolling agreement, revenue is recognized based on the contracted monthly reservation fee and throughput volumes moved through the facility.  When lubricants and drilling fluids are sold by truck or rail, revenue is recognized upon delivering product to the customers as title to the product transfers when the customer physically receives the product.

Natural Gas Services – NGL distribution revenue is recognized when product is delivered by truck, rail, or pipeline to the Partnership's NGL customers. Natural gas storage revenue is recognized when the service is provided to the customer.

Sulfur Services – Revenue from sulfur product sales is recognized when the customer takes title to the product.   Revenue from sulfur services is recognized as deliveries are made during each monthly period.

Marine Transportation – Revenue is recognized for time charters based on a per day rate. For contracted trips, revenue is recognized upon completion of the particular trip.

(e)       Equity Method Investments

The Partnership uses the equity method of accounting for investments in unconsolidated entities where the ability to exercise significant influence over such entities exists.  Investments in unconsolidated entities consist of capital contributions and advances plus the Partnership’s share of accumulated earnings as of the entities’ latest fiscal year-ends, less capital withdrawals and distributions.  Equity method investments are subject to impairment under the provisions of ASC 323-10, which relates to the equity method of accounting for investments in common stock.  No portion of the net income from these entities is included in the Partnership’s operating income.

(f)      Property, Plant, and Equipment

Owned property, plant, and equipment is stated at cost, less accumulated depreciation.  Owned buildings and equipment are depreciated using straight-line method over the estimated lives of the respective assets.

Equipment under capital leases is stated at the present value of minimum lease payments less accumulated amortization. Equipment under capital leases is amortized on a straight line basis over the estimated useful life of the asset.

Routine maintenance and repairs are charged to expense while costs of betterments and renewals are capitalized.  When an asset is retired or sold, its cost and related accumulated depreciation are removed from the accounts, and the difference between net book value of the asset and proceeds from disposition is recognized as gain or loss.

(g)      Goodwill and Other Intangible Assets

Goodwill is subject to a fair-value based impairment test on an annual basis, or more often if events or circumstances indicate there may be impairment. The Partnership is required to identify its reporting units and determine the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets. The Partnership is required to determine the fair value of each reporting unit and compare it to the carrying amount of the reporting unit. To the extent the carrying amount of a reporting unit exceeds the fair value of the reporting unit, the Partnership will record the amount of goodwill impairment as the excess of a reporting unit's carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit.

74

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

When assessing the recoverability of goodwill and other intangible assets, the Partnership may first assess qualitative factors in determining whether it is more likely than not that the fair value of a reporting unit or other intangible asset is less than its carrying amount. After assessing qualitative factors, if the Partnership determines that it is not more likely than not that the fair value of a reporting unit or other intangible asset is less than its carrying amount, then performing a quantitative assessment is not required. If an initial qualitative assessment indicates that it is more likely than not the carrying amount exceeds the fair value of a reporting unit or other intangible asset, a quantitative analysis will be performed. The Partnership may also elect to bypass the qualitative assessment and proceed directly to a quantitative analysis depending on the facts and circumstances.

Of the Partnership's four reporting units, the terminalling and storage, natural gas services, and sulfur services reporting units contain goodwill. No goodwill impairment was recorded for the year ended December 31, 2017. During the second quarter of 2016, the Partnership experienced an impairment of all the goodwill in the Partnership's marine transportation reporting unit. See Note 8 for more information.

In performing a quantitative analysis, recoverability of goodwill for each reporting unit is measured using a weighting of the discounted cash flow method and two market approaches (the guideline public company method and the guideline transaction method). The discounted cash flow model incorporates discount rates commensurate with the risks involved. Use of a discounted cash flow model is common practice in assessing impairment in the absence of available transactional market evidence to determine the fair value. The key assumptions used in the discounted cash flow valuation model include discount rates, growth rates, cash flow projections and terminal value rates. Discount rates, growth rates and cash flow projections are the most sensitive and susceptible to change as they require significant management judgment. Discount rates are determined by using a weighted average cost of capital ("WACC"). The WACC considers market and industry data as well as company-specific risk factors for each reporting unit in determining the appropriate discount rate to be used. The discount rate utilized for each reporting unit is indicative of the return an investor would expect to receive for investing in such a business. Management, considering industry and company specific historical and projected data, develops growth rates and cash flow projections for each reporting unit. Terminal value rate determination follows common methodology of capturing the present value of perpetual cash flow estimates beyond the last projected period assuming a constant WACC and low long-term growth rates. If the calculated fair value is less than the current carrying amount, the Partnership will record the amount of goodwill impairment as the excess of a reporting unit's carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit.

Significant changes in these estimates and assumptions could materially affect the determination of fair value for each reporting unit which could give rise to future impairment. Changes to these estimates and assumptions can include, but may not be limited to, varying commodity prices, volume changes and operating costs due to market conditions and/or alternative providers of services.

Other intangible assets that have finite lives are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable. An impairment is indicated if the carrying amount of a long-lived intangible asset exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If impairment is indicated, the Partnership would record an impairment loss equal to the difference between the carrying value and the fair value of the asset. There were no intangible asset impairments in 2017, 2016 or 2015.

(h)      Debt Issuance Costs

Debt issuance costs relating to the Partnership’s revolving credit facility and senior unsecured notes are deferred and amortized over the terms of the debt arrangements and are shown, net of accumulated amortization, as a reduction of the related long-term debt.

In connection with the issuance, amendment, expansion and restatement of debt arrangements, the Partnership incurred debt issuance costs of $66, $5,274 and $341 in the years ended December 31, 2017, 2016 and 2015, respectively.

During 2016, the Partnership made certain strategic amendments to its credit facility which, among other things, decreased its borrowing capacity from $700,000 to $664,444 and extended the maturity date of the facility from March 28, 2018 to March 28, 2020. In connection with the amendment, the Partnership expensed $820 of unamortized debt issuance costs determined not to have continuing benefit.

75

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

During 2015, the Partnership repurchased on the open market an aggregate $26,200 of 7.25% senior unsecured notes. The repurchase transaction resulted in the write-off of $235 of existing debt issuance costs that were determined not to have continuing benefit. On August 14, 2015, the Partnership reduced its borrowing capacity under the revolving credit facility from $900,000 to $700,000, resulting in the write-off of $1,625 of deferred debt costs that were determined not to have continuing benefit.

Remaining unamortized deferred issuance costs are amortized over the term of each respective revised debt arrangement.

Amortization and write-off of debt issuance costs, which is included in interest expense, totaled $2,897, $3,684 and $4,859 for the years ended December 31, 2017, 2016 and 2015, respectively.  Accumulated amortization amounted to $17,162 and $14,265 at December 31, 2017 and 2016, respectively.

(i)      Impairment of Long-Lived Assets

In accordance with ASC 360-10, long-lived assets, such as property, plant and equipment, and intangible assets with definite lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset.  If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset.  Assets to be disposed of would be separately presented in the balance sheet and reported at the lower of the carrying amount or fair value less costs to sell and would no longer be depreciated.  The assets and liabilities of a disposed group classified as held for sale would be presented separately in the appropriate asset and liability sections of the balance sheet.  

In the fourth quarter of 2017, the Partnership identified a triggering event related to the planned disposition of certain assets that were no longer deemed core assets in the Partnership's Marine Transportation business. The triggering event was the assets' inability to generate cash flows in recent quarters and going forward. As a result, an impairment charge of $1,625 was recorded in the Marine Transportation segment results of operations in the fourth quarter of 2017. Additionally, the Partnership recorded an adjustment to the fair value less cost to sell of a certain asset classified as held for sale in the Martin Lubricants division of the Terminalling and Storage segment. As a result, an impairment charge of $600 was recorded in the Terminalling and Storage segment results of operations in the fourth quarter of 2017.

On August 25, 2017, Hurricane Harvey made landfall as a Category 4 hurricane. The storm lingered over Texas and Louisiana for days producing over 50 inches of rain in some areas, resulting in widespread flooding and damage. The Partnership experienced an impact from Hurricane Harvey in our Terminalling and Storage and Sulfur Services segments, where damages were suffered to the Partnership's property, plant, and equipment at its Neches, Stanolind, Galveston, and Harbor Island terminals located along the Texas gulf coast. The damage incurred did not exceed the insurance deductible at these locations and therefore The Partnership does not expect to receive any insurance proceeds resulting from the damage from Hurricane Harvey. In the third quarter of 2017, the Partnership recorded a write-off in the amount of $186 related to assets damaged.

In the fourth quarter of 2016, the Partnership identified a triggering event related to certain organic growth projects in the Smackover Refinery and Specialty Terminals divisions of the Partnership's Terminalling and Storage segment. These triggering events were the decision to not move forward with certain expansion projects due to the evaporation of the economic viability of the projects. Additionally, a triggering event was identified related to the planned disposition of certain assets that were no longer deemed core assets to the Partnership's Martin Lubricants division. As a result, an impairment charge of $15,252 was recorded in the Terminalling and Storage segment results of operations for the year ended December 31, 2016. In the fourth quarter of 2016, the Partnership identified a triggering event related to the planned disposition of certain assets that were no longer deemed core assets in the Partnership's Marine Transportation business. The triggering event was the assets' inability to generate cash flows in recent quarters and going forward. As a result, an impairment charge of $11,701 was recorded in the Marine Transportation segment results of operations in the fourth quarter of 2016.

In the fourth quarter of 2015, the Partnership identified a triggering event related to the condensate splitter project in the specialty terminals division of the Partnership's Terminalling and Storage segment. The triggering event was the decision to not move forward with the project due to the evaporation of the economic viability of the project. As a result, an impairment

76

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

charge of $9,305 was recorded in the Terminalling and Storage segment results of operations in the fourth quarter of 2015. In the fourth quarter of 2015, the Partnership identified a triggering event related to one inland push boat and three inland tank barges in the Marine Transportation segment. The triggering event was the assets' inability to generate cash flows in recent quarters and going forward. As a result, an impairment charge of $1,324 was recorded in the Marine Transportation segment results of operations in the fourth quarter of 2015.

(j)      Asset Retirement Obligations

Under ASC 410-20, which relates to accounting requirements for costs associated with legal obligations to retire tangible, long-lived assets, the Partnership records an asset retirement obligation ("ARO") at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted over time towards the ultimate obligation amount and the capitalized costs are depreciated over the useful life of the related asset.  

(k)     Derivative Instruments and Hedging Activities

In accordance with certain provisions of ASC 815-10 related to accounting for derivative instruments and hedging activities, all derivatives and hedging instruments are included in the Consolidated Balance Sheets as an asset or liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings.

Derivative instruments not designated as hedges are marked to market with all market value adjustments being recorded in the Consolidated Statements of Operations.  

(l)    Use of Estimates

Management has made a number of estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with accounting principles generally accepted in the U.S.  Actual results could differ from those estimates.

(m)      Indirect Selling, General and Administrative Expenses

Indirect selling, general and administrative expenses are incurred by Martin Resource Management and allocated to the Partnership to cover costs of centralized corporate functions such as accounting, treasury, engineering, information technology, risk management and other corporate services.  Such expenses are based on the percentage of time spent by Martin Resource Management’s personnel that provide such centralized services.  Under an omnibus agreement with Martin Resource Management, the Partnership is required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses.  For the years ended December 31, 2017, 2016 and 2015, the conflicts committee of the Partnership's general partner ("Conflicts Committee") approved reimbursement amounts of  $16,416, $13,033 and $13,679, respectively, reflecting the Partnership's allocable share of such expenses.  The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.

(n)      Environmental Liabilities and Litigation

The Partnership’s policy is to accrue for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable.  Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study.  Such accruals are adjusted as further information develops or circumstances change.  Costs of future expenditures for environmental remediation obligations are not discounted to their present value.  Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable.

77

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

(o)      Trade and Accrued Accounts Receivable and Allowance for Doubtful Accounts.

Trade accounts receivable are recorded at the invoiced amount and do not bear interest.  The allowance for doubtful accounts is the Partnership’s best estimate of the amount of probable credit losses in the Partnership’s existing accounts receivable.

(p)      Deferred Catalyst Costs

The cost of the periodic replacement of catalysts is deferred and amortized over the catalyst’s estimated useful life, which ranges from 12 to 36 months.

(q)      Deferred Turnaround Costs

The Partnership capitalizes the cost of major turnarounds and amortizes these costs over the estimated period to the next turnaround, which ranges from 12 to 36 months.

(r)      Income Taxes

The Partnership is subject to the Texas margin tax, which is considered a state income tax, and is included in income tax expense on the Consolidated Statements of Operations. Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed as an income tax and, therefore, the recognition of deferred taxes applies to the margin tax. The impact on deferred taxes as a result of this provision is immaterial.

(s)      Comprehensive Income

Comprehensive income includes net income and other comprehensive income.  There are no items of other comprehensive income or loss in any of the years presented.

(3) Recent Accounting Pronouncements

In January 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2017-04 “Intangibles-Goodwill and other: Simplifying the test for goodwill impairment.” This ASU removes the second step of the two-step test currently required under the current guidance. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit's carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance does not amend the optional qualitative assessment of goodwill impairment. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. The Partnership elected to early adopt this amended guidance effective January 1, 2017. The Partnership expects that adoption of this standard will change its approach for testing goodwill for impairment if a triggering event is identified; however, this standard requires prospective application and therefore will only impact periods subsequent to adoption.

In August 2016, the Financial Accounting Standards Board FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments. This ASU is intended to clarify the presentation of cash receipts and payments in specific situations. The amendments in this ASU are effective for financial statements issued for annual periods beginning after December 15, 2017, including interim periods within those annual periods, and early application is permitted. The Partnership does not anticipate that ASU 2016-15 will have a material effect on its consolidated financial statements and related disclosures.

In February 2016, the FASB issued ASU 2016-02, Leases.  This ASU amends the existing accounting standards for lease accounting, including requiring lessees to recognize most leases on their balance sheets and making targeted changes to lessor accounting. ASU 2016-02 is effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period. Early adoption of this standard is permitted. The standard requires a modified retrospective transition approach for all leases existing at, or entered into after, the date of initial application, with an option to use certain transition relief.  The Partnership is evaluating the effect that ASU 2016-02 will have on its consolidated financial statements and related disclosures.

78

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective. The new standard is effective for the Partnership on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method. The Partnership plans to adopt 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 has completed a review of the impacts of the application of the new standard to its existing portfolio of customer contracts and has concluded its process of evaluating its new controls and processes designed to comply with ASU 2014-09 throughout 2017 to permit adoption by January 1, 2018. The Partnership's approach included performing a detailed review of key contracts representative of its different businesses and comparing historical accounting policies and practices to the new standard.

In the Terminalling and Storage segment, revenue will continue to be recognized for storage contracts based on the contracted monthly tank fixed fee.  For throughput contracts, revenue will continue to be recognized based on the volume moved through the Partnership’s terminals at the contracted rate.  For the Partnership’s tolling agreement, revenue will continue to be 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 will continue to be recognized upon delivering product to the customers as title to the product transfers when the customer physically receives the product. Delivery of product is invoiced as the transaction occurs and are generally paid within a month.

In the Natural Gas Services segment, NGL distribution revenue will continue to be recognized when product is delivered by truck, rail, or pipeline to the Partnership's NGL customers. Revenue will continue to be 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 will continue to be recognized when the service is provided to the customer. The performance of the service is invoiced as the transaction occurs and are generally paid within a month.

In the Sulfur Services segment, revenue from sulfur product sales will continue to be 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 will continue to be recognized as deliveries are made during each monthly period. The performance of the service is invoiced as the transaction occurs and are generally paid within a month.

In the Marine Transportation segment, revenue will continue to be recognized for time charters based on a per day rate. For contracted trips, revenue will continue to be recognized upon completion of the particular trip. The performance of the service is invoiced as the transaction occurs and are generally paid within a month.

Additionally, the Partnership will be required to assess variable consideration included in its contracts and make judgments and estimates throughout the applicable periods. Certain additional financial statement disclosure requirements are mandated by the new standard including disclosure of contract assets and contract liabilities as well as a disaggregated view of revenue. Based on the Partnership’s analysis, the adoption of this guidance will not have a significant impact on its consolidated financial statements.

(4) Acquisitions

79

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

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 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”), which will 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."

Purchase price	$	27,420
Historical carrying value of assets allocated to "Property, plant and equipment"	19,533
Excess purchase price over carrying value of acquired assets	$	7,887

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.

(5) Discontinued Operations, Divestitures, and Assets Held for Sale

Long-Lived Assets Held for Sale

In the fourth quarter of 2017, the Partnership identified certain assets that were no longer deemed core to the operations of the Partnership in the inland division of the Marine Transportation segment. Additionally, the Partnership recorded an adjustment to the fair value less cost to sell of a certain asset classified as held for sale in the Martin Lubricants division of the Terminalling and Storage segment. As a result, an impairment charge of $600 and $1,625 was recorded in the Terminalling and Storage and Marine Transportation segments, respectively, in the fourth quarter of 2017 and was presented as "Impairment of long-lived assets" in the Partnership's Consolidated Statements of Operations.

In the fourth quarter of 2016, the Partnership identified certain assets that were no longer deemed core to the operations of the Partnership in the Smackover refinery and Martin Lubricants divisions of the Terminalling and Storage segment as well as the inland and offshore divisions of the Marine Transportation segment. These assets were deemed non-core due to the each asset's inability to generate cash flows in recent quarters as well as the expected cash flows in future quarters. As a result, an impairment charge of $15,252 and $11,701 was recorded in the Terminalling and Storage and Marine Transportation segments, respectively in the fourth quarter of 2016 and was presented as "Impairment of long-lived assets" in the Partnership's Consolidated Statements of Operations.

At December 31, 2017 and 2016, the assets met the criteria to be classified as held for sale in accordance with ASC 360-10 and are presented at the assets' fair value less cost to sell by segment in current assets as follows:

	December 31, 2017		December 31, 2016
Terminalling and storage	$	4,152	$	10,852
Marine transportation	5,427		4,927
Assets held for sale	$	9,579	$	15,779

During 2017, the Partnership received $8,341 in proceeds from the sale of assets classified as held for sale for a gain of $822, which was presented as a component of "Other operating income (loss), net" in the Partnership's Consolidated Statements of Operations.

The non-core assets discussed above did not qualify for discontinued operations presentation under the guidance of ASC 205-20.

Divestitures

80

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

Divestiture of Terminalling Assets. On December 21, 2016, the Partnership sold its 900,000 barrel crude oil storage terminal, refined product barge terminal, certain pipelines and related easements as well as dockage and trans-loading assets located in Corpus Christi, Texas (collectively the "CCCT Assets") to NuStar Logistics, L.P. (“NuStar”) for gross consideration of $107,000 plus the reimbursement of certain capital expenditures and prepaid items of $2,057. The Partnership received net proceeds of approximately $93,347 after transaction fees and expenses as well as the application of certain net cash payments previously received by us in conjunction with its mandated relocation of certain dockage assets to the purchase price in the amount of $13,400. Proceeds from the sale were used to reduce outstanding borrowings under the Partnership's revolving credit facility. The Partnership recorded a gain from the divestiture of $37,345, which was included in "Other operating income, net on the Partnership's Consolidated Statements of Operations for the year ended December 31, 2016. Net income attributable to the CCCT Assets included in the Partnership's Consolidated Statements of Operations was $0, $43,804, and $10,880 for the years ended December 31, 2017, 2016, and 2015, respectively.

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

Divestiture of Floating Storage Assets. On February 12, 2015, the Partnership sold all six 16,101 barrel liquefied petroleum gas ("LPG") pressure barges, collectively referred to as the Floating Storage Assets for $41,250. These assets were acquired on February 28, 2013. The Partnership classified the results of operations of these assets, which were previously presented as a component of the Natural Gas Services segment, as discontinued operations in the Consolidated Statements of Operations for 2015. The Partnership has retrospectively adjusted its prior period consolidated financial statements to comparably classify the amounts related to the operations and cash flows of the Floating Storage Assets as discontinued operations. The Floating Storage Assets were presented as discontinued operations under the guidance prior to the Partnership's adoption of ASU 2014-08 related to discontinued operations. The adoption of the amended guidance was effective for the Partnership January 1, 2015.

The Floating Storage Assets’ operating results, which are included in income from discontinued operations for the year ended December 31, 2015, were as follows:

Total revenues from third parties	$	791
Total costs and expenses and other, net, excluding depreciation and amortization	1,038
Depreciation and amortization	—
Other operating income, net 1	1,462
Income (loss) from discontinued operations before income taxes	1,215
Income tax expense	—
Income (loss) from discontinued operations, net of income taxes	$	1,215

¹ Other operating income, net represents the gain on the disposition of the Floating Storage Assets.

(6) Inventories

Components of inventories at December 31, 2017 and 2016 were as follows: 

	2017		2016
Natural gas liquids	$	47,462	$	33,656
Sulfur	8,436		8,521
Sulfur based products	18,674		19,107
Lubricants	20,086		18,276
Other	2,594		3,071
	$	97,252	$	82,631

81

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

(7) Property, Plant and Equipment

At December 31, 2017 and 2016, property, plant and equipment consisted of the following:

	Depreciable Lives	2017		2016
Land	—	$	21,719	$	20,679
Improvements to land and buildings	10-25 years	135,896		135,852
Storage equipment	5-50 years	178,815		168,839
Marine vessels	4-25 years	176,782		181,659
Operating plant and equipment	3-50 years	659,854		620,303
Base Gas	—	43,799		43,799
Furniture, fixtures and other equipment	3-20 years	11,134		19,034
Transportation equipment	3-7 years	1,535		1,738
Construction in progress		23,531		32,374
		$	1,253,065	$	1,224,277

Depreciation expense for the years ended December 31, 2017, 2016 and 2015 was $70,904, $72,405 and $67,134.

Additions to property, plant and equipment included in accounts payable at December 31, 2017 and 2016 were $4,100 and $1,819, respectively.

(8)     Goodwill

The following table represents the goodwill balance at December 31, 2016, changes during the year, and the resulting balances at December 31, 2017:

	2017		2016
Carrying amount of goodwill:
Terminalling and storage	$	11,868	$	11,868
Natural gas services	79		79
Sulfur services	5,349		5,349
Total goodwill	$	17,296	$	17,296

During the impairment evaluation performed at August 31, 2017, the Partnership first assessed qualitative factors in determining whether it is more likely than not that the fair value of a reporting unit or other intangible asset is less than its carrying amount. After assessing qualitative factors, the Partnership determined that it is not more likely than not that the fair value of its reporting units are less than its carrying amount. Therefore, no impairment was recorded for the year ended December 31, 2017.

During the second quarter of 2016, the Partnership determined that the state of market conditions in the Marine Transportation reporting unit, including the demand for utilization, day rates and the current oversupply of inland tank barges, indicated that an impairment of goodwill may exist. As a result, the Partnership assessed qualitative factors and determined that the Partnership could not conclude it was more likely than not that the fair value of goodwill exceeded its carrying value. In turn, the Partnership prepared a quantitative analysis of the fair value of the goodwill as of June 30, 2016, based on the weighted average valuation of the aforementioned income and market based valuation approaches. The underlying results of the valuation were driven by actual results during the six months ended June 30, 2016 and the pricing and market conditions existing as of June 30, 2016, which were below forecasts at the time of the previous goodwill assessments. Other key estimates, assumptions and inputs used in the valuation included long-term growth rates, discounts rates, terminal values, valuation multiples and relative valuations when comparing the reporting unit to similar businesses or asset bases. Upon completion of the analysis, a $4,145 impairment of all goodwill in the Marine Transportation reporting unit was incurred during the second quarter of 2016. The Partnership did not recognize any other goodwill impairment losses for the year ended December 31, 2016.

82

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

(9)     Leases

The Partnership has numerous non-cancelable operating leases primarily for terminal facilities and transportation and other equipment. The leases generally provide that all expenses related to the equipment are to be paid by the lessee. Management expects to renew or enter into similar leasing arrangements for similar equipment upon the expiration of the current lease agreements. The Partnership also has cancelable operating lease land rentals and outside marine vessel charters.

The Partnership’s future minimum lease obligations as of December 31, 2017 consist of the following:

Fiscal year	Operating Leases
2018	$	6,841
2019	4,559
2020	3,715
2021	2,245
2022	1,079
Thereafter	7,750
Total	$	26,189

Rent expense for continuing operating leases for the years ended December 31, 2017, 2016 and 2015 was $15,908, $19,005 and $18,831, respectively.

(10)    Investments in Unconsolidated Entities and Joint Ventures

The Partnership owns a 19.8% limited partnership and 0.2% general partnership interest in West Texas LPG Pipeline Limited Partnership ("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 Balance Sheet. 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 December 31,						Years ended December 31,
	Total Assets		Long-Term Debt		Members’ Equity/Partners' Capital		Revenues		Net Income
2017
WTLPG	$	837,163	$	—	$	787,426	$	87,048	$	21,571
2016
WTLPG	$	812,464	$	—	$	790,406	$	88,468	$	23,883
2015
WTLPG	$	819,342	$	—	$	804,023	$	100,708	$	46,294

As of December 31, 2017 and 2016, the Partnership’s interest in cash of the unconsolidated equity method investee was $5,585 and $631, respectively.

83

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

(11)     Fair Value Measurements

The Partnership uses a valuation framework based upon inputs that market participants use in pricing certain assets and liabilities. These inputs are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources. Unobservable inputs represent the Partnership's own market assumptions. Unobservable inputs are used only if observable inputs are unavailable or not reasonably available without undue cost and effort. The two types of inputs are further prioritized into the following hierarchy:

Level 1: Quoted market prices in active markets for identical assets or liabilities.

Level 2: Observable market based inputs or unobservable inputs that are corroborated by market data.

Level 3: Unobservable inputs that reflect the entity's own assumptions and are not corroborated by market data.

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

	Level 2
	December 31,
	2017			2016
Commodity derivative contracts, net	$	(72	)	$	(3,904	)

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. The estimated fair value of the note receivable - affiliates was determined by calculating the net present value of the payments over the life of the note. The note is considered Level 3 due to the lack of observable inputs for similar transactions between related parties.

	December 31, 2017				December 31, 2016
	Carrying Value		Fair Value		Carrying Value		Fair Value
Note receivable - affiliates	$	—	$	—	$	15,000	$	15,797
2021 Senior unsecured notes	$	372,618	$	381,657	$	372,239	$	377,882

(12)    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

84

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

The Partnership from time to time has used derivatives to manage the risk of commodity price fluctuation. Commodity risk is the adverse effect on the value of a liability or future purchase that results from a change in commodity price.  The Partnership has established a hedging policy and monitors and manages the commodity market risk associated with potential commodity risk exposure.  In addition, the Partnership has focused on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction. The Partnership has entered into hedging transactions as of December 31, 2017 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 145 barrels settling during the period from January 31, 2018 through February 28, 2018. At December 31, 2016, the Partnership had instruments totaling a gross notional quantity of 731 barrels settling during the period from January 1, 2017 through June 30, 2017. These instruments settle against the applicable pricing source for each grade and location. MET served as the counterparty for all positions outstanding at December 31, 2016.

(b)    Interest Rate Derivative Instruments

The Partnership is exposed to market risks associated with interest rates. Market risk is the adverse effect on the value of a financial instrument that results from a change in interest rates. We minimize this market risk by establishing and monitoring parameters that limit the types and degree of market risk that may be undertaken. The Partnership enters into interest rate swaps to manage interest rate risk associated with the Partnership’s variable rate credit facility and it's senior unsecured notes.

During the twelve months ended December 31, 2016 and 2015, the Partnership entered into contracts which provided the counterparty the option to enter into swap contracts to hedge the Partnership's exposure to changes in the fair value of its senior unsecured notes ("interest rate swaptions"). In connection with the interest rate swaption contracts, the Partnership received premiums of $630 and $2,495, which represented their fair value on the date the transactions were initiated and were initially recorded as derivative liabilities on the Partnership's Consolidated Balance Sheet, during the twelve months ended December 31, 2016 and 2015, respectively. Each of the interest rate swaptions was fully amortized as of December 31, 2016. Interest rate swaption contract premiums received are amortized over the period from initiation of the contract through their termination date. For the twelve months ended December 31, 2016 and 2015, the Partnership recognized $630 and $2,495, respectively, of premium in "Interest expense, net" on the Partnership's Consolidated Statement of Operations related to the interest rate swaption contracts.

     For information regarding fair value amounts and gains and losses on interest rate derivative instruments and related hedged items, see "Tabular Presentation of Gains and Losses on Derivative Instruments and Related Hedged Items" below.

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

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

	Fair Values of Derivative Instruments in the Consolidated Balance Sheet
	Derivative Assets					Derivative Liabilities
		Fair Values					Fair Values
	Balance Sheet Location	December 31, 2017		December 31, 2016		Balance Sheet Location	December 31, 2017		December 31, 2016
Derivatives not designated as hedging instruments:	Current:
Commodity contracts	Fair value of derivatives	$	—	$	—	Fair value of derivatives	$	72	$	3,904
Total derivatives not designated as hedging instruments		$	—	$	—		$	72	$	3,904

85

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

Effect of Derivative Instruments on the Consolidated Statement of Operations For the Twelve Months Ended December 31, 2017, 2016, and 2015

	Location of Gain or (Loss) Recognized in Income on Derivatives	Amount of (Gain) or Loss Recognized in Income on Derivatives
		2017		2016			2015
Derivatives not designated as hedging instruments:
Interest rate swaption contracts	Interest expense	$	—	$	(630	)	$	(2,495	)
Interest rate contracts	Interest expense	—		(366		)	206
Commodity contracts	Cost of products sold	1,304		5,129			(818		)
Total derivatives not designated as hedging instruments		$	1,304	$	4,133		$	(3,107	)

(13)    Related Party Transactions

As of December 31, 2017, Martin Resource Management owned 6,264,532 of the Partnership’s common units representing approximately 16.3% of the Partnership’s outstanding limited partnership units.  Martin Resource Management controls the Partnership's general partner by virtue of its 51% voting interest in Holdings, the sole member of the Partnership's general partner. The Partnership’s general partner, MMGP, owns a 2% general partner interest in the Partnership and the Partnership’s incentive distribution rights.  The Partnership’s general partner’s ability, as general partner, to manage and operate the Partnership, and Martin Resource Management’s ownership as of December 31, 2017, of approximately 16.3% of the Partnership’s outstanding limited partnership units, effectively gives Martin Resource Management the ability to veto some of the Partnership’s actions and to control the Partnership’s management.

The following is a description of the Partnership’s material related party agreements:

Omnibus Agreement

              Omnibus Agreement.  The Partnership and its general partner are parties to the Omnibus Agreement dated November 1, 2002, with Martin Resource Management that governs, among other things, potential competition and indemnification obligations among the parties to the agreement, related party transactions, the provision of general administration and support services by Martin Resource Management and the Partnership’s use of certain Martin Resource Management trade names and trademarks. The Omnibus Agreement was amended on November 25, 2009, to include processing crude oil into finished products including naphthenic lubricants, distillates, asphalt and other intermediate cuts. The Omnibus Agreement was amended further on October 1, 2012, to permit the Partnership to provide certain lubricant packaging products and services to Martin Resource Management.

Non-Competition Provisions. Martin Resource Management has agreed for so long as it controls the general partner of the Partnership, not to engage in the business of:

• providing terminalling and storage services for petroleum products and by-products including the refining, blending and packaging of finished lubricants;

•providing marine transportation of petroleum products and by-products;

•distributing NGLs; and

•manufacturing and selling sulfur-based fertilizer products and other sulfur-related products.

This restriction does not apply to:

• the ownership and/or operation on the Partnership’s behalf of any asset or group of assets owned by it or its affiliates;

• any business operated by Martin Resource Management, including the following:

◦ providing land transportation of various liquids;

86

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

◦ 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; and

• any business that Martin Resource Management acquires or constructs where a portion of such business includes a restricted business and the fair market value of the restricted business is $5,000 or more and represents less than 20% of the aggregate value of the entire business to be acquired or constructed; provided that, following completion of the acquisition or construction, the Partnership will be provided the opportunity to purchase the restricted business.

Services.  Under the Omnibus Agreement, Martin Resource Management provides the Partnership with corporate staff, support services, and administrative services necessary to operate the Partnership’s business. The Omnibus Agreement requires the Partnership to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes on the Partnership’s behalf or in connection with the operation of the Partnership’s business. There is no monetary limitation on the amount the Partnership is required to reimburse Martin Resource Management for direct expenses.  In addition to the direct expenses, under the Omnibus Agreement, the Partnership is required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses.

Effective January 1, 2017, through December 31, 2017, the Conflicts Committee approved an annual reimbursement amount for indirect expenses of $16,416.  The Partnership reimbursed Martin Resource Management for $16,416, $13,033 and $13,679 of indirect expenses for the years ended December 31, 2017, 2016 and 2015, respectively.  The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.

These indirect expenses are intended to cover the centralized corporate functions Martin Resource Management provides for the Partnership, such as accounting, treasury, clerical, engineering, legal, billing, information technology, administration of insurance, general office expenses and employee benefit plans and other general corporate overhead functions the Partnership shares with Martin Resource Management retained businesses. The provisions of the Omnibus Agreement regarding Martin Resource Management’s services will terminate if Martin Resource Management ceases to control the general partner of the Partnership.

Related  Party Transactions. The Omnibus Agreement prohibits the Partnership from entering into any material agreement with Martin Resource Management without the prior approval of the Conflicts Committee. For purposes of the Omnibus Agreement, the term material agreements means any agreement between the Partnership and Martin Resource

87

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

Management that requires aggregate annual payments in excess of then-applicable agreed upon reimbursable amount of indirect general and administrative expenses. Please read "Services" above.

License Provisions. Under the Omnibus Agreement, Martin Resource Management has granted the Partnership a nontransferable, nonexclusive, royalty-free right and license to use certain of its trade names and marks, as well as the trade names and marks used by some of its affiliates.

Amendment and Termination. The Omnibus Agreement may be amended by written agreement of the parties; provided, however, that it may not be amended without the approval of the Conflicts Committee if such amendment would adversely affect the unitholders. The Omnibus Agreement was first amended on November 25, 2009, to permit the Partnership to provide refining services to Martin Resource Management.  The Omnibus Agreement was amended further on October 1, 2012, to permit the Partnership to provide certain lubricant packaging products and services to Martin Resource Management.  Such amendments were approved by the Conflicts Committee.  The Omnibus Agreement, other than the indemnification provisions and the provisions limiting the amount for which the Partnership will reimburse Martin Resource Management for general and administrative services performed on its behalf, will terminate if the Partnership is no longer an affiliate of Martin Resource Management.

