Martin Midstream Partners
Annual Report 2017

Plain-text annual report

UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549FORM 10-KMark OneAnnual Report Pursuant to Section 13 or 15(d) of the ýýSecurities Exchange Act of 1934 For the fiscal year ended December 31, 2017 ORoTransition 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 05-0527861State 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 registeredCommon Units representing limited partnership interests NASDAQ Global Select MarketSecurities Registered Pursuant to Section 12(g) of the Act:NONEIndicate 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 thepreceding 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 besubmitted 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 suchfiles). 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 ofregistrant’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 oAccelerated filer xNon-accelerated filer oSmaller reporting company o (Do not check if a smaller reportingcompany) 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 financialaccounting 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 dateapproximated $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 PagePART I 1Item 1.Business1Item 1A.Risk Factors19Item 1B.Unresolved Staff Comments37Item 2.Properties37Item 3.Legal Proceedings37Item 4.Mine Safety Disclosures37 PART II38Item 5.Market for Our Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities38Item 6.Selected Financial Data39Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations40Item 7A.Quantitative and Qualitative Disclosures about Market Risk63Item 8.Financial Statements and Supplementary Data64Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure100Item 9A.Controls and Procedures100Item 9B.Other Information101 PART III102Item 10.Directors, Executive Officers and Corporate Governance102Item 11.Executive Compensation107Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters113Item 13.Certain Relationships and Related Transactions, and Director Independence116Item 14.Principal Accounting Fees and Services121 PART IV 122Item 15.Exhibits, Financial Statement Schedules122 iPART IItem 1.BusinessReferences in this annual report to "we," "ours," "us" or like terms when used in a historical context refer to the assets and operations of MartinResource 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 inthis annual report to the "Partnership" refer to Martin Midstream Partners L.P. and its subsidiaries, unless the content otherwise requires. You should read thefollowing discussion of our financial condition and results of operations in conjunction with the consolidated financial statements and the notes theretoincluded elsewhere in this annual report. For more detailed information regarding the basis for presentation for the following information, you should readthe notes to the consolidated financial statements included elsewhere in this annual report.Forward-Looking StatementsThis annual report on Form 10-K includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, asamended, 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 relatedthereto), 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 ofoperations or of financial condition or state other "forward-looking" information. We and our representatives may from time to time make other oral or writtenstatements that are also forward-looking statements.These forward-looking statements are made based upon management's current plans, expectations, estimates, assumptions and beliefs concerningfuture events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and thatactual 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 bythese forward-looking statements for a number of important reasons, including those discussed below in "Item 1A. Risk Factors - Risks Related to ourBusiness."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. Ourfour primary business lines include:•Terminalling and storage services for petroleum products and by-products, including the refining of naphthenic crude oil and the blending andpackaging 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 gascompanies who often turn to third parties, such as us, for the transportation and disposition of these products. In addition to these major and independent oiland gas companies, our primary customers include independent refiners, large chemical companies, fertilizer manufacturers and other wholesale purchasers ofthese 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 asupplier of products and services to drilling rig contractors. Since then, Martin Resource Management has expanded its operations through acquisitions andinternal expansion initiatives as its management identified1and capitalized on the needs of producers and purchasers of petroleum products and by-products and other bulk liquids. Martin Resource Management is animportant supplier and customer of ours. As of December 31, 2017, Martin Resource Management owned 16.3% of our total outstanding common limitedpartner units. Furthermore, Martin Resource Management controls Martin Midstream GP LLC ("MMGP"), our general partner, by virtue of its 51% votinginterest in MMGP Holdings, LLC ("Holdings"), the sole member of MMGP. MMGP owns a 2.0% general partner interest in us and all of our incentivedistribution 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 ofgeneral administration and support services by Martin Resource Management and our use of certain of Martin Resource Management’s trade names andtrademarks. Under the terms of the Omnibus Agreement, the employees of Martin Resource Management are responsible for conducting our business andoperating our assets.Martin Resource Management has operated our business since 2002. Martin Resource Management began operating our natural gas servicesbusiness 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 andterminalling and storage businesses in the early 1990s. In recent years, Martin Resource Management has increased the size of our asset base throughexpansions 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 inthe U.S. Gulf Coast region that provide storage, refining, blending, packaging, and handling services for producers and suppliers of petroleumproducts and by-products, including the refining of naphthenic crude oil and the blending and packaging of various grades and quantities ofindustrial, commercial, and automotive lubricants and greases. Our facilities and resources provide us with the ability to handle variousproducts that require specialized treatment, such as molten sulfur and asphalt. We also provide land rental to oil and gas companies along withstorage 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 volumeshandled.•Natural Gas Services. We distribute natural gas liquids ("NGLs"). We purchase NGLs primarily from refineries and natural gas processors. Westore 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 millionbarrels 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. Weown 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 fromNew Mexico and Texas to Mont Belvieu, Texas, and to a lesser extent other markets, for fractionation. This asset enables us to participate in thetransportation 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 anddistribute sulfur produced by oil refineries primarily located in the U.S. Gulf Coast region. We buy and sell molten sulfur on contracts that aretied to sulfur indices and tend to provide stable margins. We process molten sulfur into prilled or pelletized sulfur at our facilities in Port ofStockton, California and Beaumont, Texas on contracts that often provide guaranteed minimum fees. The sulfur we process and handle isprimarily used in the production of fertilizers and industrial chemicals. We own and operate five sulfur-based fertilizer production plants andone 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 baseprovides additional opportunities to handle increases in U.S. supply and access to foreign demand.2•Marine Transportation. We operate a fleet of 33 inland marine tank barges, 18 inland push boats and one offshore tug and barge unit thattransport petroleum products and by-products largely in the U.S. Gulf Coast region. We provide these transportation services on a fee basisprimarily under annual contracts, and many of our customers have long standing contractual relationships with us. Our modernized asset base isattractive both to our existing customers as well as potential new customers. In addition, our fleet contains several vessels that reflect our focuson specialty products.Our Growth StrategyThe key components of our growth strategy are:•Pursue Organic Growth Projects. We continually evaluate economically attractive organic expansion opportunities in new or existing areas ofoperation that will allow us to leverage our existing market position and increase the distributable cash flow from our existing assets throughimproved utilization and efficiency.•Pursue Internal Organic Growth by Attracting New Customers and Expanding Services Provided to Existing Customers. Opportunities exist toexpand our customer base and provide additional services and products to existing customers. We generally begin a relationship with acustomer by transporting, storing or marketing a limited range of products and services. Expanding our customer base and our service andproduct 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 servicesand 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, therebyincreasing 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 establishedstrategic alliances with midstream service providers such as us to address logistical and transportation problems or achieve operationalsynergies. We intend to pursue strategic commercial alliances with such customers in the future.Competitive StrengthsFee-Based Contracts. We generate a majority of our cash flow from fee-based contracts with our customers. A significant portion of the fee-basedcontracts 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 distributionnetwork 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 operatorsof marine service shore-based terminals in the U.S. Gulf Coast region providing broad geographic coverage and distribution capability of our products andservices 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 productsand by-products with unique requirements for transportation and storage. For example, we own facilities and resources to transport a variety of specialtyproducts, including ammonia, molten sulfur and asphalt. Some of these specialty products require treatment across a wide range of temperatures rangingbetween approximately -30 to +400 degrees Fahrenheit to remain in liquid form, which our facilities are designed to accommodate. These capabilities help usenhance relationships with our customers by offering them services to handle their unique product requirements.3Strong Industry Reputation and Established Relationships with Suppliers and Customers. We have established a reputation in our industry as areliable and cost-effective supplier of services to our customers and have a track record of safe, efficient operation of our facilities. Our management has alsoestablished long-term relationships with many of our suppliers and customers. We benefit from our management's reputation and track record and from theselong-term relationships.Experienced Management Team and Operational Expertise. Members of our executive management team and the heads of our principal businesslines have a significant amount of experience in the industries in which we operate. Our management team has a successful track record of creating internalgrowth and completing acquisitions. Our management team's experience and familiarity with our industry and businesses are important assets that assist us inimplementing 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 processingfacilities 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 andstorage services. Major energy and chemical companies typically have a strong demand for terminals owned by independent operators when such terminalsare strategically located at or near key transportation links, such as deep-water ports. Major energy and chemical companies also need independent terminalstorage when their owned storage facilities are inadequate, either because of lack of capacity, the nature of the stored material or specialized handlingrequirements.The Gulf Coast region is a major hub for petroleum refining. Approximately 50% of U.S. refining capacity exists in this region. Growth in therefining and natural gas processing industries has increased the volume of petroleum products and by-products that are transported within the Gulf Coastregion, 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 providethem logistical support services as well as provide a broad range of products, including fuel oil, lubricants, chemicals and supplies. The demand for thesetypes of terminals, services and products is driven primarily by offshore exploration, development and production in the Gulf of Mexico. Offshore activity isgreatly 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 petroleumproducts and by-products. The locations and capabilities of our terminals are structured to complement our other businesses and reflect our strategy toprovide a broad range of integrated services in the storage, handling and transportation of products. We developed our terminalling and storage assets byacquisition and upgrades of existing facilities as well as developing our own properties strategically located near rail, waterways and pipelines. We anticipatefurther 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 thatcommenced 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 forone 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 inBeaumont, Texas. The Neches terminal is a deep water marine terminal located near Beaumont, Texas, on approximately 50 acres of land owned by us, andan 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 athroughput fee for the use of our facilities based on the capacity of the applicable tank. We conduct a substantial portion of our terminalling and storageoperations under long-term contracts, which enhances the stability and predictability of our operations and cash flow. We attempt to balance our short-termand long-term terminalling contracts in order to allow us to maintain a consistent level of cash flow while maintaining flexibility to earn higher storagerevenues when demand for storage space increases. In addition, a significant portion of the contracts for our specialty terminals provide for minimum feearrangements that are not based on the volume handled.4In Houston, Texas, we own and operate a terminal used for lubricant blending, storage, packaging and distribution. This terminal is used as ourcentral 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 agreementbased 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. Thisterminal is used as our central hub for branded and private label packaged lubricants where we receive, package and ship heavy-duty, passenger car, andindustrial 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 industrialgreases.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 serviceagreement 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 terminallingservice 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 terminallingservice 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 terminallingservice 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 aterminalling 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 pipelinesto 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 shippedfrom the terminal.In Jennings, Louisiana, we own a lubricant terminal whose use is dedicated to an affiliate of Martin Resource Management through a terminallingservice agreement based on throughput rates.The following is a summary description of our shore-based specialty terminals:Terminal Location Aggregate Capacity (inbarrels) Products DescriptionTampa (1) Tampa, Florida 719,000 Asphalt and fuel oil Marine terminal, loading/unloading forvessels, barges, railcars and trucksStanolind Beaumont, Texas 617,500 Asphalt, crude oil, sulfur, sulfuricacid and fuel oil Marine terminal, marine dock forloading/unloading of vessels, barges,railcars and trucksNeches Beaumont, Texas 556,800 Molten sulfur, ammonia, asphalt,fuel oil, crude oil and sulfur-based fertilizer Marine terminal, loading/unloading forvessels, 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. Thislease may be extended at the option of the tenant for one option period of five years.5The following is a summary description of our non shore-based specialty terminals:Terminal Location Aggregate Capacity Products DescriptionChannelview Houston, Texas 39,800 barrels Lubricants Lubricants blending, storage,packaging and distributionSmackover Refinery Smackover,Arkansas 7,700 barrels per day Naphthenic lubricants, distillates,asphalt Crude refining facilitySmackover Refinery Smackover,Arkansas 275,000 barrels of crudebulk storage; 641,000barrels of lubricant storage Crude oil, lubricants Crude refining facilityMartin Lubricants Smackover,Arkansas 3.9 million gallons bulkstorage Gard, SynGard, Unimark andXtreme brands, and grease Lubricants packaging facilityMartin Lubricants (1) Kansas City,Missouri 0.2 million gallons bulkstorage Automotive, commercial andindustrial greases Grease manufacturing and packagingfacilityMartin Lubricants Houston, Texas 0.2 million gallons of bulkstorage Post tension greases Grease manufacturing and packagingfacilityHondo Asphalt Hondo, Texas 182,100 barrels Asphalt Asphalt processing and storageSouth HoustonAsphalt Houston, Texas 95,500 barrels Asphalt Asphalt processing and storagePort Neches Asphalt Port Neches, Texas 30,100 barrels Asphalt Asphalt processing and storageOmaha Asphalt Omaha, Nebraska 113,900 barrels Asphalt Asphalt processing and storageDunphy (2) Elko, Nevada 63,200 barrels Sulfuric acid Sulfuric acid storageSpindletop Beaumont, Texas 90,000 barrels Natural gasoline Pipeline receipts and shipmentsJennings 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 twosuccessive 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 successivefive-year periods.Marine Shore-Based Terminals. We own or operate 22 marine shore-based terminals along the Gulf Coast from Theodore, Alabama to CorpusChristi, Texas. Our terminalling assets are located at strategic distribution points for the products we handle and are in close proximity to our customers. Weare 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. Customersare primarily oil and gas exploration and production companies and oilfield service companies, such as drilling fluid companies, marine transportationcompanies 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 offshoreoperations 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 terminalfacility for these shore bases. These contracts generally provide us a fixed land rental fee and additional rental fees that are determined based on a percentageof the sales value of the products and services delivered from the shore base. In addition, Martin Resource Management, through terminalling serviceagreements, pays us for terminalling and storage of fuels and lubricants at these terminal facilities and includes a provision for minimum volume throughputrequirements. Our marine shore-based terminals are divided into two classes of terminals: (i) full service terminals and (ii) fuel and lubricant terminals. 6Full Service Terminals. We own or operate 8 full service terminals. These facilities provide logistical support services and storage and handlingservices for fuel and lubricants. The significant difference between our full service terminals and our fuel and lubricant terminals is that our full serviceterminals generate additional revenues by providing shore bases to support our customer’s operating activities related to the offshore exploration andproduction industry. One typical use for our shore bases is for drilling fluids manufacturers to manufacture and sell drilling fluids to the offshore drillingindustry. Offshore drilling companies may also set up service facilities at these terminals to support their offshore operations. Customers of our full serviceterminals are primarily oil and gas exploration and production companies, oilfield service companies such as drilling fluids companies, marine transportationcompanies 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 2023Cameron West (1) Cameron, Louisiana — February 2033Dock 193 (2) Gueydan, Louisiana 11,000 May 2018Fourchon 15 Fourchon, Louisiana 7,600 February 2047Harbor Island (2) Harbor Island, Texas 6,800 December 2039Intracoastal City 2 Intracoastal City, Louisiana 17,700 December 2025Pelican Island Galveston, Texas 87,600 OwnTheodore 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 andhandling 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 2041Fourchon Fourchon, Louisiana 80,900 May 2027Fourchon 16 Fourchon, Louisiana 16,400 March 2022Fourchon 17 Fourchon, Louisiana 41,200 March 2023Fourchon T Fourchon, Louisiana 10,200 October 2038Galveston T (2) Galveston, Texas 1,400 OwnIntracoastal City (2) Intracoastal City, Louisiana — OwnLake Charles T Lake Charles, Louisiana 1,000 April 2023Morgan City DWC 31 Morgan City, Louisiana 7,100 December 2019Pascagoula Pascagoula, Mississippi 10,400 OwnPort Arthur Port Arthur, Texas 16,300 November 2025Port O'Connor (2) Port O'Connor, Texas 6,800 March 2018River Ridge (3) River Ridge, Louisiana — February 2018Sabine 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 2018.7Competition. We compete with independent terminal operators and major energy and chemical companies that own their own terminalling andstorage facilities. Many customers prefer to contract with independent terminal operators rather than terminal operators owned by integrated energy andchemical 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 locatedterminal 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 storagerequirements. The service function of a terminal includes, among other things, the safe storage of product at specified temperature, moisture and otherconditions and receiving and delivering product to and from the terminal. All of these services must be in compliance with applicable environmental andother regulations.We successfully compete for terminal customers because of the strategic location of our terminals along the Gulf Coast, our integrated transportationservices, our reputation, the prices we charge for our services and the quality and versatility of our services. Additionally, while some companies havesignificantly more terminalling and storage capacity than us, not all terminalling and storage facilities located in the markets we serve are equipped toproperly 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 atcertain terminals, are the locations of the facilities, availability of competing logistical support services and the experience of personnel and dependability ofservice. The distribution and marketing of our lubricant products is brand sensitive and we encounter brand loyalty competition. Shore base rental contractsare generally long-term contracts and provide more protection from competition. Our primary competitors for both lubricants and shore bases include severalindependent operations as well as major companies that maintain their own similarly equipped marine terminals, shore bases and fuel and lubricant supplysources.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 petrochemicalfeedstock in the production of ethylene and propylene, as a fuel for heating, for industrial applications, as motor fuel and as a refrigerant. Normal butane isused 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 isobutane through isomerization. Iso butane is used in the production of motor gasoline, alkylation and as a component in aerosol propellants. Natural gasolineis 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 ResourceManagement’s land transportation fleet or by contracting with common carriers, owner-operators and railroad tank cars. We typically enter into annualcontracts with independent retail propane distributors to deliver their estimated annual volume requirements based on prevailing market prices. Dependabledelivery 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.8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 storageRetail terminals Kilgore, Texas 90,000 gallons Retail propane distribution Longview, Texas 30,000 gallons Retail propane distribution Henderson, Texas 12,000 gallons Retail propane distributionRail terminal Arcadia, Louisiana 24 railcars per day NGL rail loading and unloadingcapabilitiesIn 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 andindustrial processors. We generally maintain consistent margins in our natural gas services business because we attempt to pass increases and decreases in the cost ofNGLs 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 todecrease 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, aswell 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 drivenprimarily 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 demandfrom seasonal or weather-sensitive end-users (such as gas-fired power generators and residential and commercial consumers), demand for natural gas storageservices 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 andvalues 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 northernLouisiana and Mississippi.Cardinal facilities are summarized below:Facility Name / Location Facility Type Working StorageCapacity Percent of CapacityContracted (1) Weighted AverageLife of RemainingContract TermArcadia Gas Storage, LLC Bienville Parish,Louisiana Salt dome 16.0 billion cubicfeet (bcf) 97% 2.2 yearsCadeville Gas Storage, LLC Ouachita Parish,Louisiana Depleted reservoir 17.0 bcf 100% 5.4 yearsPerryville Gas Storage, LLC Franklin Parish,Louisiana Salt dome 12.7 bcf 67% 1.7 yearsMonroe Gas Storage Company, LLC MonroeCounty, 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 thattransports NGLs from New Mexico and Texas to Mont Belvieu, Texas, and to a lesser extent other9markets, for fractionation. This asset enables us to participate in the transportation of NGL production originating in the Permian and other basins along theWTLPG pipeline route.Competition. We compete with large integrated NGL producers and marketers, as well as small local independent marketers. The primarycomponents of competition related to our natural gas storage operations are location, rates, terms and flexibility of service and supply. Our natural gas storagefacilities compete with other storage providers and increased competition could result from newly developed storage facilities or expanded capacity fromexisting competitors. Seasonality. The level of NGL supply and demand is subject to changes in domestic production, weather, inventory levels and other factors. Whileproduction is not seasonal, residential, refinery, and wholesale demand is highly seasonal. This imbalance causes increases in inventories during summermonths when consumption is low and decreases in inventories during winter months when consumption is high. Abnormally cold weather can put extraupward pressure on propane prices during the winter because there are less readily available sources of additional supply except for imports, which are lessaccessible and may take several weeks to arrive. General economic conditions and inventory levels have a greater impact on industrial and refinery use ofNGLs 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 tonsof 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 primaryapplication of sulfur in fertilizers occurs in the form of sulfuric acid. Burning sulfur creates sulfur dioxide, which is subsequently oxidized and dissolved inwater to create sulfuric acid. The sulfuric acid is then combined with phosphate rock to make phosphoric acid, the base material for most high-gradephosphate fertilizers. Sulfur-based fertilizers are manufactured chemicals containing nutrients known to improve the fertility of soils. Nitrogen, phosphorus, potassiumand sulfur are the four most important nutrients for crop growth. These nutrients are found naturally in soils. However, soils used for agriculture becomedepleted 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 gathermolten sulfur from refiners, primarily located on the Gulf Coast. We transport sulfur by inland and offshore barges, railcars and trucks. In the U.S., recoveredsulfur is mainly kept in liquid form from production to usage at a temperature of approximately 275 degrees Fahrenheit. Because of the temperaturerequirement, the sulfur industry uses specialized equipment to store and transport molten sulfur. We have the necessary assets and expertise to handle theunique 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 publishedmarket indicator and fluctuate according to the price movement of the indicator. We also provide barge transportation and tank storage services to largeproducers 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 Beaumontfacility 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. Formedsulfur at both facilities is stored in bulk until sold into local or international agricultural markets. Our forming services contracts are fee based and typicallyinclude minimum fee guarantees.Our sulfuric acid production facility at our Plainview, Texas location processes molten sulfur to produce a dedicated supply of raw material sulfuricacid to our ammonium sulfate production plant. The ammonium sulfate plant produces10approximately 400 tons per day of quality ammonium sulfate and is marketed to our customers throughout the U.S. The sulfuric acid produced and notconsumed by the captive ammonium sulfate production is sold to Saconix LLC, a limited liability company in which Martin Resource Management has aminority 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 distributioncapabilities. In the U.S., fertilizer is generally sold to farmers through local dealers. These dealers are typically owned and supplied by much larger wholesaledistributors. We sell to these wholesale distributors. Our industrial sulfur products are marketed primarily in the southern U.S., where many papermanufacturers and power plants are located. Our products are sold in accordance with price lists that vary from state to state. These price lists are updatedperiodically to reflect changes in seasonal or competitive prices. We transport our fertilizer and industrial sulfur products to our customers using third-partycommon 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 andsold 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 sulfatesolution. These products primarily serve direct application agricultural markets. We package these custom grade products under bothproprietary 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, andemulsified sulfur. We produce elemental pastille sulfur at our Odessa, Texas and Seneca, Illinois facilities. Elemental pastille sulfur is used toincrease the efficiency of the coal-fired precipitators in the power industry. These industrial ground sulfur products are also used in a variety ofdusting and wettable sulfur applications such as rubber manufacturing, fungicides, sugar and animal feeds. We produce emulsified sulfur at ourNash, 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 productis a clear liquid containing 12% nitrogen and 26% sulfur. This product serves as a liquid plant nutrient used directly through spray rigs orirrigation systems. It is also blended with other nitrogen phosphorus potassium liquids or suspensions as well. Our market is predominantly theMid-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 anduse them to transport molten sulfur between U.S. Gulf Coast storage terminals (including our terminal in Beaumont, Texas) under third-party marinetransportation agreements:Asset Class of Equipment Capacity/Horsepower Products TransportedMargaret Sue Offshore tank barge 10,500 long tons Molten sulfurM/V Martin Explorer Offshore tugboat 7,130 horsepower N/AM/V Martin Express Inland push boat 1,200 horsepower N/AMGM 101 Inland tank barge 2,500 long tons Molten sulfurMGM 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 StoredNeches Beaumont, Texas 5,500 metric tons per day Molten, prilled and granulated sulfurStockton Stockton, California 1,000 metric tons per day Molten and prilled sulfur11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 productionFertilizer plant Beaumont, Texas 110,000 tons Liquid sulfur fertilizer productionFertilizer plants Odessa, Texas 35,000 tons Dry sulfur fertilizer productionFertilizer plant Seneca, Illinois 36,000 tons Dry sulfur fertilizer productionFertilizer plant Cactus, Texas 20,000 tons Dry sulfur fertilizer productionIndustrial sulfur plant Nash, Texas 18,000 tons Emulsified sulfur productionSulfuric 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 theypurchase directly from both producers and resellers. As a reseller, we compete against producers and other resellers capable of accessing the requiredtransportation and storage assets. Our sulfur-based fertilizer products compete with several large fertilizer and sulfur product manufacturers. However, theclose 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 freightcosts and respond quickly to customer requests. Our sulfuric acid products compete with regional producers and importers in the South and Southwestportion 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 isused to transport vast quantities of products annually. This waterway system extends approximately 26,000 miles, of which 12,000 miles are generallyconsidered 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 requiretransportation in large quantities from the refinery or processor. Convenient access to and use of this waterway system by the petroleum and petrochemicalindustry is a major reason for the current location of U.S. refineries and petrochemical facilities. The marine transportation industry uses push boats andtugboats 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 inoil refining and natural gas processing. Our marine transportation business operates coastwise along the Gulf of Mexico and East Coast and on the U.S. inlandwaterway 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 consistof 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 customerrequirements. Our offshore tow consists of one tugboat, with much greater horsepower than an inland push boat, and one large tank barge. We transportasphalt, fuel oil, gasoline, sulfur and other bulk liquids. 12The following is a summary description of the marine vessels we use in our marine transportation business (excluding equipment classified as AssetsHeld 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, gasolineand sulfurInland tank barges 26 20,000 - 31,000 barrels Asphalt, crude oil, fuel oil andgasolineInland push boats 18 800 - 2,650 horsepower N/AOffshore tank barge 1 59,000 barrels Diesel fuelOffshore tugboat 1 5,100 horsepower N/AOur largest marine transportation customers include major and independent oil and gas refining companies, petroleum marketing companies andMartin 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 aspot contract basis at applicable market rates. Effective each January 1, this agreement automatically renews for consecutive one-year periods unless eitherparty 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 primarilyon price. However, customers are placing an increased emphasis on safety, environmental compliance, quality of service and the availability of a singlesource of supply of services. Specifically, customers are increasingly seeking suppliers that can offer marine, land, rail and terminal distribution serviceswhile providing a high level of flexibility, health, safety, environmental and financial responsibility, adequate insurance and quality of services consistentwith 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 250tanker trucks. Pipelines generally provide a less expensive form of transportation than marine transportation. However, pipelines are not able to transportmost 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 ofcommodities 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;13•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.OwnershipMartin Resource Management owns approximately 16.3% of the outstanding limited partner units. In addition, Martin Resource Managementcontrols MMGP, our general partner, by virtue of its 51% voting interest in Holdings, the sole member of MMGP. MMGP owns a 2% general partner interestin us and all of our incentive distribution rights.ManagementMartin Resource Management directs our business operations through its ownership interests in and control of our general partner. We benefit fromour relationship with Martin Resource Management through access to a significant pool of management expertise and established relationships throughoutthe energy industry. We do not have employees. Martin Resource Management employees are responsible for conducting our business and operating ourassets on our behalf.Related Party AgreementsThe Omnibus Agreement with Martin Resource Management requires us to reimburse Martin Resource Management for all direct expenses it incursor 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 monetarylimitation 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 generaland 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 ofsuch 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 andemployee benefit plans and other general corporate overhead functions we share with Martin Resource Management’s retained businesses. The OmnibusAgreement also contains significant non-compete provisions and indemnity obligations. Martin Resource Management also licenses certain of itstrademarks 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 tollingagreement, and a sulfuric acid sales agency agreement. Pursuant to the terms of the Omnibus Agreement, we are prohibited from entering into certain materialagreements 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 ResourceManagement, 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 MartinResource Management. Our motor carrier agreement with Martin Resource Management provides us with access to Martin Resource Management’s fleet ofroad vehicles and road trailers to provide land transportation in the areas served by Martin Resource Management. Our ability to utilize Martin ResourceManagement’s land transportation operations is currently a key component of our integrated distribution network. 