MARTIN MIDSTREAM PARTNERS L.P. - Annual Report: 2016 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K



Mark One	Annual Report Pursuant to Section 13 or 15(d) of the
ý	Securities Exchange Act of 1934
	For the fiscal year ended December 31, 2016



o	Transition Report Pursuant to Section 13 or 15(d) of the
	Securities Exchange Act of 1934

For the transition period from _____ to _____.

Commission file number 000-50056

MARTIN MIDSTREAM PARTNERS L.P.

(Exact name of registrant as specified in its charter)



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

4200 Stone Road Kilgore, Texas 75662

(Address of principal executive offices) (Zip Code)

903-983-6200

(Registrant’s telephone number, including area code)

_______________________

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



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

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

NONE

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

Yes o No ý

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

Yes o No ý

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

Yes ý No o

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

Yes ý No o

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

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



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

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, 2016, 35,454,962 common units were outstanding. The aggregate market value of the common units held by non-affiliates of the registrant as of such date approximated $674,298,933 based on the closing sale price on that date. There were 35,450,562 of the registrant’s common units outstanding as of February 15, 2017.

DOCUMENTS INCORPORATED BY REFERENCE: None.

TABLE OF CONTENTS



		Page
PART I		1
Item 1.	Business	1
Item 1A.	Risk Factors	20
Item 1B.	Unresolved Staff Comments	39
Item 2.	Properties	39
Item 3.	Legal Proceedings	39
Item 4.	Mine Safety Disclosures	39

PART II		40
Item 5.	Market for Our Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	40
Item 6.	Selected Financial Data	41
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	42
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	66
Item 8.	Financial Statements and Supplementary Data	67
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	106
Item 9A.	Controls and Procedures	106
Item 9B.	Other Information	107

PART III		108
Item 10.	Directors, Executive Officers and Corporate Governance	108
Item 11.	Executive Compensation	113
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	120
Item 13.	Certain Relationships and Related Transactions, and Director Independence	123
Item 14.	Principal Accounting Fees and Services	128

PART IV		129
Item 15.	Exhibits, Financial Statement Schedules	129

PART I



Item 1.	Business

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

Forward-Looking Statements

This annual report on Form 10-K includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Statements included in this annual report that are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions or forecasts related thereto), are forward-looking statements. These statements can be identified by the use of forward-looking terminology including "forecast," "may," "believe," "will," "expect," "anticipate," "estimate," "continue" or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other "forward-looking" information. We and our representatives may from time to time make other oral or written statements that are also forward-looking statements.

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

Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed below in "Item 1A. Risk Factors - Risks Related to our Business."

Overview

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


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


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


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


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

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

and capitalized on the needs of producers and purchasers of petroleum products and by-products and other bulk liquids. Martin Resource Management is an important supplier and customer of ours. As of December 31, 2016, Martin Resource Management owned 17.7% of our total outstanding common limited partner units. Furthermore, Martin Resource Management controls Martin Midstream GP LLC ("MMGP"), our general partner, by virtue of its 51% voting interest in MMGP Holdings, LLC ("Holdings"), the sole member of MMGP. MMGP owns a 2.0% general partner interest in us and all of our incentive distribution rights. Martin Resource Management directs our business operations through its ownership interests in and control of our general partner.

We entered into an omnibus agreement dated November 1, 2002, with Martin Resource Management (the "Omnibus Agreement") that governs, among other things, potential competition and indemnification obligations among the parties to the agreement, related party transactions, the provision of general administration and support services by Martin Resource Management and our use of certain of Martin Resource Management’s trade names and trademarks. Under the terms of the Omnibus Agreement, the employees of Martin Resource Management are responsible for conducting our business and operating our assets. The Omnibus Agreement was amended on November 25, 2009, to include processing crude oil into finished products including naphthenic lubricants, distillates, asphalt and other intermediate cuts. The Omnibus Agreement was amended further on October 1, 2012, to permit the Partnership to provide certain lubricant packaging products and services to Martin Resource Management.