Motor Carrier Agreement

Motor Carrier Agreement.  The Partnership is a party to a motor carrier agreement effective January 1, 2006 as amended, with Martin Transport, Inc., a wholly owned subsidiary of Martin Resource Management through which Martin Transport, Inc. operates its land transportation operations. Under the agreement, Martin Transport, Inc. agreed to transport the Partnership's NGLs as well as other liquid products.

Term and Pricing.  The agreement has an initial term that expired in December 2007 but automatically renews for consecutive one year periods unless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicable term.  The Partnership has the right to terminate this agreement at any time by providing 90 days prior notice.  Under this agreement, Martin Transport, Inc. transports the Partnership’s NGL shipments as well as other liquid products. These rates are subject to any adjustments which are mutually agreed or in accordance with a price index. Additionally, during the term of the agreement, shipping charges are also subject to fuel surcharges determined on a weekly basis in accordance with the U.S. Department of Energy’s national diesel price list.

Indemnification.  Martin Transport has indemnified us against all claims arising out of the negligence or willful misconduct of Martin Transport and its officers, employees, agents, representatives and subcontractors. We indemnified Martin Transport against all claims arising out of the negligence or willful misconduct of us and our officers, employees, agents, representatives and subcontractors. In the event a claim is the result of the joint negligence or misconduct of Martin Transport and us, our indemnification obligations will be shared in proportion to each party’s allocable share of such joint negligence or misconduct.

Marine Agreements

Marine Transportation Agreement. The Partnership is a party to a marine transportation agreement effective January 1, 2006, as amended, under which the Partnership provides marine transportation services to Martin Resource Management on a spot-contract basis at applicable market rates.  Effective each January 1, this agreement automatically renews for consecutive one year periods unless either party terminates the agreement by giving written notice to the other party at least 60 days prior to the expiration of the then applicable term. The fees the Partnership charges Martin Resource Management are based on applicable market rates.

Marine Fuel.  The Partnership is a party to an agreement with Martin Resource Management dated November 1, 2002 under which Martin Resource Management provides the Partnership with marine fuel from its locations in the Gulf of Mexico at a fixed rate in excess of a price index.  Under this agreement, the Partnership agreed to purchase all of its marine fuel requirements that occur in the areas serviced by Martin Resource Management.

88

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

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 Statements of Operations. The revenues, costs and expenses reflected in these tables are tabulations of the related party transactions that are recorded in the corresponding caption of the Consolidated Statements of Operations and do not reflect a statement of profits and losses for related party transactions.

The impact of related party revenues from sales of products and services is reflected in the Consolidated Statements of Operations as follows:

89

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

Revenues:	2017		2016		2015
Terminalling and storage	$	82,205	$	82,437	$	78,233
Marine transportation	16,801		21,767		27,724
Natural gas services	122		699		878
Product sales:
Natural gas services	1,043		8		196
Sulfur services	1,963		2,006		3,639
Terminalling and storage	572		1,020		1,836
	3,578		3,034		5,671
	$	102,706	$	107,937	$	112,506

The impact of related party cost of products sold is reflected in the Consolidated Statements of Operations as follows:

Cost of products sold:
Natural gas services	$	18,946	$	22,886	$	25,797
Sulfur services	15,564		15,339		16,579
Terminalling and storage	17,612		13,838		17,718
	$	52,122	$	52,063	$	60,094

The impact of related party operating expenses is reflected in the Consolidated Statements of Operations as follows:

Operating expenses:
Marine transportation	$	23,815	$	28,107	$	32,373
Natural gas services	9,007		9,258		8,639
Sulfur services	5,821		5,995		6,928
Terminalling and storage	25,701		27,481		29,931
	$	64,344	$	70,841	$	77,871

The impact of related party selling, general and administrative expenses is reflected in the Consolidated Statements of Operations as follows:

Selling, general and administrative:
Marine transportation	$	34	$	30	$	29
Natural gas services	8,162		7,566		6,216
Sulfur services	2,526		2,732		2,760
Terminalling and storage	2,278		2,526		2,284
Indirect overhead allocation, net of reimbursement	16,416		13,036		13,679
	$	29,416	$	25,890	$	24,968

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 Balance Sheets. Interest income for the years ended December 31, 2017, 2016, and 2015 was $943, $2,256 and $2,250, respectively, and is included in "Interest expense, net" in the Consolidated Statements of Operations.

90

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

(14) Supplemental Balance Sheet Information

Components of "Intangibles and other assets, net" at December 31, 2017 and 2016 were as follows:

	2017		2016
Customer contracts and relationships, net	$	25,252	$	36,528
Other intangible assets	1,752		2,280
Other	5,797		6,066
	$	32,801	$	44,874

Other intangible assets consist of covenants not-to-compete and technology-based assets.

Aggregate amortization expense for customer contracts and other intangible assets included in continuing operations was $13,887, $19,548, and $22,115, for the years ended December 31, 2017, 2016 and 2015, respectively, and accumulated amortization amounted to $39,462 and $48,876 at December 31, 2017 and 2016, respectively.

Estimated amortization expense for customer contract and relationships and other intangible assets for the years subsequent to December 31, 2017 are as follows: 2018 - $7,472; 2019 - $4,471; 2020 - $4,440; 2021 - $4,319; 2022 - $4,295; subsequent years - $2,007.

Components of "Other accrued liabilities" at December 31, 2017 and 2016 were as follows:

	2017		2016
Accrued interest	$	11,726	$	10,629
Asset retirement obligations	5,429		7,953
Property and other taxes payable	5,638		6,443
Accrued payroll	3,385		1,672
Other	162		20
	$	26,340	$	26,717

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

	Year Ended December 31,
	2017			2016
	(In thousands)
Beginning asset retirement obligations	$	16,418		$	2,163
Revisions to existing liabilities1	5,547			14,379
Accretion expense	404			178
Liabilities settled	(8,857		)	(302		)
Ending asset retirement obligations	13,512			16,418
Current portion of asset retirement obligations2	(5,429		)	(7,953		)
Long-term portion of asset retirement obligations3	$	8,083		$	8,465

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 2016 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 Balance Sheets.

91

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

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

(15)    Long-Term Debt

At December 31, 2017 and 2016, long-term debt consisted of the following:

	2017		2016
$664,444 Revolving credit facility at variable interest rate (4.55%1 weighted average at December 31, 2017), 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 $4,986 and $7,132, respectively3	$	440,014	$	435,868
$400,000 Senior notes, 7.25% interest, including unamortized premium of $956 and $1,262, respectively, also net of unamortized debt issuance costs of $2,138 and $2,823 respectively, issued $250,000 February 2013 and $150,000 April 2014, $26,200 repurchased during 2015, due February 2021, unsecured3,4	372,618		372,239
Total long-term debt	$	812,632	$	808,107

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 December 31, 2017 and 2016 were at LIBOR plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 2.00% to 3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 1.00% to 2.00%. The applicable margin for LIBOR borrowings at December 31, 2017 is 3.00%.  The credit facility contains various covenants which limit the Partnership’s ability to make certain investments and acquisitions; enter into certain agreements; incur indebtedness; sell assets; and make certain amendments to the Omnibus Agreement. The Partnership is permitted to make quarterly distributions so long as no event of default exists.

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

⁴ The 2021 indentures restrict the Partnership’s ability to sell assets; pay distributions or repurchase units or redeem or repurchase subordinated debt; make investments; incur or guarantee additional indebtedness or issue preferred units; and consolidate, merge or transfer all or substantially all of its assets. Many of these covenants will terminate if the notes achieve an investment grade rating from each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no default (as defined in the indentures) has occurred.

The Partnership paid cash interest, net of proceeds received from interest rate swaptions, in the amount of $45,728, $46,046, and $43,376 for the years ended December 31, 2017, 2016 and 2015, respectively. Capitalized interest was $730, $1,126, and $1,944 for the years ended December 31, 2017, 2016 and 2015, respectively.

(16)     Partners' Capital

As of December 31, 2017, partners’ capital consisted of 38,444,612 common limited partner units, representing a 98% partnership interest and a 2.0% general partner interest. Martin Resource Management, through subsidiaries, owned 6,264,532 of the Partnership's common limited partnership units representing approximately 16.3% of the Partnership's outstanding common limited partnership units. MMGP, the Partnership's general partner, owns the 2.0% general partnership interest.

The partnership agreement of the Partnership (the "Partnership Agreement") contains specific provisions for the allocation of net income and losses to each of the partners for purposes of maintaining their respective partner capital accounts.

Issuance of Common Units

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

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 $51,056. 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 2.0% general partner interest and certain incentive distribution rights ("IDRs") in the Partnership. IDRs are a separate class of non-voting limited partner interest that may be transferred or sold by the general partner under the terms of the Partnership Agreement, and represent the right to receive an increasing percentage of cash distributions after the minimum quarterly distribution and any cumulative arrearages on common units once certain target distribution levels have been achieved. The Partnership is required to distribute all of its available cash from operating surplus, as defined in the Partnership Agreement.

The target distribution levels entitle the general partner to receive 2.0% of quarterly cash distributions up to $0.55 per unit, 15% of quarterly cash distributions in excess of $0.55 per unit until all unitholders have received $0.625 per unit, 25% of quarterly cash distributions in excess of $0.625 per unit until all unitholders have received $0.75 per unit and 50% of quarterly cash distributions in excess of $0.75 per unit.

For the years ended December 31, 2017, 2016 and 2015, the general partner was allocated $0, $7,786, and $15,571 in incentive distributions.

Distributions of Available Cash

The Partnership distributes all of its available cash (as defined in the Partnership Agreement) within 45 days after the end of each quarter to unitholders of record and to the general partner. Available cash is generally defined as all cash and cash equivalents of the Partnership on hand at the end of each quarter less the amount of cash reserves its general partner determines in its reasonable discretion is necessary or appropriate to: (i) provide for the proper conduct of the Partnership’s business; (ii) comply with applicable law, any debt instruments or other agreements; or (iii) provide funds for distributions to unitholders and the general partner for any one or more of the next four quarters, plus all cash on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.

Net Income per Unit

The Partnership follows the provisions of the FASB ASC 260-10 related to earnings per share, which addresses the application of the two-class method in determining income per unit for master limited partnerships having multiple classes of securities that may participate in partnership distributions accounted for as equity distributions. Undistributed earnings are allocated to the general partner and limited partners utilizing the contractual terms of the Partnership Agreement. Distributions to the general partner pursuant to the IDRs are limited to available cash that will be distributed as defined in the Partnership Agreement. Accordingly, the Partnership does not allocate undistributed earnings to the general partner for the IDRs because the general partner's share of available cash is the maximum amount that the general partner would be contractually entitled to receive if all earnings for the period were distributed. When current period distributions are in excess of earnings, the excess distributions for the period are to be allocated to the general partner and limited partners based on their respective sharing of losses specified in the Partnership Agreement. Additionally, as required under FASB ASC 260-10-45-61A, unvested share-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities, as defined in FASB ASC 260-10-20, for earnings per unit calculations.

For purposes of computing diluted net income per unit, the Partnership uses the more dilutive of the two-class and if-converted methods. Under the if-converted method, the weighted-average number of subordinated units outstanding for the period is added to the weighted-average number of common units outstanding for purposes of computing basic net income per unit and the resulting amount is compared to the diluted net income per unit computed using the two-class method. The following is a reconciliation of net income from continuing operations and net income from discontinued operations allocated to the general partner and limited partners for purposes of calculating net income attributable to limited partners per unit:

93

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

	Years Ended December 31,
	2017			2016			2015
Continuing operations:
Income from continuing operations	$	17,135		$	31,652		$	37,165
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	—			7,786			15,078
Distributions payable on behalf of general partner interest	1,569			2,058			2,585
General partner interest in undistributed loss	(1,226		)	(1,425		)	(1,842		)
Less income allocable to unvested restricted units	42			90			136
Limited partners’ interest in net income	$	16,750		$	23,143		$	21,208

	Years Ended December 31,
	2017		2016		2015
Discontinued operations:
Income from discontinued operations	$	—	$	—	$	1,215
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	—		—		493
Distributions payable on behalf of general partner interest	—		—		84
General partner interest in undistributed loss	—		—		(60		)
Less income allocable to unvested restricted units	—		—		4
Limited partners’ interest in net income	$	—	$	—	$	694

The Partnership allocates the general partner's share of earnings between continuing and discontinued operations as a proportion of net income from continuing and discontinued operations to total net income.

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

	Years Ended December 31,
	2017	2016	2015
Basic weighted average limited partner units outstanding	38,101,583	35,347,032	35,308,649
Dilutive effect of restricted units issued	63,318	28,231	62,880
Total weighted average limited partner diluted units outstanding	38,164,901	35,375,263	35,371,529

All outstanding units were included in the computation of diluted earnings per unit and weighted based on the number of days such units were outstanding during the period presented.

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(17)    Unit Based Awards

The Partnership recognizes compensation cost related to stock-based awards to employees in its consolidated financial statements in accordance with certain provisions of ASC 718. The Partnership recognizes compensation costs related to stock-based awards to directors under certain provisions of ASC 505-50-55 related to equity-based payments to non-employees.   Amounts recognized in selling, general, and administrative expense in the consolidated financial statements with respect to these plans are as follows:

	For the Year Ended December 31,
	2017		2016		2015
Employees	$	534	$	783	$	1,338
Non-employee directors	116		121		91
Total unit-based compensation expense	$	650	$	904	$	1,429

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 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. Once these restrictions lapse, the grantee is entitled to full ownership of the unit without restrictions. In addition, the restricted units will vest upon a change of control of the Partnership, the general partner or Martin Resource Management or if the general partner ceases to be an affiliate of Martin Resource Management. The Partnership intends the issuance of the common units upon vesting of the restricted units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive, and the Partnership will receive no remuneration for the units. The restricted units issued to directors generally vest in equal annual installments over a four-year period. Restricted units issued to employees generally cliff vest after three years of service.

 The restricted units are valued at their fair value at the date of grant which is equal to the market value of common units on such date. A summary of the restricted unit activity for the year ended December 31, 2017 is provided below:

	Number of Units			Weighted Average Grant-Date Fair Value Per Unit
Non-vested, beginning of year	103,800			$	26.54
Granted	12,000			$	19.00
Vested	(7,800		)	$	19.18
Forfeited	(9,250		)	$	28.50
Non-Vested, end of year	98,750			$	24.80
Aggregate intrinsic value, end of year	$	1,383

A summary of the restricted units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) during the years ended December 31, 2017, 2016 and 2015 is provided below:

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	For the Year Ended December 31,
	2017		2016		2015
Aggregate intrinsic value of units vested	$	143	$	1,233	$	110
Fair value of units vested	$	208	$	1,773	$	128

As of December 31, 2017, there was $269 of unrecognized compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 0.8 years.

(18)    Income Taxes

The operations of a partnership are generally not subject to income taxes because its income is taxed directly to its partners.

The Partnership is subject to the Texas margin tax, which is considered a state income tax, and is included in income tax expense on the Consolidated Statements of Operations. Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed as an income tax and, therefore, the recognition of deferred taxes applies to the margin tax. The impact on deferred taxes as a result of this provision is immaterial. State income taxes attributable to the Texas margin tax of $352, $726 and $1,048 were recorded in income tax expense for the years ended December 31, 2017, 2016 and 2015, respectively.

A current income tax liability of $510, and $870 existed at December 31, 2017 and 2016, respectively.

Cash paid for income taxes was $712, $841, and $1,237 for the years ended December 31, 2017, 2016 and 2015, respectively.     

The Bipartisan Budget Act of 2015 provides that any tax adjustments resulting from partnership audits will generally be determined, and any resulting tax, interest and penalties collected, at the partnership level for tax years beginning after December 31, 2017. The Bipartisan Budget Act of 2015 allows a partnership to elect to apply these provisions to any return of the partnership filed for partnership taxable years beginning after the date of the enactment, November 2, 2015. The Partnership does not intend to elect to apply these provisions for any tax return filed for partnership taxable years beginning before January 1, 2018.

On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”) that makes significant changes to the U.S. Internal Revenue Code. Among other changes, the Tax Act includes a new deduction on certain pass-through income, a repeal of the partnership technical termination rule, and new limitations on certain deductions and credits, including interest expense deductions. Since the operations of a partnership are not subject to federal income tax, and most provisions of the Tax Act are effective for tax years beginning after December 31, 2017, the legislation has no material impact to the Partnership for 2017. We are in the process of analyzing the Tax Act and its possible effect going forward, as it will impact allocations to unitholders.

As of December 31, 2017, the tax years that remain open to assessment by federal and state jurisdictions are 2014-2016.

(19)    Business Segments

The Partnership has four reportable segments: terminalling and storage, natural gas services, marine transportation, and sulfur services. The Partnership’s reportable segments are strategic business units that offer different products and services. The operating income of these segments is reviewed by the chief operating decision maker to assess performance and make business decisions.

The accounting policies of the operating segments are the same as those described in Note 2. The Partnership evaluates the performance of its reportable segments based on operating income. There is no allocation of administrative expenses or interest expense.

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

The Natural Gas Services segment information below excludes the discontinued operations of the Floating Storage Assets for 2015. See Note 5.

	Operating Revenues		Intersegment Eliminations			Operating Revenues After Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures and Plant Turnaround Costs
Year Ended December 31, 2017:
Terminalling and storage	$	236,169	$	(5,998	)	$	230,171	$	45,160	$	629		$	29,644
Natural gas services	532,908		(226		)	532,682		24,916		51,663			7,430
Sulfur services	134,684		—			134,684		8,117		23,205			2,611
Marine transportation	51,915		(3,336		)	48,579		7,002		1,650			3,929
Indirect selling, general, and administrative	—		—			—		—		(17,332		)	—
Total	$	955,676	$	(9,560	)	$	946,116	$	85,195	$	59,815		$	43,614
Year Ended December 31, 2016:
Terminalling and storage	$	242,363	$	(5,653	)	$	236,710	$	45,484	$	40,660		$	26,097
Natural gas services	391,333		—			391,333		28,081		41,438			4,807
Sulfur services	141,058		—			141,058		7,995		23,393			5,093
Marine transportation	61,233		(2,943		)	58,290		10,572		(16,039		)	2,334
Indirect selling, general, and administrative	—		—			—		—		(16,794		)	—
Total	$	835,987	$	(8,596	)	$	827,391	$	92,132	$	72,658		$	38,331
Year Ended December 31, 2015:
Terminalling and storage	$	270,440	$	(5,670	)	$	264,770	$	38,731	$	15,704		$	40,421
Natural gas services	523,160		—			523,160		34,072		41,220			24,330
Sulfur services	170,161		—			170,161		8,455		23,604			1,201
Marine transportation	81,784		(3,031		)	78,753		10,992		8,576			2,775
Indirect selling, general, and administrative	—		—			—		—		(18,951		)	—
Total	$	1,045,545	$	(8,701	)	$	1,036,844	$	92,250	$	70,153		$	68,727

Revenues from two customers in the Natural Gas Services segment were $169,504, $122,381 and $148,273 for the years ended December 31, 2017, 2016 and 2015, respectively.

The Partnership's assets by reportable segment as of December 31, 2017 and 2016, are as follows:

	2017		2016
Total assets:
Terminalling and storage	$	326,920	$	328,098
Natural gas services	704,524		684,722
Sulfur services	120,790		125,356
Marine transportation	101,264		108,187
Total assets	$	1,253,498	$	1,246,363

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

(20)    Quarterly Financial Information

Consolidated Quarterly Income Statement Information

	(Unaudited)
	First Quarter		Second Quarter			Third Quarter			Fourth Quarter
	(Dollar in thousands, except per unit amounts)
2017
Revenues	$	253,325	$	193,922		$	193,128		$	305,741
Operating income (loss)	23,748		10,848			(4,484		)	29,703
Equity in earnings of unconsolidated entities	905		853			789			1,767
Net income (loss)	13,583		989			(16,286		)	18,849
Limited partners' interest in net income (loss) per limited partner unit	0.36		0.03			(0.42		)	0.47
	First Quarter		Second Quarter			Third Quarter			Fourth Quarter
	(Dollar in thousands, except per unit amounts)
2016
Revenues	$	225,605	$	190,348		$	174,537		$	236,901
Operating income	24,338		10,256			9,176			28,888
Equity in earnings of unconsolidated entities	1,677		805			1,120			1,112
Net income (loss)	15,914		(1,211		)	(933		)	17,882
Limited partners' interest in net income (loss) per limited partner unit	0.33		(0.14		)	(0.03		)	0.49

(21)    Commitments 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 will reimburse the Partnership $750 each quarter for four consecutive quarters as a reduction in the purchase price of the Redbird Class A interests.  These payments are a result of Cardinal Gas Storage Partners LLC ("Cardinal") not achieving certain financial targets set forth in the Purchase Price Reimbursement Agreement.  These payments are considered a reduction of the excess of the purchase price over the carrying value of the assets transferred to the Partnership from Martin Resource Management and will be recorded as an adjustment to "Partners' capital" in each quarter the payments are made. The agreement further provided for purchase price reimbursements of up to $4,500 in 2016 in the event certain financial conditions were not met. For the year ended December 31, 2017 and 2016, the Partnership received $1,125 and $4,125, respectively, 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.

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

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. At December 31, 2017, the 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 whereby we have committed certain terminalling and storage assets in exchange for a minimum fee. Future minimum revenues we expect to receive under these non-cancelable arrangements as of December 31, 2017, are as follows: 2018 - $14,172; 2019 - $11,190; 2020 - $9,053; 2021 - $6,200; 2022 - $5,187; subsequent years - $12,072.

(22)    Condensed Consolidating Financial Information

The Partnership's operations are conducted by its operating subsidiaries as it has no independent assets or operations. Martin Operating Partnership L.P. (the "Operating Partnership"), the Partnership’s wholly-owned subsidiary, and the Partnership's other operating subsidiaries have issued in the past, and may issue in the future, unconditional guarantees of senior or subordinated debt securities of the Partnership. The guarantees that have been issued are full, irrevocable and unconditional and joint and several. In addition, the Operating Partnership may also issue senior or subordinated debt securities which, if issued, will be fully, irrevocably and unconditionally guaranteed by the Partnership. Substantially all of the Partnership's operating subsidiaries are subsidiary guarantors of its outstanding senior unsecured notes and any subsidiaries other than the subsidiary guarantors are minor.

(23)    Subsequent Events

Quarterly Distribution.  On January 18, 2018, the Partnership declared a quarterly cash distribution of $0.50 per common unit for the fourth quarter of 2017, or $2.00 per common unit on an annualized basis, which was paid on February 14, 2018 to unitholders of record as of February 7, 2018.

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

(a)       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 Rules 13a-15(e) and 15(d)-15(e) of the Exchange Act) as of December 31, 2017.  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 December 31, 2017 to provide reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms and (ii) accumulated and communicated to the Company’s management, including its principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

(b)        Management’s Report on Internal Control Over Financial Reporting.  Management is responsible for establishing and maintaining adequate internal control over financial reporting. A company’s internal control over financial reporting is a process designed 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Our management, including the Chief Executive Officer and Chief Financial Officer of our general partner, conducted an evaluation of the effectiveness of our internal control over financial reporting based on criteria established in the Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on its evaluation under the framework in Internal Control — Integrated Framework (2013), our management concluded that our internal control over financial reporting was effective as of December 31, 2017.  The effectiveness of our internal control over financial reporting as of December 31, 2017 has been audited by KPMG LLP, our independent registered public accounting firm, as stated in their report appearing in "Item 8 - Financial Statements and Supplementary Data."

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

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Item 9B. Other Information

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

Management of Martin Midstream Partners L.P.

Martin Midstream GP LLC, as our general partner, manages our operations and activities on our behalf. Our general partner was not elected by our unitholders and will not be subject to re-election in the future. Unitholders do not directly or indirectly participate in our management or operation.  Our general partner owes a fiduciary duty to our unitholders. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically non-recourse to it. However, whenever possible, our general partner seeks to provide that our indebtedness or other obligations are non-recourse to our general partner.

Three directors of our general partner serve on a conflicts committee of the Partnership's general partner ("Conflicts Committee") to review specific matters that the directors believe may involve conflicts of interest. The Conflicts Committee determines if the resolution of the conflict of interest is fair and reasonable to us.  The members of the Conflicts Committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates and must meet the independence standards established by NASDAQ to serve on an audit committee of a board of directors.  Any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders.  The current members of our Conflicts Committee are outside directors, James M. Collingsworth, C. Scott Massey and Byron R. Kelley, all of whom meet the independence standards established by NASDAQ, except as referenced above.

The Audit Committee reviews our external financial reporting, recommends engagement of our independent auditors and reviews procedures for internal auditing and the adequacy of our internal accounting controls.   The current members of our Audit Committee are outside directors, C. Scott Massey, Byron R. Kelley and James M. Collingsworth, all of whom meet the independence standards established by NASDAQ.

The Compensation Committee oversees compensation decisions for the officers of our general partner as well as the compensation plans described below.  The current members of our Compensation Committee are our outside directors, James M. Collingsworth, C. Scott Massey, and Byron R. Kelley.

The current members of our Nominating Committee are outside directors, James M. Collingsworth, Byron R. Kelley and C. Scott Massey.

We are managed and operated by the directors and officers of our general partner. All of our operational personnel are employees of Martin Resource Management. All of the officers of our general partner will spend a substantial amount of time managing the business and affairs of Martin Resource Management and its other affiliates. These officers may face a conflict regarding the allocation of their time between our business and the other business interests of Martin Resource Management. Our general partner intends to cause its officers to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs.

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Directors and Executive Officers of Martin Midstream GP LLC

The following table shows information for the directors and executive officers of our general partner. Directors and executive officers are elected for one-year terms.

Name	Age	Position with the General Partner
Ruben S. Martin	66	President, Chief Executive Officer and Director
Robert D. Bondurant	59	Executive Vice President and Chief Financial Officer and Director
Randall L. Tauscher	52	Executive Vice President and Chief Operating Officer
Chris H. Booth	48	Executive Vice President, Chief Legal Officer, General Counsel and Secretary
Scot A. Shoup	57	Senior Vice President of Operations
C. Scott Massey	65	Director
James M. Collingsworth	63	Director
Byron R. Kelley	70	Director
Sean P. Dolan	44	Director
Zachary S. Stanton	42	Director

Ruben S. Martin serves as President, Chief Executive Officer and a member of the board of directors of our general partner. Mr. Martin has served in such capacities since June 2002. Mr. Martin has served as President of Martin Resource Management since 1981 and has served in various capacities within the company since 1974.   Mr. Martin holds a Bachelor of Science degree in industrial management from the University of Arkansas.  Mr. Martin was selected to serve as a director on our general partner's board of directors due to his depth of knowledge of the Partnership, including its strategies and operations, his business judgment and his position within the Partnership.

Robert D. Bondurant serves as Executive Vice President and Chief Financial Officer and a member of the board of directors of our general partner. Mr. Bondurant has served in such capacities since June 2002. Mr. Bondurant joined Martin Resource Management in 1983 as Controller and subsequently was appointed Chief Financial Officer and a member of its board of directors in 1990. Mr. Bondurant served in the audit department at Peat Marwick, Mitchell and Co. from 1980 to 1983. Mr. Bondurant holds a Bachelor of Business Administration degree in accounting from Texas A&M University and is a Certified Public Accountant, licensed in the state of Texas.

Randall L. Tauscher serves as Executive Vice President and Chief Operating Officer of our general partner. Mr. Tauscher has served in this capacity since May 2011.  From September 2007 through May 2011, Mr. Tauscher served as Executive Vice President.  Prior to joining Martin, Mr. Tauscher was employed by Koch Industries for over 18 years, most recently as Senior Vice President of the Koch Carbon Division.  Mr. Tauscher earned a Bachelor of Business Administration degree from Kansas State University.

Chris H. Booth serves as Executive Vice President, Chief Legal Officer, General Counsel and Secretary of our general partner.  Mr. Booth has served as an officer of our general partner since February 2006.  Mr. Booth joined Martin Resource Management in October 2005.  Prior to joining Martin Resource Management, Mr. Booth was an attorney with the law firm of Mehaffy Weber located in Beaumont, Texas.  Mr. Booth holds a Doctor of Jurisprudence degree and a Masters of Business Administration degree with a concentration in finance from the University of Houston.  Additionally, Mr. Booth holds a Bachelor of Science degree in business management from LeTourneau University.  Mr. Booth is an attorney licensed to practice in the State of Texas.

Scot A. Shoup serves as Senior Vice President of Operations for our general partner. Mr. Shoup joined Martin in May 2011. Prior to joining Martin, Mr. Shoup was employed by Exline, Inc. as Executive Vice President from 2005 to 2011 and was employed by Koch Industries in various capacities for 18 years. Mr. Shoup holds a bachelor of science degree in Civil Engineering from the University of Kansas.

C. Scott Massey serves as a member of the board of directors of our general partner. Mr. Massey has served as a Director since June 2002. Mr. Massey has been self employed as a Certified Public Accountant since 1998. From 1977 to 1998, Mr. Massey worked for KPMG Peat Marwick, LLP in various positions, including, most recently, as a Partner in the firm's Tax Practice - Energy, Real Estate, Timber from 1986 to 1998. Mr. Massey received a Bachelor of Business Administration degree from the University of Texas at Austin and a Doctor of Jurisprudence degree from the University of Houston. Mr. Massey is a Certified Public Accountant, licensed in the States of Louisiana and Texas.  Mr. Massey was selected

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to serve as a director on our general partner's board of directors due to his extensive background in public accounting and taxation.  Mr. Massey qualifies as an "audit committee financial expert" under the SEC guidelines.

James M. Collingsworth serves as a member of the board of directors of our general partner. Mr. Collingsworth has spent 41 years in all facets of the midstream and petrochemical industry. In 2013, Mr. Collingsworth retired from Enterprise Products Company as a Sr. Vice President of Regulated NGL Pipelines & Natural Gas Storage. Mr. Collingsworth currently serves on the board of directors of NGL Energy Partners LP, and has served on the board of directors of Texaco Canada, Dixie Pipeline Company, Seminole Pipeline Company and the Petrochemical Feedstock Association of America. Mr. Collingsworth has served as a Director since October 2014. Mr. Collingsworth received a bachelor’s degree in Finance and Marketing from Northeastern State University. Mr. Collingsworth was selected to serve as a director on our general partner's board of directors due to his extensive corporate business experience.

Byron R. Kelley serves as a member of the board of directors of our general partner and also served as an Advisory Director from April 2011 to August 2012. On December 31, 2013, Mr. Kelley retired as CEO, President and a member of the board of directors of CVR Partners, LP, a chemical company engaged in the production of nitrogen based fertilizers and served in this position from June 2011 through December 2013. Prior to joining CVR Partners in June of 2011 he served as President, Chief Executive Officer and a member of the board of directors of Regency GP, LLC from April 2008 to November 2010. From 2004 through March of 2008, Mr. Kelley served as Senior Vice President and Group President of Pipeline and Field Services at CenterPoint Energy. Preceding his work at CenterPoint, Mr. Kelley served as Executive Vice President of Development, Operations and Engineering, and as President of El Paso Energy International. Mr. Kelley is a past member and Chairman of the board of directors of the Interstate National Gas Association and previously served as one of the association's representatives on the United States Natural Gas Council of America. Mr. Kelley received a Bachelor of Science degree in civil engineering from Auburn University. Mr. Kelley was selected to serve as a director on our general partner's board of directors due to his extensive corporate business experience.

Sean P. Dolan serves as a member of the board of directors of our general partner. Mr. Dolan has served as a Director since 2013. Mr. Dolan is a Managing Director of Alinda Capital Partners, which he joined in 2009. Prior to joining Alinda, Mr. Dolan spent over 12 years with Citigroup Global Markets in investment banking primarily focused in the energy sector. Mr. Dolan received a bachelor's degree from Georgetown University. Mr. Dolan was selected to serve as a director on our general partner's board of directors due to his affiliation with Alinda, his knowledge of the energy industry and his financial and business expertise.

Zachary S. Stanton serves as a member of the board of directors of our general partner.  Mr. Stanton was appointed to the board of directors on February 24, 2016.  Mr. Stanton is a Director of Alinda Capital Partners, which he joined in 2011.  Prior to joining Alinda, he was a Director at Zolfo Cooper, LLC, a consulting firm based in New York.  Mr. Stanton has over 15 years of experience focused on the corporate development and operations of energy and transportation infrastructure businesses as well as diversified industrial companies. Mr. Stanton received a bachelor's degree from Wesleyan University.  Mr. Stanton was selected to serve as a director on our general partner's board of directors due to his affiliation with Alinda, his knowledge of the energy industry, and his financial and business expertise.

Independence of Directors

Messrs. Massey, Collingsworth, and Kelley qualify as "independent" in accordance with the published listing requirements of NASDAQ and applicable securities laws.  The NASDAQ independence definition includes a series of objective tests, such as that the director is not an employee of us and has not engaged in various types of business dealings with us.  In addition, as further required by the NASDAQ rules, the board of directors has made a subjective determination as to each independent director that no relationships exist which, in the opinion of the board, would interfere with the exercise of independent judgment in carrying out the responsibilities of a director. In making these determinations, the directors reviewed and discussed information provided by the directors and us with regard to each director's business and personal activities as they may relate to us and our management.

Board Meetings and Committees

                From January 1, 2017 to December 31, 2017, the board of directors of our general partner held 11 meetings.  All directors then in office attended each of these meetings, either in person, by teleconference or by videoconference with the exception of:  James M. Collingsworth, who was not in attendance at the meeting of the board of directors on the date of September 3, 2017.  Additionally, the board of directors undertook action three times during 2017 without a meeting by acting through written unanimous consent.  We have standing conflicts, audit, compensation and nominating committees of the board of directors of our general partner.  The board of directors of our general partner appoints the members of the Audit,

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Compensation, Nominating and Conflicts Committees.  Each member of the Audit Committee is an independent director in accordance with NASDAQ and applicable securities laws.  Each of the board committees has a written charter approved by the board.  Copies of each charter are posted on our website at ww.martinmidstream.com under the "Corporate Governance" section.  The current members of the committees, the number of meetings held by each committee from January 1, 2017 to December 31, 2017, and a brief description of the functions performed by each committee are set forth below:

                Conflicts Committee (9 meetings).  The members of the Conflicts Committee are: Messrs. Kelley (chairman), Massey and Collingsworth.  All of the members of the Conflicts Committee attended all meetings of the committee for the period noted above.  The primary responsibility of the Conflicts Committee is to review matters that the directors believe may involve conflicts of interest.  The Conflicts Committee determines if the resolution of the conflict of interest is fair and reasonable to us.  The members of the Conflicts Committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates and must meet the independence standards to serve on an audit committee of a board of directors established by NASDAQ.  Any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders.