14In the aggregate, our purchases from Martin Resource Management accounted for approximately 8%, 11%, and 9% of our total cost of products soldduring for the years ended December 31, 2017, 2016 and 2015, respectively. We also purchase marine fuel from Martin Resource Management, which weaccount for as an operating expense. Correspondingly, Martin Resource Management is one of our significant customers. Our sales to Martin Resource Management accounted forapproximately 11%, 13%, 11% of our total revenues for each of the years ended December 31, 2017, 2016 and 2015, respectively. We have entered intocertain agreements with Martin Resource Management pursuant to which we provide terminalling and storage and marine transportation services to itssubsidiary, 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 topay 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 ResourceManagement, please see "Item 13. Certain Relationships and Related Transactions, and Director Independence." Approval and Review of Related Party TransactionsIf we contemplate entering into a transaction, other than a routine or in the ordinary course of business transaction, in which a related person willhave a direct or indirect material interest, the proposed transaction is submitted for consideration to the board of directors of our general partner or to ourmanagement, 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 proposedtransaction from management and determines whether to engage independent legal counsel or an independent financial advisor to advise the members of thecommittee regarding the transaction. If the Conflicts Committee retains such counsel or financial advisor, it considers such advice and, in the case of afinancial advisor, such advisor’s opinion as to whether the transaction is fair and reasonable to us and to our unitholders.InsuranceOur deductible for onshore physical damage resulting from named windstorms is 5% of the total value located at an individual location subject to anoverall minimum deductible of $3.0 million for damage caused by the named windstorm at all locations. Our onshore program currently provides $40.0million per occurrence for named windstorm events. For non-windstorm events, our deductible applicable to onshore physical damage is $0.5 million peroccurrence. Business interruption coverage in connection with a windstorm event is subject to the same $40.0 million per occurrence and aggregate limit asthe 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 ofthese 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. Protectionand indemnity ("P&I") insurance coverage is provided by P&I associations and other insurance underwriters. Our vessels are entered in P&I associations thatare parties to a pooling agreement, known as the International Group Pooling Agreement ("Pooling Agreement") through which approximately 90% of theworld's ocean-going tonnage is reinsured through a group reinsurance policy. With regard to collision coverage, the first $1.0 million of coverage is insuredby 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 cargoowned 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 supplementalcalls 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 tothe Pooling Agreement. Except for our marine operations, we self-insure against liability exposure up to a predetermined amount, beyond which we arecovered 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 isadequate to protect us against most accident related risks involved in the conduct of our business.15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 toprocure 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 ofmatters, 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 orotherwise relating to protection of human health, natural resources and the environment. These laws and regulations can impair our operations that affect theenvironment in many ways, such as requiring the acquisition of permits to conduct regulated activities; restricting the manner in which we can releasematerials into the environment; requiring remedial activities or capital expenditures to mitigate pollution from former or current operations; and imposingsubstantial liabilities on us for pollution resulting from our operations. Many environmental laws and regulations can impose joint and several, strictliability, and any failure to comply with environmental laws and regulations may result in the assessment of administrative, civil, and criminal penalties, theimposition 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, anychanges in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal, or remediationrequirements could have a material adverse effect on our operations and financial position. Moreover, there is inherent risk of incurring significantenvironmental 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 incursignificant costs and liabilities as result of such handling practices, releases or spills, including those relating to claims for damage to property and persons. Inthe 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 compliancewith 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 orarranged for the disposal of the hazardous substances found at such site. Under CERCLA, these responsible persons may be subject to joint and several strictliability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for thecosts of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and propertydamage allegedly caused by the release of hazardous substances into the environment. Although certain hydrocarbons are not subject to CERCLA’s reachbecause "petroleum" is excluded from CERCLA’s definition of a "hazardous substance," in the course of our ordinary operations we will generate wastes thatmay fall within the definition of a "hazardous substance." In addition, some state counterparts to CERCLA tie liability to a broader set of substances thandoes CERCLA. Solid Waste We generate both hazardous and nonhazardous solid wastes, which are subject to requirements of the federal Resource Conservation and RecoveryAct, as amended ("RCRA") and comparable state statutes. From time to time, the U.S. Environmental Protection Agency ("EPA") has considered makingchanges in nonhazardous waste standards that would result in stricter disposal requirements for these wastes. Furthermore, it is possible some wastesgenerated by us that are currently classified as nonhazardous may in the future be designated as "hazardous wastes," resulting in the wastes being subject tomore rigorous and costly disposal requirements. Changes in applicable regulations may result in an increase in our capital expenditures or operatingexpenses. 16We currently own or lease, and have in the past owned or leased, properties that have been used for the manufacturing, processing, transportationand storage of petroleum products and by-products. Solid waste disposal practices within oil and gas related industries have improved over the years with thepassage and implementation of various environmental laws and regulations. Nevertheless, a possibility exists that petroleum and other solid wastes may havebeen disposed of on or under various properties owned or leased by us during the operating history of those facilities. In addition, a number of theseproperties have been operated by third parties over whom we had no control as to such entities’ handling of petroleum, petroleum by-products or other wastesand the manner in which such substances may have been disposed of or released. State and federal laws and regulations applicable to oil and natural gaswastes and properties have gradually become more strict and, under such laws and regulations, we could be required to remove or remediate previouslydisposed wastes or property contamination, including groundwater contamination, even under circumstances where such contamination resulted from pastoperations 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 in1990 contain provisions that may result in the imposition of increasingly stringent pollution control requirements with respect to air emissions from theoperations of our terminal facilities, processing and storage facilities and fertilizer and related products manufacturing and processing facilities. Such airpollution 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 regulationsmay lead to the assessment of administrative, civil or criminal penalties, and/or result in the limitation or cessation of construction or operation of certain airemission sources. We believe our operations, including our manufacturing, processing and storage facilities and terminals, are in substantial compliance withapplicable 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, theU.S. Congress has from time to time considered climate change-related legislation to restrict greenhouse gas emissions. Many states have already taken legalmeasures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regionalgreenhouse 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 EPAeventually concluded that it is required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt newlegislation specifically addressing emissions of greenhouse gases. The Court's holding in Massachusetts that greenhouse gases fall under the federal CAA'sdefinition of air pollutant has also led the EPA to determine that regulation of greenhouse gas emissions from stationary sources under various Clean Air Actprograms is required. To that end, EPA promulgated regulations, referred to as the Tailoring Rule, 75 Fed. Red. 31514, to begin gradually subjectingstationary greenhouse gas emission sources to various Clean Air Act programs, including permitting programs applicable to new and existing major sourcesof greenhouse gas emissions. In reviewing the regulations at issue, the Supreme Court struck down EPA’s permitting requirements as applicable only togreenhouse gas emissions, although it upheld the EPA’s authority to control greenhouse gas emissions when a permit is required due to emissions of otherpollutants.On an international level, almost 200 nations agreed in December 2015 to an international climate change agreement in Paris, France that calls for countriesto set their own greenhouse gas emissions targets and be transparent about the measures each country will use to achieve its emissions targets. Although thepresent administration has announced its intention to withdraw from the Paris accord, several states and local governments have stated their commitment toits 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 ouroperations 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 ofweather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, our operationshave the potential to be adversely affected. Potential adverse effects could include disruption of our business activities, including, for example, damages toour facilities from powerful winds or floods, or increases in our costs of operation or reductions in the efficiency of our operations, as well as potentiallyincreased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect onour financing and operations by disrupting the transportation or process related services provided by companies or suppliers with whom we have a businessrelationship. In addition, the demand for and consumption of our products and services (due to change in both costs and weather patterns), and the economichealth of the regions in which we operate, could have a material adverse effect on our business, financial condition, results of operations and17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 ofclimate 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 andstrict controls regarding the discharge of pollutants, including hydrocarbon-bearing wastes, into state waters and waters of the U.S.. Pursuant to the CleanWater Act and similar state laws, a National Pollutant Discharge Elimination System, or state permit, or both, must be obtained to discharge pollutants intofederal and state waters. In addition, the Clean Water Act and comparable state laws require that individual permits or coverage under general permits beobtained by subject facilities for discharges of storm water runoff. Furthermore, the Clean Water Act potentially requires individual permits or qualificationfor nationwide permits for activities that involve the discharge of dredged or fill material into waters of the United States, the definition of which under EPAand 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 ofland and water resources across the U.S., triggering substantial additional permitting and regulatory requirements to which our operations may be subjectfrom time to time. We believe that we are in substantial compliance with Clean Water Act permitting requirements as well as the conditions imposedthereunder, and that our continued compliance with such existing permit conditions will not have a material adverse effect on our business, financialcondition 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 spillsand 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 orpermittee 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 publicand private damages including natural resource damages. Under the OPA, vessels and shore facilities handling, storing, or transporting oil are required todevelop and implement oil spill response plans, and vessels greater than 300 tons in weight must provide to the U.S. Coast Guard evidence of financialresponsibility to cover the costs of cleaning up oil spills from such vessels. The OPA also requires that all newly constructed tank barges engaged in oiltransportation 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 andfinancial responsibility requirements. Nonetheless, in the aftermath of the Deepwater Horizon incident in 2010, Congress has from time to time considered oilspill related legislation that could have the effect of substantially increasing financial responsibility requirements and potential fines and damages forviolations and discharges subject to the OPA, and similar legislation. Any such changes in law affecting areas where we conduct business could materiallyaffect 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 internationaltreaties. 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 ourmarine 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 federalOccupational Safety and Health Act ("OSHA") and comparable state statutes. We believe we have conducted our operations in substantial compliance withOSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulatedsubstances. 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 thosedescribed 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 18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 ownedand 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 toensure 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 increasesoperating 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 andAmerican Bureau of Shipping maintain the most stringent regimen of vessel inspection in the world, which tends to result in higher regulatory compliancecosts 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 athreat 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 orrequisitioned 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 thecase 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 tankbarge 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 tobe 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 withcorporate staff and support services. These services include centralized corporate functions, such as accounting, treasury, engineering, informationtechnology, insurance, administration of employee benefit plans and other corporate services. Martin Resource Management employs approximately 748individuals, 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 consolidatedfinancial 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 thesereports 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 followingaddress: www.martinmidstream.com. These documents are provided as soon as is reasonably practicable after their filing with the SEC. This website addressis 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 theSEC’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 subjectare 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, ourbusiness, financial condition or results of operations could be materially adversely affected. In this case, we might not be able to pay distributions on ourcommon units, the trading price of our common units could decline and unitholders could lose all or part of their investment. These risk factors should beread in conjunction with the other detailed information concerning us set forth herein.19Risks Relating to Our BusinessImportant 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 areimmaterial 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 minimumquarterly 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 ofour 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 willfluctuate 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 flowfrom working capital borrowings, and not solely on profitability, which will be affected by non-cash items. In addition, our general partner determines theamount and timing of asset purchases and sales, capital expenditures, borrowings, issuances of additional partnership securities and the establishment ofreserves, each of which can affect the amount of cash available for distribution to our unitholders. As a result, we may make cash distributions during periodswhen 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 areprohibited 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 adistribution would cause a default or an event of default thereunder. Our leverage and various limitations in our credit facility may reduce our ability to incuradditional debt, engage in certain transactions, and capitalize on acquisition or other business opportunities that could increase cash flows and distributionsto 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 andproduction 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 inthe 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;20•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 ourterminalling 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 beimpaired 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 cashflows 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 byprevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are notsufficient 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 onsatisfactory 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 acquisitionsthrough 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 thecommon units. In addition, in the event our limited partner interests do not maintain a sufficient valuation, or potential acquisition candidates are unwillingto 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 financingarrangements to pursue acquisitions. If we use funds from operations, other cash resources or increased borrowings for an acquisition, the acquisition couldadversely impact our ability to make our minimum quarterly distributions to our unitholders. Additionally, if we do not have sufficient capital resources orare 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.21In order to expand our operations and increase profitability, we explore acquisition opportunities. When competing for acquisition targets, firmswith 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 weakerposition 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 toborrow 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 includedin 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 additionalfunding 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 capitalrequirements, using other sources. Alternative sources of liquidity may not be available on acceptable terms, if at all. If the cash generated from ouroperations 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 wemay need to delay or abandon capital projects or other business opportunities, which could have a material adverse effect on our business, financialcondition 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 portionof the interest expense we pay on our long-term debt under our credit facility. Uncertainty in the global economy and banking markets exists, which couldaffect whether the counterparties to such interest rate protection agreements are able to honor their agreements. If the counterparties fail to honor theircommitments, we could experience higher interest rates, which could have a material adverse effect on our business, financial condition and results ofoperations. In addition, if the counterparties fail to honor their commitments, we also may be required to replace such interest rate protection agreements withnew interest rate protection agreements, and such replacement interest rate protection agreements may be at higher rates than our current interest rateprotection 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. Withinthe 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" tofacilitate the reduction of carbon compound emissions to the atmosphere and provide tax and other incentives to produce and use more "clean energy." Coststo 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 createintegration 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 tosuccessfully integrate recent or any future acquisitions into our existing operations or achieve the desired profitability from such acquisitions. Theseacquisitions may require substantial capital expenditures and the incurrence of additional indebtedness. If we make acquisitions, our capitalization andresults 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.22If recent or any future acquisitions are unsuccessful or result in unanticipated events or if we are unable to successfully integrate acquisitions intoour 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 tomake 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 marinetransportation operations can be significantly delayed, impaired or postponed by adverse weather conditions, such as fog in the winter and spring months andcertain river conditions. Additionally, our marine transportation operations and our assets in the Gulf of Mexico, including our barges, push boats, tugboatsand terminals, can be adversely impacted or damaged by hurricanes, tropical storms, tidal waves or other related events. Demand for our lubricants and thediesel fuel we throughput in our Terminalling and Storage segment can be affected if offshore drilling operations are disrupted by weather in the Gulf ofMexico.National weather conditions have a substantial impact on the demand for our products. Unusually warm weather during the winter months can causea significant decrease in the demand for NGL products. Likewise, extreme weather conditions (either wet or dry) can decrease the demand for fertilizer. Forexample, an unusually wet spring can delay planting of seeds, which can leave insufficient time to apply fertilizer at the planting stage. Conversely, droughtconditions can kill or severely stunt the growth of crops, thus eliminating the need to nurture plants with fertilizer. Any of these or similar conditions couldresult 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 orexplosions, 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 ofpetroleum 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 oflife 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 andproperty damage, including various legal proceedings and litigation resulting from these hazards and risks. If we incur material liabilities that are not coveredby 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 orexpensive 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.23The price volatility of petroleum products and by-products could reduce our liquidity and results of operations and ability to make distributions to ourunitholders.We purchase petroleum products and by-products, such as molten sulfur, fuel oils, NGLs, lubricants, and other bulk liquids and sell these products towholesale and bulk customers and to other end users. We also generate revenues through the terminalling and storage of certain products for third parties. Theprice and market value of petroleum products and by-products could be, and has recently been, volatile. Our liquidity and revenues have been adverselyaffected by this volatility during periods of decreasing prices because of the reduction in the value and resale price of our inventory. In addition, our liquidityand costs have been adversely affected during periods of increasing prices because of the increased costs associated with our purchase of petroleum productsand by-products. Future price volatility could have an adverse impact on our liquidity and results of operations, cash flow and ability to make distributionsto 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 inoperating expenses. An increase in price of these products would increase our operating expenses, which could adversely affect our results of operationsincluding 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 affectingour 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 andstorage 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 financialimpact on us.Our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows could be adversely affected byactivities of other interstate and intrastate pipelines and storage facilities that may expand or construct competing transportation and storage systems. Inaddition, future pipeline transportation and storage capacity could be constructed in excess of actual demand and with lower fuel requirements, operating andmaintenance costs than our facilities, which could reduce the demand for and the rates that we receive for our services in particular areas. Further, natural gasalso 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 thanin other seasons. Our sulfur-based fertilizer products experience an increase in demand during the spring, which increases the revenue generated by thisbusiness 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 aquarter-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 largercompanies with greater financial and other resources than we possess. We may lose customers and future business opportunities to our competitors and anysuch 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 affectour 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 orotherwise relating to protection of human health, natural resources and the environment.24These laws and regulations may impose numerous obligations that are applicable to our operations, such as: requiring the acquisition of permits to conductregulated activities; restricting the manner in which we can release materials into the environment; requiring remedial activities or capital expenditures tomitigate pollution from former or current operations; and imposing substantial liabilities on us for pollution resulting from our operations. Numerousgovernmental authorities, such as the U.S. Environmental Protection Agency and analogous state agencies, have the power to enforce compliance with theselaws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Many environmental laws and regulations canimpose joint and several strict liability, and any failure to comply with environmental laws, regulations and permits may result in the assessment ofadministrative, civil and criminal penalties, the imposition of investigatory and remedial obligations and, in some circumstances, the issuance of injunctionsthat can limit or prohibit our operations. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affectthe 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. Thosesenior officers have significant experience in our businesses and have developed strong relationships with a broad range of industry participants. The loss ofany of these executives could have a material adverse effect on our relationships with these industry participants, our results of operations and our ability tomake 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. MartinResource Management operates businesses and conducts activities of its own in which we have no economic interest. There could be competition for the timeand effort of the officers and employees who provide services to our general partner. If these officers and employees do not or cannot devote sufficientattention 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 makedistributions to our unitholders.Martin Resource Management provides us with various services and products pursuant to various commercial contracts. The loss of any of theseservices and products provided by Martin Resource Management could have a material adverse impact on our results of operations, cash flow and ability tomake distributions to our unitholders. Additionally, we provide terminalling and storage, processing and marine transportation services to Martin ResourceManagement to support its businesses under various commercial contracts. The loss of Martin Resource Management as a customer could have a materialadverse 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 significantinterruptions. 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 theuninterrupted operations of certain facilities owned or operated by our suppliers and customers. Any significant interruption at these facilities or inability totransport 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 abilityto make distributions to our unitholders. Operations at our facilities and at the facilities owned or operated by our suppliers and customers could be partiallyor 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.25Additionally, terrorist attacks and acts of sabotage could target oil and gas production facilities, refineries, processing plants, terminals and otherinfrastructure facilities. Any significant interruptions at our facilities, facilities owned or operated by our suppliers or customers, or in the oil and gasindustry 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 makedistributions 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 amajority 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 governancerequirements.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 oreliminated.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, theJones 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 toengage 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 Guardand the application of U.S. labor and tax laws significantly increase the costs of U.S. flagged vessels when compared with foreign-flagged vessels. Duringthe past several years, certain interest groups have lobbied Congress to repeal the Jones Act to facilitate foreign flag competition for trades and cargoesreserved 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 thatwould 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 withforeign 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 MerchantMarine 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 ora 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 orrequisitioned 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 thecase 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 tankbarge 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 tobe 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 ofour vessels are purchased or requisitioned for an extended period of time by the U.S. government, such transactions could have a material adverse effect onour 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 agreementsinvolve risks, such as the risk that counterparties may fail to honor their obligations under these arrangements. In addition, these arrangements may not beeffective 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 thelong-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.26We compete with similar enterprises in our respective areas of operation. Some of our competitors are large oil, natural gas and petrochemicalcompanies that have greater financial resources and access to supplies of NGLs than we do. In addition, our customers who are significant producers ofnatural gas may develop their own gathering, processing and transportation systems in lieu of using ours. Likewise, our customers who produce NGLs maydevelop 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 tomaintain current revenues and cash flows could be adversely affected by the activities of our competitors and our customers. All of these competitivepressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to ourunitholders.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 systemscould 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 couldhave 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 "investmentsecurities" 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 ourorganizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, amongother things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to orfrom our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who areindependent 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 casewe 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 thecash 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 toforego potential future acquisitions of interests in companies that may be deemed to be investment securities within the meaning of the Investment CompanyAct 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 UnitsUnits 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 maydevelop.Common units will generally be freely transferable without restriction or further registration under the Securities Act, except that any common unitsheld by an "affiliate" of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemptionunder 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 theunitholders. Our general partner may also cause us to issue an unlimited number of additional common27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 apro 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 thewithdrawal 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 ofadditional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, andcould 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 applicablestate securities laws the offer and sale of any units that they hold. Subject to the terms and conditions of our partnership agreement, these registration rightsallow 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 ina 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 fortwo years following its withdrawal or removal as a general partner. In connection with any registration of this kind, we will indemnify each unitholderparticipating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicablestate securities laws arising from the registration statement or prospectus. Except as described below, the general partner and its affiliates may sell their unitsin private transactions at any time, subject to compliance with applicable laws. Our general partner and its affiliates, with our concurrence, have grantedcomparable 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 maydevelop.