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

Primary Business Segments

Our primary business segments can be generally described as follows:

•

Terminalling and Storage. We own or operate 26 marine shore-based terminal facilities and 14 specialty terminal facilities located primarily in the U.S. Gulf Coast region that provide storage, refining, blending, packaging, and handling services for producers and suppliers of petroleum products and by-products, including the refining of naphthenic crude oil and the blending and packaging of various grades and quantities of industrial, commercial, and automotive lubricants and greases. Our facilities and resources provide us with the ability to handle various products that require specialized treatment, such as molten sulfur and asphalt. We also provide land rental to oil and gas companies along with storage and handling services for lubricants and fuels. We provide these terminalling and storage services on a fee basis primarily under long-term contracts. A significant portion of the contracts in this segment provide for minimum fee arrangements that are not based on the volumes handled.

•

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

•

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

Illinois. Demand for our sulfur products exists in both the domestic and foreign markets, and we believe our asset base provides us with additional opportunities to handle increases in U.S. supply and access to foreign demand.

•

Marine Transportation. We operate a fleet of 35 inland marine tank barges, 19 inland push boats and one offshore tug and barge unit that transport petroleum products and by-products largely in the U.S. Gulf Coast region. We provide these transportation services on a fee basis primarily under annual contracts, and many of our customers have long standing contractual relationships with us. Our modernized asset base is attractive both to our existing customers as well as potential new customers. In addition, our fleet contains several vessels that reflect our focus on specialty products.

Recent Developments

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

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

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

Divestiture of Terminalling Assets. On December 21, 2016, we sold our 900,000 barrel crude oil storage terminal, refined product barge terminal, certain pipelines and related easements as well as dockage and trans-loading assets located in Corpus Christi, Texas (collectively the "CCCT Assets") to NuStar Logistics, L.P. (“NuStar”) for gross consideration of $107.0 million plus the reimbursement of certain capital expenditures and prepaid items of $2.1 million. We received net proceeds of approximately $93.3 million after transaction fees and expenses as well as the application of certain net cash payments previously received by us in conjunction with our mandated relocation of certain dockage assets to the purchase price in the amount of $13.4 million. Proceeds from the sale were used to reduce outstanding borrowings under our revolving credit facility.

West Texas LPG Pipeline L.P. ("WTLPG") 2015 Rate Complaints. Certain shippers filed complaints with the Railroad Commission of Texas (“RRC”) challenging the increased rates WTLPG implemented effective July 1, 2015. The complaints request that the rate increase be suspended until the RRC has determined appropriate new rates. On March 8, 2016, the RRC issued an order directing that WTLPG’s rates “in effect prior to July 1, 2015, are the lawful rates for the duration of this docket unless changed by Commission order.” A hearing on the merits is scheduled in front of the hearings examiner for the week of March 27, 2017.

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

Subsequent Events

Repayment of Note Receivable. On February 14, 2017, we notified Martin Resource Management that we would be requesting voluntary repayment of the Note Receivable due from MET of $15,000 plus accrued interest and MET has agreed to do so in a timely manner.

Acquisition of Terminalling Assets. On February 14, 2017, we entered into an agreement with Martin Resource Management to acquire certain asphalt terminalling assets located in Hondo, Texas for a purchase price of $27.4 million (the “Hondo Acquisition”). Martin Resource Management is currently constructing in Hondo, Texas an asphalt terminal facility, which will serve the asphalt market in San Antonio, Texas and surrounding areas. This terminal will have 178,000 barrels of asphalt storage with processing and blending capabilities. The acquisition is expected to close on or about February 28, 2017. After closing, we will spend $8.6 million to finalize construction of the terminal with substantial completion expected to be on or about July 1, 2017. Martin Resource Management is obligated to pay us the amount required to complete the construction of the Hondo Terminal in excess of $8.6 million, if any. The terminal will be supported by long-term contractual agreements with Martin Resource Management whereby we expect to receive cash flow of approximately $5.0 million annually.