                Audit Committee (5 meetings).  The members of the Audit Committee are Messrs. Massey (chairman), Kelley and Collingsworth.  All of the members attended all meetings of the Audit Committee for the period noted.  The primary responsibilities of the Audit Committee are to assist the board of directors in its general oversight of our financial reporting, internal controls and audit functions, and it is directly responsible for the appointment, retention, compensation and oversight of the work of our independent auditors.  The members of the Audit Committee of the board of directors of our general partner each qualify as "independent" under standards established by the SEC for members of audit committees, and the Audit Committee includes at least one member who is determined by the board of directors to meet the qualifications of an "audit committee financial expert" in accordance with SEC rules, including that the person meets the relevant definition of an "independent" director.  C. Scott Massey is the independent director who has been determined to be an audit committee financial expert.  Unitholders should understand that this designation is a disclosure requirement of the SEC related to Mr. Massey's experience and understanding with respect to certain accounting and auditing matters.  The designation does not impose on Mr. Massey any duties, obligations or liability that are greater than are generally imposed on him as a member of the Audit Committee and board of directors, and his designation as an audit committee financial expert pursuant to this SEC requirement does not affect the duties, obligations or liability of any other member of the Audit Committee or board of directors.

                Compensation Committee (3 meetings).  The members of the Compensation Committee are Messrs. Collingsworth (chairman), Massey and Kelley.  All members attended the meeting of the Compensation Committee for the period noted above.  The primary responsibility of the Compensation Committee is to oversee compensation decisions for the outside directors of our general partner and executive officers of our general partner (in the event they are to be paid by our general partner) as well as our long-term incentive plan.

                Nominating Committee (2 meetings).  The members of the Nominating Committee are Messrs. Collingsworth (chairman), Massey, and Kelley.  All of the members attended the meeting of the Nominating Committee for the period noted above.  The primary responsibility of the nominating committee is to select and recommend nominees for election to the board of directors of our general partner.

Code of Ethics and Business Conduct

Our general partner has adopted a Code of Ethics and Business Conduct applicable to all of our general partner's employees (including any employees of Martin Resource Management who undertake actions with respect to us or on our behalf), including all officers, and including our general partner's independent directors, who are not employees of our general partner, with regard to their activities relating to us.  The Code of Ethics and Business Conduct incorporate guidelines designed to deter wrongdoing and to promote honest and ethical conduct and compliance with applicable laws and regulations.  They also incorporate our expectations of our general partner's employees (including any employees of Martin Resource Management who undertake actions with respect to us or on our behalf) that enable us to provide accurate and timely disclosure in our filings with the Securities and Exchange Commission and other public communications.  The Code of Ethics and Business Conduct is publicly available on our website under the "Corporate Governance" section (at www.martinmidstream.com).  This website address is intended to be an inactive, textual reference only, and none of the material on this website is part of this report.  If any substantive amendments are made to the Code of Ethics and Business Conduct or if we or our general partner grant any waiver, including any implicit waiver, from a provision of the code to any of our general partner's executive officers and directors, we will disclose the nature of such amendment or waiver on that website or in a report on Form 8-K.

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Section 16(a) Beneficial Ownership Reporting Compliance

Our general partner's directors and officers and beneficial owners of more than 10% of a registered class of our equity securities are required to file reports of ownership and reports of changes in ownership with the SEC and NASDAQ.  Directors, officers and beneficial owners of more than 10% of our equity securities are also required to furnish us with copies of all such reports that are filed.  Based solely on our review of copies of such forms and amendments previously provided to us, we believe directors, officers and greater than 10% beneficial owners complied with all filing requirements during the year ended December 31, 2017.

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Item 11. Executive Compensation

Compensation Discussion and Analysis

Background

We are required to provide information regarding the compensation program in place as of December 31, 2017, for the CEO, CFO and the three other most highly-compensated executive officers of our general partner as reflected in the summary compensation table set forth below (the "Named Executive Officers").  This section should be read in conjunction with the detailed tables and narrative descriptions regarding compensation below.

We are a master limited partnership and have no employees.  We are managed by the executive officers of our general partner. These executive officers are employed by Martin Resource Management, a private corporation that has significant operations that are separate from ours. The executive officers of our general partner are also the executive officers of Martin Resource Management and devote significant time to the management of Martin Resource Management’s operations.  We reimburse Martin Resource Management for a portion of the indirect general and administrative expenses, including compensation expense relating to the service of these individuals that are allocated to us pursuant to the omnibus agreement between us and our general partner, as amended on October 1, 2012 ("Omnibus Agreement"). Under the Omnibus Agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses.   For the years ended December 31, 2017, 2016 and 2015 the conflicts committee of our general partner ("Conflicts Committee") approved reimbursement amounts of $16.4 million, $13.0 million and $13.7 million, respectively, reflecting our allocable share of such expenses. Please see "Item 13. Certain Relationships and Related Transactions, and Director Independence — Agreements — Omnibus Agreement" for a discussion of the Omnibus Agreement.

Compensation Objectives

As we do not directly compensate the executive officers of our general partner, we do not have any set compensation programs. The elements of Martin Resource Management’s compensation program discussed below, along with Martin Resource Management’s other rewards, are intended to provide a total rewards package designed to yield competitive total cash compensation, drive performance and reward contributions in support of the businesses of Martin Resource Management and other Martin Resource Management affiliates, including us, for which the Named Executive Officers perform services. Although we bear an allocated portion of Martin Resource Management’s costs of providing compensation and benefits to the Named Executive Officers, we do not have control over such costs and do not establish or direct the compensation policies or practices of Martin Resource Management.  During 2017, Martin Resource Management paid compensation based on the performance of Martin Resource Management but did not set any specific performance-based criteria and did not have any other specific performance-based objectives.

Elements of Compensation

Martin Resource Management’s executive officer compensation package includes a combination of annual cash, long-term incentive compensation and other compensation.  Elements of compensation which the Named Executive Officers may be eligible to receive from Martin Resource Management consist of the following: (1) annual base salary; (2) discretionary annual cash awards; (3) awards pursuant to the Martin Midstream Partners L.P. 2017 Restricted Unit Plan and Martin Resource Management employee benefit plans and (4) where appropriate, other compensation, including limited perquisites.

Annual Base Salary.  Base salary is intended to provide fixed compensation to the Named Executive Officers for their performance of core duties with respect to Martin Resource Management and its affiliates, including us, and to compensate for experience levels, scope of responsibility and future potential. Base salaries are not intended to compensate individuals for extraordinary performance or for above average company performance. The base salaries of the Named Executive Officers are reviewed on an annual basis, as well as at the time of promotion and other changes in responsibilities or market conditions.

Discretionary Annual Cash Awards.  In addition to the annual base salary, the Named Executive Officers may be eligible to receive discretionary annual cash awards that, if awarded, are paid in a lump sum in the quarter following the end of the fiscal year.  These cash awards are designed to provide the Named Executive Officers with competitive incentives to help drive performance and promote achievement of Martin Resource Management’s business objectives.  Named Executive Officers may also be eligible to receive a cash award based upon their services provided to us in the event that any such Named Executive Officer has devoted a significant amount of their time to working for us.  Any such award is determined in

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accordance with the same methodologies as the discretionary annual cash awards for Martin Resource Management, as described below.

Employee Benefit Plan Awards.  The Named Executive Officers may be eligible to receive awards pursuant to the Martin Midstream Partners L.P. 2017 Restricted Unit Plan and Martin Resource Management employee benefit plans.  These employee benefit plan awards are designed to reward the performance of the Named Executive Officers by providing annual incentive opportunities tied to the annual performance of Martin Resource Management.  In particular, these awards are provided to the Named Executive Officers in order to provide competitive incentives to these executives who can significantly impact performance and promote achievement of the business objectives of Martin Resource Management.

Other Compensation.   Martin Resource Management generally does not pay for perquisites for any of the Named Executive Officers, other than general recreational activities at certain Martin Resource Management’s properties located in Texas, including aircraft. No perquisites are paid for services rendered to us.  Martin Resource Management provides an executive life insurance policy and long term disability policy for the Named Executive Officers with the annual premiums being paid by Martin Resource Management.  Martin Resource Management does not provide any greater allocation toward employee health insurance premiums than is provided for all other employees covered on the health benefits plan.

Compensation Methodology

The compensation policies and philosophy of Martin Resource Management govern the types and amount of compensation granted to each of the Named Executive Officers. The board of directors and Conflicts Committee have responsibility for evaluating and determining the reasonableness of the total amount we are charged under the Omnibus Agreement for managerial, administrative and operational support, including compensation of the Named Executive Officers, provided by Martin Resource Management.

Our allocation for the costs incurred by Martin Resource Management in providing compensation and benefits to its employees who serve as the Named Executive Officers is governed by the Omnibus Agreement. In general, this allocation is based upon estimates of the relative amounts of time that these employees devote to the business and affairs of our general partner and to the business and affairs of Martin Resource Management. We bear substantially less than a majority of Martin Resource Management’s costs of providing compensation and benefits to the Named Executive Officers.

When setting compensation for the Named Executive Officers, the elements of compensation above are considered holistically to provide an appropriate combination of compensation. Annual base salaries for the Named Executive Officers are determined by Mr. Ruben Martin, Chief Executive Officer, Mr. Robert Bondurant, Chief Financial Officer, Mr. Randall Tauscher, Chief Operating Officer, and Mrs. Melanie Mathews, Vice President-Human Resources (collectively, the "Management Compensation Committee of Martin Resource Management") based on a periodic performance review of each Named Executive Officer. Except in the case of an exceptional amount of time devoted to us, discretionary annual cash awards are based on the performance of Martin Resource Management. Annual discretionary cash awards, if any, are calculated first by allocating a portion of Martin Resource Management’s earnings as determined by the Management Compensation Committee of Martin Resource Management for distribution to key employees of Martin Resource Management. Upon such allocation, the Management Compensation Committee of Martin Resource Management, with input from appropriate business leaders determines the allocation and distribution of the bonus pool among such employees, including the Named Executive Officers. All decisions of the Management Compensation Committee of Martin Resource Management concerning the compensation of the Named Executive Officers are reviewed and approved by the Compensation Committee of the Board of Directors of Martin Resource Management, which is made up of Mr. Cullen M. Godfrey, an independent director of Martin Resource Management and Mr. Ruben Martin. With respect to employee benefit plan awards pursuant to plans maintained by the Partnership, the Management Compensation Committee of Martin Resource Management makes a recommendation as to whether such awards should be awarded to any employees. Any such employee plan awards are then considered and must be approved by the Compensation Committee and then are distributed to the employees, including Named Executive Officers, accordingly. Further, Martin Resource Management, with the approval of the Compensation Committee of the Board of Directors of Martin Resource Management or the Compensation Committee regularly reviews market data and relevant compensation surveys when setting base compensation and, when appropriate, engages compensation consultants.  Because he serves on both the Management Compensation Committee of Martin Resource Management and on the Compensation Committee of the Board of Directors of Martin Resource Management, Mr. Martin, as Chief Executive Officer, has significant authority in setting base salaries, discretionary annual cash award allocations and amounts and employee benefit award distributions.

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Any awards granted under our long-term incentive plan, which to date have consisted of the grant of restricted common units to the independent directors and employees of our general partner, are approved by the Compensation Committee.

Determination of 2017 Compensation Amounts

During 2017, elements of all compensation paid to the Named Executive Officers by Martin Resource Management consisted of the following: (1) annual base salary; (2) discretionary annual cash awards; (3) awards pursuant to the Martin Midstream Partners L.P. 2017 Restricted Unit Plan and Martin Resource Management employee benefit plans; and (4) other compensation, including limited perquisites.  With respect to the Named Executive Officers, they were paid an allocated portion of their base salaries.

Annual Base Salary.  The portions of the annual base salaries paid by Martin Resource Management to the Named Executive Officers, which are allocable to us under our Omnibus Agreement with Martin Resource Management, are reflected in the summary compensation table below.  Based upon the agreement of our general partner with Martin Resource Management, we have reimbursed Martin Resource Management for approximately 55.5% of the aggregate annual base salaries paid to the Named Executive Officers by Martin Resource Management during 2017.  The foregoing agreement has been developed based on an assessment of the estimated percentage of the time spent by the Named Executive Officers managing our affairs, relative to the affairs of Martin Resource Management ranging from approximately 50% to 75%. Our Named Executive Officers are Mr. Ruben Martin, the President and Chief Executive Officer of our general partner, Mr. Robert Bondurant, an Executive Vice President and Chief Financial Officer of our general partner, Mr. Randall Tauscher, an Executive Vice President and Chief Operating Officer of our general partner, Mr. Chris Booth, the Executive Vice President, General Counsel and Secretary of our general partner, and Mr. Scot A. Shoup, Senior Vice President of Operations. Aggregate annual base salaries of the Named Executive Officers were not increased during 2016 or 2017.

Discretionary Annual Cash Awards.  Discretionary annual cash awards paid to the Named Executive Officers which are allocable to us are reflected in the summary compensation table below.

Martin Midstream Partners L.P. Long-Term Incentive Plan

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 our general partner’s board of directors. The purpose of the 2017 LTIP is designed to enhance our ability to attract, retain, reward and motivate the services of certain key employees, officers, and directors of the General Partner and Martin Resource Management.

Our general partner’s board of directors or the Compensation Committee, in their discretion, may terminate or amend the 2017 LTIP at any time with respect to any units for which a grant has not yet been made. Our general partner’s board of directors or the Compensation Committee also have the right to alter or amend the 2017 LTIP or any part of the plan from time to time, including increasing the number of units that may be reserved for issuance under the plan subject to any applicable unitholder approval. However, no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the participant. In addition, the restricted units will vest upon a change of control of us, our general partner or Martin Resource Management or if our general partner ceases to be an affiliate of Martin Resource Management.

Restricted Units.  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, 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, EBIT, 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.  The Compensation Committee believes this type of incentive award strengthens the tie between each grantee's pay and our financial performance. We intend the issuance of the common units

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upon vesting of the restricted units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive, and we will receive no remuneration for the units. Historically, PBRU's were not awarded under our preceding long-term incentive plan, which had a maximum amount of 241,667 restricted units that could be issued under the plan. Awards issued under the new plan will be materially larger than awards historically issued under the preceding plan. Unvested units granted under the 2017 LTIP may or may not participate in cash distributions depending on the terms of each individual award agreement.

If a grantee’s service to the Partnership terminates for any reason, the grantee’s restricted units will be automatically forfeited unless, and to the extent, the Compensation Committee provides otherwise. Common units to be delivered upon the vesting of restricted units may be common units acquired by our general partner in the open market, common units already owned by our general partner, common units acquired by our general partner directly from us or any affiliate of our general partner, newly issued common units under the LTIP, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units upon vesting of the restricted units, the total number of common units outstanding will increase.

On February 14, 2017, we issued 4,000 restricted common units to each of our three independent directors under our long-term incentive plan preceding the 2017 LTIP.  These restricted common units vest in equal installments of 1,000 units on January 24, 2018, 2019, 2020, and 2021.

Martin Resource Management Employee Benefit Plans

Martin Resource Management has employee benefit plans for its employees who perform services for us. The following summary of these plans is not complete but outlines the material provisions of these plans.

Martin Resource Management Purchase Plan for Units of Martin Midstream Partners L.P.  Martin Resource Management maintains a purchase plan for our units to provide employees of Martin Resource Management and its affiliates who perform services for us the opportunity to acquire an equity interest in us through the purchase of our common units. Each individual employed by Martin Resource Management or an affiliate of Martin Resource Management that provides services to us is eligible to participate in the purchase plan. Enrollment in the purchase plan by an eligible employee will constitute a grant by Martin Resource Management to the employee of the right to purchase common units under the purchase plan. The right to purchase common units granted by the Company under the purchase plan is for the term of a purchase period.

During each purchase period, each participating employee may elect to make contributions to his bookkeeping account each pay period in an amount not less than one percent of his compensation and not more than fifteen percent of his compensation. The rate of contribution shall be designated by the employee at the time of enrollment. On each purchase date (the last day of such purchase period), units will be purchased for each participating employee at the fair market value of such units. The fair market value of the Units to be purchased during such purchase period shall mean the closing sales price of a unit on the purchase date.

Martin Resource Management Employee Stock Ownership Plans.

MRMC Employee Stock Ownership Plan. Martin Resource Management maintains an employee stock ownership plan that covers employees who satisfy certain minimum age and service requirements ("ESOP"). Under the terms of the ESOP, Martin Resource Management has the discretion to make contributions in an amount determined by its board of directors. Those contributions are allocated under the terms of the ESOP and invested primarily in the common stock of Martin Resource Management. Participants in the ESOP become 100% vested upon completing six years of vesting service or upon their attainment of Normal Retirement Age (as defined in the plan document), permanent disability or death during employment. Any forfeitures of non-vested accounts may be used to pay administrative expenses and restore previous forfeitures of employees rehired before incurring five consecutive breaks-in-service. Any remaining forfeitures will be allocated to the accounts of employed participants. Participants are not permitted to make contributions including rollover contributions to the ESOP.

Martin Employee Stock Ownership Plan.  Martin Resource Management maintains an employee stock ownership plan that covers employees who satisfied certain minimum age and service requirements but no Employee shall become eligible to participate in the Plan on or after January 1, 2013. This plan is referred to as the "Martin Employee Stock Ownership Plan". Under the terms of the plan, Martin Resource Management has the discretion to make contributions in an amount determined by its board of directors. Those contributions are allocated under the terms of the Martin Employee Stock Ownership Plan and invested primarily in the common stock of Martin Resource Management. No contributions will be made to the Plan for any

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Plan Year commencing on or after January 1, 2013. The account balances of any participant who was employed by Martin Resource Management on December 31, 2012 shall be fully vested and non-forfeitable. This plan converted to an employee stock ownership plan on January 1, 2013.

Martin Resource Management 401(k) Profit Sharing Plan.  Martin Resource Management maintains a profit sharing plan that covers employees who satisfy certain minimum age and service requirements. This profit sharing plan is referred to as the "401(k) Plan." Eligible employees may elect to participate in the 401(k) Plan by electing pre-tax contributions up to 30% of their regular compensation and/or a portion of their discretionary bonuses. Matching contributions are made to the 401(k) Plan equal to 50% of the first 3% of eligible compensation.  Martin Resource Management may make annual discretionary profit sharing contributions in an amount at the plan year end as determined by the board of directors of Martin Resource Management. Participants in the 401(k) Plan become 100% vested in matching contributions immediately and become vested in the discretionary contributions made for them upon completing five years of vesting service or upon their attainment of age 65, permanent disability or death during employment.

Martin Resource Management Non-Qualified Option Plan.  In September 1999, Martin Resource Management adopted a stock option plan designed to retain and attract qualified management personnel, directors and consultants.  Under the plan, Martin Resource Management is authorized to issue to qualifying parties from time to time options to purchase up to 2,000 shares of its common stock with terms not to exceed ten years from the date of grant and at exercise prices generally not less than fair market value on the date of grant.  In November 2007, Martin Resource Management adopted an additional stock option plan designed to retain and attract qualified management personnel, directors and consultants. In December 2013, all outstanding options were exercised or redeemed in lieu of redemption. There are no outstanding options under this plan as of December 31, 2017.

Other Compensation

Martin Resource Management generally does not pay for perquisites for any of our named executive officers other than general recreational activities at certain Martin Resource Management’s properties located in Texas and use of Martin Resource Management vehicles, including aircraft.

SUMMARY COMPENSATION TABLE

The following table sets forth the compensation expense that was allocated to us for the services of the named executive officers for the years ended December 31, 2017, 2016 and 2015.

Name and Principal Position	Year	Salary		Bonus		Stock Awards (1)		Total Compensation
Ruben S. Martin, President and Chief Executive Officer	2017	$	412,500	$	—	$	—	$	412,500
	2016	$	412,500	$	—	$	—	$	412,500
	2015	$	412,500	$	—	$	356,250	$	768,750
Robert D. Bondurant, Executive Vice President and Chief Financial Officer	2017	$	230,000	$	—	$	—	$	230,000
	2016	$	230,000	$	—	$	—	$	230,000
	2015	$	230,000	$	—	$	85,500	$	315,500
Randall L. Tauscher, Executive Vice President and Chief Operating Officer	2017	$	276,000	$	—	$	—	$	276,000
	2016	$	308,200	$	—	$	—	$	308,200
	2015	$	230,000	$	—	$	85,500	$	315,500
Chris H. Booth, Executive Vice President, General Counsel and Secretary	2017	$	183,600	$	—	$	—	$	183,600
	2016	$	165,240	$	—	$	—	$	165,240
	2015	$	146,880	$	—	$	71,250	$	218,130
Scot A. Shoup, Senior Vice President of Operations	2017	$	270,000	$	—	$	—	$	270,000
	2016	$	180,000	$	—	$	—	$	180,000
	2015	$	180,000	$	—	$	57,000	$	237,000

(1) The amounts shown represent the grant date fair value of awards computed in accordance with FASB ASC 718, however, such awards are subject to vesting requirements which have not been met as it relates to the 2015 stock award. See Note 17 included in Item 8 herein for the assumptions made in our valuation of such awards.

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Director Compensation

As a partnership, we are managed by our general partner.  The board of directors of our general partner performs for us the functions of a board of directors of a business corporation. Directors of our general partner are entitled to receive total quarterly retainer fees of $16,250 each which are paid by the general partner.  Martin Resource Management employees who are a member of the board of directors of our general partner do not receive any additional compensation for serving in such capacity.  Officers of our general partner who also serve as directors will not receive additional compensation. All directors of our general partner are entitled to reimbursement for their reasonable out-of-pocket expenses in connection with their travel to and from, and attendance at, meetings of the board of directors or committees thereof.  Each director will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law.

The following table sets forth the compensation of our board members for the period from January 1, 2017 through December 31, 2017.

Name	Fees Earned Paid in Cash		Stock Awards		Total
Ruben S. Martin	$	—	$	—	$	—
Robert D. Bondurant	$	—	$	—	$	—
C. Scott Massey (1)	$	65,000	$	75,800	$	140,800
Byron R. Kelley (1)	$	65,000	$	75,800	$	140,800
James M. Collingsworth (1)	$	65,000	$	75,800	$	140,800
Sean P. Dolan	$	—	$	—	$	—
Zachary S. Stanton	$	—	$	—	$	—

(1) On February 14, 2017, the Partnership issued 4,000 restricted common units to each of three independent directors, C. Scott Massey, Byron R. Kelley, and James M. Collingsworth under our LTIP.  These restricted common units vest in equal installments of 1,000 units on January 24, 2018, 2019, 2020 and 2021, respectively.  In calculating the fair value of the award, we multiplied the closing price of our common units on the NASDAQ on the date of grant by the number of restricted common units granted to each director.

COMPENSATION REPORT OF THE COMPENSATION COMMITTEE

The Compensation Committee of the general partner of Martin Midstream Partners L.P. has reviewed and discussed the Compensation Discussion and Analysis section of this report with management of the general partner of Martin Midstream Partners L.P. and, based on that review and discussions, has recommended that the Compensation Discussion and Analysis be included in this report.

Members of the Compensation Committee:

/s/ James M. Collingsworth

James M. Collingsworth, Committee Chair

/s/ Byron R. Kelley

Byron R. Kelley

/s/ C. Scott Massey

C. Scott Massey

Compensation Committee Interlocks and Insider Participation

Other than these independent directors, no other officer or employee of our general partner or its subsidiaries is a member of the Compensation Committee.  Employees of Martin Resource Management, through our general partner, are the individuals who work on our matters.

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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following table sets forth the beneficial ownership of our units as of February 16, 2018 held by beneficial owners of 5% or more of the units outstanding, by directors of our general partner, by each executive officer and by all directors and executive officers of our general partner as a group.

Name of Beneficial Owner(1)	Common Units Beneficially  Owned	Percentage of  Common Units  Beneficially Owned (3)
MRMC ESOP Trust (4)	6,264,532	16.3%
Martin Resource Management Corporation (5)	6,264,532	16.3%
Martin Resource, LLC (5)	4,203,823	10.9%
Martin Product Sales LLC (5)	1,171,265	3.0%
Cross Oil Refining & Marketing Inc. (6)	889,444	2.3%
OppenheimerFunds, Inc. (2)	6,437,052	16.8%
Ruben S. Martin (6)	6,409,251	16.7%
Robert D. Bondurant	38,997	—%
Randall L. Tauscher	27,070	—%
Chris H. Booth	11,302	—%
Scot A. Shoup	5,061	—%
Sean Dolan	—	—%
Zachary S. Stanton	—	—%
C. Scott Massey (7)	31,000	—%
Byron R. Kelley	16,600	—%
James M. Collingsworth (8)	14,000	—%
All directors and executive officers as a group (10 persons) (9)	6,553,281	17.1%

(1) The address for Martin Resource Management Corporation and all of the individuals listed in this table, unless otherwise indicated, is c/o Martin Midstream Partners L.P., 4200 Stone Road, Kilgore, Texas  75662.

(2) The address for OppenheimerFunds, Inc. is 225 Liberty Street, New York, NY 10281.

(3) The percent of class shown is less than one percent unless otherwise noted.

(4) By virtue of its ownership of 86.58% of the outstanding common stock of Martin Resource Management Corporation ("Martin Resource Management"), the MRMC ESOP Trust (the "MRMC ESOP") is the controlling shareholder of Martin Resource Management, and may be deemed to beneficially own the 6,264,532 MMLP Common Units held by Martin Resource LLC, Cross Oil Refining & Marketing Inc., and Martin Product Sales LLC. Wilmington Trust Retirement and Institutional Services Company serves as trustee of the MRMC ESOP but all of its voting and investment decisions are directed by the board of directors of Martin Resource Management. The MRMC ESOP expressly disclaims beneficial ownership of the MMLP Common Units as voting and investment decisions are directed by the board of directors of Martin Resource Management.

(5) Martin Resource Management is the owner of Martin Resource, LLC, Martin Product Sales LLC, and Cross Oil Refining & Marketing Inc., and as such may be deemed to beneficially own the common units held by Martin Resource LLC, Cross Oil Refining & Marketing Inc, and Martin Product Sales LLC.  The 4,203,823 common units beneficially owned by Martin Resource Management through its ownership of Martin Resource, LLC have been pledged as security to a third party to secure payment for a loan made by such third party.   The 1,171,265 common units beneficially owned by Martin Resource Management through its ownership of Martin Product Sales LLC have been pledged as security to a third party to secure payment for a loan made by such third party. The 889,444 common units beneficially owned by Martin Resource Management through its ownership of Cross Oil Refining & Marketing Inc. have been pledged as security to a third party to secure payment for a loan made by such third party.

(6) Includes 144,719 common units owned directly by Mr. Martin, 130,247 of which are pledged to third parties to secure payment for loans. By virtue of serving as the Chairman of the Board and President of Martin Resource

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Management, Ruben S. Martin may exercise control over the voting and disposition of the securities owned by Martin Resource Management, and therefore, may be deemed the beneficial owner of the common units owned by Martin Resource Management, which include 6,264,532 common units beneficially owned through its ownership of Martin Resource LLC, Cross Oil Refining & Marketing Inc. and Martin Product Sales LLC.

(7) Mr. Massey may be deemed to be the beneficial owner of 1,500 common units held by his wife.

(8) Mr. Collingsworth may be deemed to be the beneficial owner of 775 common units held by his wife.

(9) The total for all directors and executive officers as a group includes the common units directly owned by such directors and executive officers as well as the common units beneficially owned by Martin Resource Management as Ruben S. Martin may be deemed to be the beneficial owner thereof.

Martin Resource Management owns a 51% voting interest in the holding company that is the sole member of our general partner and, together with our general partner, owns approximately 16.3% of our outstanding common limited partner units as of December 31, 2017.  The table below sets forth information as of December 31, 2017 concerning (i) each person owning beneficially in excess of 5% of the voting common stock of Martin Resource Management, and (ii) the beneficial common stock ownership of (a) each director of Martin Resource Management, (b) each executive officer of Martin Resource Management, and (c) all such executive officers and directors of Martin Resource Management as a group.  Except as indicated, each individual has sole voting and investment power over all shares listed opposite his or her name.

	Beneficial Ownership of Voting Common Stock
Name of Beneficial Owner(1)	Number of Shares	Percent of Outstanding Voting Stock
MRMC ESOP Trust (2)	176,215.51	86.58	%
Martin ESOP Trust (3)	27,325.11	13.42	%
Robert D. Bondurant (3)	27,325.11	13.42	%
Randall Tauscher (3)	27,325.11	13.42	%

(1) The business address of each shareholder, director and executive officer of Martin Resource Management Corporation is c/o Martin Resource Management Corporation, 4200 Stone Road, Kilgore, Texas 75662.

(2) The MRMC ESOP owns 176,215.51 shares of common stock of Martin Resource Management. Wilmington Trust Retirement and Institutional Services Company serves as trustee of the MRMC ESOP but all of its voting and investment decisions related to the unallocated shares of common stock are directed by the board of directors of Martin Resource Management. Of the common stock held by the MRMC ESOP, 99,407.50 shares of common stock are allocated to participant accounts, and 76,808.01 shares of common stock are unallocated.

(3) Robert D. Bondurant and Randall Tauscher (the "Co-Trustees") are co-trustees of the Martin Employee Stock Ownership Trust which converted from a profit sharing plan known as the Martin Employees' Stock Profit Sharing Plan on January 1, 2014. The Co-Trustees exercise shared control over the voting and disposition of the securities owned by this trust.  As a result, the Co-Trustees may be deemed to be the beneficial owner of the securities held by such trust; thus, the number of shares of common stock reported herein as beneficially owned by the Co-Trustees includes the 27,325 shares owned by such trust.  The Co-Trustees disclaim beneficial ownership of these 27,325 shares.

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The following table sets forth information regarding securities authorized for issuance under our equity compensation plans as of December 31, 2017:

Equity Compensation Plan Information

	Number of  securities to be  issued upon exercise of outstanding  options, Warrants and rights	Weighted-average  exercise price of  outstanding options, warrants and rights		Number of securities  remaining available for  future issuance under equity compensation plans (excluding  securities reflected in  column (a))
Plan Category	(a)	(b)		(c)
Equity compensation plans approved by security holders	N/A	N/A		3,000,000
Total	—	$	—	3,000,000

(1) Our general partner has adopted and maintains the Martin Midstream Partners L.P. Long-Term Incentive Plan.  For a description of the material features of this plan, please see "Item 11. Executive Compensation – Employee Benefit Plans – Martin Midstream Partners L.P. Long-Term Incentive Plan".

In February 2017, we issued 4,000 restricted common units to independent directors under our long-term incentive plan.  These restricted common units vest in equal installments of 1,000 units on January 24, 2018, 2019, 2020 and 2021.

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Item 13. Certain Relationships and Related Transactions, and Director Independence

Martin Resource Management owns 6,264,532 of our common limited partnership units representing approximately 16.3% of our outstanding common limited partnership units as of February 16, 2018.  Martin Resource Management controls Martin Midstream GP LLC, our general partner, by virtue of its 51% voting interest in MMGP Holdings, LLC, the sole member of our general partner. Our general partner owns a 2.0% general partner interest in us and all of our incentive distribution rights.  Our general partner’s ability to manage and operate us and Martin Resource Management’s ownership of approximately 16.3% of our outstanding common limited partnership units effectively gives Martin Resource Management the ability to veto some of our actions and to control our management.

Distributions and Payments to the General Partner and its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our formation, ongoing operation and liquidation.  These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

Formation Stage
The consideration received by our general partner and Martin Resource Management for the transfer of assets to us	Ÿ    4,253,362 subordinated units  (All of the original 4,253,362 subordinated units issued to Martin Resource Management have been converted into common units on a one-for-one basis since the formation of the Partnership.  850,672 subordinated units were converted on each of November 14, 2005, 2006, 2007 and 2008, respectively, and 850,674 subordinated units were converted on November 14, 2009)
	Ÿ    2.0% general partner interest; and Ÿ    the incentive distribution rights.
Operational Stage
Distributions of available cash to our general partner	We will generally make cash distributions 98% to our unitholders, including Martin Resource Management as holder of all of the subordinated units, and 2% to our general partner.  In addition, if distributions exceed the minimum quarterly distribution and other higher target levels, our general partner will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target level as a result of its incentive distribution rights.
	Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner would receive an annual aggregate distribution of approximately $1.6 million on its 2.0% general partner interest.
Payments to our general partner and its affiliates	Martin Resource Management is entitled to reimbursement for all direct expenses it or our general partner incurs on our behalf.  The direct expenses include the salaries and benefit costs employees of Martin Resource Management who provide services to us.  Our general partner has sole discretion in determining the amount of these expenses.  In addition to the direct expenses, Martin Resource Management is entitled to reimbursement for a portion of indirect general and administrative and corporate overhead expenses.  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 ("Conflicts Committee") will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.  Please read "Agreements — Omnibus Agreement" below.
Withdrawal or removal of our general partner	If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
Liquidation Stage
Liquidation	Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.

Agreements

Omnibus Agreement

We and our general partner are parties to an omnibus agreement with Martin Resource Management (the "Omnibus Agreement") that governs, among other things, potential competition and indemnification obligations among the parties to the

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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. 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.

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Services.  Under the Omnibus Agreement, Martin Resource Management provides us with corporate staff and support services that are substantially identical in nature and quality to the services previously provided by Martin Resource Management in connection with its management and operation of our assets during the one-year period prior to the date of the agreement. 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. 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, Martin Resource Management is entitled to reimbursement for a portion of indirect general and administrative and corporate overhead expenses.  