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 ourcommon unitholders will have sufficient voting power to elect or remove our general partner without the consent of Martin Resource Management and itsaffiliates.Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and thereforelimited ability to influence management's decisions regarding our business. Unitholders did not elect our general partner or its directors and will have noright 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 ofour 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 generalpartner 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 ofDecember 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 moreof any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the priorapproval of our general partner's directors, from voting on any matter. In addition, our partnership agreement contains provisions limiting the ability ofunitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence themanner 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 ourgeneral partner. Consequently, it is unlikely the trading price of our common units will ever reflect a takeover premium.28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 discretionto be necessary to fund our future operating expenditures. In addition, our partnership agreement permits our general partner to reduce available cash byestablishing 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 forfuture 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 controlof 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 insome 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 acourt 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 toour 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 contractualobligations that are expressly made without recourse to our general partner. In addition, under some circumstances, a unitholder may be liable to us for theamount 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 offiduciary 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 agreementalso 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 theinterests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, ouraffiliates or any limited partner;•provides that our general partner is entitled to make other decisions in its "reasonable discretion," which may reduce the obligations towhich 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 mayconsider 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 orassignees 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 mightotherwise 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 thecommon units, without unitholder approval, in a number of circumstances such as:29•the issuance of common units in additional public offerings or in connection with acquisitions that increase cash flow from operations on apro 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 thewithdrawal 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 doesnot 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 minimumquarterly 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 unitholderconsent.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 theconsent of the unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the owner of our general partner to transfer itsownership 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 partnerwith 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 theobligation, 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 personsat 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 andmay not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units. No provision in our partnershipagreement, or in any other agreement we have with our general partner or Martin Resource Management, prohibits our general partner or its affiliates fromacquiring more than 80% of our common units. For additional information about this call right and unitholders' potential tax liability, please see "RiskFactors - 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 maycontinue to be, relatively small compared to many other securities quoted on the NASDAQ. The price of our common units may, therefore, be volatile.30Failure to achieve and maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act could have a material adverse effecton 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 ofthe Sarbanes-Oxley Act requires annual management assessments of the effectiveness of our internal controls over financial reporting addressing theseassessments. 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 theSarbanes-Oxley Act for compliance with the requirements of Section 404. In addition, if we fail to maintain the adequacy of our internal controls, as suchstandards 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 haveeffective internal controls over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act. Failure to achieve and maintain an effectiveinternal control environment could have a material adverse effect on the price of our common units.Risks Relating to Our Relationship with Martin Resource ManagementCash 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 supportservices on behalf of our general partner that are substantially identical in nature and quality to the services it conducted for our business prior to ourformation. 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 detrimentof our unitholders.As of December 31, 2017, Martin Resource Management owned 16.3% of our total outstanding common limited partner units and a 51% votinginterest in Holdings, the sole member of MMGP. MMGP owns a 2.0% general partnership interest in us and all of our incentive distribution rights. Conflictsof 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 ofthese 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 ResourceManagement 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 favorsus or utilizes our assets or services. Martin Resource Management's directors and officers have a fiduciary duty to make these decisions inthe 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 resolvingconflicts 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 theremedies 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, withoutsuch consent, might otherwise constitute a breach of fiduciary or other duties under applicable state law;31•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 termsthat 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 ofthe 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 affectthe 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 ofthe Omnibus Agreement, please see "Item 13. Certain Relationships and Related Transactions, and Director Independence." If Martin Resource Managementdoes engage in competition with us, we may lose customers or business opportunities, which could have an adverse impact on our results of operations, cashflow 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 ourcredit 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 itsobligations 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. IfMartin Resources Management no longer controls our general partner, the lenders under our credit facility may declare all amounts outstanding thereunderimmediately due and payable. In addition, either a judgment against Martin Resource Management or a bankruptcy filing by or against Martin ResourceManagement could independently result in an event of default under our credit facility if it could reasonably be expected to have a material adverse effect onus. If our lenders do declare us in default and accelerate repayment, we may be required to refinance our debt on unfavorable terms, which could negativelyimpact our results of operations and our ability to make distributions to our unitholders. A bankruptcy filing by or against Martin Resource Managementcould 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 RisksThe U.S. Internal Revenue Service (“IRS”) could treat us as a corporation for tax purposes, which would substantially reduce the cash available fordistribution to unitholders.The anticipated after-tax economic benefit of an investment in us depends largely on our classification as a partnership for federal income taxpurposes. 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 asours 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, morethan 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 types32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 otherdisposition 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 incomerequirement 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 IRSdoes 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, whichis currently a maximum of 21%, and would likely owe state income tax at varying rates. Distributions would generally be taxed again to unitholders ascorporate 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 andafter-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 acorporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amountand 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 changesand 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 modifiedby 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 existingU.S. tax laws that would have affected certain publicly traded partnerships, including the elimination of partnership tax treatment for publicly tradedpartnerships. At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships toentity-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 ata 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 willreduce 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 impossibleto 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 causeus to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income andadversely 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 underSection 7704(d)(1)(E) of the Code which relates to the qualifying income exception upon which we rely for partnership tax treatment. The Final Regulationsapply to income earned in a taxable year beginning on or after January 19, 2017. The Final Regulations include “reserved” paragraphs for fertilizer andhedging, which the U.S. Department of the Treasury plans to address in future proposed and final Treasury regulations (“Treasury regulations”). The FinalRegulations provide for a ten year transition period during which certain taxpayers that either obtained a favorable private letter ruling or treated incomeunder 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. Withrespect to some of these private letter rulings, the income that we derived from certain affected activities will be treated as qualifying income only until theend of the ten year transition period. Thus, at this time and through the transition period (and possibly beyond if not involving such affected activities), webelieve 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 businesshave not yet been fully analyzed and could have an adverse effect on our net income.33 On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonlyreferred to as the Tax Cuts and Jobs Act (the “Tax Act”) that makes significant changes to the U.S. Internal Revenue Code. Amongother changes, the Tax Act includes a reduction in the corporate and individual tax rates, a new deduction on certain pass-throughincome, a repeal of the partnership technical termination rule, and new limitations on certain deductions and credits, including interestexpense deductions. The Tax Act is complex and far-reaching and we have not completed our analysis of the impact its enactment hason us. Certain of the changes made by the Tax Act could have a negative impact on our business, results of operations, financialcondition, 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 contestwill 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 matteraffecting 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 administrativeor 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'sconclusions 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 whichthey 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 ourgeneral 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 toour 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 makesaudit 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 penaltiesand interest) resulting from such audit adjustment directly from such entity. Generally, we expect to elect to have our unitholders take such audit adjustmentinto 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 allcircumstances. 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 weshould not be able to have our unitholders take such audit adjustment into account. The Proposed Partnership Audit Regulations reserved on this issue andrequested comments but noted that allowing a partnership, such as us, to have its unitholders take such audit adjustment into account would presentcomplexities, challenges, and inefficiencies. If we are unable to have our unitholders take such audit adjustment into account in accordance with theirinterests 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 ifsuch 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 oftaxes, penalties and interest as a result of audit adjustments cash available for distribution to our unitholders may be substantially reduced. These rules arenot 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 todesignate 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 thesole authority to act on our behalf for purposes of, among other things, U.S. federal income tax audits and judicial review of administrative adjustments bythe 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 PartnershipRepresentative 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 anycash 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 taxableincome even if they receive no cash distributions from us. Unitholders may not receive cash34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 acorresponding cash distribution. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, you may be allocatedtaxable 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 therefrommay exceed cash distributions or the value of the units. The ultimate effect of any such allocations will depend on the unitholder's individual tax positionwith 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 inthose common units. Prior distributions in excess of the total net taxable income unitholders were allocated for a common unit, which decreased unitholdertax 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 thatcommon 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, maybe ordinary income to our unitholders. Should the IRS successfully contest some positions we take, our unitholders could recognize more gain on the sale ofunits 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, theymay 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 plansand other retirement plans, regulated investment companies, real estate investment trusts, mutual funds and non-U.S. persons raises issues unique to them. Forexample, virtually all of our income allocated to organizations exempt from federal income tax, including IRAs and other retirement plans, will be unrelatedbusiness income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective taxrate, 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 thatmay not conform to all aspects of the Treasury regulations. Any position we take that is inconsistent with applicable Treasury regulations may have to bedisclosed on our federal income tax return. This disclosure increases the likelihood that the IRS will challenge our positions and propose adjustments to someor all of our unitholders. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It alsocould 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 ourcommon 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 businesstaxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. Unitholders may berequired 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 dobusiness or own property and may be subject to penalties for failure to comply with those requirements. We own property and/or conduct business inAlabama, Arizona, Arkansas, California, Florida, Georgia, Illinois, Indiana, Kansas, Louisiana, Minnesota, Mississippi, Missouri, Nebraska, Nevada, NewMexico, Oklahoma, Pennsylvania, Tennessee, Texas, Utah, and West Virginia. We may do business or own property in other states or foreign countries in thefuture. It is the unitholder's responsibility to file all federal, state, local35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 unrelatedincome. In cases when our unitholders are subject to the passive loss rules (generally, individuals and closely-held corporations), any losses generated by uswill 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. Aunitholder'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 passiveactivities, including losses from other publicly traded partnerships. Other limitations that may further restrict the deductibility of our losses by a unitholderinclude 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 ourunits 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 couldchange 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 ofour 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 tradedpartnerships to use a monthly simplifying convention that is similar to ours, but they do not specifically authorize all aspects of the proration method wehave adopted. Therefore, the use of our proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unableto 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 nolonger 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 loanedunits, 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 unitholdermay 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 withrespect 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 asordinary 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 ashort 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 sellerare urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.36Item 1B.Unresolved Staff CommentsNone. 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 ofthe properties that have been transferred to us in connection with our initial public offering and the assets we acquired in our acquisitions, required theconsent of third parties, which in some cases is a governmental entity. We believe we have obtained sufficient third-party consents, permits andauthorizations for the transfer of assets necessary for us to operate our business in all material respects. With respect to any third-party consents, permits orauthorizations that have not been obtained, we believe the failure to obtain these consents, permits or authorizations will not have a material adverse effecton 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 ofthese encumbrances materially detract from the value of our properties or our interest in these properties or materially interfere with their use in the operationof our business.Item 3.Legal ProceedingsFrom time to time, we are subject to certain legal proceedings, claims and disputes that arise in the ordinary course of our business. Although wecannot predict the outcomes of these legal proceedings, we do not believe these actions, in the aggregate, will have a material adverse impact on our financialposition, results of operations or liquidity. A description of our legal proceedings is included in "Item 8. Financial Statements and Supplementary Data, Note21. Commitments and Contingencies", and is incorporated herein by reference.Item 4.Mine Safety DisclosuresNot applicable.37PART IIItem 5.Market for Our Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities Market Information and HoldersOur common units are traded on the NASDAQ under the symbol "MMLP." As of January 26, 2018 there were approximately 280 holders of recordand 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 theperiods 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 LowFirst Quarter $20.10 $17.50 $22.22 $14.05Second Quarter $20.45 $16.60 $23.77 $19.40Third Quarter $19.85 $15.55 $25.12 $18.99Fourth Quarter $17.20 $12.90 $21.63 $15.80Cash DistributionsThe following table sets forth the quarterly cash distribution declared and paid for our common units during the periods indicated:Declared for Quarter Ended Distribution PerCommon Unit Date Declared Date PaidDecember 31, 2017 $0.5000 January 18, 2018 February 14, 2018September 30, 2017 $0.5000 October 19, 2017 November 14, 2017June 30, 2017 $0.5000 July 20, 2017 August 14, 2017March 31, 2017 $0.5000 April 20, 2017 May 15, 2017December 31, 2016 $0.5000 January 19, 2017 February 14, 2017September 30, 2016 $0.5000 October 20, 2016 November 14, 2016June 30, 2016 $0.8125 July 21, 2016 August 12, 2016March 31, 2016 $0.8125 April 21, 2016 May 13, 2016Cash 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 recordon the applicable record date. Our general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properlyconduct our business. These can include cash reserves for future capital and maintenance expenditures, reserves to stabilize distributions of cash to theunitholders and our general partner, reserves to reduce debt, or, as necessary, reserves to comply with the terms of any of our agreements or obligations. Ourdistributions are effectively made 98% to unitholders and 2.0% to our general partner, subject to the payment of incentive distributions to our general partnerif certain target cash distribution levels to common unitholders are achieved. Distributions to our general partner increase to 15%, 25% and 50% based onincremental 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 requiringus to maintain certain financial ratios. We are prohibited from making any distributions to unitholders if the distribution would cause a default or an event ofdefault, or a default or an event of default exists, under our credit facility. Please read "Item 7. Management’s Discussion and Analysis of FinancialCondition and Results of Operations — Liquidity and Capital Resources — Description of Our Credit Facility."38Item 6.Selected Financial DataThe 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 FinancialStatements and Notes thereto and "Management’s Discussion and Analysis of Financial Condition and Results of Operations" included elsewhere in thisdocument. 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 operations17,135 31,652 37,165 (6,367) (14,562)Income (loss) from discontinued operations, net of tax— — 1,215 (5,338) 1,208Net 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 – continuingoperations0.44 0.65 0.60 (0.27) (0.54)Net income (loss) per limited partner unit –discontinued operations— — 0.02 (0.22) 0.04Net 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 $1,097,919Long-term debt812,632 808,107 865,003 902,005 658,695 Cash dividends per common unit (in dollars)2.00 2.94 3.25 3.18 3.1139Item 7.Management’s Discussion and Analysis of Financial Condition and Results of OperationsOverview We are a publicly traded limited partnership with a diverse set of operations focused primarily in the United States ("U.S.") Gulf Coast region. Ourfour primary business lines include:•Terminalling and storage services for petroleum products and by-products, including the refining of naphthenic crude oil and the blending andpackaging 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 gascompanies who often turn to third parties, such as us, for the transportation and disposition of these products. In addition to these major and independent oiland gas companies, our primary customers include independent refiners, large chemical companies, fertilizer manufacturers and other wholesale purchasers ofthese 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 asupplier of products and services to drilling rig contractors. Since then, Martin Resource Management has expanded its operations through acquisitions andinternal expansion initiatives as its management identified and capitalized on the needs of producers and purchasers of petroleum products and by-productsand other bulk liquids. Martin Resource Management is an important supplier and customer of ours. As of December 31, 2017, Martin Resource Managementowned 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 ownershipinterests 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 ofgeneral administration and support services by Martin Resource Management and our use of certain of Martin Resource Management’s trade names andtrademarks. Under the terms of the Omnibus Agreement, the employees of Martin Resource Management are responsible for conducting our business andoperating our assets. The Omnibus Agreement was amended on November 25, 2009, to include processing crude oil into finished products includingnaphthenic lubricants, distillates, asphalt and other intermediate cuts. The Omnibus Agreement was amended further on October 1, 2012, to permit thePartnership 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 servicesbusiness 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 andterminalling and storage businesses in the early 1990s. In recent years, Martin Resource Management has increased the size of our asset base throughexpansions and strategic acquisitions.Significant Recent DevelopmentsWest Texas LPG Pipeline Limited Partnership Expansion. On October 23, 2017, we announced that the West Texas LPG Pipeline LimitedPartnership joint venture (of which we own a 20% interest with ONEOK, Inc. owning and operating the other 80% interest) plans to investapproximately $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 bythe third quarter of 2018. This project is supported by dedicated NGL production from two third-party planned natural gas processing plants innorthern Reeves County, one of the most active areas in the Delaware Basin. The expansion will be supported by long-term volume dedications estimated tobe up to 40,000 barrels per day. The Delaware Basin extension includes the construction of an approximately 120-mile, 16-inch40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 WestTexas 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 fordays producing over 50 inches of rain in some areas, resulting in widespread flooding and damage. We experienced an impact from Hurricane Harvey in ourTerminalling 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 locationsand 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 $0.7million 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 thehurricane.2017 Restricted Unit Plan. On May 26, 2017, our unitholders approved the Martin Midstream Partners L.P. 2017 Restricted Unit Plan (the “NewLTIP”), 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 forthunder the caption “Proposal to Approve the Martin Midstream Partners L.P. 2017 Restricted Unit Plan” in our definitive proxy statement filed with the SECon 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 thepayment 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 conjunctionwith 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 ourrevolving credit facility.Acquisition of Terminalling Assets. On February 22, 2017, we acquired certain asphalt terminalling assets located in Hondo, Texas for a purchaseprice of $27.4 million (the “Hondo Acquisition”). At the date of acquisition, Martin Resource Management was in the process of constructing an asphaltterminal facility in Hondo, Texas, which will serve the asphalt market in San Antonio, Texas and surrounding areas. This terminal will have 178,000 barrelsof asphalt storage with processing and blending capabilities. We spent $8.6 million to finalize construction of the terminal. The terminal is supported bylong-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 repaymentof the long-term Note Receivable - Affiliate of $15.0 million plus accrued interest. During the second quarter of 2017, the Note Receivable - Affiliate wasfully repaid.West Texas LPG Pipeline Limited Partnership ("WTLPG") 2015 Rate Complaints. Certain shippers filed complaints with the Railroad Commissionof Texas (“RRC”) challenging the increased rates WTLPG implemented effective July 1, 2015. The complainants requested that the rate increase besuspended 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 toJuly 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 hearingsexaminer during the week of March 27, 2017. The hearings examiner issued a Proposal for Decision on September 29, 2017. On December 5, 2017, thismatter was brought before the RRC. After brief discussion, the RRC determined that more time was needed to review the proposal for decision and placed thematter 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 limitedpurpose of admitting and considering additional relevant evidence on competition.Subsequent EventsQuarterly 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 41Our discussion and analysis of our financial condition and results of operations are based on the historical consolidated financial statementsincluded 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 andliabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. We based our estimates onhistorical experience and on various other assumptions we believe to be reasonable under the circumstances. We routinely evaluate these estimates, utilizinghistorical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Our results may differ from theseestimates, and any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period inwhich the facts that give rise to the revision become known. Changes in these estimates could materially affect our financial position, results of operations orcash flows. You should also read Note 2, "Significant Accounting Policies" in Notes to Consolidated Financial Statements. The following table evaluates thepotential impact of estimates utilized during the periods ended December 31, 2017 and 2016:Description Judgments and Uncertainties Effect if Actual Results Differ from Estimates andAssumptionsImpairment of Long-Lived AssetsWe periodically evaluate whether the carryingvalue of long-lived assets has been impairedwhen circumstances indicate the carrying valueof the assets may not be recoverable. Theseevaluations are based on undiscounted cash flowprojections over the remaining useful life of theasset. The carrying value is not recoverable if itexceeds the sum of the undiscounted cash flows.Any impairment loss is measured as the excess ofthe asset's carrying value over its fair value. Our impairment analyses require management touse judgment in estimating future cash flows anduseful lives, as well as assessing the probability ofdifferent outcomes. Applying this impairment review methodology, in2017 we recorded an impairment charge of $1.6million in our Marine Transportation segment and$0.6 million in our Terminalling and Storagesegment. In 2016 we recorded an impairmentcharge of $15.3 million in our Terminalling andStorage segment and $11.7 million in our MarineTransportation segment. In 2015 we recorded animpairment charge of $9.3 million in ourTerminalling and Storage segment and $1.3million in our Marine Transportation segment.Asset Retirement ObligationsAsset retirement obligations ("AROs") associatedwith a contractual or regulatory remediationrequirement are recorded at fair value in theperiod in which the obligation can be reasonablyestimated and the related asset is depreciated overits useful life or contractual term. The liability isdetermined using a credit-adjusted risk-freeinterest rate and is accreted over time until theobligation is settled. Determining the fair value of AROs requiresmanagement judgment to evaluate requiredremediation activities, estimate the cost of thoseactivities and determine the appropriate interestrate. If actual results differ from judgments andassumptions used in valuing an ARO, we mayexperience significant changes in ARO balances.The establishment of an ARO has no initial impacton 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 OmnibusAgreement. In addition to the direct expenses, under the Omnibus Agreement, we are required to reimburse Martin Resource Management for indirect generaland 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 ofsuch 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 withthe 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 andterminalling and storage services to Martin Resource Management. We purchase land transportation42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 ofagreements 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 ResourceManagement, please see "Item 13. Certain Relationships and Related Transactions, and Director Independence."How We Evaluate Our OperationsOur 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 coreprofitability for our operations and the ability to generate and distribute cash flow, and as key components of our internal financial reporting. We believeinvestors 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 andassessing an entity's financial performance, such as cost of capital and historic costs of depreciable assets. We have included information concerning EBITDAand adjusted EBITDA because they provide investors and management with additional information to better understand the following: financial performanceof our assets without regard to financing methods, capital structure or historical cost basis; our operating performance and return on capital as compared tothose of other similarly situated entities; and the viability of acquisitions and capital expenditure projects. Our method of computing adjusted EBITDA maynot be the same method used to compute similar measures reported by other entities. The economic substance behind our use of adjusted EBITDA is tomeasure 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 ourfinancial statements, such as investors, commercial banks and research analysts, to compare basic cash flows generated by us to the cash distributions weexpect to pay our unitholders. Distributable cash flow is also an important financial measure for our unitholders since it serves as an indicator of our successin providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level thatcan sustain or support an increase in our quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investmentcommunity 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 turnis 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 flowsfrom operating activities, or any other measure presented in accordance with U.S. GAAP. Our method of computing these measures may not be the samemethod used to compute similar measures reported by other entities.Non-GAAP Financial MeasuresThe following table reconciles the non-GAAP financial measurements used by management to our most directly comparable GAAP measures for theyears ended December 31, 2017, 2016, and 2015, which represents EBITDA, Adjusted EBITDA and Distributable Cash Flow from continuing operations.43Reconciliation of EBITDA, Adjusted EBITDA, and Distributable Cash Flow Year Ended December 31, 2017 2016 2015 Net income$17,135 $31,652 $38,380Less: Income from discontinued operations, net of income taxes— — (1,215)Income from continuing operations17,135 31,652 37,165Adjustments: Interest expense47,743 46,100 43,292Income tax expense352 726 1,048Depreciation and amortization85,195 92,132 92,250EBITDA150,425 170,610 173,755Adjustments: Equity in earnings of unconsolidated entities(4,314) (4,714) (8,986)(Gain) loss on sale of property, plant and equipment(523) (33,400) 2,149Gain on retirement of senior unsecured notes— — (1,242)Impairment of long-lived assets2,225 26,953 10,629Impairment of goodwill— 4,145 —Unrealized mark-to-market on commodity derivatives(3,832) 4,579 (675)Hurricane damage repair accrual657 — —Asset retirement obligation revision5,547 — —Distributions from unconsolidated entities5,400 7,500 11,200Unit-based compensation650 904 1,429Adjusted EBITDA156,235 176,577 188,259Adjustments: Interest expense(47,743) (46,100) (43,292)Income tax expense(352) (726) (1,048)Amortization of deferred debt issuance costs2,897 3,684 4,859Amortization of debt premium(306) (306) (324)Non-cash mark-to-market on interest rate derivatives— (206) 206Payments 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 $133,850Results of OperationsThe 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 operatingrevenues 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 notallocate on a segment basis. These items, including equity in earnings (loss) of unconsolidated entities, interest expense, and indirect selling, general andadministrative 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 February12, 2015 for the year ended December 31, 2015. See Item 8, Note 5.44 OperatingRevenues RevenuesIntersegmentEliminations OperatingRevenues afterEliminations OperatingIncome (loss) Operating IncomeIntersegmentEliminations OperatingIncome (loss) afterEliminations (In thousands)Year Ended December 31, 2017: Terminalling and storage$236,169 $(5,998) $230,171 $3,305 $(2,676) $629Natural gas services532,908 (226) 532,682 49,191 2,472 51,663Sulfur services134,684 — 134,684 25,862 (2,657) 23,205Marine transportation51,915 (3,336) 48,579 (1,211) 2,861 1,650Indirect selling, general andadministrative— — — (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) $40,660Natural gas services391,333 — 391,333 38,382 3,056 41,438Sulfur services141,058 — 141,058 26,815 (3,422) 23,393Marine transportation61,233 (2,943) 58,290 (19,888) 3,849 (16,039)Indirect selling, general andadministrative— — — (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) $15,704Natural gas services523,160 — 523,160 38,611 2,609 41,220Sulfur services170,161 — 170,161 27,113 (3,509) 23,604Marine transportation81,784 (3,031) 78,753 4,630 3,946 8,576Indirect selling, general andadministrative— — — (18,951) — (18,951)Total$1,045,545 $(8,701) $1,036,844 $70,153 $— $70,15345Terminalling and Storage SegmentComparative Results of Operations for the Twelve Months Ended December 31, 2017 and 2016 Year Ended December 31, Variance PercentChange 2017 2016 (In thousands) Revenues: Services$105,703 $128,783 $(23,080) (18)%Products130,466 113,580 16,886 15%Total revenues236,169 242,363 (6,194) (3)% Cost of products sold112,135 96,344 15,791 16%Operating expenses69,888 71,831 (1,943) (3)%Selling, general and administrative expenses5,832 4,677 1,155 25%Impairment of long-lived assets600 15,252 (14,652) (96)%Depreciation and amortization45,160 45,484 (324) (1)% 2,554 8,775 (6,221) (71)%Other operating income, net751 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 CorpusChristi 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 resultedin a $5.9 million increase to products revenues. Products revenues at our shore-based terminals increased $11.0 million resulting from an 18% increase inaverage 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 ofproducts 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-basedterminals 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 CorpusChristi 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 terminalfacilities 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 $0.6million 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 beingfully 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. The2016 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 PercentChange 2016 2015 (In thousands) Revenues: Services$128,783 $138,614 $(9,831) (7)%Products113,580 131,826 (18,246) (14)%Total revenues242,363 270,440 (28,077) (10)% Cost of products sold96,344 115,460 (19,116) (17)%Operating expenses71,831 83,917 (12,086) (14)%Selling, general and administrative expenses4,677 3,804 873 23%Impairment of long-lived assets15,252 9,305 5,947 64%Depreciation and amortization45,484 38,731 6,753 17% 8,775 19,223 (10,448) (54)%Other operating income (loss), net35,368 (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 CorpusChristi 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 productsrevenues. The decline in volumes resulted primarily from the downturn in the energy industry, as well as increased price competition. Products revenues atour 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 ofproducts 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-basedterminals 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 milliondecrease related to compensation expense across our specialty terminals. Operating expenses at our Smackover refinery decreased $1.8 million, primarily as aresult 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 ourshore-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 theresult of increased compensation expense and $0.2 million is the result of increased advertising in our blending and packaging operations and $0.4 million isdue 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 andequipment. The 2016 period includes the gain on the disposition of the CCCT Assets of $37.3 million.Natural Gas Services SegmentComparative Results of Operations for the Twelve Months Ended December 31, 2017 and 2016 Year Ended December 31, Variance PercentChange 2017 2016 (In thousands) Revenues: Services$58,817 $61,133 $(2,316) (4)%Products474,091 330,200 143,891 44%Total revenues532,908 391,333 141,575 36% Cost of products sold425,073 292,573 132,500 45%Operating expenses22,347 23,152 (805) (3)%Selling, general and administrative expenses11,292 9,035 2,257 25%Depreciation and amortization24,916 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 $100.7million. 