Quarterly Distribution. On January 19, 2017, we declared a quarterly cash distribution of $0.50 per common unit for the fourth quarter of 2016, or $2.00 per common unit on an annualized basis, which was paid on February 14, 2017 to unitholders of record as of February 7, 2017.

Our Growth Strategy

The key components of our growth strategy are:


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

•

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

•

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


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

Competitive Strengths

As discussed previously, commodity prices have declined substantially and experienced significant volatility. We plan for these cyclical downturns in commodity prices and we believe we are positioned to withstand the effect on our assets with respect to current and future commodity price volatility as a result of the following information.

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

Asset Base and Integrated Distribution Network. We operate a diversified asset base that enables us to offer our customers an integrated distribution network consisting of transportation, terminalling and storage and midstream logistical services while minimizing our dependence on the availability and pricing of services provided by third parties. Our integrated distribution network enables us to provide customers with a complementary portfolio of transportation, terminalling, distribution and other midstream services for petroleum products and by-products.

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

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

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

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

Terminalling and Storage Segment

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

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

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

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

Specialty Petroleum Terminals. We own or operate 14 terminalling facilities providing storage, handling and transportation of various petroleum products and by-products. The locations and capabilities of our terminals are structured to complement our other businesses and reflect our strategy to provide a broad range of integrated services in the storage,

handling and transportation of products. We developed our terminalling and storage assets by acquisition and upgrades of existing facilities as well as developing our own properties strategically located near rail, waterways and pipelines. We anticipate further expansion of our terminalling facilities through both acquisition and organic growth.

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

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

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

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

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

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

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

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

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

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

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

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

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



Terminal	Location	Aggregate Capacity	Products	Description
Tampa (1)	Tampa, Florida	719,000 barrels	Asphalt and fuel oil	Marine terminal, loading/unloading for vessels, barges, railcars and trucks
Stanolind	Beaumont, Texas	593,200 barrels	Asphalt, crude oil, sulfur, sulfuric acid and fuel oil	Marine terminal, marine dock for loading/unloading of vessels, barges, railcars and trucks
Neches	Beaumont, Texas	546,750 barrels	Molten sulfur, ammonia, asphalt, fuel oil, crude oil and sulfur-based fertilizer	Marine terminal, loading/unloading for vessels, barges, railcars and trucks


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

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



Terminal	Location	Aggregate Capacity	Products	Description
Channelview	Houston, Texas	44,000 sq. ft. Warehouse; 39,800 barrels	Lubricants	Lubricants blending, storage, packaging and distribution
Smackover Refinery	Smackover, Arkansas	7,700 barrels per day	Naphthenic lubricants, distillates, asphalt	Crude refining facility
Smackover Refinery	Smackover, Arkansas	275,000 barrels of crude bulk storage; 641,000 barrels of lubricant storage	Crude oil, lubricants	Crude refining facility
Martin Lubricants	Smackover, Arkansas	235,000 sq. ft. Warehouse; 3.9 million gallons bulk storage	Gard, SynGard, Unimark and Xtreme brands, and grease	Lubricants packaging facility
Martin Lubricants (1)	Kansas City, Missouri	75,000 sq. ft. Warehouse; 0.2 million gallons bulk storage	Automotive, commercial and industrial greases	Grease manufacturing and packaging facility
South Houston Asphalt	Houston, Texas	95,500 barrels	Asphalt	Asphalt processing and storage
Port Neches Asphalt	Port Neches, Texas	30,100 barrels	Asphalt	Asphalt processing and storage
Omaha Asphalt	Omaha, Nebraska	113,900 barrels	Asphalt	Asphalt processing and storage
Dunphy (2)	Elko, Nevada	63,200 barrels	Sulfuric acid	Sulfuric acid storage
Spindletop	Beaumont, Texas	90,000 barrels	Natural gasoline	Pipeline receipts and shipments
Jennings Bulk Plant	Jennings, Louisiana	36,000 sq. ft. building; 6,800 barrels	Lubricants, fuel	Lubricants and fuel storage