Under the Omnibus Agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses.   For the years ended December 31, 2017, 2016 and 2015, the Conflicts Committee approved and we reimbursed Martin Resource Management of $16.4 million, $13.0 million and $13.7 million, respectively, reflecting 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.

These indirect expenses cover all of the centralized corporate functions Martin Resource Management provides for us, such as accounting, treasury, clerical 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 retained businesses. The provisions of the Omnibus Agreement regarding Martin Resource Management’s services will terminate if Martin Resource Management ceases to control our general partner.

Related Party Transactions. The Omnibus Agreement prohibits us 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 us and Martin Resource Management that requires aggregate annual payments in excess of then-applicable limitation on the reimbursable amount of indirect general and administrative expenses. Please read " Services" above.

License Provisions. Under the Omnibus Agreement, Martin Resource Management has granted us 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 us to provide refining services to Martin Resource Management. The Omnibus Agreement was amended further on October 1, 2012, to permit us 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 we will reimburse Martin Resource Management for general and administrative services performed on our behalf, will terminate if we are no longer an affiliate of Martin Resource Management.

Motor Carrier Agreement

We are 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 Resource Management operates its land transportation operations.  Under the agreement, Martin Transport, Inc. agrees to ship our NGL shipments 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.  We have the right to terminate this agreement at anytime by providing 90 days prior notice. Under this agreement, Martin Transport, Inc. transports our NGL shipments as well as other liquid products. These rates are subject to any adjustment to which are mutually agreed or in accordance with a price index.  Additionally, during the term of the agreement, shipping charges are also subject to fuel surcharges determined on a weekly basis in accordance with the United States Department of Energy’s national diesel price list.

Indemnification.  Martin Transport, Inc. has indemnified us against all claims arising out of the negligence or willful misconduct of Martin Transport, Inc. and its officers, employees, agents, representatives and subcontractors. We indemnified Martin Transport against all claims arising out of the negligence or willful misconduct of us and our officers, employees, agents, representatives and subcontractors. In the event a claim is the result of the joint negligence or misconduct of Martin

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Transport and us, our indemnification obligations will be shared in proportion to each party’s allocable share of such joint negligence or misconduct.

Terminal Services Agreements

Diesel Fuel Terminal Services Agreement.  Effective January 1, 2016, we entered into a second amended and restated terminalling services agreement under which we provide terminal services to Martin Resource Management for marine fuel distribution.  At such time, the per gallon throughput fee we 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.  We are currently party to several terminal services agreements and from time to time we 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.

Marine Agreements

Marine Transportation Agreement. We are a party to a marine transportation agreement effective January 1, 2006, as amended, under which we provide 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 we charge Martin Resource Management are based on applicable market rates.

Marine Fuel.   We are a party to an agreement with Martin Resource Management dated November 1, 2002 under which Martin Resource Management provides us with marine fuel from its locations in the Gulf of Mexico at a fixed rate in excess of a price index.  Under this agreement, we agreed to purchase all of its marine fuel requirements that occur in the areas serviced by Martin Resource Management.

Other Agreements

 Cross Tolling Agreement. We are a party to an amended and restated tolling agreement with Cross dated October 28, 2014 under which we process 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, Martin Resource Management agreed to refine a minimum of 6,500 barrels per day of crude oil at the refinery at a fixed price per barrel.  Any additional barrels are refined at a modified price per barrel.  In addition, Martin Resource Management 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, every three years, the parties can negotiate an upward or downward adjustment in the fees subject to their mutual agreement.

Sulfuric Acid Sales Agency Agreement. We are 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 our sulfuric acid production plant at Plainview, Texas, that is not consumed by our 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, we sell all of our excess sulfuric acid to Saconix, who then markets and sells such acid to third-parties.  We share in the profit of such sales.

Other Miscellaneous Agreements. From time to time we enter into other miscellaneous agreements with Martin Resource Management for the provision of other services or the purchase of other goods.

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Other Related Party Transactions

Related Party Note Receivable

We had a $15.0 million 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, we notified Martin Resource Management that we 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. Interest income for the years ended December 31, 2017, 2016 and 2015 was $0.9 million, $2.3 million, and $2.3 million, respectively.

2017 Public Offerings    

In conjunction with a public offering, our general partner contributed $1.1 million in order to maintain its 2.0% general partner interest in us.    

Transfers of Assets Between Entities Under Common Control    

Acquisition of Terminalling Assets.    On February 22, 2017, we acquired 100% of the membership interests of MEH South Texas Terminals LLC (“MEH”), a subsidiary of Martin Resource Management, for a purchase price of $27.4 million (the “Hondo Acquisition”). At the date of acquisition, MEH was in the process of constructing an asphalt terminal facility in Hondo, Texas (the "Hondo Terminal”), which will serve the asphalt market in San Antonio, Texas and surrounding areas. The excess of the purchase price over the carrying value of the assets of $7.9 million was recorded as an adjustment to "Partners' capital."

Miscellaneous  

Certain of directors, officers and employees of our general partner and Martin Resource Management maintain margin accounts with broker-dealers with respect to our common units held by such persons.  Margin account transactions for such directors, officers and employees were conducted by such broker-dealers in the ordinary course of business.

For information regarding amounts of related party transactions that are included in the Partnership's Consolidated Statements of Operations, please see Footnote 13, "Related Party Transactions", in Part II, Item 8.

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 is involved in the approval process, it determines whether to refer the matter to the Conflicts Committee, as constituted under our limited partnership agreement. If a matter is referred to the Conflicts Committee, it obtains information regarding the proposed transaction from management and determines whether to engage independent legal counsel or an independent financial advisor to advise the members of the committee regarding the transaction. If the Conflicts Committee retains such counsel or financial advisor, it considers such advice and, in the case of a financial advisor, such advisor’s opinion as to whether the transaction is fair and reasonable to us and to our unitholders.

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Item 14. Principal Accounting Fees and Services

KPMG, LLP served as our independent auditors for the fiscal years ended December 31, 2017 and 2016.  The following fees were paid to KPMG, LLP for services rendered during our last two fiscal years:

	2017			2016
Audit fees	$	1,349,934	(1)	$	1,342,400	(1)
Audit related fees	—			—
Audit and audit related fees	1,349,934			1,342,400
Tax fees	123,167		(2)	105,070		(2)
All other fees	124,550		(3)	—
Total fees	$	1,597,651		$	1,447,470

(1) 2017 audit fees include fees for the annual integrated audit and fees related to services in connection with transactions. 2016 audit fees include fees for the annual integrated audit and fees related to services in connection with filing updated financial statements and in connection with transactions.

(2) Tax fees are for services related to the review of our partnership K-1's returns, and research and consultations on other tax related matters.

(3) All other fees are for accounting advisory services related to the adoption of ASC 606.

Under policies and procedures established by the Board of Directors and the Audit Committee, the Audit Committee is required to pre-approve all audit and non-audit services performed by our independent auditor to ensure that the provisions of such services do not impair the auditor’s independence.  All of the services described above that were provided by KPMG, LLP in years ended December 31, 2017 and December 31, 2016 were approved in advance by the Audit Committee.

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PART IV

Item 15. Exhibits, Financial Statement Schedules

(a)    Financial Statements, Schedules

(1) The following financial statements of Martin Midstream Partners L.P. are included in Part II, Item 8:

Reports of Independent Registered Public Accounting Firm

Consolidated Balance Sheets as of December 31, 2017 and 2016

Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015

Consolidated Statements of Changes in Capital for the years ended December 31, 2017, 2016 and 2015

Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015

Notes to the Consolidated Financial Statements

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(b)    Exhibits

INDEX TO EXHIBITS

Exhibit Number	Exhibit Name
3.1	Certificate of Limited Partnership of Martin Midstream Partners L.P. (the "Partnership"), dated June 21, 2002 (filed as Exhibit 3.1 to the Partnership's Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.2	Second Amended and Restated Agreement of Limited Partnership of the Partnership, dated November 25, 2009 (filed as Exhibit 10.1 to the Partnership's Amendment to Current Report on Form 8-K/A (SEC File No. 000-50056), filed January 19, 2010, and incorporated herein by reference).
3.3	Amendment No. 2 to the Second Amended and Restated Agreement of Limited Partnership of the Partnership dated January 31, 2011 (filed as Exhibit 3.1 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed February 1, 2011, and incorporated herein by reference).
3.4	Amendment No. 3 to the Second Amended and Restated Agreement of Limited Partnership of the Partnership dated October 2, 2012 (filed as Exhibit 10.5 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed October 9, 2012, and incorporated herein by reference).
3.5	Certificate of Limited Partnership of Martin Operating Partnership L.P. (the "Operating Partnership"), dated June 21, 2002 (filed as Exhibit 3.3 to the Partnership's Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.6	Amended and Restated Agreement of Limited Partnership of the Operating Partnership, dated November 6, 2002 (filed as Exhibit 3.2 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed November 19, 2002, and incorporated herein by reference).
3.7	Certificate of Formation of Martin Midstream GP LLC (the "General Partner"), dated June 21, 2002 (filed as Exhibit 3.5 to the Partnership's Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.8	Amended and Restated Limited Liability Company Agreement of the General Partner, dated August 30, 2013 (filed as Exhibit 3.1 to the Partnership's Current Report on Form 8-K (Reg. No. 000-50056), filed September 3, 2013, and incorporated herein by reference).
3.9	Certificate of Formation of Martin Operating GP LLC (the "Operating General Partner"), dated June 21, 2002 (filed as Exhibit 3.7 to the Partnership's Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.10	Limited Liability Company Agreement of the Operating General Partner, dated June 21, 2002 (filed as Exhibit 3.8 to the Partnership's Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.11	Certificate of Formation of Arcadia Gas Storage, LLC, dated June 26, 2006 (filed as Exhibit 3.11 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.12	Company Agreement of Arcadia Gas Storage, LLC, dated December 27, 2006 (filed as Exhibit 3.12 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.13	Amendment to the Company Agreement of Arcadia Gas Storage, LLC, dated September 5, 2014 (filed as Exhibit 3.13 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.14	Certificate of Formation of Cadeville Gas Storage LLC, dated May 23, 2008 (filed as Exhibit 3.14 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.15	Limited Liability Company Agreement of Cadeville Gas Storage LLC, dated May 23, 2008 (filed as Exhibit 3.15 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.16	First Amendment to the Limited Liability Company Agreement of Cadeville Gas Storage LLC, dated April 16, 2012 (filed as Exhibit 3.16 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.17	Second Amendment to the Limited Liability Company Agreement of Cadeville Gas Storage LLC, dated September 5, 2014 (filed as Exhibit 3.17 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.18	Certificate of Formation of Monroe Gas Storage Company, LLC, dated June 14, 2006 (filed as Exhibit 3.18 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).

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3.19	Amended and Restated Limited Liability Company Agreement of Monroe Gas Storage Company, LLC, dated May 31, 2011 (filed as Exhibit 3.19 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.20	First Amendment to the Amended and Restated Limited Liability Company Agreement of Monroe Gas Storage Company, LLC, dated September 5, 2014 (filed as Exhibit 3.20 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.21	Certificate of Formation of Perryville Gas Storage LLC, dated May 23, 2008.(filed as Exhibit 3.21 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.22	Limited Liability Company Agreement of Perryville Gas Storage LLC, dated June 16, 2008 (filed as Exhibit 3.22 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.23	First Amendment to the Limited Liability Company Agreement of Perryville Gas Storage LLC, dated April 14, 2010 (filed as Exhibit 3.23 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.24	Second Amendment to the Limited Liability Company Agreement of Perryville Gas Storage LLC, dated September 5, 2014 (filed as Exhibit 3.24 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.25	Certificate of Formation of Cardinal Gas Storage Partners LLC, dated April 2, 2008 (filed as Exhibit 3.25 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.26	Third Amended and Restated Limited Liability Company Agreement of Cardinal Gas Storage Partners LLC (F/K/A Redbird Gas Storage LLC) dated October 27, 2014 (filed as Exhibit 3.26 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.27	Certificate of Formation of Redbird Gas Storage LLC, dated May 24, 2011 (filed as Exhibit 3.27 to the Partnership's Annual Report on Form 10-K (SEC File No. 000-50056), filed March 2, 2015, and incorporation herein by reference).
3.28	Second Amended and Restated LLC Agreement of Redbird Gas Storage LLC, dated as of October 2, 2012. (filed as Exhibit 10.6 to the Partnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed November 5, 2012, and incorporated herein by reference).
3.29	Certificate of Merger of Cardinal Gas Storage Partners LLC with and into Redbird Gas Storage LLC, dated October 27, 2014 (filed as Exhibit 3.27 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
4.1	Specimen Unit Certificate for Common Units (contained in Exhibit 3.2).
4.2	Specimen Unit Certificate for Subordinated Units (filed as Exhibit 4.2 to Amendment No. 4 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-91706), filed October 25, 2002, and incorporated herein by reference).
4.3	Indenture (including form of 7.250% Senior Notes due 2021), dated February 11, 2013, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed February 12, 2013, and incorporated herein by reference).
4.4	Second Supplemental Indenture, to the Indenture dated February 11, 2013 dated September 30, 2014, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Bank National Association, as trustee (filed as Exhibit 4.4 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014 and incorporated herein by reference).
4.5	Third Supplemental Indenture, to the Indenture dated February 11, 2013 dated October 27, 2014, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Bank National Association, as trustee (filed as Exhibit 4.5 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014 and incorporated herein by reference).
10.1	Third Amended and Restated Credit Agreement, dated March 28, 2013, among the Partnership, the Operating Partnership, Royal Bank of Canada and the other Lenders set forth therein (filed as Exhibit 10.1 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed April 3, 2013 and incorporated herein by reference).
10.2	First Amendment to Third Amended and Restated Credit Agreement, dated as of July 12, 2013, among the Partnership, the Operating Partnership, Royal Bank of Canada and the other Lenders as set forth therein (filed as Exhibit 10.2 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed May 5, 2014 and incorporated herein by reference).

124

10.3	Second Amendment to Third Amended and Restated Credit Agreement, dated as of May 5, 2014, among the Partnership, the Operating Partnership, Royal Bank of Canada and the other Lenders as set forth therein (filed as Exhibit 10.2 to the Partnership's Current Report on Form 8-K/A (SEC File No. 000-50056), filed May 6, 2014 and incorporated herein by reference)
10.4	Third Amendment to Third Amended and Restated Credit Agreement, dated June 27, 2014, among the Partnership, the Operating Partnership, 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 July 1, 2014, and incorporated herein by reference).
10.5	Fourth Amendment to Third Amended and Restated Credit Agreement, dated June 23, 2015, among the Partnership, the Operating Partnership, 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 June 24, 2015, and incorporated herein by reference).
10.6	Omnibus Agreement, dated November 1, 2002, by and among Martin Resource Management Corporation, the General Partner, the Partnership and the Operating Partnership (filed as Exhibit 10.3 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed November 19, 2002, and incorporated herein by reference).
10.7	Amendment No. 1 to Omnibus Agreement, dated as of November 25, 2009, by and among Martin Resource Management Corporation, the General Partner, the Partnership and the Operating Partnership (filed as Exhibit 10.3 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed December 1, 2009, and incorporated herein by reference).
10.8	Amendment No. 2 to Omnibus Agreement, dated October 1, 2012, by Martin Resource Management Corporation, the General Partner, the Partnership and the Operating Partnership (filed as Exhibit 10.4 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed October 9, 2012, and incorporated herein by reference).
10.9	Motor Carrier Agreement, dated January 1, 2006, by and between the Operating Partnership and Martin Transport, Inc. (filed as Exhibit 10.9 to the Partnership’s Annual Report on Form 10-K (SEC File No. 000-50056), filed March 2, 2011, and incorporated herein by reference).
10.10	Membership Interests Purchase Agreement, dated August 10, 2014, by and among Energy Capital Partners and its affiliated funds and Redbird Gas Storage LLC (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (Sec File No. 000-50056), filed August 12, 2014, and incorporated herein by reference).
10.11	2014 Amended and Restated Tolling Agreement, dated October 28, 2014, by and between the Operating Partnership and Cross Oil Refining & Marketing, Inc. (filed as Exhibit 10.5 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
10.12	Marine Transportation Agreement, dated January 1, 2006, by and between the Operating Partnership and Midstream Fuel Service, L.L.C. (filed as Exhibit 10.10 to the Partnership’s Annual Report on Form 10-K (SEC File No. 000-50056), filed March 2, 2011, and incorporated herein by reference).
10.13	Product Storage Agreement, dated November 1, 2002, by and between Martin Underground Storage, Inc. and the Operating Partnership (filed as Exhibit 10.8 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed November 19, 2002, and incorporated herein by reference).
10.14	Marine Fuel Agreement, dated November 1, 2002, by and between Martin Fuel Service LLC and the Operating Partnership (filed as Exhibit 10.9 to the Partnership’s Current Report on Form 8-K (SEC No. 000-50056), filed November 19, 2002, and incorporated herein by reference).
10.15†	Martin Midstream Partners L.P. Amended and Restated Long-Term Incentive Plan (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC No. 000-50056), filed January 26, 2006, and incorporated herein by reference).
10.16†	Form of Restricted Common Unit Grant Notice (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K (SEC No. 000-50056), filed January 26, 2006, and incorporated herein by reference).
10.17	Purchaser Use Easement, Ingress-Egress Easement, and Utility Facilities Easement dated November 1, 2002, by and between MGSLLC and the Operating Partnership (filed as Exhibit 10.13 to the Partnership’s Current Report on Form 8-K/A (SEC No. 000-50056), filed November 19, 2002, and incorporated herein by reference).
10.18	Amended and Restated Terminal Services Agreement by and between the Operating Partnership and Martin Fuel Service LLC ("MFSLLC"), dated October 27, 2004 (filed as Exhibit 10.1 to the Partnership's Current Report on Form 8-K (SEC No. 000-50056), filed October 28, 2004, and incorporated herein by reference).
10.19	Lubricants and Drilling Fluids Terminal Services Agreement by and between the Operating Partnership and MFSLLC, dated December 23, 2003 (filed as Exhibit 10.4 to the Partnership’s Amendment No. 1 to Current Report on Form 8-K/A (SEC No. 000-50056), filed January 23, 2004, and incorporated herein by reference).
10.20(1)	Second Amended and Restated Sales Agency Agreement, dated August 5, 2013, by and between the Operating Partnership and Martin Product Sales LLC (filed as Exhibit 10.2 to the Partnership's Quarterly Report on Form 10-Q (SEC No. 000-50056) filed November 4, 2013).
10.21(1)	Third Amended and Restated Sales Agency Agreement, dated August 2, 2017, by and between the Operating Partnership and Martin Product Sales LLC (filed as Exhibit 10.20 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056) filed October 25, 2017, and incorporated herein by reference).

125

10.22†	Amended and Restated Martin Resource Management Corporation Purchase Plan for Units of the Partnership, effective April 1, 2015 (filed as Exhibit 10.1 to the Partnership's registration statement on Form S-8 (SEC File No. 333-203857), filed May 5, 2015, and incorporated herein by reference).
10.23	Form of Partnership Indemnification Agreement (filed as Exhibit 10.1 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed November 6, 2008, and incorporated herein by reference).
10.24	Amended and Restated Common Unit Purchase Agreement, dated as of November 24, 2009, by and between the Partnership and Martin Resource Management (filed as Exhibit 10.4 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed December 1, 2009, and incorporated herein by reference).
10.25	Supply Agreement dated, as of October 2, 2012, by and between the Partnership and Cross Oil & Refining Marketing Inc. (filed as Exhibit 10.7 to the Partnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed November 5, 2012, and incorporated herein by reference).
10.26	Noncompetition Agreement dated, as of October 2, 2012, by and among the Partnership, Cross Oil Refining & Marketing, Inc., and Martin Resource Management Corporation (filed as Exhibit 10.8 to the Partnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed November 5, 2012, and incorporated herein by reference).
10.27	Purchase Price Reimbursement Agreement, dated October 2, 2012, by Martin Resource Management Corporation to and for the benefit of the Operating Partnership (filed as Exhibit 10.2 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed October 9, 2012, and incorporated herein by reference).
10.28	Lubricants Terminalling Services Agreement, dated January 1, 2015, by and between the Operating Partnership and Martin Energy Services LLC (filed as Exhibit 10.26 to the Partnership's Annual Report on Form 10-K (SEC File No. 000-50056), filed March 2, 2015, and incorporated herein by reference).
10.29	Fuel Terminalling Services Agreement, dated January 1, 2015, by and between the Operating Partnership and Martin Energy Services LLC (filed as Exhibit 10.27 to the Partnership's Current Report on Form 10-K (SEC File No. 000-50056), filed March 2, 2015, and incorporated herein by reference).
10.30(1)	First Amended and Restated Fuel Terminalling Services Agreement, dated January 1, 2016, by and between the Operating Partnership and Martin Energy Services, LLC (filed as Exhibit 10.29 to the Partnership's Annual Report on Form 10-K (SEC File No. 000-50056), filed February 29, 2016, and incorporated herein by reference).
10.31(1)	First Amendment to the First Amended and Restated Fuel Terminalling Services Agreement, dated January 1, 2017, by and between the Operating Partnership and Martin Energy Services, LLC (filed as Exhibit 10.30 to the Partnership’s Annual Report on Form 10-K (SEC File No. 000-50056), filed February 15, 2017, and incorporated herein by reference).
10.32(1)	Second Amendment to the First Amended and Restated Fuel Terminalling Services Agreement, dated October 1, 2017, by and between the Operating Partnership and Martin Energy Services, LLC (filed as Exhibit 10.31 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056) filed October 25, 2017).
10.33	Martin Midstream Partners L.P. 2017 Restricted Unit Plan (filed as Exhibit A to the Partnership’s Definitive Proxy Statement on Schedule 14A (SEC File No. 000-50056), filed April 21, 2017, and incorporated herein by reference).
10.34*	Restricted Unit Agreement under the Martin Midstream Partners L.P. 2017 Restricted Unit Plan
21.1*	List of Subsidiaries.
23.1*	Consent of KPMG LLP.
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 Annual Report on Form 10-K for the fiscal year ended December 31, 2017, formatted in Extensible Business Reporting Language: (1) the Consolidated Balance Sheets; (2) the Consolidated Statements of Income; (3) the Consolidated Statements of Cash Flows; (4) the Consolidated Statements of Capital; and (6) the Notes to Consolidated Financial Statements.
*	Filed or furnished herewith.
†	As required by Item 15(a)(3) of Form 10-K, this exhibit is identified as a compensatory plan or arrangement.

(1) Material has been redacted from this exhibit and filed separately with the Commission pursuant to a request for confidential treatment pursuant to Rule 24b-2 of the Securities Exchange Act of 1934, as amended, which has been granted.

126

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, we have duly caused this Report to be signed on our behalf by the undersigned, thereunto duly authorized representative.

	Martin Midstream Partners L.P
	(Registrant)
	By:	Martin Midstream GP LLC
		It's General Partner
Date: February 16, 2018	By:	/s/ Ruben S. Martin
		Ruben S. Martin
		President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 16th day of February, 2018.

127

Signature	Title
/s/ Ruben S. Martin	President, Chief Executive Officer and Director of Martin Midstream GP LLC (Principal Executive Officer)
Ruben S. Martin
/s/ Robert D. Bondurant	Executive Vice President, Director, and Chief Financial Officer of Martin Midstream GP LLC (Principal Financial Officer, Principal Accounting Officer)
Robert D. Bondurant
/s/ Zachary S. Stanton	Director of Martin Midstream GP LLC
Zachary S. Stanton
/s/ James M. Collingsworth	Director of Martin Midstream GP LLC
James M. Collingsworth
/s/ Sean P. Dolan	Director of Martin Midstream GP LLC
Sean P. Dolan
/s/ Byron R. Kelley	Director of Martin Midstream GP LLC
Byron R. Kelley
/s/ C. Scott Massey	Director of Martin Midstream GP LLC
C. Scott Massey

128

EX-10.34

Exhibit 10.34

RESTRICTED UNIT AGREEMENT

UNDER THE

MARTIN MIDSTREAM PARTNERS L.P. 2017 RESTRICTED UNIT PLAN

This Award Agreement (this “Agreement”) is entered into between Martin Midstream Partners L.P., a Delaware limited partnership (the “Partnership”) and [________________] (the “Participant”), an employee of Martin Resource Management Corporation, a Martin Group entity (the “Employer”), effective [___________], 2018 (the “Date of Grant”). Capitalized terms used but not defined in this Agreement have the respective meanings provided in the Martin Midstream Partners, L.P. 2017 Restricted Unit Plan (the “Plan”).

1.Grant of Restricted Units. Effective on the Date of Grant, the Partnership hereby issues to the Participant [___] Restricted Units (the “Award”), subject to the terms, conditions, and restrictions set forth in the Plan and in this Agreement.

2.Vesting and Forfeiture.

(a)The Award will vest according to the following schedule, provided that the Participant remains employed with a Martin Group entity on the applicable vesting date:

See Schedule Attached as Exhibit A

(b)In the event that, prior to becoming fully vested as provided in Section 2(a), the Participant’s Service terminates or a Change in Control is consummated, this Award will be subject to the Plan terms applicable to such event.

(c)Notwithstanding the vesting and forfeiture provisions set forth in this Section 2, the Committee may, at any time and in its sole discretion, accelerate vesting of all or any part of the Award.

3.No Contract of Employment. Nothing in this Agreement will be construed as giving the Participant the right to continue employment with the Partnership or any Martin Group entity or in any way limit their right to terminate the Participant’s Service at any time.

4.Rights as Unitholder. The Participant will be the owner of each Unit in the Award from the Date of Grant and [any UDRs issued with respect to the Units in this Award will be paid currently as provided in the Plan][Participant will not be paid UDRs until such Unit is vested and then only from the date of vesting and thereafter].

5.Non-Transferability. This Award, any Restricted Units subject to this Award, and any other rights or privileges provided for in this Agreement, may not be transferred, assigned, pledged, or hypothecated in any manner, by operation of law or otherwise, and will not be subject to execution, attachment, or similar process.

6.Taxes.

(a)Withholding. Unless the Participant makes a Section 83(b) Election in accordance with Section 6(b), upon vesting of the Award (or at such other time as compensation related to the Award might be taken into the Participant’s income, each such date being a “Tax Date”), the Participant will be required to satisfy all applicable withholding and all other tax obligations. In order to satisfy this obligation, unless the Participant has settled such obligations with the Company by the Tax Date (whether by payment in cash or delivery of currently-owned, unrestricted Units), the Partnership will withhold from the Award a number of Units in a value equal to the statutory withholding requirement. The value of the Units to be delivered or withheld will be based on the Fair Market Value of a Unit on the day prior to the Tax Date.

(b)Section 83(b) Election. The Participant may make an election under Code Section 83(b) (a “Section 83(b) Election”) with respect to any Restricted Units in the Award. Any such election must be made within 30 days after the Date of Grant. If the Participant makes a Section 83(b) Election, the Participant must provide the Partnership with (i) a copy of an executed version, (ii) satisfactory evidence of the filing of the executed Section 83(b) Election with the Internal Revenue Service and (iii) sufficient cash to meet the Participants withholding obligation as a result of the Section 83(b) Election. The Participant agrees and understands that the Participant bears sole responsibility for ensuring that the Section 83(b) Election is actually and timely filed with the Internal Revenue Service and for all tax consequences resulting from the Section 83(b) Election.

7.Amendment. The Committee may amend, modify, or terminate this Award at any time prior to vesting in any manner not inconsistent with the terms of the Plan. Notwithstanding the foregoing, except as expressly provided in the Plan, no such amendment, modification, or termination may materially impair the rights of the Participant under this Agreement without the written consent of the Participant.

8.Notices. All notices to the Partnership related to this Agreement should be sent to the Partnership’s principal executive offices as disclosed in its filings with the Securities and Exchange Commission, addressed to the Office of General Counsel. All notices to the Participant shall be delivered to the most recent address as provided by the Participant to the human resources department.

9.Binding Effect. This Agreement is personal to the Participant and may not be assigned by the Participant. This Agreement shall inure to the benefit of and be binding upon each of the parties and any successors to the Partnership.

10.Governing Law. This Agreement will be governed by and construed in accordance with the laws of the State of Delaware, without regard to any conflicts of laws.

11.Compliance with Law. The issuance and transfer of the Units subject to this Award is intended to comply with all Applicable Laws. Notwithstanding anything else in this Agreement, no Units will be issued or transferred unless and until any then-applicable requirements of state and federal laws and regulatory agencies have been fully complied with to the satisfaction of the Partnership and its counsel. The Participant understands that the Partnership is under no obligation to register the Units with the Securities and Exchange Commission, any state securities commission, or any stock exchange to effect such compliance.

12.Severability. In the event that any provision in this Agreement shall be found to be invalid, illegal or unenforceable, the Participant and the Partnership intend for any court construing this Agreement to modify or limit such provision so as to render it valid and enforceable to the fullest extent allowed by law. Any such provision that is not susceptible of reformation shall be ignored and shall not affect the validity, legality and enforceability of the remaining provisions, which shall be valid and enforced to the fullest extent permitted by law.

13.Entire Agreement. This Agreement, together with the Plan and the Partnership Agreement, constitutes the entire agreement between the Parties with respect to the subject matter contained in this Agreement. Any oral or written agreements, representations, warranties, written inducements, or other communications with respect to the subject matter contained in this Agreement made prior to the execution of this Agreement shall be void and ineffective for all purposes.

By signature below, the Participant represents that he or she is familiar with the terms and provisions of the Plan, this Agreement, and the Partnership Agreement, and hereby accepts this Award subject to all of those terms and provisions. The Participant agrees to accept as binding, conclusive, and final all decisions or interpretations of the Committee upon any questions arising under the Plan or this Agreement.

IN WITNESS WHEREOF, the Partnership and the Participant have executed this Agreement, effective as of the Date of Grant.

MARTIN MIDSTREAM PARTNERS L.P.

By: Martin Midstream GP LLC

By:

Printed Name:    

Title:

PARTICIPANT:

Printed Name:    

EXHIBIT A

Vesting Schedule and Terms

EX-21.1

Exhibit 21.1

SUBSIDIARIES OF

MARTIN MIDSTREAM PARTNERS L.P.

Subsidiary	Jurisdiction of Organization
Martin Operating GP LLC	Delaware
Martin Operating Partnership L.P.	Delaware
Martin Midstream Finance Corp	Delaware
MOP Midstream Holdings LLC	Delaware
Cardinal Gas Storage Partners LLC	Delaware
Monroe Gas Storage Company LLC	Delaware
Arcadia Gas Storage, LLC	Texas
Cadeville Gas Storage, LLC	Delaware
Perryville Gas Storage, LLC	Delaware
Talen's Marine & Fuel LLC	Louisiana
Martin Midstream NGL Holdings, LLC	Delaware
Martin Midstream NGL Holdings II, LLC	Delaware

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

The Board of Directors

Martin Midstream GP LLC:

We consent to the incorporation by reference in the registration statements on Form S-3 (No. 333-211407 and No. 333-193715) and on Form S-8 (No. 333-218693, No. 333-203857 and No. 333-140152) of Martin Midstream Partners L.P. of our reports dated February 16, 2018, with respect to the consolidated balance sheets of Martin Midstream Partners L.P. and subsidiaries as of December 31, 2017 and 2016, and the related consolidated statements of operations, changes in capital, and cash flows for each of the years in the three-year period ended December 31, 2017, and the effectiveness of internal control over financial reporting as of December 31, 2017, which reports appear in the December 31, 2017 annual report on Form 10-K of Martin Midstream Partners L.P.

/s/ KPMG LLP

Dallas, Texas

February 16, 2018

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 annual report on Form 10-K 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.

February 16, 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 annual report on Form 10-K 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.

February 16, 2018

/s/ Robert D. Bondurant

Robert D. Bondurant, Executive Vice President and

Chief Financial Officer of

Martin Midstream GP LLC,

the General Partner of Martin Midstream Partners L.P.

EX-32.1

Exhibit 32.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER 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 Annual Report of Martin Midstream Partners L.P., a Delaware limited partnership (the “Partnership”), on Form 10-K for the year ended December 31, 2017, 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; 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,

General Partner of Martin Midstream Partners L.P.

February 16, 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 OF PRINCIPAL FINANCIAL OFFICER 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 Annual Report of Martin Midstream Partners L.P., a Delaware limited partnership (the “Partnership”), on Form 10-K for the year ended December 31, 2017, 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; 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,

General Partner of Martin Midstream Partners L.P.

February 16, 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.