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 inaverage 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 ofproducts 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 Texaspipeline, 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 increasedcompensation expense.Depreciation and amortization. Depreciation and amortization decreased primarily due to a $3.7 million decrease in amortization related tocontracts acquired during the purchase of Cardinal Gas Storage Partners, LLC (“Cardinal”), offset by a $0.6 million increase in depreciation expense relatedto 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 PercentChange 2016 2015 (In thousands) Revenues: Services$61,133 $64,858 $(3,725) (6)%Products330,200 458,302 (128,102) (28)%Total revenues391,333 523,160 (131,827) (25)% Cost of products sold292,573 416,404 (123,831) (30)%Operating expenses23,152 23,979 (827) (3)%Selling, general and administrative expenses9,035 9,791 (756) (8)%Depreciation and amortization28,081 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 $166.6million.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 inaverage 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 ofproducts 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 fuelexpense at our gas storage facilities, $0.3 million decrease in maintenance expense at our gas storage facilities, $0.1 million decrease in NGLs employmentexpense 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 ourArcadia 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 inprofessional 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 tocontracts 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 SegmentComparative Results of Operations for the Twelve Months Ended December 31, 2017 and 2016 Year Ended December 31, Variance PercentChange 2017 2016 (In thousands) Revenues: Services$10,952 $10,800 $152 1%Products123,732 130,258 (6,526) (5)%Total revenues134,684 141,058 (6,374) (5)% Cost of products sold82,760 88,325 (5,565) (6)%Operating expenses13,783 13,771 12 —%Selling, general and administrative expenses4,136 3,861 275 7%Depreciation and amortization8,117 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 revenuesincreased $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 increasedcompensation 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 duringthe 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 PercentChange 2016 2015 (In thousands) Revenues: Services$10,800 $12,270 $(1,470) (12)%Products130,258 157,891 (27,633) (18)%Total revenues141,058 170,161 (29,103) (17)% Cost of products sold88,325 115,133 (26,808) (23)%Operating expenses13,771 15,279 (1,508) (10)%Selling, general and administrative expenses3,861 3,805 56 1%Depreciation and amortization7,995 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 revenuesdecreased 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. A6% 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 compensationexpense, $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 marineoperating 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 thirdquarter of 2016.Other operating loss, net. Other operating loss, net represents losses from the disposition of property, plant and equipment.51Marine Transportation SegmentComparative Results of Operations for the Twelve Months Ended December 31, 2017 and 2016 Year Ended December 31, Variance PercentChange 2017 2016 (In thousands) Revenues$51,915 $61,233 $(9,318) (15)%Operating expenses44,028 53,118 (9,090) (17)%Selling, general and administrative expenses358 18 340 1,889%Impairment of long-lived assets1,625 11,701 (10,076) (86)%Impairment of goodwill— 4,145 (4,145) (100)%Depreciation and amortization7,002 10,572 (3,570) (34)% (1,098) (18,321) 17,223 (94)%Other operating loss, net(113) (1,567) 1,454 (93)%Operating loss$(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 fleetresulting 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 previouslydeferred 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 maintenanceof $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 includingthe 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 secondquarter of 2016. Depreciation and amortization. Depreciation and amortization decreased as a result of the disposal of property, plant and equipment combined withthe 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 PercentChange 2016 2015 (In thousands) Revenues$61,233 $81,784 $(20,551) (25)%Operating expenses53,118 63,412 (10,294) (16)%Selling, general and administrative expenses18 417 (399) (96)%Impairment of long lived assets11,701 1,324 10,377 784%Impairment of goodwill4,145 — 4,145 Depreciation and amortization10,572 10,992 (420) (4)% (18,321) 5,639 (23,960) (425)%Other operating loss, net(1,567) (1,009) (558) 55%Operating income (loss)$(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 anabundance 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 therecognition 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 andburden of $3.2 million, lower repairs and maintenance of $5.3 million and operating supplies of $0.5 million. Offsetting these decreases were increases inclaims 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 feesand 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 of2016.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 PercentChange 2017 2016 (In thousands) Equity in earnings of WTLPG$4,314 $4,714 (400) (8)% Year Ended December 31, Variance PercentChange 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, andenvironmental 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 PercentChange 2016 2015 (In thousands) Equity in earnings of WTLPG$4,714 $8,986 $(4,272) (48)% Year Ended December 31, Variance PercentChange 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 maintenanceon the asset. Distributions from WTLPG decreased $3.7 million.54Interest ExpenseComparative Components of Interest Expense, Net for the Twelve Months Ended December 31, 2017 and 2016 Year Ended December 31, Variance PercentChange 2017 2016 (In thousands) Revolving loan facility$18,192 $19,482 $(1,290) (7)%7.250 % senior unsecured notes27,101 27,326 (225) (1)%Amortization of deferred debt issuance costs2,897 3,684 (787) (21)%Amortization of debt discount and premium(306) (306) — —%Impact of interest rate derivative activity, including cash settlements— (995) 995 (100)%Other1,532 291 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 PercentChange 2016 2015 (In thousands) Revolving loan facility$19,482 $16,270 $3,212 20%7.250 % senior unsecured notes27,326 28,583 (1,257) (4)%Amortization of deferred debt issuance costs3,684 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)%Other291 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 PercentChange Year Ended December 31, Variance PercentChange 2017 2016 2016 2015 (In thousands) (In thousands) Indirect selling, general andadministrative 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 ResourceManagement 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 andother general corporate overhead functions we share with Martin Resource Management retained businesses. This allocation is based on the percentage oftime spent by Martin Resource55Management personnel that provide such centralized services. GAAP also permits other methods for allocation of these expenses, such as basing theallocation on the percentage of revenues contributed by a segment. The allocation of these expenses between Martin Resource Management and us is subjectto 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 thefuture, 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 corporateoverhead expenses. The Conflicts Committee approved the following reimbursement amounts: Year Ended December 31, Variance PercentChange Year Ended December 31, Variance PercentChange 2017 2016 2016 2015 (In thousands) (In thousands) Conflicts Committee approvedreimbursement 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 inthe reimbursement amount for indirect expenses, if any, annually.Liquidity and Capital Resources GeneralOur primary sources of liquidity to meet operating expenses, pay distributions to our unitholders and fund capital expenditures have historicallybeen cash flows generated by our operations and access to debt and equity markets, both public and private. Management believes that expenditures for ourcurrent capital projects will be funded with cash flows from operations, current cash balances and our current borrowing capacity under the expandedrevolving credit facility. Given the current environment, we have altered and reduced our planned growth capital expenditures. We believe that controllingour 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 alsodepend upon our future operating performance, which is subject to certain risks. Please read "Item 1A. Risk Factors - Risks related to Our Business" for adiscussion 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 ofunderwriters' 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 theissuance 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 revolvingcredit 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 meetour 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 willdepend upon our future operating performance, which is subject to certain risks. Please read "Item 1A. Risk Factors - Risks Relating to Our Business" for adiscussion of such risks.56Cash Flows - Twelve Months Ended December 31, 2017 Compared to Twelve Months Ended December 31, 2016The following table details the cash flow changes between the twelve months ended December 31, 2017 and 2016: Years Ended December 31, Variance PercentChange 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 fromcontinuing operations of $14.5 million and a $29.6 million unfavorable variance in working capital. Further decreases were due to an $11.8 million decreasein 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 afavorable 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 netproceeds from the sale of property, plant and equipment. The 2017 period also included an acquisition of $19.5 million compared to an acquisition of $2.2million in 2016, resulting in a $17.4 million decrease in cash. Offsetting these decreases was an increase of $15.0 million for proceeds received fromrepayment 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 decreasein net repayments of long-term borrowings of $57.0 million. Proceeds received from the issuance of common units (including the related general partnercontribution) 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 costsassociated with our credit facility amendment. Offsetting was an increase of $10.9 million related to excess purchase price over the carrying value of acquiredassets in common control transactions.Cash Flows - Twelve Months Ended December 31, 2016 Compared to Twelve Months Ended December 31, 2015The following table details the cash flow changes between the twelve months ended December 31, 2016 and 2015: Years Ended December 31, Variance PercentChange 2016 2015 (In thousands) Net cash provided by (used in): Operating activities$110,848 $182,572 $(71,724) (39)%Investing activities63,839 (23,805) 87,644 368%Financing activities(174,703) (158,778) (15,925) (10)%Net decrease in cash and cash equivalents$(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 fromcontinuing operations of $12.0 million, a decrease in distributions from WTLPG of $3.7 million, and a $57.4 million unfavorable variance in working capitaland 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 ofproperty, plant and equipment in 2016. Payments for capital expenditures and plant turnaround costs decreased $25.2 million in 2016. Offsetting theseincreases was a decrease due to the 2015 period including $41.3 million in cash proceeds from the disposition of certain floating storage assets classified asdiscontinued operations. The 2016 period also included an acquisition of intangible assets of $2.2 million compared to no acquisitions in 2015.57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 increasein 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 facilityamendment 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 millionrelated to excess purchase price over the carrying value of acquired assets in common control transactions.Capital ExpendituresOur operations require continual investment to upgrade or enhance operations and to ensure compliance with safety, operational, and environmentalregulations. 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 operatingcapacity, 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 processmaterials and equipment.The following table summarizes maintenance and expansion capital expenditures, excluding amounts paid for acquisitions, for the periodspresented: Three Months EndedDecember 31, Years Ended December 31, 2017 2016 2017 2016 (In thousands) (In thousands)Expansion capital expenditures$6,883 $4,977 $23,951 $19,107Maintenance capital expenditures5,586 4,345 18,080 17,163Plant turnaround costs— 447 1,583 2,061 Total$12,469 $9,769 $43,614 $38,331Expansion capital expenditures were made primarily in our Terminalling and Storage and Natural Gas Services segments during the twelve monthsended December 31, 2017. Within our Terminalling and Storage segment, expenditures were made primarily on project construction at our newly acquiredasphalt terminal in Hondo, Texas, at our Smackover refinery, and on certain organic growth projects ongoing in our specialty terminalling operations. Withinour 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 endedDecember 31, 2017. These expenditures were primarily made on certain organic growth projects ongoing in our Terminalling and Storage and MarineTransportation operations. Maintenance capital expenditures were made primarily in our Terminalling and Storage segment to maintain our existing assetsand 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 twelvemonths ended December 31, 2016. Within our Terminalling and Storage segment, expenditures were made primarily at our Smackover refinery and on certainorganic growth projects ongoing in our specialty terminalling operations. Within our Natural Gas Services segment, expenditures were made primarily oncertain organic growth projects ongoing in our Natural Gas Services operations. Maintenance capital expenditures were made primarily in our Terminallingand Storage, Sulfur Services, and Natural Gas Services segments to maintain our existing assets and operations during the three and twelve months endedDecember 31, 2016.Capital ResourcesHistorically, we have generally satisfied our working capital requirements and funded our capital expenditures with cash generated from operationsand borrowings. We expect our primary sources of funds for short-term liquidity will be cash flows from operations and borrowings under our credit facility.58Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of December 31, 2017, is as follows (dollars inthousands): Payments due by periodType of ObligationTotalObligation Less thanOne Year 1-3Years 3-5Years DueThereafterRevolving credit facility$445,000 $— $445,000 $— $—2021 senior unsecured notes373,800 — — 373,800 —Throughput commitment21,946 6,184 12,866 2,896 —Operating leases26,189 6,841 8,274 3,324 7,750Interest payable on fixed long-term obligations84,690 27,101 54,201 3,388 —Total contractual cash obligations$951,625 $40,126 $520,341 $383,408 $7,750The 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 ourrevolving credit facility.Off Balance Sheet Arrangements. We do not have any off-balance sheet financing arrangements. Description of Our Long-Term Debt2021 Senior NotesWe 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, the2021 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 aprivate placement add-on of $150.0 million of the 2021 Notes. In 2015, we repurchased on the open market and subsequently retired an aggregate $26.2million 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 underthe Securities Act of 1933, as amended (the "Securities Act"). The 2021 Notes were resold to qualified institutional buyers pursuant to Rule 144A under theSecurities 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 theredemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make whole premium at the redemption date, plus accrued and unpaidinterest, 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 atthe 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 atany 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 interestsin our subsidiaries; (ii) pay distributions on, redeem or repurchase our units or redeem or repurchase our subordinated debt; (iii) make investments; (iv) incuror guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or otherpayments from our restricted subsidiaries to us; (vii) consolidate, merge or transfer all or substantially all of our assets; (viii) engage in transactions withaffiliates; (ix) create unrestricted subsidiaries; (x) enter into sale and leaseback transactions; or (xi) engage in certain business activities. These covenants aresubject to a number of important exceptions and qualifications. If the 2021 Notes achieve an59investment grade rating from each of Moody's Investors Service, Inc. and Standard & Poor's Ratings Services and no Default (as defined in the 2021Indenture) 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 ofinterest 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 withcertain 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 daysafter 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 anyof the other agreements in the 2021 Indenture; (vi) default under any mortgage, indenture or instrument governing any indebtedness for money borrowed orguaranteed 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, ifsuch 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, theprincipal amount of the indebtedness, together with the principal amount of any other such indebtedness under which there has been a payment default oracceleration 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 finaljudgments 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 bythe 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 oreffect, 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 subsidiariesthat is a significant subsidiary or any group of restricted subsidiaries that, taken together, would constitute a significant subsidiary of us. Upon a continuingEvent 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 noticeto 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 abankruptcy, insolvency or reorganization with respect to the Issuers, any restricted subsidiary of us that is a significant subsidiary or any group of itsrestricted subsidiaries that, taken together, would constitute a significant subsidiary of us, will automatically cause the 2021 Notes to become due andpayable.Revolving Credit FacilityAt December 31, 2017, we maintained a $664.4 million credit facility. This facility was most recently amended on April 27, 2016, when we madecertain strategic amendments to our revolving credit facility which, among other things, decreased our borrowing capacity from $700.0 million to $664.4million 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, leavinga maximum available to be borrowed under our credit facility for future revolving credit borrowings and letters of credit of $205.0 million. Subject to thefinancial 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, 2017evaluation, we expect to improve leverage during the first quarter of 2018 through the impacts of selling inventory built during the second and third quartersin 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 lowof $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 onsubstantially 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 breakagecosts), subject to certain notice requirements. The credit facility requires mandatory prepayments of amounts outstanding thereunder with the net proceeds ofcertain 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 anapplicable 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’sprime rate) plus an applicable margin. We pay a per annum fee60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 creditfacility. 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 inthe credit facility, being generally computed as the ratio of total funded debt to consolidated earnings before interest, taxes, depreciation, amortization andcertain other non-cash charges) and are as follows as of December 31, 2017: Leverage RatioBase RateLoans EurodollarRateLoans Letters of CreditLess than 3.00 to 1.001.00% 2.00% 2.00%Greater than or equal to 3.00 to 1.00 and less than 3.50 to 1.001.25% 2.25% 2.25%Greater than or equal to 3.50 to 1.00 and less than 4.00 to 1.001.50% 2.50% 2.50%Greater than or equal to 4.00 to 1.00 and less than 4.50 to 1.001.75% 2.75% 2.75%Greater than or equal to 4.50 to 1.002.00% 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 forrevolving 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 dayof 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. Themaximum permitted senior leverage ratio (as defined in the credit facility but generally computed as the ratio of total secured funded debt to consolidatedearnings before interest, taxes, depreciation, amortization and certain other non-cash charges) is 3.50 to 1.00. The minimum interest coverage ratio (as definedin the credit facility but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cashcharges 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 assumeliens; (ii) make investments (including investments in our joint ventures) and acquisitions; (iii) enter into certain types of hedging agreements; (iv) incur orassume indebtedness; (v) sell, transfer, assign or convey assets; (vi) repurchase our equity, make distributions and certain other restricted payments, but thecredit facility permits us to make quarterly distributions to unitholders so long as no default or event of default exists under the credit facility; (vii) changethe nature of our business; (viii) engage in transactions with affiliates; (ix) enter into certain burdensome agreements; (x) make certain amendments to theOmnibus Agreement and our material agreements; (xi) make capital expenditures; and (xii) permit our joint ventures to incur indebtedness or grant certainliens.The credit facility contains customary events of default, including, without limitation: (i) failure to pay any principal, interest, fees, expenses orother amounts when due; (ii) failure to meet the quarterly financial covenants; (iii) failure to observe any other agreement, obligation, or covenant in thecredit facility or any related loan document, subject to cure periods for certain failures; (iv) the failure of any representation or warranty to be materially trueand correct when made; (v) our, or any of our subsidiaries’ default under other indebtedness that exceeds a threshold amount; (vi) bankruptcy or otherinsolvency events involving us or any of our subsidiaries; (vii) judgments against us or any of our subsidiaries, in excess of a threshold amount; (viii) certainERISA 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) theinvalidity 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 longercontrols 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 isdeemed 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 underour credit facility will immediately become due and payable. If any other event of default exists under our credit facility, the lenders may terminate theircommitments to lend us money, accelerate the maturity of the indebtedness outstanding under the credit facility and exercise other rights and remedies. Inaddition, if any event of default exists under our credit facility, the lenders may commence foreclosure or other actions against the collateral. 61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 variablerate 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.SeasonalityA substantial portion of our revenues are dependent on sales prices of products, particularly NGLs and fertilizers, which fluctuate in part based onwinter and spring weather conditions. The demand for NGLs is strongest during the winter heating season and the refinery blending season. The demand forfertilizers is strongest during the early spring planting season. However, our WTLPG and natural gas storage divisions of the Natural Gas Services segmenteach provide stable cash flows and are not generally subject to seasonal demand factors. Additionally, our Terminalling and Storage and MarineTransportation segments and the molten sulfur business are typically not impacted by seasonal fluctuations and a significant portion of our net income isderived from our terminalling and storage, sulfur and marine transportation businesses. Therefore, we do not expect that our overall net income will beimpacted by seasonality factors. However, extraordinary weather events, such as hurricanes, have in the past, and could in the future, impact ourTerminalling and Storage and Marine Transportation segments.Impact of InflationInflation did not have a material impact on our results of operations in 2017, 2016 or 2015. Although the impact of inflation has been insignificantin 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 thecosts of labor and supplies. In the future, increasing energy prices could adversely affect our results of operations. Diesel fuel, natural gas, chemicals andother supplies are recorded in operating expenses. An increase in price of these products would increase our operating expenses which could adversely affectnet income. We cannot provide assurance that we will be able to pass along increased operating expenses to our customers.Environmental MattersOur operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which theseoperations are conducted. We incurred no material environmental costs, liabilities or expenditures to mitigate or eliminate environmental contaminationduring 2017, 2016 or 2015.62Item 7A.Quantitative and Qualitative Disclosures about Market RiskCommodity Risk. The Partnership from time to time uses derivatives to manage the risk of commodity price fluctuation. Commodity risk is theadverse 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 monitorand manage the commodity market risk associated with potential commodity risk exposure. In addition, we focus on utilizing counterparties for thesetransactions 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 hedgingarrangements are in the form of swaps for NGLs. We have instruments totaling a gross notional quantity of 145,000 barrels settling during the period fromJanuary 31, 2018 through February 28, 2018. These instruments settle against the applicable pricing source for each grade and location. These instrumentsare 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 thecurrent 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 ininterest 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 millionannually.We are not exposed to changes in interest rates with respect to our senior unsecured notes as these obligations are fixed rate. The estimated fairvalue 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 pointincrease 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 atDecember 31, 2017. 63Item 8.Financial Statements and Supplementary DataThe following financial statements of Martin Midstream Partners L.P. (Partnership) are listed below: PageReports of Independent Registered Public Accounting Firm65Consolidated Balance Sheets as of December 31, 2017 and 201667Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 201568Consolidated Statements of Changes in Capital for the years ended December 31, 2017, 2016 and 201571Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 201572Notes to Consolidated Financial Statements7364Report of Independent Registered Public Accounting Firm To the Unitholders and Board of DirectorsMartin Midstream Partners LP and Martin Midstream GP LLC:Opinion on the Consolidated Financial StatementsWe 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 endedDecember 31, 2017,and the related notes collectively, the “consolidated financial statements”. In our opinion, the consolidated financial statements presentfairly, 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 flowsfor 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’sinternal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued bythe Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 16, 2018 expressed an unqualified opinion on theeffectiveness of the Partnership’s internal control over financial reporting.Basis for OpinionThese consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on theseconsolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent withrespect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and ExchangeCommission 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 reasonableassurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performingprocedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures thatrespond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financialstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating theoverall 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 1981Dallas, TexasFebruary 16, 2018 65Report of Independent Registered Public Accounting FirmTo the Unitholders and Board of DirectorsMartin Midstream Partners LP and Martin Midstream GP LLC:Opinion on Internal Control Over Financial ReportingWe have audited Martin Midstream Partners LP and subsidiaries' (the “Partnership”) internal control over financial reporting as of December 31, 2017, basedon criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the TreadwayCommission. 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 TreadwayCommission.