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Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 16, 2018	Jun. 30, 2017
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-K
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding (in shares)		38,425,812
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 564,892,029

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Assets
Cash	$ 27	$ 15
Trade and accrued accounts receivable, less allowance for doubtful accounts of $314 and $372 respectively	107,242	80,508
Product exchange receivables	29	207
Inventories	97,252	82,631
Due from affiliates	23,668	11,567
Other current assets	4,866	3,296
Assets held for sale	9,579	15,779
Total current assets	242,663	194,003
Property, plant and equipment, at cost	1,253,065	1,224,277
Accumulated depreciation	(421,137)	(378,593)
Property, plant and equipment, net	831,928	845,684
Goodwill	17,296	17,296
Investment in unconsolidated entities	128,810	129,506
Notes receivable - Martin Energy Trading LLC	0	15,000
Intangibles and other assets, net	32,801	44,874
Total assets	1,253,498	1,246,363
Liabilities and Partners’ Capital
Trade and other accounts payable	92,567	70,249
Product exchange payables	11,751	7,360
Due to affiliates	3,168	8,474
Income taxes payable	510	870
Fair value of derivatives	72	3,904
Other accrued liabilities	26,340	26,717
Total current liabilities	134,408	117,574
Long-term debt, net	812,632	808,107
Other long-term obligations	8,217	8,676
Total liabilities	955,257	934,357
Commitments and contingencies
Partners’ capital	298,241	312,006
Total partners’ capital	298,241	312,006
Total liabilities and partners' capital	$ 1,253,498	$ 1,246,363

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Assets
Doubtful accounts for accounts and other receivables	$ 314	$ 372

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CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues:
Terminalling and storage	[1]	$ 99,705,000	$ 123,132,000	$ 132,945,000
Marine transportation	[1]	48,579,000	58,290,000	78,753,000
Natural gas storage services	[1]	58,817,000	61,133,000	64,858,000
Sulfur services		10,952,000	10,800,000	12,270,000
Product sales:
Natural gas services	[1]	473,865,000	330,200,000	458,302,000
Sulfur services	[1]	123,732,000	130,258,000	157,891,000
Terminalling and storage	[1]	130,466,000	113,578,000	131,825,000
Total product sales	[1]	728,063,000	574,036,000	748,018,000
Total revenues		946,116,000	827,391,000	1,036,844,000
Cost of products sold: (excluding depreciation and amortization)
Natural gas services	[1]	421,444,000	289,516,000	413,795,000
Sulfur services	[1]	82,338,000	87,963,000	114,766,000
Terminalling and storage	[1]	109,798,000	94,175,000	112,836,000
Total cost of products sold (excluding depreciation and amortization)		613,580,000	471,654,000	641,397,000
Expenses:
Operating expenses	[1]	146,874,000	158,864,000	183,466,000
Selling, general and administrative	[1]	38,950,000	34,385,000	36,788,000
Impairment of long-lived assets		2,225,000	26,953,000	10,629,000
Impairment of goodwill		0	4,145,000	0
Depreciation and amortization		85,195,000	92,132,000	92,250,000
Total costs and expenses		886,824,000	788,133,000	964,530,000
Other operating income (loss), net		523,000	33,400,000	(2,161,000)
Operating income		59,815,000	72,658,000	70,153,000
Other income (expense):
Equity in earnings of unconsolidated entities		4,314,000	4,714,000	8,986,000
Interest expense, net		(47,743,000)	(46,100,000)	(43,292,000)
Gain on retirement of senior unsecured notes		0	0	1,242,000
Other, net		1,101,000	1,106,000	1,124,000
Total other income (expense)		(42,328,000)	(40,280,000)	(31,940,000)
Net income before taxes		17,487,000	32,378,000	38,213,000
Income tax expense		(352,000)	(726,000)	(1,048,000)
Income from continuing operations		17,135,000	31,652,000	37,165,000
Income from discontinued operations, net of income taxes		0	0	1,215,000
Net income		17,135,000	31,652,000	38,380,000
Less general partner's interest in net income		(343,000)	(8,419,000)	(16,338,000)
Less income allocable to unvested restricted units		(42,000)	(90,000)	(140,000)
Limited partner's interest in net income		$ 16,750,000	$ 23,143,000	$ 21,902,000

[1] *Related Party Transactions Included Above   Year Ended December 31,   2017   2016   2015 Revenues:           Terminalling and storage $ 82,205
  $ 82,437
  $ 78,233
Marine transportation 16,801
  21,767
  27,724
Natural gas services 122
  699
  878
Product sales 3,578
  3,034
  5,671
Costs and expenses:  
   
   
Cost of products sold: (excluding depreciation and amortization)  
   
   
Natural gas services 18,946
  22,886
  25,797
Sulfur services 15,564
  15,339
  16,579
          Terminalling and storage 17,612
  13,838
  17,718
Expenses:  
   
   
Operating expenses 64,344
  70,841
  77,871
Selling, general and administrative 29,416
  25,890
  24,968

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CONSOLIDATED STATEMENTS OF OPERATIONS - (Allocation of Net Income) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Limited partner interest:
Continuing operations	$ 16,750	$ 23,143	$ 21,208
Discontinued operations	0	0	694
Limited partner's interest in net income	16,750	23,143	21,902
General partner interest:
Continuing operations	343	8,419	15,821
Discontinued operations	0	0	517
Net income allocated to general partners	$ 343	$ 8,419	$ 16,338
Basic:
Continuing operations (in dollars per share)	$ 0.44	$ 0.65	$ 0.60
Discontinued operations (in dollars per share)	0	0	0.02
Net Income, Basic (in dollars per share)	$ 0.44	$ 0.65	$ 0.62
Weighted average limited partner units - basic (in shares)	38,101,583	35,347,032	35,308,649
Diluted:
Continuing operations (in dollars per share)	$ 0.44	$ 0.65	$ 0.60
Discontinued operations (in dollars per share)	0	0	0.02
Net Income, Diluted (in dollars per share)	$ 0.44	$ 0.65	$ 0.62
Weighted average limited partner units - diluted (in shares)	38,164,901	35,375,263	35,371,529

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CONSOLIDATED STATEMENTS OF OPERATIONS - (Related Party Transactions) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues:
Terminalling and storage	$ 82,205	$ 82,437	$ 78,233
Marine transportation	16,801	21,767	27,724
Natural gas services	122	699	878
Product sales	3,578	3,034	5,671
Cost of products sold: (excluding depreciation and amortization)
Natural gas services	18,946	22,886	25,797
Sulfur services	15,564	15,339	16,579
Terminalling and storage	17,612	13,838	17,718
Expenses:
Operating expenses	64,344	70,841	77,871
Selling, general and administrative	$ 29,416	$ 25,890	$ 24,968

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CONSOLIDATED STATEMENTS OF CHANGES IN CAPITAL - USD ($) $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2017	Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Increase (Decrease) in Partners' Capital [Roll Forward]
Beginning balance		$ 312,006		$ 393,879	$ 312,006	$ 393,879	$ 485,671
Net income	$ 18,849	$ 13,583	$ 17,882	$ 15,914	17,135	31,652	38,380
Issuance of common units, net					51,056	(29)	(590)
General partner contribution					1,098		55
Cash distributions					(76,938)	(118,178)	(133,316)
Reimbursement of excess purchase price over carrying value of acquired assets					1,125	4,125	2,250
Excess purchase price over carrying value of acquired assets					(7,887)
Unit-based compensation					650	904	1,429
Purchase of treasury units					(4)	(347)
Ending balance	298,241		312,006		$ 298,241	$ 312,006	$ 393,879
Common | Common
Increase (Decrease) in Partners' Capital [Roll Forward]
Beginning balance (in shares)		35,452,062		35,456,612	35,452,062	35,456,612	35,365,912
Beginning balance		$ 304,594		$ 380,845	$ 304,594	$ 380,845	$ 470,943
Net income					$ 16,792	23,233	22,042
Issuance of common units, net (in shares)					2,990,000
Issuance of common units, net					$ 51,056	$ (29)	$ (590)
Issuance of restricted units (in shares)					12,000	13,800	91,950
Forfeiture of restricted units (in shares)					(9,250)	(2,250)	(1,250)
Cash distributions					$ (75,399)	$ (104,137)	$ (115,229)
Reimbursement of excess purchase price over carrying value of acquired assets					1,125	4,125	2,250
Excess purchase price over carrying value of acquired assets					(7,887)
Unit-based compensation					$ 650	$ 904	1,429
Purchase of treasury units (in shares)					(200)	(16,100)
Purchase of treasury units					$ (4)	$ (347)
Ending balance	$ 290,927		$ 304,594		$ 290,927	$ 304,594	$ 380,845
Ending balance (in shares)	38,444,612		35,452,062		38,444,612	35,452,062	35,456,612
General Partner
Increase (Decrease) in Partners' Capital [Roll Forward]
Beginning balance		$ 7,412		$ 13,034	$ 7,412	$ 13,034	$ 14,728
Net income					343	8,419	16,338
General partner contribution					1,098		55
Cash distributions					(1,539)	(14,041)	(18,087)
Ending balance	$ 7,314		$ 7,412		$ 7,314	$ 7,412	$ 13,034

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities:
Net income	$ 17,135,000	$ 31,652,000	$ 38,380,000
Less: Income from discontinued operations	0	0	(1,215,000)
Net income from continuing operations	17,135,000	31,652,000	37,165,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	85,195,000	92,132,000	92,250,000
Amortization of deferred debt issue costs	2,897,000	3,684,000	4,859,000
Amortization of premium on notes payable	(306,000)	(306,000)	(324,000)
(Gain) loss on disposition or sale of property, plant, and equipment	(523,000)	(33,400,000)	2,149,000
Gain on retirement of senior unsecured notes	0	0	(1,242,000)
Impairment of long-lived assets	2,225,000	26,953,000	10,629,000
Impairment of goodwill	0	4,145,000	0
Equity in earnings unconsolidated entities	(4,314,000)	(4,714,000)	(8,986,000)
Derivative (income) loss	1,304,000	4,133,000	(3,107,000)
Net cash (paid) received for commodity derivatives	(5,136,000)	(550,000)	143,000
Net cash received for interest rate derivatives	0	160,000	0
Net premiums received on derivatives that settled during the year on interest rate swaption contracts	0	630,000	2,495,000
Unit-based compensation	650,000	904,000	1,429,000
Return on investment	5,400,000	7,500,000	11,200,000
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables	(26,739,000)	(6,153,000)	59,479,000
Product exchange receivables	178,000	843,000	1,996,000
Inventories	(14,656,000)	(6,761,000)	12,799,000
Due from affiliates	(12,096,000)	(1,441,000)	4,386,000
Other current assets	(1,699,000)	2,478,000	891,000
Trade and other accounts payable	20,037,000	3,254,000	(44,153,000)
Product exchange payables	4,391,000	(5,372,000)	2,336,000
Due to affiliates	(5,306,000)	2,736,000	866,000
Income taxes payable	(360,000)	(115,000)	(189,000)
Other accrued liabilities	(3,187,000)	686,000	(2,802,000)
Change in other non-current assets and liabilities	2,416,000	(12,230,000)	(345,000)
Net cash provided by continuing operating activities	67,506,000	110,848,000	183,924,000
Net cash used in discontinued operating activities	0	0	(1,352,000)
Net cash provided by operating activities	67,506,000	110,848,000	182,572,000
Cash flows from investing activities:
Payments for property, plant, and equipment	(39,749,000)	(40,455,000)	(65,791,000)
Acquisitions, net of cash acquired	(19,533,000)	(2,150,000)	0
Payments for plant turnaround costs	(1,583,000)	(2,061,000)	(1,908,000)
Proceeds from sale of property, plant, and equipment	8,377,000	108,505,000	2,644,000
Proceeds from repayment of Note receivable - affiliate	15,000,000	0	0
Contributions to unconsolidated entities for operations	(390,000)	0	0
Net cash provided by (used in) continuing investing activities	(37,878,000)	63,839,000	(65,055,000)
Net cash provided by discontinued investing activities	0	0	41,250,000
Net cash provided by (used in) investing activities	(37,878,000)	63,839,000	(23,805,000)
Cash flows from financing activities:
Payments of long-term debt	(339,000,000)	(386,700,000)	(308,836,000)
Proceeds from long-term debt	341,000,000	331,700,000	282,000,000
Net proceeds from issuance of common units	51,056,000	(29,000)	(590,000)
General partner contributions	1,098,000	0	55,000
Excess purchase price over carrying value of acquired assets	(7,887,000)	0	0
Reimbursement of excess purchase price over carrying value of acquired assets	1,125,000	4,125,000	2,250,000
Purchase of treasury units	(4,000)	(347,000)	0
Payments of debt issuance costs	(66,000)	(5,274,000)	(341,000)
Cash distributions paid	(76,938,000)	(118,178,000)	(133,316,000)
Net cash used in financing activities	(29,616,000)	(174,703,000)	(158,778,000)
Net increase (decrease) in cash	12,000	(16,000)	(11,000)
Cash at beginning of year	15,000	31,000	42,000
Cash at end of year	$ 27,000	$ 15,000	$ 31,000

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Organization and Description of Business

12 Months Ended

Dec. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Description of Business

Organization and Description of Business

Martin Midstream Partners L.P. (the "Partnership") is a publicly traded limited partnership with a diverse set of operations focused primarily in the United States ("U.S.") Gulf Coast region. Its four primary business lines include:  terminalling and storage services for petroleum products and by-products including the refining of naphthenic crude oil and the blending and packaging of finished lubricants; natural gas services, including liquids transportation and distribution services and natural gas storage; sulfur and sulfur-based products processing, manufacturing, marketing and distribution; and marine transportation services for petroleum products and by-products.

The petroleum products and by-products the Partnership collects, transports, stores and distributes are produced primarily by major and independent oil and gas companies who often turn to third parties, such as the Partnership, for the transportation and disposition of these products.  In addition to these major and independent oil and gas companies, the Partnership's primary customers include independent refiners, large chemical companies, fertilizer manufacturers and other wholesale purchasers of these products. The Partnership operates primarily in the U.S. Gulf Coast region, which is a major hub for petroleum refining, natural gas gathering and processing and support services for the oil and gas exploration and production industry.

On August 30, 2013, Martin Resource Management completed the sale of a 49% non-controlling voting interest (50% economic interest) in MMGP Holdings, LLC ("Holdings"), a newly-formed sole member of Martin Midstream GP LLC ("MMGP"), the general partner of the Partnership, to certain affiliated investment funds managed by Alinda Capital Partners ("Alinda"). Upon closing the transaction, Alinda appointed two representatives to serve on the board of directors of the general partner of the Partnership.

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Significant Accounting Policies

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Significant Accounting Policies

Significant Accounting Policies

(a)       Principles of Presentation and Consolidation

The consolidated financial statements include the financial statements of the Partnership and its wholly-owned subsidiaries and equity method investees.  In the opinion of the management of the Partnership’s general partner, all adjustments and elimination of significant intercompany balances necessary for a fair presentation of the Partnership’s results of operations, financial position and cash flows for the periods shown have been made.  All such adjustments are of a normal recurring nature.  In addition, the Partnership evaluates its relationships with other entities to identify whether they are variable interest entities under certain provisions of the Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC"), 810-10 and to assess whether it is the primary beneficiary of such entities.  If the determination is made that the Partnership is the primary beneficiary, then that entity is included in the consolidated financial statements in accordance with ASC 810-10.  No such variable interest entities exist as of December 31, 2017 or 2016.

As discussed in Note 5, on February 12, 2015, the Partnership sold all six 16,101 barrel liquefied petroleum gas ("LPG") pressure barges, collectively referred to as the "Floating Storage Assets." These assets were acquired on February 28, 2013. On December 19, 2014, the Partnership made the decision to dispose of the Floating Storage Assets. As a result, the Partnership has presented the results of operations and cash flows of the Floating Storage Assets as discontinued operations for the year ended December 31, 2015.

(b)       Product Exchanges

The Partnership enters into product exchange agreements with third parties, whereby the Partnership agrees to exchange natural gas liquids ("NGLs") and sulfur with third parties.  The Partnership records the balance of exchange products due to other companies under these agreements at quoted market product prices and the balance of exchange products due from other companies at the lower of cost or market.  Cost is determined using the first-in, first-out ("FIFO") method.  Product exchanges with the same counterparty are entered into in contemplation of one another and are combined. The net amount related to location differentials is reported in "Product sales" or "Cost of products sold" in the Consolidated Statements of Operations.

(c)       Inventories

Inventories are stated at the lower of cost or market.  Cost is generally determined by using the FIFO method for all inventories except lubricants and lubricants packaging inventories. Lubricants and lubricants packaging inventories cost is determined using standard cost, which approximates actual cost, computed on a FIFO basis.

(d)      Revenue Recognition

Terminalling and Storage – Revenue is recognized for storage contracts based on the contracted monthly tank fixed fee.  For throughput contracts, revenue is recognized based on the volume moved through the Partnership’s terminals at the contracted rate.  For the Partnership’s tolling agreement, revenue is recognized based on the contracted monthly reservation fee and throughput volumes moved through the facility.  When lubricants and drilling fluids are sold by truck or rail, revenue is recognized upon delivering product to the customers as title to the product transfers when the customer physically receives the product.

Natural Gas Services – NGL distribution revenue is recognized when product is delivered by truck, rail, or pipeline to the Partnership's NGL customers. Natural gas storage revenue is recognized when the service is provided to the customer.

Sulfur Services – Revenue from sulfur product sales is recognized when the customer takes title to the product.   Revenue from sulfur services is recognized as deliveries are made during each monthly period.

Marine Transportation – Revenue is recognized for time charters based on a per day rate. For contracted trips, revenue is recognized upon completion of the particular trip.

(e)       Equity Method Investments

The Partnership uses the equity method of accounting for investments in unconsolidated entities where the ability to exercise significant influence over such entities exists.  Investments in unconsolidated entities consist of capital contributions and advances plus the Partnership’s share of accumulated earnings as of the entities’ latest fiscal year-ends, less capital withdrawals and distributions.  Equity method investments are subject to impairment under the provisions of ASC 323-10, which relates to the equity method of accounting for investments in common stock.  No portion of the net income from these entities is included in the Partnership’s operating income.

(f)      Property, Plant, and Equipment

Owned property, plant, and equipment is stated at cost, less accumulated depreciation.  Owned buildings and equipment are depreciated using straight-line method over the estimated lives of the respective assets.

Equipment under capital leases is stated at the present value of minimum lease payments less accumulated amortization. Equipment under capital leases is amortized on a straight line basis over the estimated useful life of the asset.

Routine maintenance and repairs are charged to expense while costs of betterments and renewals are capitalized.  When an asset is retired or sold, its cost and related accumulated depreciation are removed from the accounts, and the difference between net book value of the asset and proceeds from disposition is recognized as gain or loss.

(g)      Goodwill and Other Intangible Assets

Goodwill is subject to a fair-value based impairment test on an annual basis, or more often if events or circumstances indicate there may be impairment. The Partnership is required to identify its reporting units and determine the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets. The Partnership is required to determine the fair value of each reporting unit and compare it to the carrying amount of the reporting unit. To the extent the carrying amount of a reporting unit exceeds the fair value of the reporting unit, the Partnership will record the amount of goodwill impairment as the excess of a reporting unit's carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit.

When assessing the recoverability of goodwill and other intangible assets, the Partnership may first assess qualitative factors in determining whether it is more likely than not that the fair value of a reporting unit or other intangible asset is less than its carrying amount. After assessing qualitative factors, if the Partnership determines that it is not more likely than not that the fair value of a reporting unit or other intangible asset is less than its carrying amount, then performing a quantitative assessment is not required. If an initial qualitative assessment indicates that it is more likely than not the carrying amount exceeds the fair value of a reporting unit or other intangible asset, a quantitative analysis will be performed. The Partnership may also elect to bypass the qualitative assessment and proceed directly to a quantitative analysis depending on the facts and circumstances.

Of the Partnership's four reporting units, the terminalling and storage, natural gas services, and sulfur services reporting units contain goodwill. No goodwill impairment was recorded for the year ended December 31, 2017. During the second quarter of 2016, the Partnership experienced an impairment of all the goodwill in the Partnership's marine transportation reporting unit. See Note 8 for more information.

In performing a quantitative analysis, recoverability of goodwill for each reporting unit is measured using a weighting of the discounted cash flow method and two market approaches (the guideline public company method and the guideline transaction method). The discounted cash flow model incorporates discount rates commensurate with the risks involved. Use of a discounted cash flow model is common practice in assessing impairment in the absence of available transactional market evidence to determine the fair value. The key assumptions used in the discounted cash flow valuation model include discount rates, growth rates, cash flow projections and terminal value rates. Discount rates, growth rates and cash flow projections are the most sensitive and susceptible to change as they require significant management judgment. Discount rates are determined by using a weighted average cost of capital ("WACC"). The WACC considers market and industry data as well as company-specific risk factors for each reporting unit in determining the appropriate discount rate to be used. The discount rate utilized for each reporting unit is indicative of the return an investor would expect to receive for investing in such a business. Management, considering industry and company specific historical and projected data, develops growth rates and cash flow projections for each reporting unit. Terminal value rate determination follows common methodology of capturing the present value of perpetual cash flow estimates beyond the last projected period assuming a constant WACC and low long-term growth rates. If the calculated fair value is less than the current carrying amount, the Partnership will record the amount of goodwill impairment as the excess of a reporting unit's carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit.

Significant changes in these estimates and assumptions could materially affect the determination of fair value for each reporting unit which could give rise to future impairment. Changes to these estimates and assumptions can include, but may not be limited to, varying commodity prices, volume changes and operating costs due to market conditions and/or alternative providers of services.

Other intangible assets that have finite lives are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable. An impairment is indicated if the carrying amount of a long-lived intangible asset exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If impairment is indicated, the Partnership would record an impairment loss equal to the difference between the carrying value and the fair value of the asset. There were no intangible asset impairments in 2017, 2016 or 2015.

(h)      Debt Issuance Costs

Debt issuance costs relating to the Partnership’s revolving credit facility and senior unsecured notes are deferred and amortized over the terms of the debt arrangements and are shown, net of accumulated amortization, as a reduction of the related long-term debt.

In connection with the issuance, amendment, expansion and restatement of debt arrangements, the Partnership incurred debt issuance costs of $66, $5,274 and $341 in the years ended December 31, 2017, 2016 and 2015, respectively.

During 2016, the Partnership made certain strategic amendments to its credit facility which, among other things, decreased its borrowing capacity from $700,000 to $664,444 and extended the maturity date of the facility from March 28, 2018 to March 28, 2020. In connection with the amendment, the Partnership expensed $820 of unamortized debt issuance costs determined not to have continuing benefit.

During 2015, the Partnership repurchased on the open market an aggregate $26,200 of 7.25% senior unsecured notes. The repurchase transaction resulted in the write-off of $235 of existing debt issuance costs that were determined not to have continuing benefit. On August 14, 2015, the Partnership reduced its borrowing capacity under the revolving credit facility from $900,000 to $700,000, resulting in the write-off of $1,625 of deferred debt costs that were determined not to have continuing benefit.

Remaining unamortized deferred issuance costs are amortized over the term of each respective revised debt arrangement.

Amortization and write-off of debt issuance costs, which is included in interest expense, totaled $2,897, $3,684 and $4,859 for the years ended December 31, 2017, 2016 and 2015, respectively.  Accumulated amortization amounted to $17,162 and $14,265 at December 31, 2017 and 2016, respectively.

(i)      Impairment of Long-Lived Assets

In accordance with ASC 360-10, long-lived assets, such as property, plant and equipment, and intangible assets with definite lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset.  If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset.  Assets to be disposed of would be separately presented in the balance sheet and reported at the lower of the carrying amount or fair value less costs to sell and would no longer be depreciated.  The assets and liabilities of a disposed group classified as held for sale would be presented separately in the appropriate asset and liability sections of the balance sheet.  

In the fourth quarter of 2017, the Partnership identified a triggering event related to the planned disposition of certain assets that were no longer deemed core assets in the Partnership's Marine Transportation business. The triggering event was the assets' inability to generate cash flows in recent quarters and going forward. As a result, an impairment charge of $1,625 was recorded in the Marine Transportation segment results of operations in the fourth quarter of 2017. Additionally, the Partnership recorded an adjustment to the fair value less cost to sell of a certain asset classified as held for sale in the Martin Lubricants division of the Terminalling and Storage segment. As a result, an impairment charge of $600 was recorded in the Terminalling and Storage segment results of operations in the fourth quarter of 2017.

On August 25, 2017, Hurricane Harvey made landfall as a Category 4 hurricane. The storm lingered over Texas and Louisiana for days producing over 50 inches of rain in some areas, resulting in widespread flooding and damage. The Partnership experienced an impact from Hurricane Harvey in our Terminalling and Storage and Sulfur Services segments, where damages were suffered to the Partnership's property, plant, and equipment at its Neches, Stanolind, Galveston, and Harbor Island terminals located along the Texas gulf coast. The damage incurred did not exceed the insurance deductible at these locations and therefore The Partnership does not expect to receive any insurance proceeds resulting from the damage from Hurricane Harvey. In the third quarter of 2017, the Partnership recorded a write-off in the amount of $186 related to assets damaged.

In the fourth quarter of 2016, the Partnership identified a triggering event related to certain organic growth projects in the Smackover Refinery and Specialty Terminals divisions of the Partnership's Terminalling and Storage segment. These triggering events were the decision to not move forward with certain expansion projects due to the evaporation of the economic viability of the projects. Additionally, a triggering event was identified related to the planned disposition of certain assets that were no longer deemed core assets to the Partnership's Martin Lubricants division. As a result, an impairment charge of $15,252 was recorded in the Terminalling and Storage segment results of operations for the year ended December 31, 2016. In the fourth quarter of 2016, the Partnership identified a triggering event related to the planned disposition of certain assets that were no longer deemed core assets in the Partnership's Marine Transportation business. The triggering event was the assets' inability to generate cash flows in recent quarters and going forward. As a result, an impairment charge of $11,701 was recorded in the Marine Transportation segment results of operations in the fourth quarter of 2016.

In the fourth quarter of 2015, the Partnership identified a triggering event related to the condensate splitter project in the specialty terminals division of the Partnership's Terminalling and Storage segment. The triggering event was the decision to not move forward with the project due to the evaporation of the economic viability of the project. As a result, an impairment

charge of $9,305 was recorded in the Terminalling and Storage segment results of operations in the fourth quarter of 2015. In the fourth quarter of 2015, the Partnership identified a triggering event related to one inland push boat and three inland tank barges in the Marine Transportation segment. The triggering event was the assets' inability to generate cash flows in recent quarters and going forward. As a result, an impairment charge of $1,324 was recorded in the Marine Transportation segment results of operations in the fourth quarter of 2015.

(j)      Asset Retirement Obligations

Under ASC 410-20, which relates to accounting requirements for costs associated with legal obligations to retire tangible, long-lived assets, the Partnership records an asset retirement obligation ("ARO") at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted over time towards the ultimate obligation amount and the capitalized costs are depreciated over the useful life of the related asset.  

(k)     Derivative Instruments and Hedging Activities

In accordance with certain provisions of ASC 815-10 related to accounting for derivative instruments and hedging activities, all derivatives and hedging instruments are included in the Consolidated Balance Sheets as an asset or liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings.

Derivative instruments not designated as hedges are marked to market with all market value adjustments being recorded in the Consolidated Statements of Operations.  

(l)    Use of Estimates

Management has made a number of estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with accounting principles generally accepted in the U.S.  Actual results could differ from those estimates.

(m)      Indirect Selling, General and Administrative Expenses

Indirect selling, general and administrative expenses are incurred by Martin Resource Management and allocated to the Partnership to cover costs of centralized corporate functions such as accounting, treasury, engineering, information technology, risk management and other corporate services.  Such expenses are based on the percentage of time spent by Martin Resource Management’s personnel that provide such centralized services.  Under an omnibus agreement with Martin Resource Management, the Partnership is required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses.  For the years ended December 31, 2017, 2016 and 2015, the conflicts committee of the Partnership's general partner ("Conflicts Committee") approved reimbursement amounts of  $16,416, $13,033 and $13,679, respectively, reflecting the Partnership's allocable share of such expenses.  The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.

(n)      Environmental Liabilities and Litigation

The Partnership’s policy is to accrue for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable.  Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study.  Such accruals are adjusted as further information develops or circumstances change.  Costs of future expenditures for environmental remediation obligations are not discounted to their present value.  Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable.

(o)      Trade and Accrued Accounts Receivable and Allowance for Doubtful Accounts.

Trade accounts receivable are recorded at the invoiced amount and do not bear interest.  The allowance for doubtful accounts is the Partnership’s best estimate of the amount of probable credit losses in the Partnership’s existing accounts receivable.

(p)      Deferred Catalyst Costs

The cost of the periodic replacement of catalysts is deferred and amortized over the catalyst’s estimated useful life, which ranges from 12 to 36 months.

(q)      Deferred Turnaround Costs

The Partnership capitalizes the cost of major turnarounds and amortizes these costs over the estimated period to the next turnaround, which ranges from 12 to 36 months.

(r)      Income Taxes

The Partnership is subject to the Texas margin tax, which is considered a state income tax, and is included in income tax expense on the Consolidated Statements of Operations. Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed as an income tax and, therefore, the recognition of deferred taxes applies to the margin tax. The impact on deferred taxes as a result of this provision is immaterial.

(s)      Comprehensive Income

Comprehensive income includes net income and other comprehensive income.  There are no items of other comprehensive income or loss in any of the years presented.

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Recent Accounting Pronouncements

12 Months Ended

Dec. 31, 2017

Accounting Changes and Error Corrections [Abstract]

Recent Accounting Pronouncements

Recent Accounting Pronouncements

In January 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2017-04 “Intangibles-Goodwill and other: Simplifying the test for goodwill impairment.” This ASU removes the second step of the two-step test currently required under the current guidance. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit's carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance does not amend the optional qualitative assessment of goodwill impairment. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. The Partnership elected to early adopt this amended guidance effective January 1, 2017. The Partnership expects that adoption of this standard will change its approach for testing goodwill for impairment if a triggering event is identified; however, this standard requires prospective application and therefore will only impact periods subsequent to adoption.

In August 2016, the Financial Accounting Standards Board FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments. This ASU is intended to clarify the presentation of cash receipts and payments in specific situations. The amendments in this ASU are effective for financial statements issued for annual periods beginning after December 15, 2017, including interim periods within those annual periods, and early application is permitted. The Partnership does not anticipate that ASU 2016-15 will have a material effect on its consolidated financial statements and related disclosures.

In February 2016, the FASB issued ASU 2016-02, Leases.  This ASU amends the existing accounting standards for lease accounting, including requiring lessees to recognize most leases on their balance sheets and making targeted changes to lessor accounting. ASU 2016-02 is effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period. Early adoption of this standard is permitted. The standard requires a modified retrospective transition approach for all leases existing at, or entered into after, the date of initial application, with an option to use certain transition relief.  The Partnership is evaluating the effect that ASU 2016-02 will have on its consolidated financial statements and related disclosures.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective. The new standard is effective for the Partnership on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method. The Partnership plans to adopt 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 has completed a review of the impacts of the application of the new standard to its existing portfolio of customer contracts and has concluded its process of evaluating its new controls and processes designed to comply with ASU 2014-09 throughout 2017 to permit adoption by January 1, 2018. The Partnership's approach included performing a detailed review of key contracts representative of its different businesses and comparing historical accounting policies and practices to the new standard.

In the Terminalling and Storage segment, revenue will continue to be recognized for storage contracts based on the contracted monthly tank fixed fee.  For throughput contracts, revenue will continue to be recognized based on the volume moved through the Partnership’s terminals at the contracted rate.  For the Partnership’s tolling agreement, revenue will continue to be 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 will continue to be recognized upon delivering product to the customers as title to the product transfers when the customer physically receives the product. Delivery of product is invoiced as the transaction occurs and are generally paid within a month.

In the Natural Gas Services segment, NGL distribution revenue will continue to be recognized when product is delivered by truck, rail, or pipeline to the Partnership's NGL customers. Revenue will continue to be 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 will continue to be recognized when the service is provided to the customer. The performance of the service is invoiced as the transaction occurs and are generally paid within a month.

In the Sulfur Services segment, revenue from sulfur product sales will continue to be 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 will continue to be recognized as deliveries are made during each monthly period. The performance of the service is invoiced as the transaction occurs and are generally paid within a month.

In the Marine Transportation segment, revenue will continue to be recognized for time charters based on a per day rate. For contracted trips, revenue will continue to be recognized upon completion of the particular trip. The performance of the service is invoiced as the transaction occurs and are generally paid within a month.

Additionally, the Partnership will be required to assess variable consideration included in its contracts and make judgments and estimates throughout the applicable periods. Certain additional financial statement disclosure requirements are mandated by the new standard including disclosure of contract assets and contract liabilities as well as a disaggregated view of revenue. Based on the Partnership’s analysis, the adoption of this guidance will not have a significant impact on its consolidated financial statements.

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Acquisitions

12 Months Ended

Dec. 31, 2017

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 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”), which will 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."

Purchase price	$	27,420
Historical carrying value of assets allocated to "Property, plant and equipment"	19,533
Excess purchase price over carrying value of acquired assets	$	7,887

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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Discontinued Operations, Divestitures, and Assets Held for Sale

12 Months Ended

Dec. 31, 2017

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations, Divestitures, and Assets Held for Sale

Discontinued Operations, Divestitures, and Assets Held for Sale

Long-Lived Assets Held for Sale

In the fourth quarter of 2017, the Partnership identified certain assets that were no longer deemed core to the operations of the Partnership in the inland division of the Marine Transportation segment. Additionally, the Partnership recorded an adjustment to the fair value less cost to sell of a certain asset classified as held for sale in the Martin Lubricants division of the Terminalling and Storage segment. As a result, an impairment charge of $600 and $1,625 was recorded in the Terminalling and Storage and Marine Transportation segments, respectively, in the fourth quarter of 2017 and was presented as "Impairment of long-lived assets" in the Partnership's Consolidated Statements of Operations.

In the fourth quarter of 2016, the Partnership identified certain assets that were no longer deemed core to the operations of the Partnership in the Smackover refinery and Martin Lubricants divisions of the Terminalling and Storage segment as well as the inland and offshore divisions of the Marine Transportation segment. These assets were deemed non-core due to the each asset's inability to generate cash flows in recent quarters as well as the expected cash flows in future quarters. As a result, an impairment charge of $15,252 and $11,701 was recorded in the Terminalling and Storage and Marine Transportation segments, respectively in the fourth quarter of 2016 and was presented as "Impairment of long-lived assets" in the Partnership's Consolidated Statements of Operations.

At December 31, 2017 and 2016, the assets met the criteria to be classified as held for sale in accordance with ASC 360-10 and are presented at the assets' fair value less cost to sell by segment in current assets as follows:

	December 31, 2017		December 31, 2016
Terminalling and storage	$	4,152	$	10,852
Marine transportation	5,427		4,927
Assets held for sale	$	9,579	$	15,779

During 2017, the Partnership received $8,341 in proceeds from the sale of assets classified as held for sale for a gain of $822, which was presented as a component of "Other operating income (loss), net" in the Partnership's Consolidated Statements of Operations.

The non-core assets discussed above did not qualify for discontinued operations presentation under the guidance of ASC 205-20.

Divestitures

Divestiture of Terminalling Assets. On December 21, 2016, the Partnership sold its 900,000 barrel crude oil storage terminal, refined product barge terminal, certain pipelines and related easements as well as dockage and trans-loading assets located in Corpus Christi, Texas (collectively the "CCCT Assets") to NuStar Logistics, L.P. (“NuStar”) for gross consideration of $107,000 plus the reimbursement of certain capital expenditures and prepaid items of $2,057. The Partnership received net proceeds of approximately $93,347 after transaction fees and expenses as well as the application of certain net cash payments previously received by us in conjunction with its mandated relocation of certain dockage assets to the purchase price in the amount of $13,400. Proceeds from the sale were used to reduce outstanding borrowings under the Partnership's revolving credit facility. The Partnership recorded a gain from the divestiture of $37,345, which was included in "Other operating income, net on the Partnership's Consolidated Statements of Operations for the year ended December 31, 2016. Net income attributable to the CCCT Assets included in the Partnership's Consolidated Statements of Operations was $0, $43,804, and $10,880 for the years ended December 31, 2017, 2016, and 2015, respectively.

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

Divestiture of Floating Storage Assets. On February 12, 2015, the Partnership sold all six 16,101 barrel liquefied petroleum gas ("LPG") pressure barges, collectively referred to as the Floating Storage Assets for $41,250. These assets were acquired on February 28, 2013. The Partnership classified the results of operations of these assets, which were previously presented as a component of the Natural Gas Services segment, as discontinued operations in the Consolidated Statements of Operations for 2015. The Partnership has retrospectively adjusted its prior period consolidated financial statements to comparably classify the amounts related to the operations and cash flows of the Floating Storage Assets as discontinued operations. The Floating Storage Assets were presented as discontinued operations under the guidance prior to the Partnership's adoption of ASU 2014-08 related to discontinued operations. The adoption of the amended guidance was effective for the Partnership January 1, 2015.

The Floating Storage Assets’ operating results, which are included in income from discontinued operations for the year ended December 31, 2015, were as follows:

Total revenues from third parties	$	791
Total costs and expenses and other, net, excluding depreciation and amortization	1,038
Depreciation and amortization	—
Other operating income, net 1	1,462
Income (loss) from discontinued operations before income taxes	1,215
Income tax expense	—
Income (loss) from discontinued operations, net of income taxes	$	1,215

¹ Other operating income, net represents the gain on the disposition of the Floating Storage Assets.

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Inventories

12 Months Ended

Dec. 31, 2017

Inventory Disclosure [Abstract]

Inventories

Inventories

Components of inventories at December 31, 2017 and 2016 were as follows: 

	2017		2016
Natural gas liquids	$	47,462	$	33,656
Sulfur	8,436		8,521
Sulfur based products	18,674		19,107
Lubricants	20,086		18,276
Other	2,594		3,071
	$	97,252	$	82,631

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2017

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, Plant and Equipment

At December 31, 2017 and 2016, property, plant and equipment consisted of the following:

	Depreciable Lives	2017		2016
Land	—	$	21,719	$	20,679
Improvements to land and buildings	10-25 years	135,896		135,852
Storage equipment	5-50 years	178,815		168,839
Marine vessels	4-25 years	176,782		181,659
Operating plant and equipment	3-50 years	659,854		620,303
Base Gas	—	43,799		43,799
Furniture, fixtures and other equipment	3-20 years	11,134		19,034
Transportation equipment	3-7 years	1,535		1,738
Construction in progress		23,531		32,374
		$	1,253,065	$	1,224,277

Depreciation expense for the years ended December 31, 2017, 2016 and 2015 was $70,904, $72,405 and $67,134.

Additions to property, plant and equipment included in accounts payable at December 31, 2017 and 2016 were $4,100 and $1,819, respectively.

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Goodwill

12 Months Ended

Dec. 31, 2017

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill

Goodwill

The following table represents the goodwill balance at December 31, 2016, changes during the year, and the resulting balances at December 31, 2017:

	2017		2016
Carrying amount of goodwill:
Terminalling and storage	$	11,868	$	11,868
Natural gas services	79		79
Sulfur services	5,349		5,349
Total goodwill	$	17,296	$	17,296

During the impairment evaluation performed at August 31, 2017, the Partnership first assessed qualitative factors in determining whether it is more likely than not that the fair value of a reporting unit or other intangible asset is less than its carrying amount. After assessing qualitative factors, the Partnership determined that it is not more likely than not that the fair value of its reporting units are less than its carrying amount. Therefore, no impairment was recorded for the year ended December 31, 2017.

During the second quarter of 2016, the Partnership determined that the state of market conditions in the Marine Transportation reporting unit, including the demand for utilization, day rates and the current oversupply of inland tank barges, indicated that an impairment of goodwill may exist. As a result, the Partnership assessed qualitative factors and determined that the Partnership could not conclude it was more likely than not that the fair value of goodwill exceeded its carrying value. In turn, the Partnership prepared a quantitative analysis of the fair value of the goodwill as of June 30, 2016, based on the weighted average valuation of the aforementioned income and market based valuation approaches. The underlying results of the valuation were driven by actual results during the six months ended June 30, 2016 and the pricing and market conditions existing as of June 30, 2016, which were below forecasts at the time of the previous goodwill assessments. Other key estimates, assumptions and inputs used in the valuation included long-term growth rates, discounts rates, terminal values, valuation multiples and relative valuations when comparing the reporting unit to similar businesses or asset bases. Upon completion of the analysis, a $4,145 impairment of all goodwill in the Marine Transportation reporting unit was incurred during the second quarter of 2016. The Partnership did not recognize any other goodwill impairment losses for the year ended December 31, 2016.

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Leases

12 Months Ended

Dec. 31, 2017

Leases [Abstract]

Leases

Leases

The Partnership has numerous non-cancelable operating leases primarily for terminal facilities and transportation and other equipment. The leases generally provide that all expenses related to the equipment are to be paid by the lessee. Management expects to renew or enter into similar leasing arrangements for similar equipment upon the expiration of the current lease agreements. The Partnership also has cancelable operating lease land rentals and outside marine vessel charters.

The Partnership’s future minimum lease obligations as of December 31, 2017 consist of the following:

Fiscal year	Operating Leases
2018	$	6,841
2019	4,559
2020	3,715
2021	2,245
2022	1,079
Thereafter	7,750
Total	$	26,189

Rent expense for continuing operating leases for the years ended December 31, 2017, 2016 and 2015 was $15,908, $19,005 and $18,831, respectively.

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Investments in Unconsolidated Entities and Joint Ventures

12 Months Ended

Dec. 31, 2017

Equity Method Investments and Joint Ventures [Abstract]

Investments in Unconsolidated Entities and Joint Ventures

Investments in Unconsolidated Entities and Joint Ventures

The Partnership owns a 19.8% limited partnership and 0.2% general partnership interest in West Texas LPG Pipeline Limited Partnership ("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 Balance Sheet. 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 December 31,						Years ended December 31,
	Total Assets		Long-Term Debt		Members’ Equity/Partners' Capital		Revenues		Net Income
2017
WTLPG	$	837,163	$	—	$	787,426	$	87,048	$	21,571
2016
WTLPG	$	812,464	$	—	$	790,406	$	88,468	$	23,883
2015
WTLPG	$	819,342	$	—	$	804,023	$	100,708	$	46,294

As of December 31, 2017 and 2016, the Partnership’s interest in cash of the unconsolidated equity method investee was $5,585 and $631, respectively.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

The Partnership uses a valuation framework based upon inputs that market participants use in pricing certain assets and liabilities. These inputs are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources. Unobservable inputs represent the Partnership's own market assumptions. Unobservable inputs are used only if observable inputs are unavailable or not reasonably available without undue cost and effort. The two types of inputs are further prioritized into the following hierarchy:

Level 1: Quoted market prices in active markets for identical assets or liabilities.

Level 2: Observable market based inputs or unobservable inputs that are corroborated by market data.

Level 3: Unobservable inputs that reflect the entity's own assumptions and are not corroborated by market data.

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

	Level 2
	December 31,
	2017			2016
Commodity derivative contracts, net	$	(72	)	$	(3,904	)

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. The estimated fair value of the note receivable - affiliates was determined by calculating the net present value of the payments over the life of the note. The note is considered Level 3 due to the lack of observable inputs for similar transactions between related parties.

	December 31, 2017				December 31, 2016
	Carrying Value		Fair Value		Carrying Value		Fair Value
Note receivable - affiliates	$	—	$	—	$	15,000	$	15,797
2021 Senior unsecured notes	$	372,618	$	381,657	$	372,239	$	377,882

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Derivative Instruments and Hedging Activities

12 Months Ended

Dec. 31, 2017

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 December 31, 2017 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 145 barrels settling during the period from January 31, 2018 through February 28, 2018. At December 31, 2016, the Partnership had instruments totaling a gross notional quantity of 731 barrels settling during the period from January 1, 2017 through June 30, 2017. These instruments settle against the applicable pricing source for each grade and location. MET served as the counterparty for all positions outstanding at December 31, 2016.

(b)    Interest Rate Derivative Instruments

The Partnership is exposed to market risks associated with interest rates. Market risk is the adverse effect on the value of a financial instrument that results from a change in interest rates. We minimize this market risk by establishing and monitoring parameters that limit the types and degree of market risk that may be undertaken. The Partnership enters into interest rate swaps to manage interest rate risk associated with the Partnership’s variable rate credit facility and it's senior unsecured notes.

During the twelve months ended December 31, 2016 and 2015, the Partnership entered into contracts which provided the counterparty the option to enter into swap contracts to hedge the Partnership's exposure to changes in the fair value of its senior unsecured notes ("interest rate swaptions"). In connection with the interest rate swaption contracts, the Partnership received premiums of $630 and $2,495, which represented their fair value on the date the transactions were initiated and were initially recorded as derivative liabilities on the Partnership's Consolidated Balance Sheet, during the twelve months ended December 31, 2016 and 2015, respectively. Each of the interest rate swaptions was fully amortized as of December 31, 2016. Interest rate swaption contract premiums received are amortized over the period from initiation of the contract through their termination date. For the twelve months ended December 31, 2016 and 2015, the Partnership recognized $630 and $2,495, respectively, of premium in "Interest expense, net" on the Partnership's Consolidated Statement of Operations related to the interest rate swaption contracts.

     For information regarding fair value amounts and gains and losses on interest rate derivative instruments and related hedged items, see "Tabular Presentation of Gains and Losses on Derivative Instruments and Related Hedged Items" below.

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

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

	Fair Values of Derivative Instruments in the Consolidated Balance Sheet
	Derivative Assets					Derivative Liabilities
		Fair Values					Fair Values
	Balance Sheet Location	December 31, 2017		December 31, 2016		Balance Sheet Location	December 31, 2017		December 31, 2016
Derivatives not designated as hedging instruments:	Current:
Commodity contracts	Fair value of derivatives	$	—	$	—	Fair value of derivatives	$	72	$	3,904
Total derivatives not designated as hedging instruments		$	—	$	—		$	72	$	3,904

Effect of Derivative Instruments on the Consolidated Statement of Operations For the Twelve Months Ended December 31, 2017, 2016, and 2015

	Location of Gain or (Loss) Recognized in Income on Derivatives	Amount of (Gain) or Loss Recognized in Income on Derivatives
		2017		2016			2015
Derivatives not designated as hedging instruments:
Interest rate swaption contracts	Interest expense	$	—	$	(630	)	$	(2,495	)
Interest rate contracts	Interest expense	—		(366		)	206
Commodity contracts	Cost of products sold	1,304		5,129			(818		)
Total derivatives not designated as hedging instruments		$	1,304	$	4,133		$	(3,107	)

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Related Party Transactions

12 Months Ended

Dec. 31, 2017

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

As of December 31, 2017, Martin Resource Management owned 6,264,532 of the Partnership’s common units representing approximately 16.3% of the Partnership’s outstanding limited partnership units.  Martin Resource Management controls the Partnership's general partner by virtue of its 51% voting interest in Holdings, the sole member of the Partnership's general partner. The Partnership’s general partner, MMGP, owns a 2% general partner interest in the Partnership and the Partnership’s incentive distribution rights.  The Partnership’s general partner’s ability, as general partner, to manage and operate the Partnership, and Martin Resource Management’s ownership as of December 31, 2017, of approximately 16.3% of the Partnership’s outstanding limited partnership units, effectively gives Martin Resource Management the ability to veto some of the Partnership’s actions and to control the Partnership’s management.

The following is a description of the Partnership’s material related party agreements:

Omnibus Agreement

              Omnibus Agreement.  The Partnership and its general partner are parties to the Omnibus Agreement dated November 1, 2002, with Martin Resource Management that governs, among other things, potential competition and indemnification obligations among the parties to the agreement, related party transactions, the provision of general administration and support services by Martin Resource Management and the Partnership’s use of certain Martin Resource Management trade names and trademarks. The Omnibus Agreement was amended on November 25, 2009, to include processing crude oil into finished products including naphthenic lubricants, distillates, asphalt and other intermediate cuts. The Omnibus Agreement was amended further on October 1, 2012, to permit the Partnership to provide certain lubricant packaging products and services to Martin Resource Management.

Non-Competition Provisions. Martin Resource Management has agreed for so long as it controls the general partner of the Partnership, not to engage in the business of:

• providing terminalling and storage services for petroleum products and by-products including the refining, blending and packaging of finished lubricants;

•providing marine transportation of petroleum products and by-products;

•distributing NGLs; and

•manufacturing and selling sulfur-based fertilizer products and other sulfur-related products.

This restriction does not apply to:

• the ownership and/or operation on the Partnership’s behalf of any asset or group of assets owned by it or its affiliates;

• any business operated by Martin Resource Management, including the following:

◦ providing land transportation of various liquids;

◦ distributing fuel oil, 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; and

• any business that Martin Resource Management acquires or constructs where a portion of such business includes a restricted business and the fair market value of the restricted business is $5,000 or more and represents less than 20% of the aggregate value of the entire business to be acquired or constructed; provided that, following completion of the acquisition or construction, the Partnership will be provided the opportunity to purchase the restricted business.

Services.  Under the Omnibus Agreement, Martin Resource Management provides the Partnership with corporate staff, support services, and administrative services necessary to operate the Partnership’s business. The Omnibus Agreement requires the Partnership to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes on the Partnership’s behalf or in connection with the operation of the Partnership’s business. There is no monetary limitation on the amount the Partnership is required to reimburse Martin Resource Management for direct expenses.  In addition to the direct expenses, under the Omnibus Agreement, the Partnership is required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses.

Effective January 1, 2017, through December 31, 2017, the Conflicts Committee approved an annual reimbursement amount for indirect expenses of $16,416.  The Partnership reimbursed Martin Resource Management for $16,416, $13,033 and $13,679 of indirect expenses for the years ended December 31, 2017, 2016 and 2015, respectively.  The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.

These indirect expenses are intended to cover the centralized corporate functions Martin Resource Management provides for the Partnership, such as accounting, treasury, clerical, engineering, legal, billing, information technology, administration of insurance, general office expenses and employee benefit plans and other general corporate overhead functions the Partnership shares with Martin Resource Management retained businesses. The provisions of the Omnibus Agreement regarding Martin Resource Management’s services will terminate if Martin Resource Management ceases to control the general partner of the Partnership.

Related  Party Transactions. The Omnibus Agreement prohibits the Partnership from entering into any material agreement with Martin Resource Management without the prior approval of the Conflicts Committee. For purposes of the Omnibus Agreement, the term material agreements means any agreement between the Partnership and Martin Resource

Management that requires aggregate annual payments in excess of then-applicable agreed upon reimbursable amount of indirect general and administrative expenses. Please read "Services" above.

License Provisions. Under the Omnibus Agreement, Martin Resource Management has granted the Partnership a nontransferable, nonexclusive, royalty-free right and license to use certain of its trade names and marks, as well as the trade names and marks used by some of its affiliates.

Amendment and Termination. The Omnibus Agreement may be amended by written agreement of the parties; provided, however, that it may not be amended without the approval of the Conflicts Committee if such amendment would adversely affect the unitholders. The Omnibus Agreement was first amended on November 25, 2009, to permit the Partnership to provide refining services to Martin Resource Management.  The Omnibus Agreement was amended further on October 1, 2012, to permit the Partnership to provide certain lubricant packaging products and services to Martin Resource Management.  Such amendments were approved by the Conflicts Committee.  The Omnibus Agreement, other than the indemnification provisions and the provisions limiting the amount for which the Partnership will reimburse Martin Resource Management for general and administrative services performed on its behalf, will terminate if the Partnership is no longer an affiliate of Martin Resource Management.

Motor Carrier Agreement

Motor Carrier Agreement.  The Partnership is a party to a motor carrier agreement effective January 1, 2006 as amended, with Martin Transport, Inc., a wholly owned subsidiary of Martin Resource Management through which Martin Transport, Inc. operates its land transportation operations. Under the agreement, Martin Transport, Inc. agreed to transport the Partnership's NGLs as well as other liquid products.

Term and Pricing.  The agreement has an initial term that expired in December 2007 but automatically renews for consecutive one year periods unless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicable term.  The Partnership has the right to terminate this agreement at any time by providing 90 days prior notice.  Under this agreement, Martin Transport, Inc. transports the Partnership’s NGL shipments as well as other liquid products. These rates are subject to any adjustments which are mutually agreed or in accordance with a price index. Additionally, during the term of the agreement, shipping charges are also subject to fuel surcharges determined on a weekly basis in accordance with the U.S. Department of Energy’s national diesel price list.

Indemnification.  Martin Transport has indemnified us against all claims arising out of the negligence or willful misconduct of Martin Transport and its officers, employees, agents, representatives and subcontractors. We indemnified Martin Transport against all claims arising out of the negligence or willful misconduct of us and our officers, employees, agents, representatives and subcontractors. In the event a claim is the result of the joint negligence or misconduct of Martin Transport and us, our indemnification obligations will be shared in proportion to each party’s allocable share of such joint negligence or misconduct.

Marine Agreements

Marine Transportation Agreement. The Partnership is a party to a marine transportation agreement effective January 1, 2006, as amended, under which the Partnership provides marine transportation services to Martin Resource Management on a spot-contract basis at applicable market rates.  Effective each January 1, this agreement automatically renews for consecutive one year periods unless either party terminates the agreement by giving written notice to the other party at least 60 days prior to the expiration of the then applicable term. The fees the Partnership charges Martin Resource Management are based on applicable market rates.

Marine Fuel.  The Partnership is a party to an agreement with Martin Resource Management dated November 1, 2002 under which Martin Resource Management provides the Partnership with marine fuel from its locations in the Gulf of Mexico at a fixed rate in excess of a price index.  Under this agreement, the Partnership agreed to purchase all of its marine fuel requirements that occur in the areas serviced by Martin Resource Management.

Terminal Services Agreements

Diesel Fuel Terminal Services Agreement.  Effective January 1, 2016, the Partnership entered into a 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 Statements of Operations. The revenues, costs and expenses reflected in these tables are tabulations of the related party transactions that are recorded in the corresponding caption of the Consolidated Statements of Operations and do not reflect a statement of profits and losses for related party transactions.

The impact of related party revenues from sales of products and services is reflected in the Consolidated Statements of Operations as follows:

Revenues:	2017		2016		2015
Terminalling and storage	$	82,205	$	82,437	$	78,233
Marine transportation	16,801		21,767		27,724
Natural gas services	122		699		878
Product sales:
Natural gas services	1,043		8		196
Sulfur services	1,963		2,006		3,639
Terminalling and storage	572		1,020		1,836
	3,578		3,034		5,671
	$	102,706	$	107,937	$	112,506

The impact of related party cost of products sold is reflected in the Consolidated Statements of Operations as follows:

Cost of products sold:
Natural gas services	$	18,946	$	22,886	$	25,797
Sulfur services	15,564		15,339		16,579
Terminalling and storage	17,612		13,838		17,718
	$	52,122	$	52,063	$	60,094

The impact of related party operating expenses is reflected in the Consolidated Statements of Operations as follows:

Operating expenses:
Marine transportation	$	23,815	$	28,107	$	32,373
Natural gas services	9,007		9,258		8,639
Sulfur services	5,821		5,995		6,928
Terminalling and storage	25,701		27,481		29,931
	$	64,344	$	70,841	$	77,871

The impact of related party selling, general and administrative expenses is reflected in the Consolidated Statements of Operations as follows:

Selling, general and administrative:
Marine transportation	$	34	$	30	$	29
Natural gas services	8,162		7,566		6,216
Sulfur services	2,526		2,732		2,760
Terminalling and storage	2,278		2,526		2,284
Indirect overhead allocation, net of reimbursement	16,416		13,036		13,679
	$	29,416	$	25,890	$	24,968

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 Balance Sheets. Interest income for the years ended December 31, 2017, 2016, and 2015 was $943, $2,256 and $2,250, respectively, and is included in "Interest expense, net" in the Consolidated Statements of Operations.

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Supplemental Balance Sheet Information

12 Months Ended

Dec. 31, 2017

Balance Sheet Related Disclosures [Abstract]

Supplemental Balance Sheet Information

Supplemental Balance Sheet Information

Components of "Intangibles and other assets, net" at December 31, 2017 and 2016 were as follows:

	2017		2016
Customer contracts and relationships, net	$	25,252	$	36,528
Other intangible assets	1,752		2,280
Other	5,797		6,066
	$	32,801	$	44,874

Other intangible assets consist of covenants not-to-compete and technology-based assets.

Aggregate amortization expense for customer contracts and other intangible assets included in continuing operations was $13,887, $19,548, and $22,115, for the years ended December 31, 2017, 2016 and 2015, respectively, and accumulated amortization amounted to $39,462 and $48,876 at December 31, 2017 and 2016, respectively.

Estimated amortization expense for customer contract and relationships and other intangible assets for the years subsequent to December 31, 2017 are as follows: 2018 - $7,472; 2019 - $4,471; 2020 - $4,440; 2021 - $4,319; 2022 - $4,295; subsequent years - $2,007.

Components of "Other accrued liabilities" at December 31, 2017 and 2016 were as follows:

	2017		2016
Accrued interest	$	11,726	$	10,629
Asset retirement obligations	5,429		7,953
Property and other taxes payable	5,638		6,443
Accrued payroll	3,385		1,672
Other	162		20
	$	26,340	$	26,717

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

	Year Ended December 31,
	2017			2016
	(In thousands)
Beginning asset retirement obligations	$	16,418		$	2,163
Revisions to existing liabilities1	5,547			14,379
Accretion expense	404			178
Liabilities settled	(8,857		)	(302		)
Ending asset retirement obligations	13,512			16,418
Current portion of asset retirement obligations2	(5,429		)	(7,953		)
Long-term portion of asset retirement obligations3	$	8,083		$	8,465

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 2016 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 Balance Sheets.

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

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Long-Term Debt

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt

At December 31, 2017 and 2016, long-term debt consisted of the following:

	2017		2016
$664,444 Revolving credit facility at variable interest rate (4.55%1 weighted average at December 31, 2017), 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 $4,986 and $7,132, respectively3	$	440,014	$	435,868
$400,000 Senior notes, 7.25% interest, including unamortized premium of $956 and $1,262, respectively, also net of unamortized debt issuance costs of $2,138 and $2,823 respectively, issued $250,000 February 2013 and $150,000 April 2014, $26,200 repurchased during 2015, due February 2021, unsecured3,4	372,618		372,239
Total long-term debt	$	812,632	$	808,107

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 December 31, 2017 and 2016 were at LIBOR plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 2.00% to 3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 1.00% to 2.00%. The applicable margin for LIBOR borrowings at December 31, 2017 is 3.00%.  The credit facility contains various covenants which limit the Partnership’s ability to make certain investments and acquisitions; enter into certain agreements; incur indebtedness; sell assets; and make certain amendments to the Omnibus Agreement. The Partnership is permitted to make quarterly distributions so long as no event of default exists.

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

⁴ The 2021 indentures restrict the Partnership’s ability to sell assets; pay distributions or repurchase units or redeem or repurchase subordinated debt; make investments; incur or guarantee additional indebtedness or issue preferred units; and consolidate, merge or transfer all or substantially all of its assets. Many of these covenants will terminate if the notes achieve an investment grade rating from each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no default (as defined in the indentures) has occurred.

The Partnership paid cash interest, net of proceeds received from interest rate swaptions, in the amount of $45,728, $46,046, and $43,376 for the years ended December 31, 2017, 2016 and 2015, respectively. Capitalized interest was $730, $1,126, and $1,944 for the years ended December 31, 2017, 2016 and 2015, respectively.

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Partners' Capital

12 Months Ended

Dec. 31, 2017

Equity [Abstract]

Partners' Capital

Partners' Capital

As of December 31, 2017, partners’ capital consisted of 38,444,612 common limited partner units, representing a 98% partnership interest and a 2.0% general partner interest. Martin Resource Management, through subsidiaries, owned 6,264,532 of the Partnership's common limited partnership units representing approximately 16.3% of the Partnership's outstanding common limited partnership units. MMGP, the Partnership's general partner, owns the 2.0% general partnership interest.

The partnership agreement of the Partnership (the "Partnership Agreement") contains specific provisions for the allocation of net income and losses to each of the partners for purposes of maintaining their respective partner capital accounts.

Issuance of Common Units

On 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 $51,056. 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 2.0% general partner interest and certain incentive distribution rights ("IDRs") in the Partnership. IDRs are a separate class of non-voting limited partner interest that may be transferred or sold by the general partner under the terms of the Partnership Agreement, and represent the right to receive an increasing percentage of cash distributions after the minimum quarterly distribution and any cumulative arrearages on common units once certain target distribution levels have been achieved. The Partnership is required to distribute all of its available cash from operating surplus, as defined in the Partnership Agreement.

The target distribution levels entitle the general partner to receive 2.0% of quarterly cash distributions up to $0.55 per unit, 15% of quarterly cash distributions in excess of $0.55 per unit until all unitholders have received $0.625 per unit, 25% of quarterly cash distributions in excess of $0.625 per unit until all unitholders have received $0.75 per unit and 50% of quarterly cash distributions in excess of $0.75 per unit.

For the years ended December 31, 2017, 2016 and 2015, the general partner was allocated $0, $7,786, and $15,571 in incentive distributions.

Distributions of Available Cash

The Partnership distributes all of its available cash (as defined in the Partnership Agreement) within 45 days after the end of each quarter to unitholders of record and to the general partner. Available cash is generally defined as all cash and cash equivalents of the Partnership on hand at the end of each quarter less the amount of cash reserves its general partner determines in its reasonable discretion is necessary or appropriate to: (i) provide for the proper conduct of the Partnership’s business; (ii) comply with applicable law, any debt instruments or other agreements; or (iii) provide funds for distributions to unitholders and the general partner for any one or more of the next four quarters, plus all cash on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.

Net Income per Unit

The Partnership follows the provisions of the FASB ASC 260-10 related to earnings per share, which addresses the application of the two-class method in determining income per unit for master limited partnerships having multiple classes of securities that may participate in partnership distributions accounted for as equity distributions. Undistributed earnings are allocated to the general partner and limited partners utilizing the contractual terms of the Partnership Agreement. Distributions to the general partner pursuant to the IDRs are limited to available cash that will be distributed as defined in the Partnership Agreement. Accordingly, the Partnership does not allocate undistributed earnings to the general partner for the IDRs because the general partner's share of available cash is the maximum amount that the general partner would be contractually entitled to receive if all earnings for the period were distributed. When current period distributions are in excess of earnings, the excess distributions for the period are to be allocated to the general partner and limited partners based on their respective sharing of losses specified in the Partnership Agreement. Additionally, as required under FASB ASC 260-10-45-61A, unvested share-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities, as defined in FASB ASC 260-10-20, for earnings per unit calculations.

For purposes of computing diluted net income per unit, the Partnership uses the more dilutive of the two-class and if-converted methods. Under the if-converted method, the weighted-average number of subordinated units outstanding for the period is added to the weighted-average number of common units outstanding for purposes of computing basic net income per unit and the resulting amount is compared to the diluted net income per unit computed using the two-class method. The following is a reconciliation of net income from continuing operations and net income from discontinued operations allocated to the general partner and limited partners for purposes of calculating net income attributable to limited partners per unit:

	Years Ended December 31,
	2017			2016			2015
Continuing operations:
Income from continuing operations	$	17,135		$	31,652		$	37,165
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	—			7,786			15,078
Distributions payable on behalf of general partner interest	1,569			2,058			2,585
General partner interest in undistributed loss	(1,226		)	(1,425		)	(1,842		)
Less income allocable to unvested restricted units	42			90			136
Limited partners’ interest in net income	$	16,750		$	23,143		$	21,208

	Years Ended December 31,
	2017		2016		2015
Discontinued operations:
Income from discontinued operations	$	—	$	—	$	1,215
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	—		—		493
Distributions payable on behalf of general partner interest	—		—		84
General partner interest in undistributed loss	—		—		(60		)
Less income allocable to unvested restricted units	—		—		4
Limited partners’ interest in net income	$	—	$	—	$	694

The Partnership allocates the general partner's share of earnings between continuing and discontinued operations as a proportion of net income from continuing and discontinued operations to total net income.

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

	Years Ended December 31,
	2017	2016	2015
Basic weighted average limited partner units outstanding	38,101,583	35,347,032	35,308,649
Dilutive effect of restricted units issued	63,318	28,231	62,880
Total weighted average limited partner diluted units outstanding	38,164,901	35,375,263	35,371,529

All outstanding units were included in the computation of diluted earnings per unit and weighted based on the number of days such units were outstanding during the period presented.

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Unit Based Awards

12 Months Ended

Dec. 31, 2017

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

Unit Based Awards

Unit Based Awards

The Partnership recognizes compensation cost related to stock-based awards to employees in its consolidated financial statements in accordance with certain provisions of ASC 718. The Partnership recognizes compensation costs related to stock-based awards to directors under certain provisions of ASC 505-50-55 related to equity-based payments to non-employees.   Amounts recognized in selling, general, and administrative expense in the consolidated financial statements with respect to these plans are as follows:

	For the Year Ended December 31,
	2017		2016		2015
Employees	$	534	$	783	$	1,338
Non-employee directors	116		121		91
Total unit-based compensation expense	$	650	$	904	$	1,429

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 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. Once these restrictions lapse, the grantee is entitled to full ownership of the unit without restrictions. In addition, the restricted units will vest upon a change of control of the Partnership, the general partner or Martin Resource Management or if the general partner ceases to be an affiliate of Martin Resource Management. The Partnership intends the issuance of the common units upon vesting of the restricted units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive, and the Partnership will receive no remuneration for the units. The restricted units issued to directors generally vest in equal annual installments over a four-year period. Restricted units issued to employees generally cliff vest after three years of service.

 The restricted units are valued at their fair value at the date of grant which is equal to the market value of common units on such date. A summary of the restricted unit activity for the year ended December 31, 2017 is provided below:

	Number of Units			Weighted Average Grant-Date Fair Value Per Unit
Non-vested, beginning of year	103,800			$	26.54
Granted	12,000			$	19.00
Vested	(7,800		)	$	19.18
Forfeited	(9,250		)	$	28.50
Non-Vested, end of year	98,750			$	24.80
Aggregate intrinsic value, end of year	$	1,383

A summary of the restricted units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) during the years ended December 31, 2017, 2016 and 2015 is provided below:

	For the Year Ended December 31,
	2017		2016		2015
Aggregate intrinsic value of units vested	$	143	$	1,233	$	110
Fair value of units vested	$	208	$	1,773	$	128

As of December 31, 2017, there was $269 of unrecognized compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 0.8 years.

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Income Taxes

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The operations of a partnership are generally not subject to income taxes because its income is taxed directly to its partners.

The Partnership is subject to the Texas margin tax, which is considered a state income tax, and is included in income tax expense on the Consolidated Statements of Operations. Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed as an income tax and, therefore, the recognition of deferred taxes applies to the margin tax. The impact on deferred taxes as a result of this provision is immaterial. State income taxes attributable to the Texas margin tax of $352, $726 and $1,048 were recorded in income tax expense for the years ended December 31, 2017, 2016 and 2015, respectively.

A current income tax liability of $510, and $870 existed at December 31, 2017 and 2016, respectively.

Cash paid for income taxes was $712, $841, and $1,237 for the years ended December 31, 2017, 2016 and 2015, respectively.     

The Bipartisan Budget Act of 2015 provides that any tax adjustments resulting from partnership audits will generally be determined, and any resulting tax, interest and penalties collected, at the partnership level for tax years beginning after December 31, 2017. The Bipartisan Budget Act of 2015 allows a partnership to elect to apply these provisions to any return of the partnership filed for partnership taxable years beginning after the date of the enactment, November 2, 2015. The Partnership does not intend to elect to apply these provisions for any tax return filed for partnership taxable years beginning before January 1, 2018.

On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”) that makes significant changes to the U.S. Internal Revenue Code. Among other changes, the Tax Act includes a new deduction on certain pass-through income, a repeal of the partnership technical termination rule, and new limitations on certain deductions and credits, including interest expense deductions. Since the operations of a partnership are not subject to federal income tax, and most provisions of the Tax Act are effective for tax years beginning after December 31, 2017, the legislation has no material impact to the Partnership for 2017. We are in the process of analyzing the Tax Act and its possible effect going forward, as it will impact allocations to unitholders.

As of December 31, 2017, the tax years that remain open to assessment by federal and state jurisdictions are 2014-2016.

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Business Segments

12 Months Ended

Dec. 31, 2017

Segment Reporting [Abstract]

Business Segments

Business Segments

The Partnership has four reportable segments: terminalling and storage, natural gas services, marine transportation, and sulfur services. The Partnership’s reportable segments are strategic business units that offer different products and services. The operating income of these segments is reviewed by the chief operating decision maker to assess performance and make business decisions.

The accounting policies of the operating segments are the same as those described in Note 2. The Partnership evaluates the performance of its reportable segments based on operating income. There is no allocation of administrative expenses or interest expense.

The Natural Gas Services segment information below excludes the discontinued operations of the Floating Storage Assets for 2015. See Note 5.