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidatedbalance sheets of the Partnership as of December 31, 2017 and 2016, the related consolidated statements of operations, changes in capital, and cash flows foreach of the years in the three‑year period ended December 31, 2017,and the related notes (collectively, the “consolidated financial statements”), and ourreport dated February 16, 2018, expressed an unqualified opinion on those consolidated financial statements.Basis for OpinionThe Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness ofinternal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Ourresponsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firmregistered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and theapplicable 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 reasonableassurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financialreporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing andevaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures aswe 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 ReportingA company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reportingand the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal controlover financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permitpreparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are beingmade only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention ortimely 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 ofeffectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliancewith the policies or procedures may deteriorate./s/ KPMG LLP Dallas, TexasFebruary 16, 201866MARTIN MIDSTREAM PARTNERS L.P.CONSOLIDATED BALANCE SHEETS(Dollars in thousands) December 31, 2017 2016Assets Cash$27 $15Trade and accrued accounts receivable, less allowance for doubtful accounts of $314 and $372 respectively107,242 80,508Product exchange receivables29 207Inventories97,252 82,631Due from affiliates23,668 11,567Other current assets4,866 3,296Assets held for sale9,579 15,779Total current assets242,663 194,003 Property, plant and equipment, at cost1,253,065 1,224,277Accumulated depreciation(421,137) (378,593)Property, plant and equipment, net831,928 845,684 Goodwill17,296 17,296Investment in unconsolidated entities128,810 129,506Notes receivable - Martin Energy Trading LLC— 15,000Intangibles and other assets, net32,801 44,874 $1,253,498 $1,246,363Liabilities and Partners’ Capital Trade and other accounts payable$92,567 $70,249Product exchange payables11,751 7,360Due to affiliates3,168 8,474Income taxes payable510 870Fair value of derivatives72 3,904Other accrued liabilities26,340 26,717Total current liabilities134,408 117,574 Long-term debt, net812,632 808,107Other long-term obligations8,217 8,676Total liabilities955,257 934,357Commitments and contingencies Partners’ capital298,241 312,006Total partners’ capital298,241 312,006 $1,253,498 $1,246,363See 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 2015Revenues: Terminalling and storage *$99,705 $123,132 $132,945Marine transportation *48,579 58,290 78,753Natural gas storage services *58,817 61,133 64,858Sulfur services10,952 10,800 12,270Product sales: * Natural gas services473,865 330,200 458,302Sulfur services123,732 130,258 157,891Terminalling and storage130,466 113,578 131,825 728,063 574,036 748,018Total revenues946,116 827,391 1,036,844 Costs and expenses: Cost of products sold: (excluding depreciation and amortization) Natural gas services *421,444 289,516 413,795Sulfur services *82,338 87,963 114,766Terminalling and storage *109,798 94,175 112,836 613,580 471,654 641,397Expenses: Operating expenses *146,874 158,864 183,466Selling, general and administrative *38,950 34,385 36,788Impairment of long-lived assets2,225 26,953 10,629Impairment of goodwill— 4,145 —Depreciation and amortization85,195 92,132 92,250Total costs and expenses886,824 788,133 964,530Other operating income (loss), net523 33,400 (2,161)Operating income59,815 72,658 70,153 Other income (expense): Equity in earnings of unconsolidated entities4,314 4,714 8,986Interest expense, net(47,743) (46,100) (43,292)Gain on retirement of senior unsecured notes— — 1,242Other, net1,101 1,106 1,124Total other income (expense)(42,328) (40,280) (31,940)Net income before taxes17,487 32,378 38,213Income tax expense(352) (726) (1,048)Income from continuing operations17,135 31,652 37,165Income from discontinued operations, net of income taxes— — 1,215Net income17,135 31,652 38,380Less 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 BelowSee 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 2015Revenues: Terminalling and storage$82,205 $82,437 $78,233Marine transportation16,801 21,767 27,724Natural gas services122 699 878Product sales3,578 3,034 5,671Costs and expenses: Cost of products sold: (excluding depreciation and amortization) Natural gas services18,946 22,886 25,797Sulfur services15,564 15,339 16,579 Terminalling and storage17,612 13,838 17,718Expenses: Operating expenses64,344 70,841 77,871Selling, general and administrative29,416 25,890 24,968See 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 2015Allocation of net income attributable to: Limited partner interest: Continuing operations$16,750 $23,143 $21,208 Discontinued operations— — 694 $16,750 $23,143 $21,902General 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 $0.60Discontinued operations— — 0.02 $0.44 $0.65 $0.62 Weighted average limited partner units - basic38,102 35,347 35,309 Diluted: Continuing operations$0.44 $0.65 $0.60Discontinued operations— — 0.02 $0.44 $0.65 $0.62 Weighted average limited partner units - diluted38,165 35,375 35,372See 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 TotalBalances – December 31, 201435,365,912 $470,943 $14,728 $485,671 Net income— 22,042 16,338 38,380Issuance of common units, net— (590) — (590)Issuance of restricted units91,950 — — —Forfeiture of restricted units(1,250) — — —General partner contribution— — 55 55Cash distributions— (115,229) (18,087) (133,316)Reimbursement of excess purchase price over carrying value of acquired assets— 2,250 — 2,250Unit-based compensation— 1,429 — 1,429Balances – December 31, 201535,456,612 380,845 13,034 393,879 Net income— 23,233 8,419 31,652Issuance of common units, net— (29) — (29)Issuance of restricted units13,800 — — —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 — 4,125Unit-based compensation— 904 — 904Purchase of treasury units(16,100) (347) — (347)Balances – December 31, 201635,452,062 304,594 7,412 312,006 Net income— 16,792 343 17,135Issuance of common units, net2,990,000 51,056 — 51,056Issuance of restricted units12,000 — — —Forfeiture of restricted units(9,250) — — —General partner contribution— — 1,098 1,098Cash distributions— (75,399) (1,539) (76,938)Reimbursement of excess purchase price over carrying value of acquired assets— 1,125 — 1,125Excess purchase price over carrying value of acquired assets— (7,887) — (7,887)Unit-based compensation— 650 — 650Purchase of treasury units(200) (4) — (4)Balances – December 31, 201738,444,612 $290,927 $7,314 $298,241See 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 2015Cash flows from operating activities: Net income$17,135 $31,652 $38,380Less: Income from discontinued operations— — (1,215)Net income from continuing operations17,135 31,652 37,165Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization85,195 92,132 92,250Amortization of deferred debt issue costs2,897 3,684 4,859Amortization of premium on notes payable(306) (306) (324)(Gain) loss on disposition or sale of property, plant, and equipment(523) (33,400) 2,149Gain on retirement of senior unsecured notes— — (1,242)Impairment of long lived assets2,225 26,953 10,629Impairment of goodwill— 4,145 —Equity in earnings unconsolidated entities(4,314) (4,714) (8,986)Derivative (income) loss1,304 4,133 (3,107)Net cash (paid) received for commodity derivatives(5,136) (550) 143Net cash received for interest rate derivatives— 160 —Net premiums received on derivatives that settled during the year on interest rate swaption contracts— 630 2,495Unit-based compensation650 904 1,429Return on investment5,400 7,500 11,200Change in current assets and liabilities, excluding effects of acquisitions and dispositions: Accounts and other receivables(26,739) (6,153) 59,479Product exchange receivables178 843 1,996Inventories(14,656) (6,761) 12,799Due from affiliates(12,096) (1,441) 4,386Other current assets(1,699) 2,478 891Trade and other accounts payable20,037 3,254 (44,153)Product exchange payables4,391 (5,372) 2,336Due to affiliates(5,306) 2,736 866Income taxes payable(360) (115) (189)Other accrued liabilities(3,187) 686 (2,802)Change in other non-current assets and liabilities2,416 (12,230) (345)Net cash provided by continuing operating activities67,506 110,848 183,924Net cash used in discontinued operating activities— — (1,352)Net cash provided by operating activities67,506 110,848 182,572Cash 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 equipment8,377 108,505 2,644Proceeds from repayment of Note receivable - affiliate15,000 — —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— — 41,250Net 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 debt341,000 331,700 282,000Net proceeds from issuance of common units51,056 (29) (590)General partner contributions1,098 — 55Excess purchase price over carrying value of acquired assets(7,887) — —Reimbursement of excess purchase price over carrying value of acquired assets1,125 4,125 2,250Purchase 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 cash12 (16) (11)Cash at beginning of year15 31 42Cash 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 BusinessMartin Midstream Partners L.P. (the "Partnership") is a publicly traded limited partnership with a diverse set of operations focused primarily in theUnited States ("U.S.") Gulf Coast region. Its four primary business lines include: terminalling and storage services for petroleum products and by-productsincluding the refining of naphthenic crude oil and the blending and packaging of finished lubricants; natural gas services, including liquids transportationand distribution services and natural gas storage; sulfur and sulfur-based products processing, manufacturing, marketing and distribution; and marinetransportation 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 independentoil and gas companies who often turn to third parties, such as the Partnership, for the transportation and disposition of these products. In addition to thesemajor and independent oil and gas companies, the Partnership's primary customers include independent refiners, large chemical companies, fertilizermanufacturers and other wholesale purchasers of these products. The Partnership operates primarily in the U.S. Gulf Coast region, which is a major hub forpetroleum 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 MMGPHoldings, LLC ("Holdings"), a newly-formed sole member of Martin Midstream GP LLC ("MMGP"), the general partner of the Partnership, to certain affiliatedinvestment funds managed by Alinda Capital Partners ("Alinda"). Upon closing the transaction, Alinda appointed two representatives to serve on the board ofdirectors of the general partner of the Partnership.(2)Significant Accounting Policies(a) Principles of Presentation and ConsolidationThe consolidated financial statements include the financial statements of the Partnership and its wholly-owned subsidiaries and equity methodinvestees. In the opinion of the management of the Partnership’s general partner, all adjustments and elimination of significant intercompany balancesnecessary for a fair presentation of the Partnership’s results of operations, financial position and cash flows for the periods shown have been made. All suchadjustments are of a normal recurring nature. In addition, the Partnership evaluates its relationships with other entities to identify whether they are variableinterest entities under certain provisions of the Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC"), 810-10 and toassess whether it is the primary beneficiary of such entities. If the determination is made that the Partnership is the primary beneficiary, then that entity isincluded 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, collectivelyreferred to as the "Floating Storage Assets." These assets were acquired on February 28, 2013. On December 19, 2014, the Partnership made the decision todispose of the Floating Storage Assets. As a result, the Partnership has presented the results of operations and cash flows of the Floating Storage Assets asdiscontinued 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 marketproduct 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 relatedto 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 andlubricants 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, revenueis recognized based on the contracted monthly reservation fee and throughput volumes moved through the facility. When lubricants and drilling fluids aresold by truck or rail, revenue is recognized upon delivering product to the customers as title to the product transfers when the customer physically receivesthe product. Natural Gas Services – NGL distribution revenue is recognized when product is delivered by truck, rail, or pipeline to the Partnership's NGLcustomers. 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 isrecognized 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 uponcompletion 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 influenceover such entities exists. Investments in unconsolidated entities consist of capital contributions and advances plus the Partnership’s share of accumulatedearnings as of the entities’ latest fiscal year-ends, less capital withdrawals and distributions. Equity method investments are subject to impairment under theprovisions of ASC 323-10, which relates to the equity method of accounting for investments in common stock. No portion of the net income from theseentities is included in the Partnership’s operating income.(f) Property, Plant, and EquipmentOwned property, plant, and equipment is stated at cost, less accumulated depreciation. Owned buildings and equipment are depreciated usingstraight-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 capitalleases 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, itscost and related accumulated depreciation are removed from the accounts, and the difference between net book value of the asset and proceeds fromdisposition is recognized as gain or loss. (g) Goodwill and Other Intangible AssetsGoodwill is subject to a fair-value based impairment test on an annual basis, or more often if events or circumstances indicate there may beimpairment. The Partnership is required to identify its reporting units and determine the carrying value of each reporting unit by assigning the assets andliabilities, including the existing goodwill and intangible assets. The Partnership is required to determine the fair value of each reporting unit and compare itto 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 Partnershipwill 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 ofgoodwill 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 whetherit 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, ifthe 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 amountexceeds the fair value of a reporting unit or other intangible asset, a quantitative analysis will be performed. The Partnership may also elect to bypass thequalitative 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. Nogoodwill impairment was recorded for the year ended December 31, 2017. During the second quarter of 2016, the Partnership experienced an impairment ofall 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 flowmethod and two market approaches (the guideline public company method and the guideline transaction method). The discounted cash flow modelincorporates discount rates commensurate with the risks involved. Use of a discounted cash flow model is common practice in assessing impairment in theabsence of available transactional market evidence to determine the fair value. The key assumptions used in the discounted cash flow valuation modelinclude discount rates, growth rates, cash flow projections and terminal value rates. Discount rates, growth rates and cash flow projections are the mostsensitive and susceptible to change as they require significant management judgment. Discount rates are determined by using a weighted average cost ofcapital ("WACC"). The WACC considers market and industry data as well as company-specific risk factors for each reporting unit in determining theappropriate discount rate to be used. The discount rate utilized for each reporting unit is indicative of the return an investor would expect to receive forinvesting in such a business. Management, considering industry and company specific historical and projected data, develops growth rates and cash flowprojections for each reporting unit. Terminal value rate determination follows common methodology of capturing the present value of perpetual cash flowestimates beyond the last projected period assuming a constant WACC and low long-term growth rates. If the calculated fair value is less than the currentcarrying 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 toexceed 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 couldgive rise to future impairment. Changes to these estimates and assumptions can include, but may not be limited to, varying commodity prices, volumechanges 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 berecoverable. An impairment is indicated if the carrying amount of a long-lived intangible asset exceeds the sum of the undiscounted future cash flowsexpected to result from the use and eventual disposition of the asset. If impairment is indicated, the Partnership would record an impairment loss equal to thedifference 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 CostsDebt issuance costs relating to the Partnership’s revolving credit facility and senior unsecured notes are deferred and amortized over the terms of thedebt 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 capacityfrom $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, thePartnership 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 transactionresulted in the write-off of $235 of existing debt issuance costs that were determined not to have continuing benefit. On August 14, 2015, the Partnershipreduced 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 thatwere 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 endedDecember 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 forimpairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to beheld 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 theasset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carryingamount 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 lowerof 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 forsale 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 longerdeemed core assets in the Partnership's Marine Transportation business. The triggering event was the assets' inability to generate cash flows in recent quartersand going forward. As a result, an impairment charge of $1,625 was recorded in the Marine Transportation segment results of operations in the fourth quarterof 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 MartinLubricants division of the Terminalling and Storage segment. As a result, an impairment charge of $600 was recorded in the Terminalling and Storagesegment 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 producingover 50 inches of rain in some areas, resulting in widespread flooding and damage. The Partnership experienced an impact from Hurricane Harvey in ourTerminalling 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 theselocations and therefore The Partnership does not expect to receive any insurance proceeds resulting from the damage from Hurricane Harvey. In the thirdquarter 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 andSpecialty Terminals divisions of the Partnership's Terminalling and Storage segment. These triggering events were the decision to not move forward withcertain expansion projects due to the evaporation of the economic viability of the projects. Additionally, a triggering event was identified related to theplanned disposition of certain assets that were no longer deemed core assets to the Partnership's Martin Lubricants division. As a result, an impairment chargeof $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'sMarine Transportation business. The triggering event was the assets' inability to generate cash flows in recent quarters and going forward. As a result, animpairment 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 divisionof the Partnership's Terminalling and Storage segment. The triggering event was the decision to not move forward with the project due to the evaporation ofthe economic viability of the project. As a result, an impairment76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, thePartnership identified a triggering event related to one inland push boat and three inland tank barges in the Marine Transportation segment. The triggeringevent 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 theMarine 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, thePartnership records an asset retirement obligation ("ARO") at fair value in the period in which it is incurred by increasing the carrying amount of the relatedlong-lived asset. In each subsequent period, the liability is accreted over time towards the ultimate obligation amount and the capitalized costs aredepreciated 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 andhedging instruments are included in the Consolidated Balance Sheets as an asset or liability measured at fair value and changes in fair value are recognizedcurrently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offsetagainst 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 isrecognized in earnings. Derivative instruments not designated as hedges are marked to market with all market value adjustments being recorded in the ConsolidatedStatements of Operations. (l) Use of EstimatesManagement has made a number of estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingentassets and liabilities to prepare these consolidated financial statements in conformity with accounting principles generally accepted in the U.S. Actual resultscould 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 ofcentralized corporate functions such as accounting, treasury, engineering, information technology, risk management and other corporate services. Suchexpenses are based on the percentage of time spent by Martin Resource Management’s personnel that provide such centralized services. Under an omnibusagreement with Martin Resource Management, the Partnership is required to reimburse Martin Resource Management for indirect general and administrativeand 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 ofsuch 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 reasonablyestimable. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remedialfeasibility study. Such accruals are adjusted as further information develops or circumstances change. Costs of future expenditures for environmentalremediation obligations are not discounted to their present value. Recoveries of environmental remediation costs from other parties are recorded as assetswhen 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’sbest estimate of the amount of probable credit losses in the Partnership’s existing accounts receivable. (p) 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 36months.(q) Deferred Turnaround CostsThe Partnership capitalizes the cost of major turnarounds and amortizes these costs over the estimated period to the next turnaround, which rangesfrom 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 theConsolidated Statements of Operations. Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed asan 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 isimmaterial.(s) Comprehensive Income Comprehensive income includes net income and other comprehensive income. There are no items of other comprehensive income or loss in any ofthe years presented.(3)Recent Accounting PronouncementsIn 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 thecurrent 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 carryingamount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance does not amend the optionalqualitative assessment of goodwill impairment. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscalyears, 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 CertainCash Receipts and Cash Payments. This ASU is intended to clarify the presentation of cash receipts and payments in specific situations. The amendments inthis ASU are effective for financial statements issued for annual periods beginning after December 15, 2017, including interim periods within those annualperiods, and early application is permitted. The Partnership does not anticipate that ASU 2016-15 will have a material effect on its consolidated financialstatements and related disclosures.In February 2016, the FASB issued ASU 2016-02, Leases. This ASU amends the existing accounting standards for lease accounting, includingrequiring lessees to recognize most leases on their balance sheets and making targeted changes to lessor accounting. ASU 2016-02 is effective for annualreporting 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 optionto use certain transition relief. The Partnership is evaluating the effect that ASU 2016-02 will have on its consolidated financial statements and relateddisclosures.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 ofrevenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU will replace most existing revenue recognitionguidance 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 eitherthe retrospective or cumulative effect transition method. The Partnership plans to adopt the new standard utilizing the cumulative effect method which willresult 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 applicationof the new standard to its existing portfolio of customer contracts and has concluded its process of evaluating its new controls and processes designed tocomply with ASU 2014-09 throughout 2017 to permit adoption by January 1, 2018. The Partnership's approach included performing a detailed review of keycontracts 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 fixedfee. For throughput contracts, revenue will continue to be recognized based on the volume moved through the Partnership’s terminals at the contractedrate. For the Partnership’s tolling agreement, revenue will continue to be recognized based on the contracted monthly reservation fee and throughputvolumes moved through the facility. When lubricants and drilling fluids are sold by truck or rail, revenue will continue to be recognized upon deliveringproduct to the customers as title to the product transfers when the customer physically receives the product. Delivery of product is invoiced as the transactionoccurs 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 tothe Partnership's NGL customers. Revenue will continue to be recognized on title transfer of the product to the customer. Delivery of product is invoiced asthe transaction occurs and are generally paid within a month. Natural gas storage revenue will continue to be recognized when the service is provided to thecustomer. 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 theproduct. Delivery of product is invoiced as the transaction occurs and are generally paid within a month. Revenue from sulfur services will continue to berecognized as deliveries are made during each monthly period. The performance of the service is invoiced as the transaction occurs and are generally paidwithin 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, revenuewill continue to be recognized upon completion of the particular trip. The performance of the service is invoiced as the transaction occurs and are generallypaid within a month.Additionally, the Partnership will be required to assess variable consideration included in its contracts and make judgments and estimatesthroughout the applicable periods. Certain additional financial statement disclosure requirements are mandated by the new standard including disclosure ofcontract assets and contract liabilities as well as a disaggregated view of revenue. Based on the Partnership’s analysis, the adoption of this guidance will nothave a significant impact on its consolidated financial statements.(4)Acquisitions79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 TexasTerminals LLC (“MEH”), a subsidiary of Martin Resource Management, for a purchase price of $27,420 (the “Hondo Acquisition”), which was was fundedwith borrowings under the Partnership's revolving credit facility. At the date of acquisition, MEH was in the process of constructing an asphalt terminalfacility in Hondo, Texas (the "Hondo Terminal”), which will serve the asphalt market in San Antonio, Texas and surrounding areas. This acquisition isconsidered a transfer of net assets between entities under common control. The acquisition of these assets was recorded at the historical carrying value of theassets 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$27,420Historical carrying value of assets allocated to "Property, plant and equipment"19,533Excess purchase price over carrying value of acquired assets$7,887As no individual line item of the historical financial statements of the acquired assets was in excess of 3% of the Partnership's relative consolidatedfinancial 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 SaleLong-Lived Assets Held for SaleIn the fourth quarter of 2017, the Partnership identified certain assets that were no longer deemed core to the operations of the Partnership in theinland division of the Marine Transportation segment. Additionally, the Partnership recorded an adjustment to the fair value less cost to sell of a certain assetclassified as held for sale in the Martin Lubricants division of the Terminalling and Storage segment. As a result, an impairment charge of $600 and $1,625was 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 theSmackover refinery and Martin Lubricants divisions of the Terminalling and Storage segment as well as the inland and offshore divisions of the MarineTransportation 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 expectedcash flows in future quarters. As a result, an impairment charge of $15,252 and $11,701 was recorded in the Terminalling and Storage and MarineTransportation segments, respectively in the fourth quarter of 2016 and was presented as "Impairment of long-lived assets" in the Partnership's ConsolidatedStatements 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 theassets' fair value less cost to sell by segment in current assets as follows: December 31, 2017 December 31, 2016 Terminalling and storage$4,152 $10,852Marine transportation5,427 4,927 Assets held for sale$9,579 $15,779During 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 asa 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.Divestitures80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 bargeterminal, certain pipelines and related easements as well as dockage and trans-loading assets located in Corpus Christi, Texas (collectively the "CCCTAssets") 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 cashpayments 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 thedivestiture of $37,345, which was included in "Other operating income, net on the Partnership's Consolidated Statements of Operations for the year endedDecember 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") pressurebarges, collectively referred to as the Floating Storage Assets for $41,250. These assets were acquired on February 28, 2013. The Partnership classified theresults of operations of these assets, which were previously presented as a component of the Natural Gas Services segment, as discontinued operations in theConsolidated Statements of Operations for 2015. The Partnership has retrospectively adjusted its prior period consolidated financial statements tocomparably classify the amounts related to the operations and cash flows of the Floating Storage Assets as discontinued operations. The Floating StorageAssets 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$791Total costs and expenses and other, net, excluding depreciation and amortization1,038Depreciation and amortization—Other operating income, net 11,462Income (loss) from discontinued operations before income taxes1,215Income tax expense—Income (loss) from discontinued operations, net of income taxes$1,2151 Other operating income, net represents the gain on the disposition of the Floating Storage Assets.(6)InventoriesComponents of inventories at December 31, 2017 and 2016 were as follows: 2017 2016Natural gas liquids$47,462 $33,656Sulfur8,436 8,521Sulfur based products18,674 19,107Lubricants20,086 18,276Other2,594 3,071 $97,252 $82,63181MARTIN MIDSTREAM PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Dollars in thousands, except where otherwise indicated)(7)Property, Plant and EquipmentAt December 31, 2017 and 2016, property, plant and equipment consisted of the following: Depreciable Lives 2017 2016Land— $21,719 $20,679Improvements to land and buildings10-25 years 135,896 135,852Storage equipment5-50 years 178,815 168,839Marine vessels4-25 years 176,782 181,659Operating plant and equipment3-50 years 659,854 620,303Base Gas— 43,799 43,799Furniture, fixtures and other equipment3-20 years 11,134 19,034Transportation equipment3-7 years 1,535 1,738Construction in progress 23,531 32,374 $1,253,065 $1,224,277Depreciation 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) GoodwillThe following table represents the goodwill balance at December 31, 2016, changes during the year, and the resulting balances at December 31,2017: 2017 2016Carrying amount of goodwill: Terminalling and storage$11,868 $11,868 Natural gas services79 79 Sulfur services5,349 5,349 Total goodwill$17,296 $17,296During the impairment evaluation performed at August 31, 2017, the Partnership first assessed qualitative factors in determining whether it is morelikely than not that the fair value of a reporting unit or other intangible asset is less than its carrying amount. After assessing qualitative factors, thePartnership 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 impairmentwas 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 aresult, the Partnership assessed qualitative factors and determined that the Partnership could not conclude it was more likely than not that the fair value ofgoodwill 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 onthe weighted average valuation of the aforementioned income and market based valuation approaches. The underlying results of the valuation were drivenby 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 forecastsat 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. Uponcompletion 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) LeasesThe Partnership has numerous non-cancelable operating leases primarily for terminal facilities and transportation and other equipment. The leasesgenerally provide that all expenses related to the equipment are to be paid by the lessee. Management expects to renew or enter into similar leasingarrangements for similar equipment upon the expiration of the current lease agreements. The Partnership also has cancelable operating lease land rentals andoutside marine vessel charters.The Partnership’s future minimum lease obligations as of December 31, 2017 consist of the following:Fiscal yearOperating Leases 2018$6,84120194,55920203,71520212,24520221,079Thereafter7,750Total$26,189Rent 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 VenturesThe 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 pipelinesystem that primarily transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. The Partnership recognizes its 20% interest inWTLPG as "Investment in WTLPG" on its Consolidated Balance Sheet. The Partnership accounts for its ownership interest in WTLPG under the equitymethod 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 Income2017 WTLPG$837,163 $— $787,426 $87,048 $21,5712016 WTLPG$812,464 $— $790,406 $88,468 $23,8832015 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 $631,respectively.83MARTIN MIDSTREAM PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Dollars in thousands, except where otherwise indicated)(11) Fair Value MeasurementsThe Partnership uses a valuation framework based upon inputs that market participants use in pricing certain assets and liabilities. These inputs areclassified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources.Unobservable inputs represent the Partnership's own market assumptions. Unobservable inputs are used only if observable inputs are unavailable or notreasonably available without undue cost and effort. The two types of inputs are further prioritized into the following hierarchy:Level 1: Quoted market prices in active markets for identical assets or liabilities.Level 2: Observable market based inputs or unobservable inputs that are corroborated by market data.Level 3: Unobservable inputs that reflect the entity's own assumptions and are not corroborated by market data.Assets and liabilities measured at fair value on a recurring basis are summarized below: Level 2 December 31, 2017 2016Commodity derivative contracts, net$(72) $(3,904)The Partnership is required to disclose estimated fair values for its financial instruments. Fair value estimates are set forth below for these financialinstruments. The following methods and assumptions were used to estimate the fair value of each class of financial instrument:•Accounts and other receivables, trade and other accounts payable, accrued interest payable, other accrued liabilities, income taxes payable and duefrom/to affiliates: The carrying amounts approximate fair value due to the short maturity and highly liquid nature of these instruments, and as suchthese have been excluded from the table below. There is negligible credit risk associated with these instruments.•Note receivable and long-term debt: The carrying amount of the revolving credit facility approximates fair value due to the debt having a variableinterest rate and is in Level 2. The Partnership has not had any indicators which represent a change in the market spread associated with its variableinterest rate debt. The estimated fair value of the senior unsecured notes is considered Level 1, as the fair value is based on quoted market prices inactive markets. The estimated fair value of the note receivable - affiliates was determined by calculating the net present value of the payments overthe life of the note. The note is considered Level 3 due to the lack of observable inputs for similar transactions between related parties. December 31, 2017 December 31, 2016 CarryingValue FairValue CarryingValue FairValueNote receivable - affiliates$— $— $15,000 $15,7972021 Senior unsecured notes$372,618 $381,657 $372,239 $377,882(12) Derivative Instruments and Hedging ActivitiesThe Partnership’s revenues and cost of products sold are materially impacted by changes in NGL prices. Additionally, the Partnership's results ofoperations are materially impacted by changes in interest rates. In an effort to manage its exposure to these risks, the Partnership periodically enters intovarious derivative instruments, including commodity and interest rate hedges. All derivatives and hedging instruments are included on the balance sheet asan 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-hedgederivatives 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 Instruments84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 onthe value of a liability or future purchase that results from a change in commodity price. The Partnership has established a hedging policy and monitors andmanages the commodity market risk associated with potential commodity risk exposure. In addition, the Partnership has focused on utilizing counterpartiesfor these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction. The Partnership has entered intohedging transactions as of December 31, 2017 to protect a portion of its commodity price risk exposure. These hedging arrangements are in the form of swapsfor NGLs. The Partnership has instruments totaling a gross notional quantity of 145 barrels settling during the period from January 31, 2018 through February28, 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 forall positions outstanding at December 31, 2016.