	Operating Revenues		Intersegment Eliminations			Operating Revenues After Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures and Plant Turnaround Costs
Year Ended December 31, 2017:
Terminalling and storage	$	236,169	$	(5,998	)	$	230,171	$	45,160	$	629		$	29,644
Natural gas services	532,908		(226		)	532,682		24,916		51,663			7,430
Sulfur services	134,684		—			134,684		8,117		23,205			2,611
Marine transportation	51,915		(3,336		)	48,579		7,002		1,650			3,929
Indirect selling, general, and administrative	—		—			—		—		(17,332		)	—
Total	$	955,676	$	(9,560	)	$	946,116	$	85,195	$	59,815		$	43,614
Year Ended December 31, 2016:
Terminalling and storage	$	242,363	$	(5,653	)	$	236,710	$	45,484	$	40,660		$	26,097
Natural gas services	391,333		—			391,333		28,081		41,438			4,807
Sulfur services	141,058		—			141,058		7,995		23,393			5,093
Marine transportation	61,233		(2,943		)	58,290		10,572		(16,039		)	2,334
Indirect selling, general, and administrative	—		—			—		—		(16,794		)	—
Total	$	835,987	$	(8,596	)	$	827,391	$	92,132	$	72,658		$	38,331
Year Ended December 31, 2015:
Terminalling and storage	$	270,440	$	(5,670	)	$	264,770	$	38,731	$	15,704		$	40,421
Natural gas services	523,160		—			523,160		34,072		41,220			24,330
Sulfur services	170,161		—			170,161		8,455		23,604			1,201
Marine transportation	81,784		(3,031		)	78,753		10,992		8,576			2,775
Indirect selling, general, and administrative	—		—			—		—		(18,951		)	—
Total	$	1,045,545	$	(8,701	)	$	1,036,844	$	92,250	$	70,153		$	68,727

Revenues from two customers in the Natural Gas Services segment were $169,504, $122,381 and $148,273 for the years ended December 31, 2017, 2016 and 2015, respectively.

The Partnership's assets by reportable segment as of December 31, 2017 and 2016, are as follows:

	2017		2016
Total assets:
Terminalling and storage	$	326,920	$	328,098
Natural gas services	704,524		684,722
Sulfur services	120,790		125,356
Marine transportation	101,264		108,187
Total assets	$	1,253,498	$	1,246,363

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Quarterly Financial Information

12 Months Ended

Dec. 31, 2017

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Information

Quarterly Financial Information

Consolidated Quarterly Income Statement Information

	(Unaudited)
	First Quarter		Second Quarter			Third Quarter			Fourth Quarter
	(Dollar in thousands, except per unit amounts)
2017
Revenues	$	253,325	$	193,922		$	193,128		$	305,741
Operating income (loss)	23,748		10,848			(4,484		)	29,703
Equity in earnings of unconsolidated entities	905		853			789			1,767
Net income (loss)	13,583		989			(16,286		)	18,849
Limited partners' interest in net income (loss) per limited partner unit	0.36		0.03			(0.42		)	0.47
	First Quarter		Second Quarter			Third Quarter			Fourth Quarter
	(Dollar in thousands, except per unit amounts)
2016
Revenues	$	225,605	$	190,348		$	174,537		$	236,901
Operating income	24,338		10,256			9,176			28,888
Equity in earnings of unconsolidated entities	1,677		805			1,120			1,112
Net income (loss)	15,914		(1,211		)	(933		)	17,882
Limited partners' interest in net income (loss) per limited partner unit	0.33		(0.14		)	(0.03		)	0.49

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments 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 will reimburse the Partnership $750 each quarter for four consecutive quarters as a reduction in the purchase price of the Redbird Class A interests.  These payments are a result of Cardinal Gas Storage Partners LLC ("Cardinal") not achieving certain financial targets set forth in the Purchase Price Reimbursement Agreement.  These payments are considered a reduction of the excess of the purchase price over the carrying value of the assets transferred to the Partnership from Martin Resource Management and will be recorded as an adjustment to "Partners' capital" in each quarter the payments are made. The agreement further provided for purchase price reimbursements of up to $4,500 in 2016 in the event certain financial conditions were not met. For the year ended December 31, 2017 and 2016, the Partnership received $1,125 and $4,125, respectively, 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.

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. At December 31, 2017, the 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 whereby we have committed certain terminalling and storage assets in exchange for a minimum fee. Future minimum revenues we expect to receive under these non-cancelable arrangements as of December 31, 2017, are as follows: 2018 - $14,172; 2019 - $11,190; 2020 - $9,053; 2021 - $6,200; 2022 - $5,187; subsequent years - $12,072.

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Condensed Consolidating Financial Information

12 Months Ended

Dec. 31, 2017

Consolidating Financial Statements [Abstract]

Condensed Consolidating Financial Information

Condensed Consolidating 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

12 Months Ended

Dec. 31, 2017

Subsequent Events [Abstract]

Subsequent Events

Subsequent EventsQuarterly Distribution.  On January 18, 2018, the Partnership declared a quarterly cash distribution of $0.50 per common unit for the fourth quarter of 2017, or $2.00 per common unit on an annualized basis, which was paid on February 14, 2018 to unitholders of record as of February 7, 2018.

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Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Principles of Presentation and Consolidation

Principles of Presentation and Consolidation

The consolidated financial statements include the financial statements of the Partnership and its wholly-owned subsidiaries and equity method investees.  In the opinion of the management of the Partnership’s general partner, all adjustments and elimination of significant intercompany balances necessary for a fair presentation of the Partnership’s results of operations, financial position and cash flows for the periods shown have been made.  All such adjustments are of a normal recurring nature.  In addition, the Partnership evaluates its relationships with other entities to identify whether they are variable interest entities under certain provisions of the Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC"), 810-10 and to assess whether it is the primary beneficiary of such entities.  If the determination is made that the Partnership is the primary beneficiary, then that entity is included in the consolidated financial statements in accordance with ASC 810-10.  No such variable interest entities exist as of December 31, 2017 or 2016.

As discussed in Note 5, on February 12, 2015, the Partnership sold all six 16,101 barrel liquefied petroleum gas ("LPG") pressure barges, collectively referred to as the "Floating Storage Assets." These assets were acquired on February 28, 2013. On December 19, 2014, the Partnership made the decision to dispose of the Floating Storage Assets. As a result, the Partnership has presented the results of operations and cash flows of the Floating Storage Assets as discontinued operations for the year ended December 31, 2015.

Product Exchanges

Product ExchangesThe Partnership enters into product exchange agreements with third parties, whereby the Partnership agrees to exchange natural gas liquids ("NGLs") and sulfur with third parties.  The Partnership records the balance of exchange products due to other companies under these agreements at quoted market product prices and the balance of exchange products due from other companies at the lower of cost or market.  Cost is determined using the first-in, first-out ("FIFO") method.  Product exchanges with the same counterparty are entered into in contemplation of one another and are combined. The net amount related to location differentials is reported in "Product sales" or "Cost of products sold" in the Consolidated Statements of Operations.

Inventories

InventoriesInventories are stated at the lower of cost or market.  Cost is generally determined by using the FIFO method for all inventories except lubricants and lubricants packaging inventories. Lubricants and lubricants packaging inventories cost is determined using standard cost, which approximates actual cost, computed on a FIFO basis.

Revenue Recognition

Revenue Recognition

Terminalling and Storage – Revenue is recognized for storage contracts based on the contracted monthly tank fixed fee.  For throughput contracts, revenue is recognized based on the volume moved through the Partnership’s terminals at the contracted rate.  For the Partnership’s tolling agreement, revenue is recognized based on the contracted monthly reservation fee and throughput volumes moved through the facility.  When lubricants and drilling fluids are sold by truck or rail, revenue is recognized upon delivering product to the customers as title to the product transfers when the customer physically receives the product.

Natural Gas Services – NGL distribution revenue is recognized when product is delivered by truck, rail, or pipeline to the Partnership's NGL customers. Natural gas storage revenue is recognized when the service is provided to the customer.

Sulfur Services – Revenue from sulfur product sales is recognized when the customer takes title to the product.   Revenue from sulfur services is recognized as deliveries are made during each monthly period.

Marine Transportation – Revenue is recognized for time charters based on a per day rate. For contracted trips, revenue is recognized upon completion of the particular trip.

Equity Method Investments

Equity Method Investments

The Partnership uses the equity method of accounting for investments in unconsolidated entities where the ability to exercise significant influence over such entities exists.  Investments in unconsolidated entities consist of capital contributions and advances plus the Partnership’s share of accumulated earnings as of the entities’ latest fiscal year-ends, less capital withdrawals and distributions.  Equity method investments are subject to impairment under the provisions of ASC 323-10, which relates to the equity method of accounting for investments in common stock.  No portion of the net income from these entities is included in the Partnership’s operating income.

Property, Plant and Equipment

Property, Plant, and Equipment

Owned property, plant, and equipment is stated at cost, less accumulated depreciation.  Owned buildings and equipment are depreciated using straight-line method over the estimated lives of the respective assets.

Equipment under capital leases is stated at the present value of minimum lease payments less accumulated amortization. Equipment under capital leases is amortized on a straight line basis over the estimated useful life of the asset.

Routine maintenance and repairs are charged to expense while costs of betterments and renewals are capitalized.  When an asset is retired or sold, its cost and related accumulated depreciation are removed from the accounts, and the difference between net book value of the asset and proceeds from disposition is recognized as gain or loss.

Goodwill and Other Intangible Assets

Goodwill and Other Intangible Assets

Goodwill is subject to a fair-value based impairment test on an annual basis, or more often if events or circumstances indicate there may be impairment. The Partnership is required to identify its reporting units and determine the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets. The Partnership is required to determine the fair value of each reporting unit and compare it to the carrying amount of the reporting unit. To the extent the carrying amount of a reporting unit exceeds the fair value of the reporting unit, the Partnership will record the amount of goodwill impairment as the excess of a reporting unit's carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit.

When assessing the recoverability of goodwill and other intangible assets, the Partnership may first assess qualitative factors in determining whether it is more likely than not that the fair value of a reporting unit or other intangible asset is less than its carrying amount. After assessing qualitative factors, if the Partnership determines that it is not more likely than not that the fair value of a reporting unit or other intangible asset is less than its carrying amount, then performing a quantitative assessment is not required. If an initial qualitative assessment indicates that it is more likely than not the carrying amount exceeds the fair value of a reporting unit or other intangible asset, a quantitative analysis will be performed. The Partnership may also elect to bypass the qualitative assessment and proceed directly to a quantitative analysis depending on the facts and circumstances.

Of the Partnership's four reporting units, the terminalling and storage, natural gas services, and sulfur services reporting units contain goodwill. No goodwill impairment was recorded for the year ended December 31, 2017. During the second quarter of 2016, the Partnership experienced an impairment of all the goodwill in the Partnership's marine transportation reporting unit. See Note 8 for more information.

In performing a quantitative analysis, recoverability of goodwill for each reporting unit is measured using a weighting of the discounted cash flow method and two market approaches (the guideline public company method and the guideline transaction method). The discounted cash flow model incorporates discount rates commensurate with the risks involved. Use of a discounted cash flow model is common practice in assessing impairment in the absence of available transactional market evidence to determine the fair value. The key assumptions used in the discounted cash flow valuation model include discount rates, growth rates, cash flow projections and terminal value rates. Discount rates, growth rates and cash flow projections are the most sensitive and susceptible to change as they require significant management judgment. Discount rates are determined by using a weighted average cost of capital ("WACC"). The WACC considers market and industry data as well as company-specific risk factors for each reporting unit in determining the appropriate discount rate to be used. The discount rate utilized for each reporting unit is indicative of the return an investor would expect to receive for investing in such a business. Management, considering industry and company specific historical and projected data, develops growth rates and cash flow projections for each reporting unit. Terminal value rate determination follows common methodology of capturing the present value of perpetual cash flow estimates beyond the last projected period assuming a constant WACC and low long-term growth rates. If the calculated fair value is less than the current carrying amount, the Partnership will record the amount of goodwill impairment as the excess of a reporting unit's carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit.

Significant changes in these estimates and assumptions could materially affect the determination of fair value for each reporting unit which could give rise to future impairment. Changes to these estimates and assumptions can include, but may not be limited to, varying commodity prices, volume changes and operating costs due to market conditions and/or alternative providers of services.

Other intangible assets that have finite lives are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable. An impairment is indicated if the carrying amount of a long-lived intangible asset exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If impairment is indicated, the Partnership would record an impairment loss equal to the difference between the carrying value and the fair value of the asset.

Debt Issuance Costs

Debt Issuance Costs

Debt issuance costs relating to the Partnership’s revolving credit facility and senior unsecured notes are deferred and amortized over the terms of the debt arrangements and are shown, net of accumulated amortization, as a reduction of the related long-term debt.

In connection with the issuance, amendment, expansion and restatement of debt arrangements, the Partnership incurred debt issuance costs of $66, $5,274 and $341 in the years ended December 31, 2017, 2016 and 2015, respectively.

During 2016, the Partnership made certain strategic amendments to its credit facility which, among other things, decreased its borrowing capacity from $700,000 to $664,444 and extended the maturity date of the facility from March 28, 2018 to March 28, 2020. In connection with the amendment, the Partnership expensed $820 of unamortized debt issuance costs determined not to have continuing benefit.

During 2015, the Partnership repurchased on the open market an aggregate $26,200 of 7.25% senior unsecured notes. The repurchase transaction resulted in the write-off of $235 of existing debt issuance costs that were determined not to have continuing benefit. On August 14, 2015, the Partnership reduced its borrowing capacity under the revolving credit facility from $900,000 to $700,000, resulting in the write-off of $1,625 of deferred debt costs that were determined not to have continuing benefit.

Remaining unamortized deferred issuance costs are amortized over the term of each respective revised debt arrangement.

Impairment of Long-Lived Assets

Impairment of Long-Lived Assets

In accordance with ASC 360-10, long-lived assets, such as property, plant and equipment, and intangible assets with definite lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset.  If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset.  Assets to be disposed of would be separately presented in the balance sheet and reported at the lower of the carrying amount or fair value less costs to sell and would no longer be depreciated.  The assets and liabilities of a disposed group classified as held for sale would be presented separately in the appropriate asset and liability sections of the balance sheet.  

Asset Retirement Obligations

Asset Retirement Obligations

Under ASC 410-20, which relates to accounting requirements for costs associated with legal obligations to retire tangible, long-lived assets, the Partnership records an asset retirement obligation ("ARO") at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted over time towards the ultimate obligation amount and the capitalized costs are depreciated over the useful life of the related asset.  

Derivative Instruments and Hedging Activities

Derivative Instruments and Hedging Activities

In accordance with certain provisions of ASC 815-10 related to accounting for derivative instruments and hedging activities, all derivatives and hedging instruments are included in the Consolidated Balance Sheets as an asset or liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings.

Derivative instruments not designated as hedges are marked to market with all market value adjustments being recorded in the Consolidated Statements of Operations.

Use of Estimates

Use of EstimatesManagement has made a number of estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with accounting principles generally accepted in the U.S.  Actual results could differ from those estimates.

Indirect Selling, General and Administrative Expense

Indirect Selling, General and Administrative ExpensesIndirect selling, general and administrative expenses are incurred by Martin Resource Management and allocated to the Partnership to cover costs of centralized corporate functions such as accounting, treasury, engineering, information technology, risk management and other corporate services.  Such expenses are based on the percentage of time spent by Martin Resource Management’s personnel that provide such centralized services.  Under an omnibus agreement with Martin Resource Management, the Partnership is required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses.  For the years ended December 31, 2017, 2016 and 2015, the conflicts committee of the Partnership's general partner ("Conflicts Committee") approved reimbursement amounts of  $16,416, $13,033 and $13,679, respectively, reflecting the Partnership's allocable share of such expenses.  The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.

Environmental Liabilities and Litigation

Environmental Liabilities and LitigationThe Partnership’s policy is to accrue for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable.  Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study.  Such accruals are adjusted as further information develops or circumstances change.  Costs of future expenditures for environmental remediation obligations are not discounted to their present value.  Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable.

Trade and Accrued Accounts Receivable and Allowance for Doubtful Accounts

Trade and Accrued Accounts Receivable and Allowance for Doubtful Accounts.Trade accounts receivable are recorded at the invoiced amount and do not bear interest.  The allowance for doubtful accounts is the Partnership’s best estimate of the amount of probable credit losses in the Partnership’s existing accounts receivable.

Deferred Catalyst Costs

Deferred Catalyst CostsThe cost of the periodic replacement of catalysts is deferred and amortized over the catalyst’s estimated useful life, which ranges from 12 to 36 months.

Deferred Turnaround Costs

Deferred Turnaround CostsThe Partnership capitalizes the cost of major turnarounds and amortizes these costs over the estimated period to the next turnaround, which ranges from 12 to 36 months.

Income Taxes

Income Taxes

The Partnership is subject to the Texas margin tax, which is considered a state income tax, and is included in income tax expense on the Consolidated Statements of Operations. Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed as an income tax and, therefore, the recognition of deferred taxes applies to the margin tax. The impact on deferred taxes as a result of this provision is immaterial.

Comprehensive Income

Comprehensive IncomeComprehensive income includes net income and other comprehensive income.  There are no items of other comprehensive income or loss in any of the years presented.

Recent Accounting Pronouncements

Recent Accounting Pronouncements

In January 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2017-04 “Intangibles-Goodwill and other: Simplifying the test for goodwill impairment.” This ASU removes the second step of the two-step test currently required under the current guidance. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit's carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance does not amend the optional qualitative assessment of goodwill impairment. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. The Partnership elected to early adopt this amended guidance effective January 1, 2017. The Partnership expects that adoption of this standard will change its approach for testing goodwill for impairment if a triggering event is identified; however, this standard requires prospective application and therefore will only impact periods subsequent to adoption.

In August 2016, the Financial Accounting Standards Board FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments. This ASU is intended to clarify the presentation of cash receipts and payments in specific situations. The amendments in this ASU are effective for financial statements issued for annual periods beginning after December 15, 2017, including interim periods within those annual periods, and early application is permitted. The Partnership does not anticipate that ASU 2016-15 will have a material effect on its consolidated financial statements and related disclosures.

In February 2016, the FASB issued ASU 2016-02, Leases.  This ASU amends the existing accounting standards for lease accounting, including requiring lessees to recognize most leases on their balance sheets and making targeted changes to lessor accounting. ASU 2016-02 is effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period. Early adoption of this standard is permitted. The standard requires a modified retrospective transition approach for all leases existing at, or entered into after, the date of initial application, with an option to use certain transition relief.  The Partnership is evaluating the effect that ASU 2016-02 will have on its consolidated financial statements and related disclosures.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective. The new standard is effective for the Partnership on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method. The Partnership plans to adopt 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 has completed a review of the impacts of the application of the new standard to its existing portfolio of customer contracts and has concluded its process of evaluating its new controls and processes designed to comply with ASU 2014-09 throughout 2017 to permit adoption by January 1, 2018. The Partnership's approach included performing a detailed review of key contracts representative of its different businesses and comparing historical accounting policies and practices to the new standard.

In the Terminalling and Storage segment, revenue will continue to be recognized for storage contracts based on the contracted monthly tank fixed fee.  For throughput contracts, revenue will continue to be recognized based on the volume moved through the Partnership’s terminals at the contracted rate.  For the Partnership’s tolling agreement, revenue will continue to be 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 will continue to be recognized upon delivering product to the customers as title to the product transfers when the customer physically receives the product. Delivery of product is invoiced as the transaction occurs and are generally paid within a month.

In the Natural Gas Services segment, NGL distribution revenue will continue to be recognized when product is delivered by truck, rail, or pipeline to the Partnership's NGL customers. Revenue will continue to be 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 will continue to be recognized when the service is provided to the customer. The performance of the service is invoiced as the transaction occurs and are generally paid within a month.

In the Sulfur Services segment, revenue from sulfur product sales will continue to be 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 will continue to be recognized as deliveries are made during each monthly period. The performance of the service is invoiced as the transaction occurs and are generally paid within a month.

In the Marine Transportation segment, revenue will continue to be recognized for time charters based on a per day rate. For contracted trips, revenue will continue to be recognized upon completion of the particular trip. The performance of the service is invoiced as the transaction occurs and are generally paid within a month.

Additionally, the Partnership will be required to assess variable consideration included in its contracts and make judgments and estimates throughout the applicable periods. Certain additional financial statement disclosure requirements are mandated by the new standard including disclosure of contract assets and contract liabilities as well as a disaggregated view of revenue. Based on the Partnership’s analysis, the adoption of this guidance will not have a significant impact on its consolidated financial statements.

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Acquisitions (Tables)

12 Months Ended

Dec. 31, 2017

Business Combinations [Abstract]

Schedule of Business Acquisitions

Purchase price	$	27,420
Historical carrying value of assets allocated to "Property, plant and equipment"	19,533
Excess purchase price over carrying value of acquired assets	$	7,887

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Discontinued Operations, Divestitures, and Assets Held for Sale (Tables)

12 Months Ended

Dec. 31, 2017

Discontinued Operations and Disposal Groups [Abstract]

Disclosure of long lived assets held-for-sale

At December 31, 2017 and 2016, the assets met the criteria to be classified as held for sale in accordance with ASC 360-10 and are presented at the assets' fair value less cost to sell by segment in current assets as follows:

	December 31, 2017		December 31, 2016
Terminalling and storage	$	4,152	$	10,852
Marine transportation	5,427		4,927
Assets held for sale	$	9,579	$	15,779

Schedule of disposal groups including discontinued operations income statement and balance sheet

The Floating Storage Assets’ operating results, which are included in income from discontinued operations for the year ended December 31, 2015, were as follows:

Total revenues from third parties	$	791
Total costs and expenses and other, net, excluding depreciation and amortization	1,038
Depreciation and amortization	—
Other operating income, net 1	1,462
Income (loss) from discontinued operations before income taxes	1,215
Income tax expense	—
Income (loss) from discontinued operations, net of income taxes	$	1,215

¹ Other operating income, net represents the gain on the disposition of the Floating Storage Assets.

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Inventories (Tables)

12 Months Ended

Dec. 31, 2017

Inventory Disclosure [Abstract]

Components of inventory

Components of inventories at December 31, 2017 and 2016 were as follows: 

	2017		2016
Natural gas liquids	$	47,462	$	33,656
Sulfur	8,436		8,521
Sulfur based products	18,674		19,107
Lubricants	20,086		18,276
Other	2,594		3,071
	$	97,252	$	82,631

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2017

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

At December 31, 2017 and 2016, property, plant and equipment consisted of the following:

	Depreciable Lives	2017		2016
Land	—	$	21,719	$	20,679
Improvements to land and buildings	10-25 years	135,896		135,852
Storage equipment	5-50 years	178,815		168,839
Marine vessels	4-25 years	176,782		181,659
Operating plant and equipment	3-50 years	659,854		620,303
Base Gas	—	43,799		43,799
Furniture, fixtures and other equipment	3-20 years	11,134		19,034
Transportation equipment	3-7 years	1,535		1,738
Construction in progress		23,531		32,374
		$	1,253,065	$	1,224,277

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Goodwill (Tables)

12 Months Ended

Dec. 31, 2017

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill

The following table represents the goodwill balance at December 31, 2016, changes during the year, and the resulting balances at December 31, 2017:

	2017		2016
Carrying amount of goodwill:
Terminalling and storage	$	11,868	$	11,868
Natural gas services	79		79
Sulfur services	5,349		5,349
Total goodwill	$	17,296	$	17,296

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Leases (Tables)

12 Months Ended

Dec. 31, 2017

Leases [Abstract]

Schedule of Future Minimum Obligations

The Partnership’s future minimum lease obligations as of December 31, 2017 consist of the following:

Fiscal year	Operating Leases
2018	$	6,841
2019	4,559
2020	3,715
2021	2,245
2022	1,079
Thereafter	7,750
Total	$	26,189

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Investments in Unconsolidated Entities and Joint Ventures (Tables)

12 Months Ended

Dec. 31, 2017

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 December 31,						Years ended December 31,
	Total Assets		Long-Term Debt		Members’ Equity/Partners' Capital		Revenues		Net Income
2017
WTLPG	$	837,163	$	—	$	787,426	$	87,048	$	21,571
2016
WTLPG	$	812,464	$	—	$	790,406	$	88,468	$	23,883
2015
WTLPG	$	819,342	$	—	$	804,023	$	100,708	$	46,294

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

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

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

	Level 2
	December 31,
	2017			2016
Commodity derivative contracts, net	$	(72	)	$	(3,904	)

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. The estimated fair value of the note receivable - affiliates was determined by calculating the net present value of the payments over the life of the note. The note is considered Level 3 due to the lack of observable inputs for similar transactions between related parties.

	December 31, 2017				December 31, 2016
	Carrying Value		Fair Value		Carrying Value		Fair Value
Note receivable - affiliates	$	—	$	—	$	15,000	$	15,797
2021 Senior unsecured notes	$	372,618	$	381,657	$	372,239	$	377,882

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Derivative Instruments and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Effect of derivative instruments on the Consolidated Balance Sheets

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

	Fair Values of Derivative Instruments in the Consolidated Balance Sheet
	Derivative Assets					Derivative Liabilities
		Fair Values					Fair Values
	Balance Sheet Location	December 31, 2017		December 31, 2016		Balance Sheet Location	December 31, 2017		December 31, 2016
Derivatives not designated as hedging instruments:	Current:
Commodity contracts	Fair value of derivatives	$	—	$	—	Fair value of derivatives	$	72	$	3,904
Total derivatives not designated as hedging instruments		$	—	$	—		$	72	$	3,904

Effect of derivative instruments on the Consolidated Statement of Operations

Effect of Derivative Instruments on the Consolidated Statement of Operations For the Twelve Months Ended December 31, 2017, 2016, and 2015

	Location of Gain or (Loss) Recognized in Income on Derivatives	Amount of (Gain) or Loss Recognized in Income on Derivatives
		2017		2016			2015
Derivatives not designated as hedging instruments:
Interest rate swaption contracts	Interest expense	$	—	$	(630	)	$	(2,495	)
Interest rate contracts	Interest expense	—		(366		)	206
Commodity contracts	Cost of products sold	1,304		5,129			(818		)
Total derivatives not designated as hedging instruments		$	1,304	$	4,133		$	(3,107	)

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2017

Related Party Transactions [Abstract]

The Impact of Related Party Transactions

The impact of related party revenues from sales of products and services is reflected in the Consolidated Statements of Operations as follows:

Revenues:	2017		2016		2015
Terminalling and storage	$	82,205	$	82,437	$	78,233
Marine transportation	16,801		21,767		27,724
Natural gas services	122		699		878
Product sales:
Natural gas services	1,043		8		196
Sulfur services	1,963		2,006		3,639
Terminalling and storage	572		1,020		1,836
	3,578		3,034		5,671
	$	102,706	$	107,937	$	112,506

The impact of related party cost of products sold is reflected in the Consolidated Statements of Operations as follows:

Cost of products sold:
Natural gas services	$	18,946	$	22,886	$	25,797
Sulfur services	15,564		15,339		16,579
Terminalling and storage	17,612		13,838		17,718
	$	52,122	$	52,063	$	60,094

The impact of related party operating expenses is reflected in the Consolidated Statements of Operations as follows:

Operating expenses:
Marine transportation	$	23,815	$	28,107	$	32,373
Natural gas services	9,007		9,258		8,639
Sulfur services	5,821		5,995		6,928
Terminalling and storage	25,701		27,481		29,931
	$	64,344	$	70,841	$	77,871

The impact of related party selling, general and administrative expenses is reflected in the Consolidated Statements of Operations as follows:

Selling, general and administrative:
Marine transportation	$	34	$	30	$	29
Natural gas services	8,162		7,566		6,216
Sulfur services	2,526		2,732		2,760
Terminalling and storage	2,278		2,526		2,284
Indirect overhead allocation, net of reimbursement	16,416		13,036		13,679
	$	29,416	$	25,890	$	24,968

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Supplemental Balance Sheet Information (Tables)

12 Months Ended

Dec. 31, 2017

Balance Sheet Related Disclosures [Abstract]

Schedule of Intangible and Other Assets, Net

Components of "Intangibles and other assets, net" at December 31, 2017 and 2016 were as follows:

	2017		2016
Customer contracts and relationships, net	$	25,252	$	36,528
Other intangible assets	1,752		2,280
Other	5,797		6,066
	$	32,801	$	44,874

Schedule of Other Accrued Liabilities

Components of "Other accrued liabilities" at December 31, 2017 and 2016 were as follows:

	2017		2016
Accrued interest	$	11,726	$	10,629
Asset retirement obligations	5,429		7,953
Property and other taxes payable	5,638		6,443
Accrued payroll	3,385		1,672
Other	162		20
	$	26,340	$	26,717

Schedule of Asset Retirement Obligations

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

	Year Ended December 31,
	2017			2016
	(In thousands)
Beginning asset retirement obligations	$	16,418		$	2,163
Revisions to existing liabilities1	5,547			14,379
Accretion expense	404			178
Liabilities settled	(8,857		)	(302		)
Ending asset retirement obligations	13,512			16,418
Current portion of asset retirement obligations2	(5,429		)	(7,953		)
Long-term portion of asset retirement obligations3	$	8,083		$	8,465

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 2016 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 Balance Sheets.

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

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Schedule of long-term debt

At December 31, 2017 and 2016, long-term debt consisted of the following:

	2017		2016
$664,444 Revolving credit facility at variable interest rate (4.55%1 weighted average at December 31, 2017), 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 $4,986 and $7,132, respectively3	$	440,014	$	435,868
$400,000 Senior notes, 7.25% interest, including unamortized premium of $956 and $1,262, respectively, also net of unamortized debt issuance costs of $2,138 and $2,823 respectively, issued $250,000 February 2013 and $150,000 April 2014, $26,200 repurchased during 2015, due February 2021, unsecured3,4	372,618		372,239
Total long-term debt	$	812,632	$	808,107

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 December 31, 2017 and 2016 were at LIBOR plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 2.00% to 3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 1.00% to 2.00%. The applicable margin for LIBOR borrowings at December 31, 2017 is 3.00%.  The credit facility contains various covenants which limit the Partnership’s ability to make certain investments and acquisitions; enter into certain agreements; incur indebtedness; sell assets; and make certain amendments to the Omnibus Agreement. The Partnership is permitted to make quarterly distributions so long as no event of default exists.

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

⁴ The 2021 indentures restrict the Partnership’s ability to sell assets; pay distributions or repurchase units or redeem or repurchase subordinated debt; make investments; incur or guarantee additional indebtedness or issue preferred units; and consolidate, merge or transfer all or substantially all of its assets. Many of these covenants will terminate if the notes achieve an investment grade rating from each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no default (as defined in the indentures) has occurred.

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Partners' Capital (Tables)

12 Months Ended

Dec. 31, 2017

Equity [Abstract]

Reconciliation of net income to partners interest in net income

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

	Years Ended December 31,
	2017			2016			2015
Continuing operations:
Income from continuing operations	$	17,135		$	31,652		$	37,165
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	—			7,786			15,078
Distributions payable on behalf of general partner interest	1,569			2,058			2,585
General partner interest in undistributed loss	(1,226		)	(1,425		)	(1,842		)
Less income allocable to unvested restricted units	42			90			136
Limited partners’ interest in net income	$	16,750		$	23,143		$	21,208

	Years Ended December 31,
	2017		2016		2015
Discontinued operations:
Income from discontinued operations	$	—	$	—	$	1,215
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	—		—		493
Distributions payable on behalf of general partner interest	—		—		84
General partner interest in undistributed loss	—		—		(60		)
Less income allocable to unvested restricted units	—		—		4
Limited partners’ interest in net income	$	—	$	—	$	694

The Partnership allocates the general partner's share of earnings between continuing and discontinued operations as a proportion of net income from continuing and discontinued operations to total net income.

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

	Years Ended December 31,
	2017	2016	2015
Basic weighted average limited partner units outstanding	38,101,583	35,347,032	35,308,649
Dilutive effect of restricted units issued	63,318	28,231	62,880
Total weighted average limited partner diluted units outstanding	38,164,901	35,375,263	35,371,529

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Unit Based Awards (Tables)

12 Months Ended

Dec. 31, 2017

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

Schedule of compensation costs related to unit based plan

Amounts recognized in selling, general, and administrative expense in the consolidated financial statements with respect to these plans are as follows:

	For the Year Ended December 31,
	2017		2016		2015
Employees	$	534	$	783	$	1,338
Non-employee directors	116		121		91
Total unit-based compensation expense	$	650	$	904	$	1,429

Summary of restricted unit activity

A summary of the restricted unit activity for the year ended December 31, 2017 is provided below:

	Number of Units			Weighted Average Grant-Date Fair Value Per Unit
Non-vested, beginning of year	103,800			$	26.54
Granted	12,000			$	19.00
Vested	(7,800		)	$	19.18
Forfeited	(9,250		)	$	28.50
Non-Vested, end of year	98,750			$	24.80
Aggregate intrinsic value, end of year	$	1,383

Summary of aggregate intrinsic value and fair value of units vested

A summary of the restricted units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) during the years ended December 31, 2017, 2016 and 2015 is provided below:

	For the Year Ended December 31,
	2017		2016		2015
Aggregate intrinsic value of units vested	$	143	$	1,233	$	110
Fair value of units vested	$	208	$	1,773	$	128

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Business Segments (Tables)

12 Months Ended

Dec. 31, 2017

Segment Reporting [Abstract]

Schedule of segment reporting information, by segment

The Natural Gas Services segment information below excludes the discontinued operations of the Floating Storage Assets for 2015. See Note 5.