(b) Interest Rate Derivative InstrumentsThe Partnership is exposed to market risks associated with interest rates. Market risk is the adverse effect on the value of a financial instrument thatresults from a change in interest rates. We minimize this market risk by establishing and monitoring parameters that limit the types and degree of market riskthat may be undertaken. The Partnership enters into interest rate swaps to manage interest rate risk associated with the Partnership’s variable rate creditfacility 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 toenter into swap contracts to hedge the Partnership's exposure to changes in the fair value of its senior unsecured notes ("interest rate swaptions"). Inconnection with the interest rate swaption contracts, the Partnership received premiums of $630 and $2,495, which represented their fair value on the date thetransactions were initiated and were initially recorded as derivative liabilities on the Partnership's Consolidated Balance Sheet, during the twelve monthsended December 31, 2016 and 2015, respectively. Each of the interest rate swaptions was fully amortized as of December 31, 2016. Interest rate swaptioncontract premiums received are amortized over the period from initiation of the contract through their termination date. For the twelve months endedDecember 31, 2016 and 2015, the Partnership recognized $630 and $2,495, respectively, of premium in "Interest expense, net" on the Partnership'sConsolidated Statement of Operations related to the interest rate swaption contracts. For information regarding fair value amounts and gains and losses on interest rate derivative instruments and related hedged items, see "TabularPresentation of Gains and Losses on Derivative Instruments and Related Hedged Items" below.(c) Tabular Presentation of Gains and Losses on Derivative InstrumentsThe following table summarizes the fair values and classification of the Partnership’s derivative instruments in its Consolidated Balance Sheets: Fair Values of Derivative Instruments in the Consolidated Balance Sheet Derivative AssetsDerivative Liabilities Fair Values Fair Values Balance SheetLocationDecember 31, 2017 December 31, 2016 Balance SheetLocationDecember 31, 2017 December 31,2016Derivatives not designated ashedging instruments:Current: Commodity contractsFair value ofderivatives$— $—Fair value ofderivatives$72 $3,904Total derivatives notdesignated as hedginginstruments $— $— $72 $3,90485MARTIN MIDSTREAM PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Dollars in thousands, except where otherwise indicated)Effect of Derivative Instruments on the Consolidated Statement of Operations For the Twelve Months Ended December 31, 2017, 2016, and 2015 Location of Gain or (Loss) Recognized inIncome on DerivativesAmount of (Gain) or Loss Recognized in Income on Derivatives 2017 2016 2015Derivatives not designated as hedging instruments: Interest rate swaption contractsInterest expense$— $(630) $(2,495)Interest rate contractsInterest expense— (366) 206Commodity contractsCost of products sold1,304 5,129 (818)Total derivatives not designated as hedging instruments$1,304 $4,133 $(3,107)(13) Related Party TransactionsAs of December 31, 2017, Martin Resource Management owned 6,264,532 of the Partnership’s common units representing approximately 16.3% ofthe Partnership’s outstanding limited partnership units. Martin Resource Management controls the Partnership's general partner by virtue of its 51% votinginterest in Holdings, the sole member of the Partnership's general partner. The Partnership’s general partner, MMGP, owns a 2% general partner interest in thePartnership and the Partnership’s incentive distribution rights. The Partnership’s general partner’s ability, as general partner, to manage and operate thePartnership, and Martin Resource Management’s ownership as of December 31, 2017, of approximately 16.3% of the Partnership’s outstanding limitedpartnership units, effectively gives Martin Resource Management the ability to veto some of the Partnership’s actions and to control the Partnership’smanagement. 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 ResourceManagement that governs, among other things, potential competition and indemnification obligations among the parties to the agreement, related partytransactions, the provision of general administration and support services by Martin Resource Management and the Partnership’s use of certain MartinResource Management trade names and trademarks. The Omnibus Agreement was amended on November 25, 2009, to include processing crude oil intofinished products including naphthenic lubricants, distillates, asphalt and other intermediate cuts. The Omnibus Agreement was amended further on October1, 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 engagein the business of:•providing terminalling and storage services for petroleum products and by-products including the refining, blending and packaging of finishedlubricants;•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 SouthHouston, 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 beenoffered the opportunity to purchase the business for fair market value and the Partnership declines to do so with the concurrence of the ConflictsCommittee; and•any business that Martin Resource Management acquires or constructs where a portion of such business includes a restricted business and the fairmarket 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 orconstructed; provided that, following completion of the acquisition or construction, the Partnership will be provided the opportunity to purchase therestricted business. Services. Under the Omnibus Agreement, Martin Resource Management provides the Partnership with corporate staff, support services, andadministrative services necessary to operate the Partnership’s business. The Omnibus Agreement requires the Partnership to reimburse Martin ResourceManagement for all direct expenses it incurs or payments it makes on the Partnership’s behalf or in connection with the operation of the Partnership’sbusiness. There is no monetary limitation on the amount the Partnership is required to reimburse Martin Resource Management for direct expenses. Inaddition to the direct expenses, under the Omnibus Agreement, the Partnership is required to reimburse Martin Resource Management for indirect general andadministrative 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 asaccounting, treasury, clerical, engineering, legal, billing, information technology, administration of insurance, general office expenses and employee benefitplans and other general corporate overhead functions the Partnership shares with Martin Resource Management retained businesses. The provisions of theOmnibus Agreement regarding Martin Resource Management’s services will terminate if Martin Resource Management ceases to control the general partnerof the Partnership.Related Party Transactions. The Omnibus Agreement prohibits the Partnership from entering into any material agreement with Martin ResourceManagement without the prior approval of the Conflicts Committee. For purposes of the Omnibus Agreement, the term material agreements means anyagreement between the Partnership and Martin Resource87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 administrativeexpenses. 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 beamended without the approval of the Conflicts Committee if such amendment would adversely affect the unitholders. The Omnibus Agreement was firstamended on November 25, 2009, to permit the Partnership to provide refining services to Martin Resource Management. The Omnibus Agreement wasamended further on October 1, 2012, to permit the Partnership to provide certain lubricant packaging products and services to Martin ResourceManagement. Such amendments were approved by the Conflicts Committee. The Omnibus Agreement, other than the indemnification provisions and theprovisions limiting the amount for which the Partnership will reimburse Martin Resource Management for general and administrative services performed onits behalf, will terminate if the Partnership is no longer an affiliate of Martin Resource Management.Motor Carrier AgreementMotor 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 theagreement, 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 periodsunless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicableterm. 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 inaccordance with a price index. Additionally, during the term of the agreement, shipping charges are also subject to fuel surcharges determined on a weeklybasis 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 andits officers, employees, agents, representatives and subcontractors. We indemnified Martin Transport against all claims arising out of the negligence or willfulmisconduct of us and our officers, employees, agents, representatives and subcontractors. In the event a claim is the result of the joint negligence ormisconduct of Martin Transport and us, our indemnification obligations will be shared in proportion to each party’s allocable share of such joint negligenceor misconduct.Marine AgreementsMarine Transportation Agreement. The Partnership is a party to a marine transportation agreement effective January 1, 2006, as amended, underwhich the Partnership provides marine transportation services to Martin Resource Management on a spot-contract basis at applicable market rates. Effectiveeach January 1, this agreement automatically renews for consecutive one year periods unless either party terminates the agreement by giving written notice tothe other party at least 60 days prior to the expiration of the then applicable term. The fees the Partnership charges Martin Resource Management are basedon applicable market rates.Marine Fuel. The Partnership is a party to an agreement with Martin Resource Management dated November 1, 2002 under which Martin ResourceManagement 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 thisagreement, 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 AgreementsDiesel Fuel Terminal Services Agreement. Effective January 1, 2016, the Partnership entered into a second amended and restated terminallingservices agreement under which the Partnership provides terminal services to Martin Resource Management for marine fuel distribution. At such time, the pergallon throughput fee the Partnership charged under this agreement was increased when compared to the previous agreement and may be adjusted annuallybased on a price index. This agreement was further amended on January 1, 2017 and October 1, 2017 to modify its minimum throughput requirements andthroughput fees. This agreement, as amended, continues until September 30, 2018 and thereafter on a month to month basis until terminated by either partyby giving 60 days’ written notice. Miscellaneous Terminal Services Agreements. The Partnership is currently party to several terminal services agreements and from time to time thePartnership may enter into other terminal service agreements for the purpose of providing terminal services to related parties. Individually, each of theseagreements is immaterial but when considered in the aggregate they could be deemed material. These agreements are throughput based with a minimumvolume 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, asphaltand other intermediate cuts for Cross. The tolling agreement expires November 25, 2031. Under this tolling agreement, Cross agreed to process a minimumof 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 thesefees (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 specifiedannual period. In addition, on the third, sixth and ninth anniversaries of the agreement, the parties can negotiate an upward or downward adjustment in thefees 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”), alimited liability company in which Martin Resource Management has a minority equity interest, purchases and markets the sulfuric acid produced by thePartnership’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 oftermination prior to the expiration of the then existing term. Under this agreement, the Partnership sells all of its excess sulfuric acid to Saconix, who thenmarkets 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 Managementfor 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 thePartnership’s Consolidated Statements of Operations. The revenues, costs and expenses reflected in these tables are tabulations of the related partytransactions that are recorded in the corresponding caption of the Consolidated Statements of Operations and do not reflect a statement of profits and lossesfor 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 2015Terminalling and storage$82,205 $82,437 $78,233Marine transportation16,801 21,767 27,724Natural gas services122 699 878Product sales: Natural gas services1,043 8 196Sulfur services1,963 2,006 3,639Terminalling and storage572 1,020 1,836 3,578 3,034 5,671 $102,706 $107,937 $112,506The 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 $25,797Sulfur services15,564 15,339 16,579Terminalling and storage17,612 13,838 17,718 $52,122 $52,063 $60,094The impact of related party operating expenses is reflected in the Consolidated Statements of Operations as follows:Operating expenses: Marine transportation$23,815 $28,107 $32,373Natural gas services9,007 9,258 8,639Sulfur services5,821 5,995 6,928Terminalling and storage25,701 27,481 29,931 $64,344 $70,841 $77,871The 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 $29Natural gas services8,162 7,566 6,216Sulfur services2,526 2,732 2,760Terminalling and storage2,278 2,526 2,284Indirect overhead allocation, net of reimbursement16,416 13,036 13,679 $29,416 $25,890 $24,968Other Related Party TransactionsThe Partnership had a $15,000 note receivable from an affiliate of Martin Resource Management which previously bore an annual interest rate of15% 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 Partnershipnotified Martin Resource Management that it would be requesting voluntary repayment of the long-term Note Receivable plus accrued interest. Duringsecond quarter of 2017, the Note Receivable was fully repaid. The note has historically been recorded in "Note receivable - affiliates" on the Partnership'sConsolidated Balance Sheets. Interest income for the years ended December 31, 2017, 2016, and 2015 was $943, $2,256 and $2,250, respectively, and isincluded 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 InformationComponents of "Intangibles and other assets, net" at December 31, 2017 and 2016 were as follows: 2017 2016Customer contracts and relationships, net$25,252 $36,528Other intangible assets1,752 2,280Other5,797 6,066 $32,801 $44,874Other 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 atDecember 31, 2017 and 2016, respectively.Estimated amortization expense for customer contract and relationships and other intangible assets for the years subsequent to December 31, 2017are 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 2016Accrued interest$11,726 $10,629Asset retirement obligations5,429 7,953Property and other taxes payable5,638 6,443Accrued payroll3,385 1,672Other162 20 $26,340 $26,717The schedule below summarizes the changes in our asset retirement obligations: Year Ended December 31, 2017 2016 (In thousands) Beginning asset retirement obligations$16,418 $2,163Revisions to existing liabilities15,547 14,379Accretion expense404 178Liabilities settled(8,857) (302)Ending asset retirement obligations13,512 16,418Current portion of asset retirement obligations2(5,429) (7,953)Long-term portion of asset retirement obligations3$8,083 $8,4651Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, discount rates, and the estimatedremaining 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 DebtAt 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), dueMarch 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 subsidiariesand 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 netof 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, unsecured3,4372,618 372,239Total long-term debt$812,632 $808,1071 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 everythree months. Indebtedness under the credit facility bears interest at LIBOR plus an applicable margin or the base prime rate plus an applicable margin. Allamounts outstanding at December 31, 2017 and 2016 were at LIBOR plus an applicable margin. The applicable margin for revolving loans that are LIBORloans 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 applicablemargin for LIBOR borrowings at December 31, 2017 is 3.00%. The credit facility contains various covenants which limit the Partnership’s ability to makecertain 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’sRatings 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 theyears 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' CapitalAs of December 31, 2017, partners’ capital consisted of 38,444,612 common limited partner units, representing a 98% partnership interest anda 2.0% general partner interest. Martin Resource Management, through subsidiaries, owned 6,264,532 of the Partnership's common limited partnership unitsrepresenting approximately 16.3% of the Partnership's outstanding common limited partnership units. MMGP, the Partnership's general partner, ownsthe 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 toeach of the partners for purposes of maintaining their respective partner capital accounts.Issuance of Common Units92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 thepayment of underwriters' discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the2,990,000 common units, net of underwriters' discounts, commissions and offering expenses, were $51,056. Additionally, the Partnership's general partnercontributed $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 ofthe net proceeds were used to pay down outstanding amounts under the Partnership's revolving credit facility.Incentive Distribution RightsMMGP, 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 toreceive an increasing percentage of cash distributions after the minimum quarterly distribution and any cumulative arrearages on common units once certaintarget distribution levels have been achieved. The Partnership is required to distribute all of its available cash from operating surplus, as defined in thePartnership 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 cashdistributions 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 unituntil 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 CashThe Partnership distributes all of its available cash (as defined in the Partnership Agreement) within 45 days after the end of each quarter tounitholders 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 ofeach quarter less the amount of cash reserves its general partner determines in its reasonable discretion is necessary or appropriate to: (i) provide for the properconduct of the Partnership’s business; (ii) comply with applicable law, any debt instruments or other agreements; or (iii) provide funds for distributions tounitholders 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 quarterresulting from working capital borrowings made after the end of the quarter.Net Income per UnitThe Partnership follows the provisions of the FASB ASC 260-10 related to earnings per share, which addresses the application of the two-classmethod in determining income per unit for master limited partnerships having multiple classes of securities that may participate in partnership distributionsaccounted for as equity distributions. Undistributed earnings are allocated to the general partner and limited partners utilizing the contractual terms of thePartnership Agreement. Distributions to the general partner pursuant to the IDRs are limited to available cash that will be distributed as defined in thePartnership Agreement. Accordingly, the Partnership does not allocate undistributed earnings to the general partner for the IDRs because the general partner'sshare of available cash is the maximum amount that the general partner would be contractually entitled to receive if all earnings for the period weredistributed. When current period distributions are in excess of earnings, the excess distributions for the period are to be allocated to the general partner andlimited 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 inFASB 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 theif-converted method, the weighted-average number of subordinated units outstanding for the period is added to the weighted-average number of commonunits outstanding for purposes of computing basic net income per unit and the resulting amount is compared to the diluted net income per unit computedusing the two-class method. The following is a reconciliation of net income from continuing operations and net income from discontinued operationsallocated 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 2015Continuing operations: Income from continuing operations$17,135 $31,652 $37,165Less general partner’s interest in net income: Distributions payable on behalf of IDRs— 7,786 15,078Distributions payable on behalf of general partner interest1,569 2,058 2,585General partner interest in undistributed loss(1,226) (1,425) (1,842)Less income allocable to unvested restricted units42 90 136Limited partners’ interest in net income$16,750 $23,143 $21,208 Years Ended December 31, 2017 2016 2015Discontinued operations: Income from discontinued operations$— $— $1,215Less general partner’s interest in net income: Distributions payable on behalf of IDRs— — 493Distributions payable on behalf of general partner interest— — 84General partner interest in undistributed loss— — (60)Less income allocable to unvested restricted units— — 4Limited partners’ interest in net income$— $— $694The Partnership allocates the general partner's share of earnings between continuing and discontinued operations as a proportion of net income fromcontinuing 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 2015Basic weighted average limited partner units outstanding 38,101,583 35,347,032 35,308,649Dilutive effect of restricted units issued 63,318 28,231 62,880Total weighted average limited partner diluted units outstanding 38,164,901 35,375,263 35,371,529All outstanding units were included in the computation of diluted earnings per unit and weighted based on the number of days such units wereoutstanding during the period presented.94(17) Unit Based Awards The Partnership recognizes compensation cost related to stock-based awards to employees in its consolidated financial statements in accordancewith certain provisions of ASC 718. The Partnership recognizes compensation costs related to stock-based awards to directors under certain provisions ofASC 505-50-55 related to equity-based payments to non-employees. Amounts recognized in selling, general, and administrative expense in theconsolidated financial statements with respect to these plans are as follows: For the Year Ended December 31, 2017 2016 2015Employees$534 $783 $1,338Non-employee directors116 121 91 Total unit-based compensation expense$650 $904 $1,429Long-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 performservices 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 currentlypermits 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 isadministered 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 fullownership of the unit without restrictions. In addition, the restricted units will vest upon a change of control of the Partnership, the general partner or MartinResource Management or if the general partner ceases to be an affiliate of Martin Resource Management. The Partnership intends the issuance of the commonunits 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 toparticipate 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 ofthe restricted unit activity for the year ended December 31, 2017 is provided below: Number of Units WeightedAverage Grant-Date Fair ValuePer UnitNon-vested, beginning of year103,800 $26.54 Granted12,000 $19.00 Vested(7,800) $19.18 Forfeited(9,250) $28.50Non-Vested, end of year98,750 $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 ofgrant) during the years ended December 31, 2017, 2016 and 2015 is provided below:95 For the Year EndedDecember 31, 2017 2016 2015Aggregate intrinsic value of units vested$143 $1,233 $110Fair value of units vested$208 $1,773 $128As of December 31, 2017, there was $269 of unrecognized compensation cost related to non-vested restricted units. That cost is expected to berecognized over a weighted-average period of 0.8 years.(18) Income TaxesThe 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 theConsolidated Statements of Operations. Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed asan 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 isimmaterial. State income taxes attributable to the Texas margin tax of $352, $726 and $1,048 were recorded in income tax expense for the years endedDecember 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 anyresulting tax, interest and penalties collected, at the partnership level for tax years beginning after December 31, 2017. The Bipartisan Budget Act of 2015allows a partnership to elect to apply these provisions to any return of the partnership filed for partnership taxable years beginning after the date of theenactment, November 2, 2015. The Partnership does not intend to elect to apply these provisions for any tax return filed for partnership taxable yearsbeginning 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 Cutsand 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 deductionon certain pass-through income, a repeal of the partnership technical termination rule, and new limitations on certain deductions and credits, includinginterest expense deductions. Since the operations of a partnership are not subject to federal income tax, and most provisions of the Tax Act are effective fortax 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 TaxAct 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 SegmentsThe Partnership has four reportable segments: terminalling and storage, natural gas services, marine transportation, and sulfur services. ThePartnership’s reportable segments are strategic business units that offer different products and services. The operating income of these segments is reviewedby 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 itsreportable segments based on operating income. There is no allocation of administrative expenses or interest expense.96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. OperatingRevenues IntersegmentEliminations OperatingRevenues AfterEliminations Depreciation andAmortization Operating Income(Loss) afterEliminations CapitalExpenditures andPlant TurnaroundCosts Year Ended December 31, 2017: Terminalling and storage$236,169 $(5,998) $230,171 $45,160 $629 $29,644Natural gas services532,908 (226) 532,682 24,916 51,663 7,430Sulfur services134,684 — 134,684 8,117 23,205 2,611Marine transportation51,915 (3,336) 48,579 7,002 1,650 3,929Indirect selling, general, andadministrative— — — — (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 $26,097Natural gas services391,333 — 391,333 28,081 41,438 4,807Sulfur services141,058 — 141,058 7,995 23,393 5,093Marine transportation61,233 (2,943) 58,290 10,572 (16,039) 2,334Indirect selling, general, andadministrative— — — — (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 $40,421Natural gas services523,160 — 523,160 34,072 41,220 24,330Sulfur services170,161 — 170,161 8,455 23,604 1,201Marine transportation81,784 (3,031) 78,753 10,992 8,576 2,775Indirect selling, general, andadministrative— — — — (18,951) —Total$1,045,545 $(8,701) $1,036,844 $92,250 $70,153 $68,727Revenues 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 2016Total assets: Terminalling and storage$326,920 $328,098Natural gas services704,524 684,722Sulfur services120,790 125,356Marine transportation101,264 108,187Total assets$1,253,498 $1,246,36397MARTIN MIDSTREAM PARTNERS L.P.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Dollars in thousands, except where otherwise indicated)(20) Quarterly Financial InformationConsolidated Quarterly Income Statement Information (Unaudited) First Quarter Second Quarter Third Quarter FourthQuarter (Dollar in thousands, except per unit amounts)2017 Revenues$253,325 $193,922 $193,128 $305,741Operating income (loss)23,748 10,848 (4,484) 29,703Equity in earnings of unconsolidated entities905 853 789 1,767Net income (loss)13,583 989 (16,286) 18,849Limited partners' interest in net income (loss) per limited partner unit0.36 0.03 (0.42) 0.47 First Quarter Second Quarter Third Quarter FourthQuarter (Dollar in thousands, except per unit amounts)2016 Revenues$225,605 $190,348 $174,537 $236,901Operating income24,338 10,256 9,176 28,888Equity in earnings of unconsolidated entities1,677 805 1,120 1,112Net income (loss)15,914 (1,211) (933) 17,882Limited partners' interest in net income (loss) per limited partner unit0.33 (0.14) (0.03) 0.49(21) Commitments and ContingenciesContingenciesFrom time to time, the Partnership is subject to various claims and legal actions arising in the ordinary course of business. In the opinion ofmanagement, 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’sacquisition of the Redbird Gas Storage LLC ("Redbird") Class A interests on October 2, 2012, beginning in the second quarter of 2015, Martin ResourceManagement will reimburse the Partnership $750 each quarter for four consecutive quarters as a reduction in the purchase price of the Redbird Class Ainterests. These payments are a result of Cardinal Gas Storage Partners LLC ("Cardinal") not achieving certain financial targets set forth in the Purchase PriceReimbursement Agreement. These payments are considered a reduction of the excess of the purchase price over the carrying value of the assets transferred tothe Partnership from Martin Resource Management and will be recorded as an adjustment to "Partners' capital" in each quarter the payments are made. Theagreement further provided for purchase price reimbursements of up to $4,500 in 2016 in the event certain financial conditions were not met. For the yearended December 31, 2017 and 2016, the Partnership received $1,125 and $4,125, respectively, related to the Purchase Price Reimbursement Agreement. Theamount 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 effectiveJuly 1, 2015. The complainants requested that the rate increase be suspended until the RRC has determined appropriate new rates. On March 8, 2016, theRRC 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 byCommission 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 aProposal for Decision on September 29, 2017. On December 5, 2017, this matter was brought before the RRC. After brief discussion, the RRC determined thatmore 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, theRRC voted to remand the case to the hearings examiner for the limited purpose of admitting and considering additional relevant evidence on competition.98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 JudicialDistrict Court, Cameron Parish, Louisiana. The plaintiff alleged that the Partnership breached a lease agreement by failing to perform work to the plaintiff'sproperty 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 thesettlement 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 inconnection with lawsuits filed against it in various United States District Courts, which generally allege that the customer engaged in unlawful and deceptivebusiness practices in connection with its marketing and advertising of its private label motor oil. The Partnership disputes that it has any obligation todefend or indemnify the customer for its conduct. Accordingly, on January 7, 2016, the Partnership filed a Complaint for Declaratory Judgment in theChancery Court of Davidson County, Tennessee requesting a judicial determination that the Partnership does not owe the customer the demanded defenseand indemnity obligations. The lawsuits against the customer have been transferred to the United States District Court for the Western District of Missouri forconsolidated pretrial proceedings. On March 1, 2017, at the request of the parties, the Chancery Court of Davidson County, Tennessee administrativelyclosed the Partnership's lawsuit pending rulings in the United States District Court for the Western District of Missouri. In the event that either party movesthe 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 isreopened, we are currently unable to determine the exposure we may have in this matter, if any.CommitmentsThe Partnership has non-cancelable revenue arrangements whereby we have committed certain terminalling and storage assets in exchange for aminimum 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 InformationThe Partnership's operations are conducted by its operating subsidiaries as it has no independent assets or operations. Martin Operating PartnershipL.P. (the "Operating Partnership"), the Partnership’s wholly-owned subsidiary, and the Partnership's other operating subsidiaries have issued in the past, andmay 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, ifissued, will be fully, irrevocably and unconditionally guaranteed by the Partnership. Substantially all of the Partnership's operating subsidiaries aresubsidiary 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 quarterof 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. 99Item 9.Changes in and Disagreements with Accountants on Accounting and Financial DisclosureNone. 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, asamended (the "Exchange Act"), we, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of our generalpartner, 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 theExchange Act) as of December 31, 2017. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of our general partner concludedthat our disclosure controls and procedures were effective as of December 31, 2017 to provide reasonable assurance that information required to be disclosedby the Company in reports that it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported within the time periodsspecified in the SEC rules and forms and (ii) accumulated and communicated to the Company’s management, including its principal executive officer andprincipal 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 maintainingadequate internal control over financial reporting. A company’s internal control over financial reporting is a process designed to provide reasonableassurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generallyaccepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to themaintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) providereasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally acceptedaccounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management anddirectors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition ofthe 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 anyevaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degreeof 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 theeffectiveness of our internal control over financial reporting based on criteria established in the Internal Control — Integrated Framework (2013) issued bythe Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in Internal Control — IntegratedFramework (2013), our management concluded that our internal control over financial reporting was effective as of December 31, 2017. The effectiveness ofour internal control over financial reporting as of December 31, 2017 has been audited by KPMG LLP, our independent registered public accounting firm, asstated 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 definedin 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 reasonablylikely to materially affect, our internal controls over financial reporting. 