	Operating Revenues		Intersegment Eliminations			Operating Revenues After Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures and Plant Turnaround Costs
Year Ended December 31, 2017:
Terminalling and storage	$	236,169	$	(5,998	)	$	230,171	$	45,160	$	629		$	29,644
Natural gas services	532,908		(226		)	532,682		24,916		51,663			7,430
Sulfur services	134,684		—			134,684		8,117		23,205			2,611
Marine transportation	51,915		(3,336		)	48,579		7,002		1,650			3,929
Indirect selling, general, and administrative	—		—			—		—		(17,332		)	—
Total	$	955,676	$	(9,560	)	$	946,116	$	85,195	$	59,815		$	43,614
Year Ended December 31, 2016:
Terminalling and storage	$	242,363	$	(5,653	)	$	236,710	$	45,484	$	40,660		$	26,097
Natural gas services	391,333		—			391,333		28,081		41,438			4,807
Sulfur services	141,058		—			141,058		7,995		23,393			5,093
Marine transportation	61,233		(2,943		)	58,290		10,572		(16,039		)	2,334
Indirect selling, general, and administrative	—		—			—		—		(16,794		)	—
Total	$	835,987	$	(8,596	)	$	827,391	$	92,132	$	72,658		$	38,331
Year Ended December 31, 2015:
Terminalling and storage	$	270,440	$	(5,670	)	$	264,770	$	38,731	$	15,704		$	40,421
Natural gas services	523,160		—			523,160		34,072		41,220			24,330
Sulfur services	170,161		—			170,161		8,455		23,604			1,201
Marine transportation	81,784		(3,031		)	78,753		10,992		8,576			2,775
Indirect selling, general, and administrative	—		—			—		—		(18,951		)	—
Total	$	1,045,545	$	(8,701	)	$	1,036,844	$	92,250	$	70,153		$	68,727

Assets by segment

The Partnership's assets by reportable segment as of December 31, 2017 and 2016, are as follows:

	2017		2016
Total assets:
Terminalling and storage	$	326,920	$	328,098
Natural gas services	704,524		684,722
Sulfur services	120,790		125,356
Marine transportation	101,264		108,187
Total assets	$	1,253,498	$	1,246,363

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Quarterly Financial Information (Tables)

12 Months Ended

Dec. 31, 2017

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information

Consolidated Quarterly Income Statement Information

	(Unaudited)
	First Quarter		Second Quarter			Third Quarter			Fourth Quarter
	(Dollar in thousands, except per unit amounts)
2017
Revenues	$	253,325	$	193,922		$	193,128		$	305,741
Operating income (loss)	23,748		10,848			(4,484		)	29,703
Equity in earnings of unconsolidated entities	905		853			789			1,767
Net income (loss)	13,583		989			(16,286		)	18,849
Limited partners' interest in net income (loss) per limited partner unit	0.36		0.03			(0.42		)	0.47
	First Quarter		Second Quarter			Third Quarter			Fourth Quarter
	(Dollar in thousands, except per unit amounts)
2016
Revenues	$	225,605	$	190,348		$	174,537		$	236,901
Operating income	24,338		10,256			9,176			28,888
Equity in earnings of unconsolidated entities	1,677		805			1,120			1,112
Net income (loss)	15,914		(1,211		)	(933		)	17,882
Limited partners' interest in net income (loss) per limited partner unit	0.33		(0.14		)	(0.03		)	0.49

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Organization and Description of Business (Details)		12 Months Ended
	Aug. 30, 2013 representative	Dec. 31, 2017 segment
Schedule of Equity Method Investments [Line Items]
Number of primary business lines | segment		4
Ownership percentage		98.00%
Martin Resource Management
Schedule of Equity Method Investments [Line Items]
Ownership percentage	49.00%
Economic ownership percentage by parent	50.00%
Number of representatives appointed to board of directors | representative	2

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Significant Accounting Policies (Details)			3 Months Ended					12 Months Ended
	Aug. 25, 2017 Inch	Aug. 14, 2015 USD ($)	Dec. 31, 2017 USD ($)	Sep. 30, 2017 USD ($)	Dec. 31, 2016 USD ($)	Jun. 30, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2017 USD ($) segment	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Aug. 13, 2015 USD ($)	Feb. 12, 2015 barge bbl
Equity Method Investments
Number of pressure barges disposed of | barge												6
Volume of pressure barges disposed of (in bbl) | bbl												16,101
Goodwill and Other Intangibles
Number of reporting units | segment								4
Impairment of goodwill								$ 0	$ 4,145,000	$ 0
Impairment of intangible assets								0	0	0
Debt Issuance Costs
Debt issuance cost								66,000	5,274,000	341,000
Amortization of debt issuance costs								2,897,000	3,684,000	4,859,000
Accumulated amortization of debt issuance costs			$ 17,162,000		$ 14,265,000			17,162,000	14,265,000
Impairment of Long-Lived Assets
Impairment of long-lived assets								2,225,000	26,953,000	10,629,000
Indirect Selling, General and Administrative Expenses
Indirect selling, general and administrative expenses								$ 16,416,000	13,033,000	13,679,000
Minimum
Deferred Catalyst Costs
Catalyst, useful life (in months)								12 months
Deferred Turnaround Costs
Turnarounds, useful life (in months)								12 months
Maximum
Deferred Catalyst Costs
Catalyst, useful life (in months)								36 months
Deferred Turnaround Costs
Turnarounds, useful life (in months)								36 months
Terminalling and storage
Impairment of Long-Lived Assets
Impairment of long-lived assets			600,000						15,252,000	9,305,000
Marine transportation
Goodwill and Other Intangibles
Impairment of goodwill						$ 4,145,000
Impairment of Long-Lived Assets
Impairment of long-lived assets			1,625,000		11,701,000		$ 1,324,000
Revolving Loan Facility
Debt Issuance Costs
Face amount			$ 664,444,000		$ 664,444,000		700,000,000	$ 664,444,000	664,444,000	700,000,000
Write off of existing debt issuance costs		$ 1,625,000							$ 820,000
Borrowing capacity		$ 700,000,000									$ 900,000,000
Senior Unsecured Notes 7.25% | Senior Notes
Debt Issuance Costs
Write off of existing debt issuance costs										235,000
Amount of debt repurchased							$ 26,200,000			$ 26,200,000
Fixed rate cost							7.25%			7.25%
Hurricane Harvey
Impairment of Long-Lived Assets
Impairment of long-lived assets				$ 186,000
Inches of rain produced | Inch	50

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Acquisitions - Narrative (Details) - USD ($) $ in Thousands		12 Months Ended
	Feb. 22, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Business Acquisition [Line Items]
Excess purchase price over carrying value of acquired assets		$ 7,887	$ 0	$ 0
MEH South Texas Terminals LLC
Business Acquisition [Line Items]
Percentage of voting interests acquired	100.00%
Purchase price	$ 27,420
Excess purchase price over carrying value of acquired assets	$ 7,887
Excess purchase price over carrying value of acquired assets, percentage	3.00%

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Acquisitions - Purchase Price (Details) - USD ($) $ in Thousands		12 Months Ended
	Feb. 22, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Business Acquisition [Line Items]
Excess purchase price over carrying value of acquired assets		$ 7,887	$ 0	$ 0
MEH South Texas Terminals LLC
Business Acquisition [Line Items]
Purchase price	$ 27,420
Historical carrying value of assets allocated to Property, plant and equipment	19,533
Excess purchase price over carrying value of acquired assets	$ 7,887

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Discontinued Operations, Divestitures, and Assets Held for Sale (Narrative) (Details) $ in Thousands			3 Months Ended		12 Months Ended
	Dec. 21, 2016 USD ($) bbl	Feb. 12, 2015 USD ($) barge bbl	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of pressure barges disposed of | barge		6
Volume of pressure barges disposed of (in bbl) | bbl		16,101
Disposal Group, Held-for-sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain from divestiture					$ 822
Proceeds from divestiture of businesses					8,341
CCCT Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain from divestiture						$ 37,345
Proceeds from dock relocation	$ 13,400
Net income					$ 0	$ 43,804	$ 10,880
CCCT Assets | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of barrels in crude oil storage terminal (in bbl) | bbl	900,000
Sale price	$ 107,000
Reimbursement of capital expenditures and prepaid Items	2,057
Proceeds from divestiture of businesses	$ 93,347
Floating Storage Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of pressure barges disposed of | barge		6
Volume of pressure barges disposed of (in bbl) | bbl		16,101
Floating Storage Assets | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture of businesses		$ 41,250
Terminalling and storage | Disposal Group, Held-for-sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment of long-lived assets			$ 600	$ 15,252
Marine transportation | Disposal Group, Held-for-sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment of long-lived assets			$ 1,625	$ 11,701

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Discontinued Operations, Divestitures, and Assets Held for Sale (Long-Lived Assets Held-for-Sale) (Details) - Disposal Group, Held-for-sale, Not Discontinued Operations - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long lived assets held-for-sale fair value disclosure	$ 9,579	$ 15,779
Terminalling and storage
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long lived assets held-for-sale fair value disclosure	4,152	10,852
Marine transportation
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long lived assets held-for-sale fair value disclosure	$ 5,427	$ 4,927

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Discontinued Operations, Divestitures, and Assets Held for Sale (Operating Results) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total costs and expenses and other, net, excluding depreciation and amortization	$ 886,824	$ 788,133	$ 964,530
Depreciation and amortization	85,195	92,132	92,250
Income from discontinued operations, net of income taxes	$ 0	$ 0	1,215
Floating Storage Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total revenues from third parties			791
Total costs and expenses and other, net, excluding depreciation and amortization			1,038
Depreciation and amortization			0
Other operating income, net			1,462
Income from discontinued operations before income taxes			1,215
Income tax expense			0
Income from discontinued operations, net of income taxes			$ 1,215

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Inventories (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Inventory Disclosure [Abstract]
Natural gas liquids	$ 47,462	$ 33,656
Sulfur	8,436	8,521
Sulfur based products	18,674	19,107
Lubricants	20,086	18,276
Other	2,594	3,071
Inventories	$ 97,252	$ 82,631

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Property, Plant and Equipment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Property, plant and equipment, at cost	$ 1,253,065	$ 1,224,277
Depreciation expense	70,904	72,405	$ 67,134
Additions to property, plant and equipment included in accounts payable	4,100	1,819
Land
Property, Plant and Equipment [Line Items]
Property, plant and equipment, at cost	21,719	20,679
Improvements to land and buildings
Property, Plant and Equipment [Line Items]
Property, plant and equipment, at cost	$ 135,896	135,852
Improvements to land and buildings | Minimum
Property, Plant and Equipment [Line Items]
Depreciable lives (in years)	10 years
Improvements to land and buildings | Maximum
Property, Plant and Equipment [Line Items]
Depreciable lives (in years)	25 years
Storage equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment, at cost	$ 178,815	168,839
Storage equipment | Minimum
Property, Plant and Equipment [Line Items]
Depreciable lives (in years)	5 years
Storage equipment | Maximum
Property, Plant and Equipment [Line Items]
Depreciable lives (in years)	50 years
Marine vessels
Property, Plant and Equipment [Line Items]
Property, plant and equipment, at cost	$ 176,782	181,659
Marine vessels | Minimum
Property, Plant and Equipment [Line Items]
Depreciable lives (in years)	4 years
Marine vessels | Maximum
Property, Plant and Equipment [Line Items]
Depreciable lives (in years)	25 years
Operating plant and equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment, at cost	$ 659,854	620,303
Operating plant and equipment | Minimum
Property, Plant and Equipment [Line Items]
Depreciable lives (in years)	3 years
Operating plant and equipment | Maximum
Property, Plant and Equipment [Line Items]
Depreciable lives (in years)	50 years
Base Gas
Property, Plant and Equipment [Line Items]
Property, plant and equipment, at cost	$ 43,799	43,799
Furniture, fixtures and other equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment, at cost	$ 11,134	19,034
Furniture, fixtures and other equipment | Minimum
Property, Plant and Equipment [Line Items]
Depreciable lives (in years)	3 years
Furniture, fixtures and other equipment | Maximum
Property, Plant and Equipment [Line Items]
Depreciable lives (in years)	20 years
Transportation equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment, at cost	$ 1,535	1,738
Transportation equipment | Minimum
Property, Plant and Equipment [Line Items]
Depreciable lives (in years)	3 years
Transportation equipment | Maximum
Property, Plant and Equipment [Line Items]
Depreciable lives (in years)	7 years
Construction in progress
Property, Plant and Equipment [Line Items]
Property, plant and equipment, at cost	$ 23,531	$ 32,374

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Goodwill (Details) - USD ($)	3 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Goodwill [Line Items]
Carrying amount of goodwill		$ 17,296,000	$ 17,296,000
Impairment of goodwill		0	4,145,000	$ 0
Terminalling and storage
Goodwill [Line Items]
Carrying amount of goodwill		11,868,000	11,868,000
Natural gas services
Goodwill [Line Items]
Carrying amount of goodwill		79,000	79,000
Sulfur services
Goodwill [Line Items]
Carrying amount of goodwill		$ 5,349,000	$ 5,349,000
Marine transportation
Goodwill [Line Items]
Impairment of goodwill	$ 4,145,000

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Leases (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Leases
2018	$ 6,841
2019	4,559
2020	3,715
2021	2,245
2022	1,079
Thereafter	7,750
Total	26,189
Rent expense for operating leases	$ 15,908	$ 19,005	$ 18,831

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Investments in Unconsolidated Entities and Joint Ventures (Details) $ in Thousands	Dec. 31, 2017 USD ($) mi	Dec. 31, 2016 USD ($)
Schedule of Equity Method Investments [Line Items]
Partnership's interest in cash of the unconsolidated equity method investees | $	$ 5,585	$ 631
West Texas LPG Pipeline L.P.
Schedule of Equity Method Investments [Line Items]
Ownership percentage	20.00%
Length common carrier pipeline (in miles) | mi	2,300
West Texas LPG Pipeline L.P. | Common
Schedule of Equity Method Investments [Line Items]
Ownership percentage	19.80%
West Texas LPG Pipeline L.P. | General Partner
Schedule of Equity Method Investments [Line Items]
Ownership percentage	0.20%

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Investments in Unconsolidated Entities and Joint Ventures - Information for Significant Unconsolidated Equity Method Investees (Details) - WTLPG - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
Total Assets	$ 837,163	$ 812,464	$ 819,342
Long-Term Debt	0	0	0
Members’ Equity/Partners' Capital	787,426	790,406	804,023
Revenues	87,048	88,468	100,708
Net Income	$ 21,571	$ 23,883	$ 46,294

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Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Recurring | Commodity derivative contracts, net | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity derivative contracts, net	$ (72)	$ (3,904)
Nonrecurring | Carrying Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Note receivable - affiliates	0	15,000
Nonrecurring | Carrying Value | 2021 Senior unsecured notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Senior notes	372,618	372,239
Nonrecurring | Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Note receivable - affiliates	0	15,797
Nonrecurring | Fair Value | 2021 Senior unsecured notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Senior notes	$ 381,657	$ 377,882

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Derivative Instruments and Hedging Activities (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017 USD ($) bbl	Dec. 31, 2016 USD ($) bbl
Commodity derivative contracts, net
Derivative [Line Items]
Notional quantity (in bbl) | bbl	145	731
Interest Rate Swap
Derivative [Line Items]
Premiums received	$ 630	$ 2,495
Interest Expense | Interest Rate Swap
Derivative [Line Items]
Premiums received	$ 630	$ 2,495

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Derivative Instruments and Hedging Activities - Balance Sheet Derivatives (Details) - Not Designated as Hedging Instrument - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Derivative asset, fair value	$ 0	$ 0
Derivative liability, fair value	72	3,904
Commodity derivative contracts, net | Fair Value of Derivatives, Current
Derivatives, Fair Value [Line Items]
Derivative asset, fair value	0	0
Derivative liability, fair value	$ 72	$ 3,904

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Derivative Instruments and Hedging Activities - Effect of derivative instruments on the Consolidated Statement of Operations (Details) - Not Designated as Hedging Instrument - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Amount of (Gain) or Loss Recognized in Income on Derivatives	$ 1,304	$ 4,133	$ (3,107)
Interest rate swaption contracts | Interest expense
Derivative Instruments, Gain (Loss) [Line Items]
Amount of (Gain) or Loss Recognized in Income on Derivatives	0	(630)	(2,495)
Interest rate contracts | Interest expense
Derivative Instruments, Gain (Loss) [Line Items]
Amount of (Gain) or Loss Recognized in Income on Derivatives	0	(366)	206
Commodity contracts | Cost of products sold
Derivative Instruments, Gain (Loss) [Line Items]
Amount of (Gain) or Loss Recognized in Income on Derivatives	$ 1,304	$ 5,129	$ (818)

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Related Party Transactions (Details)	12 Months Ended
	Dec. 31, 2017 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	16.30%
General partner interest percentage	2.00%
Martin Resource Management | MMGP Holdings, LLC
Related Party Transaction [Line Items]
General partner interest percentage	51.00%

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Related Party Transactions - Omnibus Agreement Narrative (Details) - Omnibus Agreement - Martin Resource Management - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
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	$ 16,416,000	$ 13,033,000	$ 13,679,000

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Related Party Transactions - Motor Carrier Agreement (Details) - Motor Carrier Agreement - Martin Resource Management	12 Months Ended
	Dec. 31, 2017
Related Party Transaction [Line Items]
Automatic consecutive term renewal (in years)	1 year
Termination written notice, minimum (in days)	30 days
Partnership notice period to terminate agreement (in days)	90 days

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Related Party Transactions - Marine Agreements (Details) - Marine Transportation Agreement - Martin Resource Management	12 Months Ended
	Dec. 31, 2017
Related Party Transaction [Line Items]
Automatic consecutive term renewal (in years)	1 year
Termination written notice, minimum (in days)	60 days

XML

Related Party Transactions - Terminal Services Agreements (Details)	12 Months Ended
	Dec. 31, 2017
Terminal Services Agreements | 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	12 Months Ended
	Dec. 31, 2017 bbl_per_day
Cross Tolling Agreement
Related Party Transaction [Line Items]
Production minimum per day (in bbl)	6,500
Annual escalation benchmark percentage	3.00%
Sulfuric Acid Sales Agency Agreement
Related Party Transaction [Line Items]
Termination written notice, minimum (in days)	90 days

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Related Party Transactions - Schedule of the impact of Related Party Transactions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues:
Terminalling and storage	$ 82,205	$ 82,437	$ 78,233
Marine transportation	16,801	21,767	27,724
Natural gas services	122	699	878
Product sales:
Product Sales Related Party	3,578	3,034	5,671
Cost of products sold:
Natural gas services	18,946	22,886	25,797
Sulfur services	15,564	15,339	16,579
Terminalling and storage	17,612	13,838	17,718
Operating expenses:
Operating expenses	64,344	70,841	77,871
Related Party
Product sales:
Product Sales Related Party	3,578	3,034	5,671
Revenue from related parties	102,706	107,937	112,506
Cost of products sold:
Natural gas services	18,946	22,886	25,797
Sulfur services	15,564	15,339	16,579
Costs of products sold	52,122	52,063	60,094
Operating expenses:
Operating expenses	64,344	70,841	77,871
Selling, general and administrative:
Selling, general and administrative	29,416	25,890	24,968
Related Party | Terminalling and storage
Revenues:
Terminalling and storage	82,205	82,437	78,233
Product sales:
Product Sales Related Party	572	1,020	1,836
Cost of products sold:
Terminalling and storage	17,612	13,838	17,718
Operating expenses:
Operating expenses	25,701	27,481	29,931
Selling, general and administrative:
Selling, general and administrative	2,278	2,526	2,284
Related Party | Marine transportation
Revenues:
Marine transportation	16,801	21,767	27,724
Operating expenses:
Operating expenses	23,815	28,107	32,373
Selling, general and administrative:
Selling, general and administrative	34	30	29
Related Party | Natural gas services
Revenues:
Natural gas services	122	699	878
Product sales:
Product Sales Related Party	1,043	8	196
Operating expenses:
Operating expenses	9,007	9,258	8,639
Selling, general and administrative:
Selling, general and administrative	8,162	7,566	6,216
Related Party | Sulfur services
Product sales:
Product Sales Related Party	1,963	2,006	3,639
Operating expenses:
Operating expenses	5,821	5,995	6,928
Selling, general and administrative:
Selling, general and administrative	2,526	2,732	2,760
Related Party | Indirect overhead allocation, net of reimbursement
Selling, general and administrative:
Selling, general and administrative	$ 16,416	$ 13,036	$ 13,679

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Related Party Transactions - Other Related Party Transactions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Notes receivable	$ 0	$ 15,000
Martin Energy Trading LLC
Related Party Transaction [Line Items]
Interest rate, note receivable due from related party	15.00%
Notes Receivable | Martin Energy Trading LLC
Related Party Transaction [Line Items]
Notes receivable	$ 15,000
Interest Expense | Martin Energy Trading LLC
Related Party Transaction [Line Items]
Interest income from related parties	$ 943	$ 2,256	$ 2,250

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Supplemental Balance Sheet Information - Other Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Balance Sheet Related Disclosures [Abstract]
Customer contracts and relationships, net	$ 25,252	$ 36,528
Other intangible assets	1,752	2,280
Other	5,797	6,066
Intangible and other assets, net	$ 32,801	$ 44,874

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Supplemental Balance Sheet Information - Other Intangible Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Balance Sheet Related Disclosures [Abstract]
Amortization of intangible assets	$ 13,887	$ 19,548	$ 22,115
Accumulated amortization	39,462	$ 48,876
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2018	7,472
2019	4,471
2020	4,440
2021	4,319
2022	4,295
Subsequent years	$ 2,007

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Supplemental Balance Sheet Information - Other Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Balance Sheet Related Disclosures [Abstract]
Accrued interest	$ 11,726	$ 10,629
Asset retirement obligations	5,429	7,953
Property and other taxes payable	5,638	6,443
Accrued payroll	3,385	1,672
Other	162	20
Total other accrued liabilities	$ 26,340	$ 26,717

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Supplemental Balance Sheet Information - Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning asset retirement obligations	$ 16,418	$ 2,163
Revisions to existing liabilities	5,547	14,379
Accretion expense	404	178
Liabilities settled	(8,857)	(302)
Ending asset retirement obligations	13,512	16,418
Current portion of asset retirement obligations	(5,429)	(7,953)
Long-term portion of asset retirement obligations	$ 8,083	$ 8,465

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Long-Term Debt (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Apr. 30, 2014	Feb. 28, 2013
Debt Instrument [Line Items]
Total long-term debt	$ 812,632,000	$ 808,107,000
Cash paid for interest	45,728,000	46,046,000	$ 43,376,000
Capitalized interest	730,000	1,126,000	1,944,000
Revolving Loan Facility
Debt Instrument [Line Items]
Total long-term debt	440,014,000	435,868,000
Face amount	664,444,000	664,444,000	700,000,000
Unamortized debt issuance costs	$ 4,986,000	7,132,000
Weighted average interest rate	4.55%
Revolving Loan Facility | LIBOR
Debt Instrument [Line Items]
Applicable margins	3.00%
Revolving Loan Facility | Minimum | LIBOR
Debt Instrument [Line Items]
Applicable margins	2.00%
Revolving Loan Facility | Minimum | Prime Rate
Debt Instrument [Line Items]
Applicable margins	1.00%
Revolving Loan Facility | Maximum | LIBOR
Debt Instrument [Line Items]
Applicable margins	3.00%
Revolving Loan Facility | Maximum | Prime Rate
Debt Instrument [Line Items]
Applicable margins	2.00%
Senior Notes | Senior Notes 7.250%
Debt Instrument [Line Items]
Total long-term debt	$ 372,618,000	372,239,000
Face amount	$ 400,000,000			$ 150,000,000	$ 250,000,000
Fixed rate cost	7.25%
Unamortized debt issuance costs	$ 2,138,000	2,823,000
Unamortized premium	$ 956,000	$ 1,262,000
Amount of debt repurchased			$ 26,200,000

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Partners' Capital (Details)	12 Months Ended
	Dec. 31, 2017 shares
Limited Partners' Capital Account [Line Items]
Common limited partner units (in shares)	38,444,612
Ownership percentage	98.00%
General partner interest percentage	2.00%
Martin Resource Management
Limited Partners' Capital Account [Line Items]
Common limited partner units (in shares)	6,264,532
Ownership percentage	16.30%
General partner interest percentage	2.00%

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Partners' Capital - Issuance of Common Units (Details) - USD ($) $ / shares in Units, $ in Thousands		12 Months Ended
	Feb. 22, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Limited Partners' Capital Account [Line Items]
Units issued in public offering (in shares)	2,990,000
Share price (in dollars per share)	$ 18.00
Proceeds from issuance of common units	$ 51,056
General partner contribution to maintain GP interest	$ 1,098	$ 1,098	$ 0	$ 55
General partner interest percentage		2.00%
Martin Resource Management
Limited Partners' Capital Account [Line Items]
General partner interest percentage		2.00%

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Partners' Capital - Incentive Distribution Rights (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Limited Partners' Capital Account [Line Items]
General partner interest percentage	2.00%
Martin Midstream GP LLC
Limited Partners' Capital Account [Line Items]
General partner interest percentage	2.00%
Distributions payable on behalf of IDRs	$ 0	$ 7,786	$ 15,571
Martin Midstream GP LLC | Target Level 1
Limited Partners' Capital Account [Line Items]
Target cash distribution, percent	2.00%
Target cash distribution (in dollars per share)	$ 0.55
Martin Midstream GP LLC | Target Level 2
Limited Partners' Capital Account [Line Items]
Target cash distribution, percent	15.00%
Target cash distribution (in dollars per share)	$ 0.625
Martin Midstream GP LLC | Target Level 3
Limited Partners' Capital Account [Line Items]
Target cash distribution, percent	25.00%
Target cash distribution (in dollars per share)	$ 0.75
Martin Midstream GP LLC | Target Level 4
Limited Partners' Capital Account [Line Items]
Target cash distribution, percent	50.00%

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Partners' Capital - Distributions of Available Cash (Details)	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Distribution period (in days)	45 days

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Partners' Capital - Reconciliation of net income to partners interest in net income (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reconciliation of Net Income from Continuing and Discontinued Operations [Line Items]
Net income (loss)	$ 18,849	$ (16,286)	$ 989	$ 13,583	$ 17,882	$ (933)	$ (1,211)	$ 15,914	$ 17,135	$ 31,652	$ 38,380
Less general partner’s interest in net income:
Less income allocable to unvested restricted units									(42)	(90)	(140)
Limited partner's interest in net income									$ 16,750	$ 23,143	$ 21,902
Basic weighted average limited partner units outstanding (in shares)									38,101,583	35,347,032	35,308,649
Dilutive effect of restricted units issued (in shares)									63,318	28,231	62,880
Total weighted average limited partner diluted units outstanding (in shares)									38,164,901	35,375,263	35,371,529
Continuing operations:
Reconciliation of Net Income from Continuing and Discontinued Operations [Line Items]
Net income (loss)									$ 17,135	$ 31,652	$ 37,165
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs									0	7,786	15,078
Distributions payable on behalf of general partner interest									1,569	2,058	2,585
General partner interest in undistributed loss									(1,226)	(1,425)	(1,842)
Less income allocable to unvested restricted units									42	90	136
Limited partner's interest in net income									16,750	23,143	21,208
Discontinued operations:
Reconciliation of Net Income from Continuing and Discontinued Operations [Line Items]
Net income (loss)									0	0	1,215
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs									0	0	493
Distributions payable on behalf of general partner interest									0	0	84
General partner interest in undistributed loss									0	0	(60)
Less income allocable to unvested restricted units									0	0	4
Limited partner's interest in net income									$ 0	$ 0	$ 694

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Unit Based Awards - Schedule of compensation costs relate to unit based plan (Details) - Selling, General and Administrative Expense - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 650	$ 904	$ 1,429
Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	534	783	1,338
Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 116	$ 121	$ 91

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Unit Based Awards (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	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]
Compensation costs not yet recognized	$ 269
Weighted average period for recognition (in years)	9 months 18 days
Restricted Units | Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)	4 years
Restricted Units | Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)	3 years

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Unit Based Awards - Summary of restricted unit activity (Details) - Restricted Units $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017 USD ($) $ / shares shares
Number of Units
Non-vested, beginning of period, numbers of units (in shares) | shares	103,800
Granted, number of units (in shares) | shares	12,000
Vested, number of units (in shares) | shares	(7,800)
Forfeited, number of units (in shares) | shares	(9,250)
Non-vested, end of period, number of units (in shares) | shares	98,750
Weighted Average Grant-Date Fair Value Per Unit
Non-vested, beginning of period, weighted average grant-date fair value per unit (in dollars per share) | $ / shares	$ 26.54
Granted, weighted average grant-date fair value per unit (in dollars per share) | $ / shares	19.00
Vested, weighted average grant-date fair value per unit (in dollars per share) | $ / shares	19.18
Forfeited, weighted average grant-date fair value per unit (in dollars per share) | $ / shares	28.50
Non-vested, end of period, weighted average grant-date fair value per unit (in dollars per share) | $ / shares	$ 24.80
Aggregate intrinsic value, end of period | $	$ 1,383

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Unit Based Awards - Summary of aggregate intrinsic value and fair value of units vested (Details) - Restricted Units - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate intrinsic value of units vested	$ 143	$ 1,233	$ 110
Fair value of units vested	$ 208	$ 1,773	$ 128

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Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Loss Carryforwards [Line Items]
Deferred tax liability	$ 510	$ 870
Cash paid for income taxes	712	841	$ 1,237
Texas | State
Operating Loss Carryforwards [Line Items]
State income taxes	$ 352	$ 726	$ 1,048

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Business Segments (Details) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017 USD ($)	Sep. 30, 2017 USD ($)	Jun. 30, 2017 USD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Sep. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2017 USD ($) segment	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Segment Reporting Information [Line Items]
Number of reporting units | segment									4
Revenues	$ 305,741	$ 193,128	$ 193,922	$ 253,325	$ 236,901	$ 174,537	$ 190,348	$ 225,605	$ 946,116	$ 827,391	$ 1,036,844
Depreciation and Amortization									85,195	92,132	92,250
Operating Income (Loss) after Eliminations	29,703	$ (4,484)	$ 10,848	$ 23,748	28,888	$ 9,176	$ 10,256	$ 24,338	59,815	72,658	70,153
Capital Expenditures and Plant Turnaround Costs									43,614	38,331	68,727
Total Assets [Abstract]
Total assets	1,253,498				1,246,363				1,253,498	1,246,363
Operating Revenues
Segment Reporting Information [Line Items]
Revenues									955,676	835,987	1,045,545
Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues									(9,560)	(8,596)	(8,701)
Indirect selling, general, and administrative
Segment Reporting Information [Line Items]
Depreciation and Amortization									0	0	0
Operating Income (Loss) after Eliminations									(17,332)	(16,794)	(18,951)
Capital Expenditures and Plant Turnaround Costs									0	0	0
Terminalling and storage
Segment Reporting Information [Line Items]
Revenues									230,171	236,710	264,770
Depreciation and Amortization									45,160	45,484	38,731
Operating Income (Loss) after Eliminations									629	40,660	15,704
Capital Expenditures and Plant Turnaround Costs									29,644	26,097	40,421
Total Assets [Abstract]
Total assets	326,920				328,098				326,920	328,098
Terminalling and storage | Operating Revenues
Segment Reporting Information [Line Items]
Revenues									236,169	242,363	270,440
Terminalling and storage | Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues									(5,998)	(5,653)	(5,670)
Natural gas services
Segment Reporting Information [Line Items]
Revenues									532,682	391,333	523,160
Depreciation and Amortization									24,916	28,081	34,072
Operating Income (Loss) after Eliminations									51,663	41,438	41,220
Capital Expenditures and Plant Turnaround Costs									7,430	4,807	24,330
Total Assets [Abstract]
Total assets	704,524				684,722				704,524	684,722
Natural gas services | Operating Revenues
Segment Reporting Information [Line Items]
Revenues									532,908	391,333	523,160
Natural gas services | Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues									(226)	0	0
Sulfur services
Segment Reporting Information [Line Items]
Revenues									134,684	141,058	170,161
Depreciation and Amortization									8,117	7,995	8,455
Operating Income (Loss) after Eliminations									23,205	23,393	23,604
Capital Expenditures and Plant Turnaround Costs									2,611	5,093	1,201
Total Assets [Abstract]
Total assets	120,790				125,356				120,790	125,356
Sulfur services | Operating Revenues
Segment Reporting Information [Line Items]
Revenues									134,684	141,058	170,161
Sulfur services | Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues									0	0	0
Marine transportation
Segment Reporting Information [Line Items]
Revenues									48,579	58,290	78,753
Depreciation and Amortization									7,002	10,572	10,992
Operating Income (Loss) after Eliminations									1,650	(16,039)	8,576
Capital Expenditures and Plant Turnaround Costs									3,929	2,334	2,775
Total Assets [Abstract]
Total assets	$ 101,264				$ 108,187				101,264	108,187
Marine transportation | Operating Revenues
Segment Reporting Information [Line Items]
Revenues									51,915	61,233	81,784
Marine transportation | Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues									(3,336)	(2,943)	(3,031)
Two customers | Natural gas services | Revenue | Customer concentration risk
Segment Reporting Information [Line Items]
Revenues									$ 169,504	$ 122,381	$ 148,273

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Quarterly Financial Information (Details) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017 USD ($) $ / unit	Sep. 30, 2017 USD ($) $ / unit	Jun. 30, 2017 USD ($) $ / unit	Mar. 31, 2017 USD ($) $ / unit	Dec. 31, 2016 USD ($) $ / unit	Sep. 30, 2016 USD ($) $ / unit	Jun. 30, 2016 USD ($) $ / unit	Mar. 31, 2016 USD ($) $ / unit	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 305,741	$ 193,128	$ 193,922	$ 253,325	$ 236,901	$ 174,537	$ 190,348	$ 225,605	$ 946,116	$ 827,391	$ 1,036,844
Operating income (loss)	29,703	(4,484)	10,848	23,748	28,888	9,176	10,256	24,338	59,815	72,658	70,153
Equity in earnings of unconsolidated entities	1,767	789	853	905	1,112	1,120	805	1,677	4,314	4,714	8,986
Net income (loss)	$ 18,849	$ (16,286)	$ 989	$ 13,583	$ 17,882	$ (933)	$ (1,211)	$ 15,914	$ 17,135	$ 31,652	$ 38,380
Limited partners' interest in net income (loss) per limited partner unit (in dollars per shares) | $ / unit	0.47	(0.42)	0.03	0.36	0.49	(0.03)	(0.14)	0.33

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Commitments and Contingencies - Contingencies (Details) - Martin Resource Management $ in Thousands		12 Months Ended
	Oct. 02, 2012 USD ($) quarter	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Loss Contingencies [Line Items]
Quarterly purchase price reimbursement for non compliance	$ 750	$ 1,125	$ 4,125
Quarterly purchase price reimbursement for non compliance, number of consecutive quarters | quarter	4
Maximum purchase price reimbursement for non compliance			$ 4,500

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Commitments and Contingencies - Commitments (Details) $ in Thousands	Dec. 31, 2017 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Non-cancelable revenue arrangements, future minimum revenues, 2018	$ 14,172
Non-cancelable revenue arrangements, future minimum revenues, 2019	11,190
Non-cancelable revenue arrangements, future minimum revenues, 2020	9,053
Non-cancelable revenue arrangements, future minimum revenues, 2021	6,200
Non-cancelable revenue arrangements, future minimum revenues, 2022	5,187
Non-cancelable revenue arrangements, future minimum revenues, subsequent years	$ 12,072

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Subsequent Events (Details) - Subsequent Event	Jan. 18, 2018 $ / shares
Subsequent Event [Line Items]
Dividends declared (in dollars per share)	$ 0.50
Annualized dividends declared (in dollars per share)	$ 2.00