100Item 9B.Other InformationNone.101PART IIIItem 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 ourunitholders and will not be subject to re-election in the future. Unitholders do not directly or indirectly participate in our management or operation. Ourgeneral 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 ourassets), except for indebtedness or other obligations that are made specifically non-recourse to it. However, whenever possible, our general partner seeks toprovide 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 specificmatters that the directors believe may involve conflicts of interest. The Conflicts Committee determines if the resolution of the conflict of interest is fair andreasonable to us. The members of the Conflicts Committee may not be officers or employees of our general partner or directors, officers, or employees of itsaffiliates and must meet the independence standards established by NASDAQ to serve on an audit committee of a board of directors. Any matters approvedby 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 generalpartner 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 forinternal 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 describedbelow. 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 ResourceManagement. All of the officers of our general partner will spend a substantial amount of time managing the business and affairs of Martin ResourceManagement and its other affiliates. These officers may face a conflict regarding the allocation of their time between our business and the other businessinterests of Martin Resource Management. Our general partner intends to cause its officers to devote as much time to the management of our business andaffairs as is necessary for the proper conduct of our business and affairs.102Directors and Executive Officers of Martin Midstream GP LLCThe following table shows information for the directors and executive officers of our general partner. Directors and executive officers are elected forone-year terms.Name Age Position with the General PartnerRuben S. Martin 66 President, Chief Executive Officer and DirectorRobert D. Bondurant 59 Executive Vice President and Chief Financial Officer and DirectorRandall L. Tauscher 52 Executive Vice President and Chief Operating OfficerChris H. Booth 48 Executive Vice President, Chief Legal Officer, General Counsel and SecretaryScot A. Shoup 57 Senior Vice President of OperationsC. Scott Massey 65 DirectorJames M. Collingsworth 63 DirectorByron R. Kelley 70 DirectorSean P. Dolan 44 DirectorZachary S. Stanton 42 DirectorRuben S. Martin serves as President, Chief Executive Officer and a member of the board of directors of our general partner. Mr. Martin has served insuch capacities since June 2002. Mr. Martin has served as President of Martin Resource Management since 1981 and has served in various capacities withinthe company since 1974. Mr. Martin holds a Bachelor of Science degree in industrial management from the University of Arkansas. Mr. Martin was selectedto 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, hisbusiness 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 subsequentlywas 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 aCertified 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 capacitysince May 2011. From September 2007 through May 2011, Mr. Tauscher served as Executive Vice President. Prior to joining Martin, Mr. Tauscher wasemployed by Koch Industries for over 18 years, most recently as Senior Vice President of the Koch Carbon Division. Mr. Tauscher earned a Bachelor ofBusiness 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 servedas an officer of our general partner since February 2006. Mr. Booth joined Martin Resource Management in October 2005. Prior to joining Martin ResourceManagement, Mr. Booth was an attorney with the law firm of Mehaffy Weber located in Beaumont, Texas. Mr. Booth holds a Doctor of Jurisprudence degreeand a Masters of Business Administration degree with a concentration in finance from the University of Houston. Additionally, Mr. Booth holds a Bachelorof 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 18years. 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. Masseyhas been self employed as a Certified Public Accountant since 1998. From 1977 to 1998, Mr. Massey worked for KPMG Peat Marwick, LLP in variouspositions, 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 ofBusiness Administration degree from the University of Texas at Austin and a Doctor of Jurisprudence degree from the University of Houston. Mr. Massey is aCertified Public Accountant, licensed in the States of Louisiana and Texas. Mr. Massey was selected103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 asan "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 themidstream and petrochemical industry. In 2013, Mr. Collingsworth retired from Enterprise Products Company as a Sr. Vice President of Regulated NGLPipelines & Natural Gas Storage. Mr. Collingsworth currently serves on the board of directors of NGL Energy Partners LP, and has served on the board ofdirectors 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 StateUniversity. Mr. Collingsworth was selected to serve as a director on our general partner's board of directors due to his extensive corporate businessexperience. 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 toAugust 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 companyengaged in the production of nitrogen based fertilizers and served in this position from June 2011 through December 2013. Prior to joining CVR Partners inJune 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 PasoEnergy International. Mr. Kelley is a past member and Chairman of the board of directors of the Interstate National Gas Association and previously served asone of the association's representatives on the United States Natural Gas Council of America. Mr. Kelley received a Bachelor of Science degree in civilengineering from Auburn University. Mr. Kelley was selected to serve as a director on our general partner's board of directors due to his extensive corporatebusiness 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 aManaging Director of Alinda Capital Partners, which he joined in 2009. Prior to joining Alinda, Mr. Dolan spent over 12 years with Citigroup GlobalMarkets in investment banking primarily focused in the energy sector. Mr. Dolan received a bachelor's degree from Georgetown University. Mr. Dolan wasselected 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 hisfinancial 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 onFebruary 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 andtransportation 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 DirectorsMessrs. Massey, Collingsworth, and Kelley qualify as "independent" in accordance with the published listing requirements of NASDAQ andapplicable securities laws. The NASDAQ independence definition includes a series of objective tests, such as that the director is not an employee of us andhas 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 asubjective determination as to each independent director that no relationships exist which, in the opinion of the board, would interfere with the exercise ofindependent judgment in carrying out the responsibilities of a director. In making these determinations, the directors reviewed and discussed informationprovided 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 attendedeach of these meetings, either in person, by teleconference or by videoconference with the exception of: James M. Collingsworth, who was not in attendanceat the meeting of the board of directors on the date of September 3, 2017. Additionally, the board of directors undertook action three times during 2017without a meeting by acting through written unanimous consent. We have standing conflicts, audit, compensation and nominating committees of the boardof directors of our general partner. The board of directors of our general partner appoints the members of the Audit,104Compensation, Nominating and Conflicts Committees. Each member of the Audit Committee is an independent director in accordance with NASDAQ andapplicable securities laws. Each of the board committees has a written charter approved by the board. Copies of each charter are posted on our website atww.martinmidstream.com under the "Corporate Governance" section. The current members of the committees, the number of meetings held by eachcommittee 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 themembers of the Conflicts Committee attended all meetings of the committee for the period noted above. The primary responsibility of the ConflictsCommittee is to review matters that the directors believe may involve conflicts of interest. The Conflicts Committee determines if the resolution of theconflict 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 byNASDAQ. 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 membersattended all meetings of the Audit Committee for the period noted. The primary responsibilities of the Audit Committee are to assist the board of directors inits 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 partnereach qualify as "independent" under standards established by the SEC for members of audit committees, and the Audit Committee includes at least onemember 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 tobe an audit committee financial expert. Unitholders should understand that this designation is a disclosure requirement of the SEC related to Mr. Massey'sexperience 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 asan audit committee financial expert pursuant to this SEC requirement does not affect the duties, obligations or liability of any other member of the AuditCommittee 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 Committeeis 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 bepaid 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 ofthe members attended the meeting of the Nominating Committee for the period noted above. The primary responsibility of the nominating committee is toselect 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 anyemployees of Martin Resource Management who undertake actions with respect to us or on our behalf), including all officers, and including our generalpartner's independent directors, who are not employees of our general partner, with regard to their activities relating to us. The Code of Ethics and BusinessConduct incorporate guidelines designed to deter wrongdoing and to promote honest and ethical conduct and compliance with applicable laws andregulations. They also incorporate our expectations of our general partner's employees (including any employees of Martin Resource Management whoundertake 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 ExchangeCommission and other public communications. The Code of Ethics and Business Conduct is publicly available on our website under the "CorporateGovernance" section (at www.martinmidstream.com). This website address is intended to be an inactive, textual reference only, and none of the material onthis 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 grantany 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 thenature of such amendment or waiver on that website or in a report on Form 8-K.105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 filereports of ownership and reports of changes in ownership with the SEC and NASDAQ. Directors, officers and beneficial owners of more than 10% of ourequity 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 andamendments previously provided to us, we believe directors, officers and greater than 10% beneficial owners complied with all filing requirements during theyear ended December 31, 2017. 106Item 11.Executive Compensation Compensation Discussion and AnalysisBackgroundWe are required to provide information regarding the compensation program in place as of December 31, 2017, for the CEO, CFO and the three othermost highly-compensated executive officers of our general partner as reflected in the summary compensation table set forth below (the "Named ExecutiveOfficers"). 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 executiveofficers are employed by Martin Resource Management, a private corporation that has significant operations that are separate from ours. The executiveofficers of our general partner are also the executive officers of Martin Resource Management and devote significant time to the management of MartinResource Management’s operations. We reimburse Martin Resource Management for a portion of the indirect general and administrative expenses, includingcompensation expense relating to the service of these individuals that are allocated to us pursuant to the omnibus agreement between us and our generalpartner, as amended on October 1, 2012 ("Omnibus Agreement"). Under the Omnibus Agreement, we are required to reimburse Martin Resource Managementfor indirect general and administrative and corporate overhead expenses. For the years ended December 31, 2017, 2016 and 2015 the conflicts committee ofour general partner ("Conflicts Committee") approved reimbursement amounts of $16.4 million, $13.0 million and $13.7 million, respectively, reflecting ourallocable 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 ObjectivesAs we do not directly compensate the executive officers of our general partner, we do not have any set compensation programs. The elements ofMartin Resource Management’s compensation program discussed below, along with Martin Resource Management’s other rewards, are intended to provide atotal rewards package designed to yield competitive total cash compensation, drive performance and reward contributions in support of the businesses ofMartin 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, wedo 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-basedcriteria and did not have any other specific performance-based objectives.Elements of CompensationMartin Resource Management’s executive officer compensation package includes a combination of annual cash, long-term incentive compensationand other compensation. Elements of compensation which the Named Executive Officers may be eligible to receive from Martin Resource Managementconsist of the following: (1) annual base salary; (2) discretionary annual cash awards; (3) awards pursuant to the Martin Midstream Partners L.P. 2017Restricted 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 dutieswith respect to Martin Resource Management and its affiliates, including us, and to compensate for experience levels, scope of responsibility and futurepotential. Base salaries are not intended to compensate individuals for extraordinary performance or for above average company performance. The basesalaries 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 marketconditions.Discretionary Annual Cash Awards. In addition to the annual base salary, the Named Executive Officers may be eligible to receive discretionaryannual 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 theNamed Executive Officers with competitive incentives to help drive performance and promote achievement of Martin Resource Management’s businessobjectives. 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 NamedExecutive Officer has devoted a significant amount of their time to working for us. Any such award is determined in107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 theperformance of the Named Executive Officers by providing annual incentive opportunities tied to the annual performance of Martin ResourceManagement. In particular, these awards are provided to the Named Executive Officers in order to provide competitive incentives to these executives whocan 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 thangeneral recreational activities at certain Martin Resource Management’s properties located in Texas, including aircraft. No perquisites are paid for servicesrendered to us. Martin Resource Management provides an executive life insurance policy and long term disability policy for the Named Executive Officerswith the annual premiums being paid by Martin Resource Management. Martin Resource Management does not provide any greater allocation towardemployee health insurance premiums than is provided for all other employees covered on the health benefits plan.Compensation MethodologyThe compensation policies and philosophy of Martin Resource Management govern the types and amount of compensation granted to each of theNamed Executive Officers. The board of directors and Conflicts Committee have responsibility for evaluating and determining the reasonableness of the totalamount we are charged under the Omnibus Agreement for managerial, administrative and operational support, including compensation of the NamedExecutive 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 theNamed Executive Officers is governed by the Omnibus Agreement. In general, this allocation is based upon estimates of the relative amounts of time thatthese employees devote to the business and affairs of our general partner and to the business and affairs of Martin Resource Management. We bearsubstantially 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 anappropriate combination of compensation. Annual base salaries for the Named Executive Officers are determined by Mr. Ruben Martin, Chief ExecutiveOfficer, Mr. Robert Bondurant, Chief Financial Officer, Mr. Randall Tauscher, Chief Operating Officer, and Mrs. Melanie Mathews, Vice President-HumanResources (collectively, the "Management Compensation Committee of Martin Resource Management") based on a periodic performance review of eachNamed Executive Officer. Except in the case of an exceptional amount of time devoted to us, discretionary annual cash awards are based on the performanceof Martin Resource Management. Annual discretionary cash awards, if any, are calculated first by allocating a portion of Martin Resource Management’searnings as determined by the Management Compensation Committee of Martin Resource Management for distribution to key employees of MartinResource Management. Upon such allocation, the Management Compensation Committee of Martin Resource Management, with input from appropriatebusiness leaders determines the allocation and distribution of the bonus pool among such employees, including the Named Executive Officers. All decisionsof the Management Compensation Committee of Martin Resource Management concerning the compensation of the Named Executive Officers are reviewedand approved by the Compensation Committee of the Board of Directors of Martin Resource Management, which is made up of Mr. Cullen M. Godfrey, anindependent director of Martin Resource Management and Mr. Ruben Martin. With respect to employee benefit plan awards pursuant to plans maintained bythe Partnership, the Management Compensation Committee of Martin Resource Management makes a recommendation as to whether such awards should beawarded to any employees. Any such employee plan awards are then considered and must be approved by the Compensation Committee and then aredistributed to the employees, including Named Executive Officers, accordingly. Further, Martin Resource Management, with the approval of theCompensation Committee of the Board of Directors of Martin Resource Management or the Compensation Committee regularly reviews market data andrelevant compensation surveys when setting base compensation and, when appropriate, engages compensation consultants. Because he serves on both theManagement Compensation Committee of Martin Resource Management and on the Compensation Committee of the Board of Directors of Martin ResourceManagement, Mr. Martin, as Chief Executive Officer, has significant authority in setting base salaries, discretionary annual cash award allocations andamounts and employee benefit award distributions.108Any awards granted under our long-term incentive plan, which to date have consisted of the grant of restricted common units to the independentdirectors 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 MartinResource 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 areallocable to us under our Omnibus Agreement with Martin Resource Management, are reflected in the summary compensation table below. Based upon theagreement of our general partner with Martin Resource Management, we have reimbursed Martin Resource Management for approximately 55.5% of theaggregate annual base salaries paid to the Named Executive Officers by Martin Resource Management during 2017. The foregoing agreement has beendeveloped based on an assessment of the estimated percentage of the time spent by the Named Executive Officers managing our affairs, relative to the affairsof Martin Resource Management ranging from approximately 50% to 75%. Our Named Executive Officers are Mr. Ruben Martin, the President and ChiefExecutive Officer of our general partner, Mr. Robert Bondurant, an Executive Vice President and Chief Financial Officer of our general partner, Mr. RandallTauscher, an Executive Vice President and Chief Operating Officer of our general partner, Mr. Chris Booth, the Executive Vice President, General Counseland Secretary of our general partner, and Mr. Scot A. Shoup, Senior Vice President of Operations. Aggregate annual base salaries of the Named ExecutiveOfficers 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 reflectedin the summary compensation table below.Martin Midstream Partners L.P. Long-Term Incentive PlanOn May 26, 2017, the unitholders of the Partnership approved the Martin Midstream Partners L.P. 2017 Restricted Unit Plan (the "2017 LTIP"). Theplan 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. Theplan is administered by the Compensation Committee of our general partner’s board of directors. The purpose of the 2017 LTIP is designed to enhance ourability to attract, retain, reward and motivate the services of certain key employees, officers, and directors of the General Partner and Martin ResourceManagement.Our general partner’s board of directors or the Compensation Committee, in their discretion, may terminate or amend the 2017 LTIP at any time withrespect 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 toalter 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 theplan subject to any applicable unitholder approval. However, no change in any outstanding grant may be made that would materially impair the rights of theparticipant without the consent of the participant. In addition, the restricted units will vest upon a change of control of us, our general partner or MartinResource 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 tomake 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 CompensationCommittee may also award a percentage of restricted units with vesting requirements based upon the achievement of specified pre-established performancetargets ("Performance Based Restricted Units" or "PBRU's"). The performance targets may include, but are not limited to, the following: revenue and incomemeasures, cash flow measures, EBIT, EBITDA, distribution coverage metrics, expense measures, liquidity measures, market measures, corporate sustainabilitymetrics, and other measures related to acquisitions, dispositions, operational objectives and succession planning objectives. PBRU's are earned only upon ourachievement of an objective performance measure for the performance period. PBRU's which vest are payable in common units. The CompensationCommittee believes this type of incentive award strengthens the tie between each grantee's pay and our financial performance. We intend the issuance of thecommon units109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 toparticipate 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 amaximum amount of 241,667 restricted units that could be issued under the plan. Awards issued under the new plan will be materially larger than awardshistorically issued under the preceding plan. Unvested units granted under the 2017 LTIP may or may not participate in cash distributions depending on theterms 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 theextent, the Compensation Committee provides otherwise. Common units to be delivered upon the vesting of restricted units may be common units acquiredby our general partner in the open market, common units already owned by our general partner, common units acquired by our general partner directly fromus 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 entitledto 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 numberof 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 planpreceding 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 PlansMartin Resource Management has employee benefit plans for its employees who perform services for us. The following summary of these plans isnot 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 planfor our units to provide employees of Martin Resource Management and its affiliates who perform services for us the opportunity to acquire an equity interestin us through the purchase of our common units. Each individual employed by Martin Resource Management or an affiliate of Martin Resource Managementthat 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 byMartin Resource Management to the employee of the right to purchase common units under the purchase plan. The right to purchase common units grantedby 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 anamount not less than one percent of his compensation and not more than fifteen percent of his compensation. The rate of contribution shall be designated bythe employee at the time of enrollment. On each purchase date (the last day of such purchase period), units will be purchased for each participating employeeat 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 aunit 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 whosatisfy certain minimum age and service requirements ("ESOP"). Under the terms of the ESOP, Martin Resource Management has the discretion to makecontributions in an amount determined by its board of directors. Those contributions are allocated under the terms of the ESOP and invested primarily in thecommon stock of Martin Resource Management. Participants in the ESOP become 100% vested upon completing six years of vesting service or upon theirattainment of Normal Retirement Age (as defined in the plan document), permanent disability or death during employment. Any forfeitures of non-vestedaccounts 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 includingrollover contributions to the ESOP.Martin Employee Stock Ownership Plan. Martin Resource Management maintains an employee stock ownership plan that covers employees whosatisfied certain minimum age and service requirements but no Employee shall become eligible to participate in the Plan on or after January 1, 2013. Thisplan is referred to as the "Martin Employee Stock Ownership Plan". Under the terms of the plan, Martin Resource Management has the discretion to makecontributions in an amount determined by its board of directors. Those contributions are allocated under the terms of the Martin Employee Stock OwnershipPlan and invested primarily in the common stock of Martin Resource Management. No contributions will be made to the Plan for any110Plan Year commencing on or after January 1, 2013. The account balances of any participant who was employed by Martin Resource Management onDecember 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 employeeswho satisfy certain minimum age and service requirements. This profit sharing plan is referred to as the "401(k) Plan." Eligible employees may elect toparticipate 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 annualdiscretionary 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 forthem 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 plandesigned to retain and attract qualified management personnel, directors and consultants. Under the plan, Martin Resource Management is authorized toissue 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 ofgrant and at exercise prices generally not less than fair market value on the date of grant. In November 2007, Martin Resource Management adopted anadditional stock option plan designed to retain and attract qualified management personnel, directors and consultants. In December 2013, all outstandingoptions were exercised or redeemed in lieu of redemption. There are no outstanding options under this plan as of December 31, 2017.Other CompensationMartin Resource Management generally does not pay for perquisites for any of our named executive officers other than general recreationalactivities at certain Martin Resource Management’s properties located in Texas and use of Martin Resource Management vehicles, including aircraft. SUMMARY COMPENSATION TABLEThe following table sets forth the compensation expense that was allocated to us for the services of the named executive officers for the years endedDecember 31, 2017, 2016 and 2015.Name and Principal Position Year Salary Bonus Stock Awards(1) Total CompensationRuben S. Martin, President and Chief Executive Officer 2017 $412,500 $— $— $412,500 2016 $412,500 $— $— $412,500 2015 $412,500 $— $356,250 $768,750Robert D. Bondurant, Executive Vice President and ChiefFinancial Officer 2017 $230,000 $— $— $230,000 2016 $230,000 $— $— $230,000 2015 $230,000 $— $85,500 $315,500Randall L. Tauscher, Executive Vice President and ChiefOperating Officer 2017 $276,000 $— $— $276,000 2016 $308,200 $— $— $308,200 2015 $230,000 $— $85,500 $315,500Chris H. Booth, Executive Vice President, General Counseland Secretary 2017 $183,600 $— $— $183,600 2016 $165,240 $— $— $165,240 2015 $146,880 $— $71,250 $218,130Scot 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 requirementswhich 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.111Director CompensationAs 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 ofdirectors 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 thegeneral partner. Martin Resource Management employees who are a member of the board of directors of our general partner do not receive any additionalcompensation for serving in such capacity. Officers of our general partner who also serve as directors will not receive additional compensation. All directorsof 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 theextent 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 EarnedPaid inCash StockAwards TotalRuben S. Martin $— $— $—Robert D. Bondurant $— $— $—C. Scott Massey (1) $65,000 $75,800 $140,800Byron R. Kelley (1) $65,000 $75,800 $140,800James M. Collingsworth (1) $65,000 $75,800 $140,800Sean 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 and2021, 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 bythe 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 Discussionand Analysis section of this report with management of the general partner of Martin Midstream Partners L.P. and, based on that review and discussions, hasrecommended that the Compensation Discussion and Analysis be included in this report. Members of the Compensation Committee:/s/ James M. CollingsworthJames M. Collingsworth, Committee Chair /s/ Byron R. KelleyByron R. Kelley /s/ C. Scott MasseyC. Scott Massey Compensation Committee Interlocks and Insider ParticipationOther than these independent directors, no other officer or employee of our general partner or its subsidiaries is a member of the CompensationCommittee. Employees of Martin Resource Management, through our general partner, are the individuals who work on our matters. 112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 unitsoutstanding, 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 UnitsBeneficially Owned Percentage of Common Units BeneficiallyOwned (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 MartinMidstream 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 ResourceManagement"), the MRMC ESOP Trust (the "MRMC ESOP") is the controlling shareholder of Martin Resource Management, and may be deemedto beneficially own the 6,264,532 MMLP Common Units held by Martin Resource LLC, Cross Oil Refining & Marketing Inc., and Martin ProductSales LLC. Wilmington Trust Retirement and Institutional Services Company serves as trustee of the MRMC ESOP but all of its voting andinvestment decisions are directed by the board of directors of Martin Resource Management. The MRMC ESOP expressly disclaims beneficialownership of the MMLP Common Units as voting and investment decisions are directed by the board of directors of Martin ResourceManagement.(5)Martin Resource Management is the owner of Martin Resource, LLC, Martin Product Sales LLC, and Cross Oil Refining & Marketing Inc., and assuch may be deemed to beneficially own the common units held by Martin Resource LLC, Cross Oil Refining & Marketing Inc, and MartinProduct Sales LLC. The 4,203,823 common units beneficially owned by Martin Resource Management through its ownership of MartinResource, 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 commonunits beneficially owned by Martin Resource Management through its ownership of Martin Product Sales LLC have been pledged as security to athird party to secure payment for a loan made by such third party. The 889,444 common units beneficially owned by Martin ResourceManagement through its ownership of Cross Oil Refining & Marketing Inc. have been pledged as security to a third party to secure payment for aloan 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. Byvirtue of serving as the Chairman of the Board and President of Martin Resource113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 6,264,532common units beneficially owned through its ownership of Martin Resource LLC, Cross Oil Refining & Marketing Inc. and Martin Product SalesLLC.(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 aswell as the common units beneficially owned by Martin Resource Management as Ruben S. Martin may be deemed to be the beneficial ownerthereof.Martin Resource Management owns a 51% voting interest in the holding company that is the sole member of our general partner and, together withour general partner, owns approximately 16.3% of our outstanding common limited partner units as of December 31, 2017. The table below sets forthinformation as of December 31, 2017 concerning (i) each person owning beneficially in excess of 5% of the voting common stock of Martin ResourceManagement, and (ii) the beneficial common stock ownership of (a) each director of Martin Resource Management, (b) each executive officer of MartinResource Management, and (c) all such executive officers and directors of Martin Resource Management as a group. Except as indicated, each individual hassole voting and investment power over all shares listed opposite his or her name. Beneficial Ownership ofVoting Common StockName of Beneficial Owner(1) Number ofShares Percent ofOutstanding VotingStockMRMC 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 ResourceManagement 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 InstitutionalServices Company serves as trustee of the MRMC ESOP but all of its voting and investment decisions related to the unallocated shares ofcommon stock are directed by the board of directors of Martin Resource Management. Of the common stock held by the MRMC ESOP, 99,407.50shares 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 convertedfrom a profit sharing plan known as the Martin Employees' Stock Profit Sharing Plan on January 1, 2014. The Co-Trustees exercise shared controlover 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 thesecurities held by such trust; thus, the number of shares of common stock reported herein as beneficially owned by the Co-Trustees includes the27,325 shares owned by such trust. The Co-Trustees disclaim beneficial ownership of these 27,325 shares.114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 exerciseof outstanding options, Warrantsand rights Weighted-average exercise price of outstanding options,warrants and rights Number of securities remaining availablefor future issuance underequity compensationplans (excluding securities reflected in column (a))Plan Category(a) (b) (c)Equity compensation plans approved by security holdersN/A N/A 3,000,000Total— $— 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 materialfeatures 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 commonunits vest in equal installments of 1,000 units on January 24, 2018, 2019, 2020 and 2021.115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 outstandingcommon limited partnership units as of February 16, 2018. Martin Resource Management controls Martin Midstream GP LLC, our general partner, by virtueof 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 usand all of our incentive distribution rights. Our general partner’s ability to manage and operate us and Martin Resource Management’s ownership ofapproximately 16.3% of our outstanding common limited partnership units effectively gives Martin Resource Management the ability to veto some of ouractions 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 ourformation, ongoing operation and liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, are notthe result of arm’s-length negotiations. Formation Stage The consideration received by our generalpartner and Martin Resource Managementfor the transfer of assets to usŸ 4,253,362 subordinated units (All of the original 4,253,362 subordinated units issued to Martin ResourceManagement have been converted into common units on a one-for-one basis since the formation of thePartnership. 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; andŸ the incentive distribution rights.Operational Stage Distributions of available cash to our generalpartnerWe will generally make cash distributions 98% to our unitholders, including Martin Resource Management asholder of all of the subordinated units, and 2% to our general partner. In addition, if distributions exceed theminimum quarterly distribution and other higher target levels, our general partner will be entitled to increasingpercentages of the distributions, up to 50% of the distributions above the highest target level as a result of itsincentive distribution rights. Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of ouroutstanding units for four quarters, our general partner would receive an annual aggregate distribution ofapproximately $1.6 million on its 2.0% general partner interest.Payments to our general partner and itsaffiliatesMartin Resource Management is entitled to reimbursement for all direct expenses it or our general partnerincurs on our behalf. The direct expenses include the salaries and benefit costs employees of Martin ResourceManagement who provide services to us. Our general partner has sole discretion in determining the amount ofthese expenses. In addition to the direct expenses, Martin Resource Management is entitled to reimbursementfor a portion of indirect general and administrative and corporate overhead expenses. Under the omnibusagreement, we are required to reimburse Martin Resource Management for indirect general and administrativeand corporate overhead expenses. The conflicts committee of our general partner ("Conflicts Committee") willreview 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 rightswill either be sold to the new general partner for cash or converted into common units, in each case for anamount 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 liquidatingdistributions according to their particular capital account balances.Agreements Omnibus AgreementWe and our general partner are parties to an omnibus agreement with Martin Resource Management (the "Omnibus Agreement") that governs, amongother things, potential competition and indemnification obligations among the parties to the116agreement, related party transactions, the provision of general administration and support services by Martin Resource Management and our use of certain ofMartin Resource Management’s trade names and trademarks. The Omnibus Agreement was amended on November 25, 2009, to include processing crude oilinto finished products including naphthenic lubricants, distillates, asphalt and other intermediate cuts. The Omnibus Agreement was amended further onOctober 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 engagein the business of:•providing terminalling and storage services for petroleum products and by-products including the refining, blending and packaging of finishedlubricants;•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 SouthHouston, 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 beenoffered the opportunity to purchase the business for fair market value and the Partnership declines to do so with the concurrence of the conflictscommittee 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 fairmarket 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 orconstructed; provided that, following completion of the acquisition or construction, the Partnership will be provided the opportunity to purchase therestricted business.117Services. Under the Omnibus Agreement, Martin Resource Management provides us with corporate staff and support services that are substantiallyidentical in nature and quality to the services previously provided by Martin Resource Management in connection with its management and operation of ourassets during the one-year period prior to the date of the agreement. The Omnibus Agreement requires us to reimburse Martin Resource Management for alldirect 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 theamount we are required to reimburse Martin Resource Management for direct expenses. In addition to the direct expenses, Martin Resource Management isentitled 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 corporateoverhead expenses. For the years ended December 31, 2017, 2016 and 2015, the Conflicts Committee approved and we reimbursed Martin ResourceManagement of $16.4 million, $13.0 million and $13.7 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committee willreview 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 corporateoverhead functions we share with Martin Resource Management retained businesses. The provisions of the Omnibus Agreement regarding Martin ResourceManagement’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 Managementwithout the prior approval of the Conflicts Committee. For purposes of the Omnibus Agreement, the term material agreements means any agreement betweenus and Martin Resource Management that requires aggregate annual payments in excess of then-applicable limitation on the reimbursable amount of indirectgeneral and administrative expenses. Please read " Services" above.License Provisions. Under the Omnibus Agreement, Martin Resource Management has granted us a nontransferable, nonexclusive, royalty-free rightand 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 beamended without the approval of the Conflicts Committee if such amendment would adversely affect the unitholders. The Omnibus Agreement was firstamended on November 25, 2009, to permit us to provide refining services to Martin Resource Management. The Omnibus Agreement was amended further onOctober 1, 2012, to permit us to provide certain lubricant packaging products and services to Martin Resource Management. Such amendments wereapproved by the Conflicts Committee. The Omnibus Agreement, other than the indemnification provisions and the provisions limiting the amount for whichwe will reimburse Martin Resource Management for general and administrative services performed on our behalf, will terminate if we are no longer anaffiliate of Martin Resource Management.Motor Carrier AgreementWe are a party to a motor carrier agreement effective January 1, 2006, as amended, with Martin Transport, Inc., a wholly owned subsidiary of MartinResource 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 periodsunless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicableterm. We have the right to terminate this agreement at anytime by providing 90 days prior notice. Under this agreement, Martin Transport, Inc. transports ourNGL shipments as well as other liquid products. These rates are subject to any adjustment to which are mutually agreed or in accordance with a priceindex. Additionally, during the term of the agreement, shipping charges are also subject to fuel surcharges determined on a weekly basis in accordance withthe 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 MartinTransport, Inc. and its officers, employees, agents, representatives and subcontractors. We indemnified Martin Transport against all claims arising out of thenegligence or willful misconduct of us and our officers, employees, agents, representatives and subcontractors. In the event a claim is the result of the jointnegligence or misconduct of Martin118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 AgreementsDiesel Fuel Terminal Services Agreement. Effective January 1, 2016, we entered into a second amended and restated terminalling servicesagreement under which we provide terminal services to Martin Resource Management for marine fuel distribution. At such time, the per gallon throughputfee we charged under this agreement was increased when compared to the previous agreement and may be adjusted annually based on a price index. Thisagreement was further amended on January 1, 2017 and October 1, 2017 to modify its minimum throughput requirements and throughput fees. Thisagreement, 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 enterinto other terminal service agreements for the purpose of providing terminal services to related parties. Individually, each of these agreements is immaterialbut 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 AgreementsMarine Transportation Agreement. We are a party to a marine transportation agreement effective January 1, 2006, as amended, under which weprovide marine transportation services to Martin Resource Management on a spot-contract basis at applicable market rates. Effective each January 1, thisagreement automatically renews for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party atleast 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 ResourceManagement 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 agreedto 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 processcrude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts for Cross. The tolling agreement expiresNovember 25, 2031. Under this tolling agreement, Martin Resource Management agreed to refine a minimum of 6,500 barrels per day of crude oil at therefinery at a fixed price per barrel. Any additional barrels are refined at a modified price per barrel. In addition, Martin Resource Management agreed to paya monthly reservation fee and a periodic fuel surcharge fee based on certain parameters specified in the tolling agreement. All of these fees (other than thefuel 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. Inaddition, 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 buteffective October 1, 2017, under which a successor in interest to the agreement from Martin Resource Management, Saconix LLC (“Saconix”), a limitedliability company in which Martin Resource Management has a minority equity interest, purchases and markets the sulfuric acid produced by our sulfuricacid production plant at Plainview, Texas, that is not consumed by our internal operations. This agreement, as amended, will remain in place until September30, 2020 and shall automatically renew year to year thereafter until either party provides 90 days’ written notice of termination prior to the expiration of thethen 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 inthe profit of such sales.Other Miscellaneous Agreements. From time to time we enter into other miscellaneous agreements with Martin Resource Management for theprovision of other services or the purchase of other goods.119Other Related Party TransactionsRelated Party Note ReceivableWe had a $15.0 million note receivable from an affiliate of Martin Resource Management which previously bore an annual interest rate of 15% andhad 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 MartinResource Management that we would be requesting voluntary repayment of the long-term Note Receivable plus accrued interest. During second quarter of2017, 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 $2.3million, 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, MEHwas 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-dealerswith respect to our common units held by such persons. Margin account transactions for such directors, officers and employees were conducted by suchbroker-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, pleasesee 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 willhave a direct or indirect material interest, the proposed transaction is submitted for consideration to the board of directors of our general partner or to ourmanagement, 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 proposedtransaction from management and determines whether to engage independent legal counsel or an independent financial advisor to advise the members of thecommittee regarding the transaction. If the Conflicts Committee retains such counsel or financial advisor, it considers such advice and, in the case of afinancial advisor, such advisor’s opinion as to whether the transaction is fair and reasonable to us and to our unitholders.120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 feesfor the annual integrated audit and fees related to services in connection with filing updated financial statements and in connection withtransactions.(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 allaudit and non-audit services performed by our independent auditor to ensure that the provisions of such services do not impair the auditor’sindependence. All of the services described above that were provided by KPMG, LLP in years ended December 31, 2017 and December 31, 2016 wereapproved in advance by the Audit Committee.121PART IVItem 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 FirmConsolidated Balance Sheets as of December 31, 2017 and 2016Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015Consolidated Statements of Changes in Capital for the years ended December 31, 2017, 2016 and 2015Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015Notes to the Consolidated Financial Statements122(b) ExhibitsINDEX TO EXHIBITSExhibitNumberExhibit Name 3.1Certificate of Limited Partnership of Martin Midstream Partners L.P. (the "Partnership"), dated June 21, 2002 (filed as Exhibit 3.1 to thePartnership's Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).3.2Second Amended and Restated Agreement of Limited Partnership of the Partnership, dated November 25, 2009 (filed as Exhibit 10.1 to thePartnership's Amendment to Current Report on Form 8-K/A (SEC File No. 000-50056), filed January 19, 2010, and incorporated herein byreference).3.3Amendment No. 2 to the Second Amended and Restated Agreement of Limited Partnership of the Partnership dated January 31, 2011 (filed asExhibit 3.1 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed February 1, 2011, and incorporated herein byreference).3.4Amendment No. 3 to the Second Amended and Restated Agreement of Limited Partnership of the Partnership dated October 2, 2012 (filed asExhibit 10.5 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed October 9, 2012, and incorporated herein byreference).3.5Certificate of Limited Partnership of Martin Operating Partnership L.P. (the "Operating Partnership"), dated June 21, 2002 (filed as Exhibit 3.3to the Partnership's Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).3.6Amended and Restated Agreement of Limited Partnership of the Operating Partnership, dated November 6, 2002 (filed as Exhibit 3.2 to thePartnership's Current Report on Form 8-K (SEC File No. 000-50056), filed November 19, 2002, and incorporated herein by reference).3.7Certificate of Formation of Martin Midstream GP LLC (the "General Partner"), dated June 21, 2002 (filed as Exhibit 3.5 to the Partnership'sRegistration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).3.8Amended and Restated Limited Liability Company Agreement of the General Partner, dated August 30, 2013 (filed as Exhibit 3.1 to thePartnership's Current Report on Form 8-K (Reg. No. 000-50056), filed September 3, 2013, and incorporated herein by reference).3.9Certificate of Formation of Martin Operating GP LLC (the "Operating General Partner"), dated June 21, 2002 (filed as Exhibit 3.7 to thePartnership's Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).3.10Limited Liability Company Agreement of the Operating General Partner, dated June 21, 2002 (filed as Exhibit 3.8 to the Partnership'sRegistration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).3.11Certificate of Formation of Arcadia Gas Storage, LLC, dated June 26, 2006 (filed as Exhibit 3.11 to the Partnership’s Quarterly Report on Form10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).3.12Company Agreement of Arcadia Gas Storage, LLC, dated December 27, 2006 (filed as Exhibit 3.12 to the Partnership’s Quarterly Report onForm 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).3.13Amendment to the Company Agreement of Arcadia Gas Storage, LLC, dated September 5, 2014 (filed as Exhibit 3.13 to the Partnership’sQuarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).3.14Certificate of Formation of Cadeville Gas Storage LLC, dated May 23, 2008 (filed as Exhibit 3.14 to the Partnership’s Quarterly Report onForm 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).3.15Limited Liability Company Agreement of Cadeville Gas Storage LLC, dated May 23, 2008 (filed as Exhibit 3.15 to the Partnership’sQuarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).3.16First Amendment to the Limited Liability Company Agreement of Cadeville Gas Storage LLC, dated April 16, 2012 (filed as Exhibit 3.16 tothe Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).3.17Second Amendment to the Limited Liability Company Agreement of Cadeville Gas Storage LLC, dated September 5, 2014 (filed as Exhibit3.17 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein byreference).3.18Certificate of Formation of Monroe Gas Storage Company, LLC, dated June 14, 2006 (filed as Exhibit 3.18 to the Partnership’s QuarterlyReport on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).1233.19Amended and Restated Limited Liability Company Agreement of Monroe Gas Storage Company, LLC, dated May 31, 2011 (filed as Exhibit3.19 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein byreference).3.20First Amendment to the Amended and Restated Limited Liability Company Agreement of Monroe Gas Storage Company, LLC, datedSeptember 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).3.21Certificate of Formation of Perryville Gas Storage LLC, dated May 23, 2008.(filed as Exhibit 3.21 to the Partnership’s Quarterly Report onForm 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).3.22Limited Liability Company Agreement of Perryville Gas Storage LLC, dated June 16, 2008 (filed as Exhibit 3.22 to the Partnership’sQuarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).3.23First Amendment to the Limited Liability Company Agreement of Perryville Gas Storage LLC, dated April 14, 2010 (filed as Exhibit 3.23 tothe Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).3.24Second Amendment to the Limited Liability Company Agreement of Perryville Gas Storage LLC, dated September 5, 2014 (filed as Exhibit3.24 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein byreference).3.25Certificate of Formation of Cardinal Gas Storage Partners LLC, dated April 2, 2008 (filed as Exhibit 3.25 to the Partnership’s Quarterly Reporton Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).3.26Third 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).3.27Certificate of Formation of Redbird Gas Storage LLC, dated May 24, 2011 (filed as Exhibit 3.27 to the Partnership's Annual Report on Form10-K (SEC File No. 000-50056), filed March 2, 2015, and incorporation herein by reference).3.28Second Amended and Restated LLC Agreement of Redbird Gas Storage LLC, dated as of October 2, 2012. (filed as Exhibit 10.6 to thePartnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed November 5, 2012, and incorporated herein by reference).3.29Certificate of Merger of Cardinal Gas Storage Partners LLC with and into Redbird Gas Storage LLC, dated October 27, 2014 (filed as Exhibit3.27 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein byreference).4.1Specimen Unit Certificate for Common Units (contained in Exhibit 3.2).4.2Specimen Unit Certificate for Subordinated Units (filed as Exhibit 4.2 to Amendment No. 4 to the Partnership’s Registration Statement onForm S-1 (SEC File No. 333-91706), filed October 25, 2002, and incorporated herein by reference).4.3Indenture (including form of 7.250% Senior Notes due 2021), dated February 11, 2013, by and among the Partnership, Martin MidstreamFinance Corp., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Partnership'sCurrent Report on Form 8-K (SEC File No. 000-50056), filed February 12, 2013, and incorporated herein by reference).4.4Second Supplemental Indenture, to the Indenture dated February 11, 2013 dated September 30, 2014, by and among the Partnership, MartinMidstream Finance Corp., the Guarantors named therein and Wells Fargo Bank National Association, as trustee (filed as Exhibit 4.4 to thePartnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014 and incorporated herein by reference).4.5Third Supplemental Indenture, to the Indenture dated February 11, 2013 dated October 27, 2014, by and among the Partnership, MartinMidstream Finance Corp., the Guarantors named therein and Wells Fargo Bank National Association, as trustee (filed as Exhibit 4.5 to thePartnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014 and incorporated herein by reference).10.1Third Amended and Restated Credit Agreement, dated March 28, 2013, among the Partnership, the Operating Partnership, Royal Bank ofCanada 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).10.2First Amendment to Third Amended and Restated Credit Agreement, dated as of July 12, 2013, among the Partnership, the OperatingPartnership, Royal Bank of Canada and the other Lenders as set forth therein (filed as Exhibit 10.2 to the Partnership’s Quarterly Report onForm 10-Q (SEC File No. 000-50056), filed May 5, 2014 and incorporated herein by reference).12410.3Second Amendment to Third Amended and Restated Credit Agreement, dated as of May 5, 2014, among the Partnership, the OperatingPartnership, Royal Bank of Canada and the other Lenders as set forth therein (filed as Exhibit 10.2 to the Partnership's Current Report on Form8-K/A (SEC File No. 000-50056), filed May 6, 2014 and incorporated herein by reference)10.4Third 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 (SECFile No. 000-50056), filed July 1, 2014, and incorporated herein by reference).10.5Fourth 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 (SECFile No. 000-50056), filed June 24, 2015, and incorporated herein by reference).10.6Omnibus Agreement, dated November 1, 2002, by and among Martin Resource Management Corporation, the General Partner, the Partnershipand the Operating Partnership (filed as Exhibit 10.3 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filedNovember 19, 2002, and incorporated herein by reference).10.7Amendment No. 1 to Omnibus Agreement, dated as of November 25, 2009, by and among Martin Resource Management Corporation, theGeneral Partner, the Partnership and the Operating Partnership (filed as Exhibit 10.3 to the Partnership’s Current Report on Form 8-K (SEC FileNo. 000-50056), filed December 1, 2009, and incorporated herein by reference).10.8Amendment No. 2 to Omnibus Agreement, dated October 1, 2012, by Martin Resource Management Corporation, the General Partner, thePartnership 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).10.9Motor Carrier Agreement, dated January 1, 2006, by and between the Operating Partnership and Martin Transport, Inc. (filed as Exhibit 10.9 tothe Partnership’s Annual Report on Form 10-K (SEC File No. 000-50056), filed March 2, 2011, and incorporated herein by reference).10.10Membership Interests Purchase Agreement, dated August 10, 2014, by and among Energy Capital Partners and its affiliated funds and RedbirdGas 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, andincorporated herein by reference).10.112014 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).10.12Marine Transportation Agreement, dated January 1, 2006, by and between the Operating Partnership and Midstream Fuel Service, L.L.C. (filedas 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 byreference).10.13Product Storage Agreement, dated November 1, 2002, by and between Martin Underground Storage, Inc. and the Operating Partnership (filedas Exhibit 10.8 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed November 19, 2002, and incorporated hereinby reference).10.14Marine Fuel Agreement, dated November 1, 2002, by and between Martin Fuel Service LLC and the Operating Partnership (filed as Exhibit10.9 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 onForm 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).10.17Purchaser Use Easement, Ingress-Egress Easement, and Utility Facilities Easement dated November 1, 2002, by and between MGSLLC and theOperating 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).10.18Amended 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).10.19Lubricants 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 ProductSales 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 ProductSales 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, andincorporated 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 asExhibit 10.1 to the Partnership's registration statement on Form S-8 (SEC File No. 333-203857), filed May 5, 2015, and incorporated herein byreference).10.23Form 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).10.24Amended and Restated Common Unit Purchase Agreement, dated as of November 24, 2009, by and between the Partnership and MartinResource 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).10.25Supply Agreement dated, as of October 2, 2012, by and between the Partnership and Cross Oil & Refining Marketing Inc. (filed as Exhibit10.7 to the Partnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed November 5, 2012, and incorporated herein byreference).10.26Noncompetition Agreement dated, as of October 2, 2012, by and among the Partnership, Cross Oil Refining & Marketing, Inc., and MartinResource Management Corporation (filed as Exhibit 10.8 to the Partnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056), filedNovember 5, 2012, and incorporated herein by reference).10.27Purchase Price Reimbursement Agreement, dated October 2, 2012, by Martin Resource Management Corporation to and for the benefit of theOperating 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).10.28Lubricants Terminalling Services Agreement, dated January 1, 2015, by and between the Operating Partnership and Martin Energy ServicesLLC (filed as Exhibit 10.26 to the Partnership's Annual Report on Form 10-K (SEC File No. 000-50056), filed March 2, 2015, andincorporated herein by reference).10.29Fuel 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 incorporatedherein by reference).10.30(1)First Amended and Restated Fuel Terminalling Services Agreement, dated January 1, 2016, by and between the Operating Partnership andMartin Energy Services, LLC (filed as Exhibit 10.29 to the Partnership's Annual Report on Form 10-K (SEC File No. 000-50056), filedFebruary 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 theOperating Partnership and Martin Energy Services, LLC (filed as Exhibit 10.30 to the Partnership’s Annual Report on Form 10-K (SEC FileNo. 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 theOperating Partnership and Martin Energy Services, LLC (filed as Exhibit 10.31 to the Partnership’s Quarterly Report on Form 10-Q (SEC FileNo. 000-50056) filed October 25, 2017).10.33Martin 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 Plan21.1*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 of2002. 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 of2002. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be "filed."101Interactive Data: the following financial information from Martin Midstream Partners L.P.’s Annual Report on Form 10-K for the fiscal yearended December 31, 2017, formatted in Extensible Business Reporting Language: (1) the Consolidated Balance Sheets; (2) the ConsolidatedStatements of Income; (3) the Consolidated Statements of Cash Flows; (4) the Consolidated Statements of Capital; and (6) the Notes toConsolidated 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 Rule24b-2 of the Securities Exchange Act of 1934, as amended, which has been granted.126SIGNATURESPursuant 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 ourbehalf 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, 2018By:/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 theregistrant 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 GPLLC (Principal Executive Officer)Ruben S. Martin /s/ Robert D. Bondurant Executive Vice President, Director, and Chief Financial Officer of MartinMidstream GP LLC (Principal Financial Officer, Principal AccountingOfficer)Robert D. Bondurant /s/ Zachary S. Stanton Director of Martin Midstream GP LLCZachary S. Stanton /s/ James M. Collingsworth Director of Martin Midstream GP LLCJames M. Collingsworth /s/ Sean P. Dolan Director of Martin Midstream GP LLCSean P. Dolan /s/ Byron R. Kelley Director of Martin Midstream GP LLCByron R. Kelley /s/ C. Scott Massey Director of Martin Midstream GP LLCC. Scott Massey 128Exhibit 10.34RESTRICTED UNIT AGREEMENTUNDER THEMARTIN MIDSTREAM PARTNERS L.P. 2017 RESTRICTED UNIT PLANThis Award Agreement (this “Agreement”) is entered into between Martin Midstream Partners L.P., a Delaware limitedpartnership (the “Partnership”) and [________________] (the “Participant”), an employee of Martin Resource ManagementCorporation, a Martin Group entity (the “Employer”), effective [___________], 2018 (the “Date of Grant”). Capitalized terms used butnot 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 witha 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 Serviceterminates 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 anytime 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 tocontinue employment with the Partnership or any Martin Group entity or in any way limit their right to terminate the Participant’sService 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 [anyUDRs issued with respect to the Units in this Award will be paid currently as provided in the Plan][Participant will not be paid UDRsuntil 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 privilegesprovided for in this Agreement, may not be transferred, assigned, pledged, or hypothecated in any manner, by operation of law orotherwise, 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), uponvesting 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 taxobligations. In order to satisfy this obligation, unless the Participant has settled such obligations with the Company by the TaxDate (whether by payment in cash or delivery of currently-owned, unrestricted Units), the Partnership will withhold from theAward a number of Units in a value equal to the statutory withholding requirement. The value of the Units to be delivered orwithheld 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 ofGrant. If the Participant makes a Section 83(b) Election, the Participant must provide the Partnership with (i) a copy of anexecuted version, (ii) satisfactory evidence of the filing of the executed Section 83(b) Election with the Internal Revenue Serviceand (iii) sufficient cash to meet the Participants withholding obligation as a result of the Section 83(b) Election. The Participantagrees and understands that the Participant bears sole responsibility for ensuring that the Section 83(b) Election is actually andtimely 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 mannernot inconsistent with the terms of the Plan. Notwithstanding the foregoing, except as expressly provided in the Plan, no suchamendment, modification, or termination may materially impair the rights of the Participant under this Agreement without the writtenconsent of the Participant.8.Notices. All notices to the Partnership related to this Agreement should be sent to the Partnership’s principal executiveoffices as disclosed in its filings with the Securities and Exchange Commission, addressed to the Office of General Counsel. All noticesto 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. ThisAgreement 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 ofDelaware, 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 allApplicable 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 thePartnership and its counsel. The Participant understands that the Partnership is under no obligation to register the Units with theSecurities 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 itvalid and enforceable to the fullest extent allowed by law. Any such provision that is not susceptible of reformation shall be ignoredand shall not affect the validity, legality and enforceability of the remaining provisions, which shall be valid and enforced to the fullestextent permitted by law.13.Entire Agreement. This Agreement, together with the Plan and the Partnership Agreement, constitutes the entireagreement 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 thisAgreement 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, thisAgreement, and the Partnership Agreement, and hereby accepts this Award subject to all of those terms and provisions. The Participantagrees to accept as binding, conclusive, and final all decisions or interpretations of the Committee upon any questions arising under thePlan 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 LLCBy: Printed Name: Title:PARTICIPANT: Printed Name: EXHIBIT AVesting Schedule and TermsExhibit 21.1 SUBSIDIARIES OFMARTIN 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 Exhibit 23.1 Consent of Independent Registered Public Accounting FirmThe Board of DirectorsMartin 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 consolidatedbalance 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 overfinancial 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 LLPDallas, TexasFebruary 16, 2018Exhibit 31.1CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICERPursuant 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 thestatements 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 thefinancial 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 ExchangeAct 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 registrantand have: a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, 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 oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for externalpurposes 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 theeffectiveness 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 recentfiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materiallyaffect, 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 theregistrant’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 reasonablylikely 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 controlover 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. Exhibit 31.2 CERTIFICATION OF PRINCIPAL FINANCIAL OFFICERPursuant 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 thestatements 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 thefinancial 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 ExchangeAct 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 registrantand have: a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, 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 oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for externalpurposes 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 theeffectiveness 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 recentfiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materiallyaffect, 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 theregistrant’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 reasonablylikely 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 controlover 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. Exhibit 32.1CERTIFICATION 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 theyear ended December 31, 2017, as filed with the Securities and Exchange Commission (the “Report”), I, Ruben S. Martin, Chief Executive Officer of MartinMidstream 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), thatto 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 andfurnished to the Securities and Exchange Commission or its staff upon request.Exhibit 32.2CERTIFICATION 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 theyear ended December 31, 2017, as filed with the Securities and Exchange Commission (the “Report”), I, Robert D. Bondurant, Chief Financial Officer ofMartin 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. Section1350), 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 andfurnished to the Securities and Exchange Commission or its staff upon request.

Continue reading text version or see original annual report in PDF format above