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


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

Marine Shore-Based Terminals. We own or operate 26 marine shore-based terminals along the Gulf Coast from Theodore, Alabama to Port O'Connor, Texas. Our terminalling assets are located at strategic distribution points for the products we handle and are in close proximity to our customers. We are one of the largest operators of marine shore-based terminals in the Gulf Coast region. These terminals are used to distribute and market fuel and lubricants. Additionally, full

service terminals also provide shore bases for companies that are operating in the offshore exploration and production industry. Customers are primarily oil and gas exploration and production companies and oilfield service companies, such as drilling fluid companies, marine transportation companies and offshore construction companies. Shore bases typically provide logistical support, including the storing and handling of tubular goods, loading and unloading bulk materials, providing facilities from which major and independent oil companies can communicate with and control offshore operations and leasing dockside facilities to companies which provide complementary products and services such as drilling fluids and cementing services. We generate revenues from our terminals that have shore bases by fees that we charge our customers under land rental contracts for the use of our terminal facility for these shore bases. These contracts generally provide us a fixed land rental fee and additional rental fees that are determined based on a percentage of the sales value of the products and services delivered from the shore base. In addition, Martin Resource Management, through terminalling service agreements, pays us for terminalling and storage of fuels and lubricants at these terminal facilities and includes a provision for minimum volume throughput requirements.

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

Full Service Terminals. We own or operate 10 full service terminals. These facilities provide logistical support services and storage and handling services for fuel and lubricants. The significant difference between our full service terminals and our fuel and lubricant terminals is that our full service terminals generate additional revenues by providing shore bases to support our customer’s operating activities related to the offshore exploration and production industry. One typical use for our shore bases is for drilling fluids manufacturers to manufacture and sell drilling fluids to the offshore drilling industry. Offshore drilling companies may also set up service facilities at these terminals to support their offshore operations. Customers of our full service terminals are primarily oil and gas exploration and production companies, oilfield service companies such as drilling fluids companies, marine transportation companies and offshore construction companies.

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



Terminal	Location	Aggregate Capacity (barrels)	End of Lease (Including Options)
Amelia 2	Amelia, Louisiana	13,000	August 2023
Cameron West (2)	Cameron, Louisiana	16,300	February 2033
Dock 193 (3)	Gueydan, Louisiana	11,000	May 2018
Fourchon 15	Fourchon, Louisiana	7,600	February 2047
Freshwater City (1)	Freshwater City, Louisiana	0	March 2017
Harbor Island (3)	Harbor Island, Texas	6,800	December 2039
Intracoastal City-2	Intracoastal City, Louisiana	17,700	December 2025
Pelican Island	Galveston, Texas	87,600	Own
Theodore	Theodore, Alabama	19,900	Own
Venice (1)	Venice, Louisiana	25,100	September 2017


(1)	These terminals are currently in caretaker status and the lease will not be renewed at the end of the term.


(2)	This terminal is currently in caretaker status.


(3)	A portion of this terminal is owned.

Fuel and Lubricant Terminals. We own or operate 16 lubricant and fuel terminals located in the Gulf Coast region that provide storage and handling services for lubricants and fuel oil.

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



Terminal	Location	Aggregate Capacity (barrels)	End of Lease (Including Options)
Berwick (1)	Berwick, Louisiana	0	September 2017
Cameron East (1)	Cameron, Louisiana	0	March 2017
Dulac (1)	Dulac, Louisiana	15,400	December 2021
Fourchon	Fourchon, Louisiana	80,900	May 2027
Fourchon 16	Fourchon, Louisiana	16,400	March 2022
Fourchon 17	Fourchon, Louisiana	41,200	March 2023
Fourchon T	Fourchon, Louisiana	10,200	October 2038
Galveston T (2)	Galveston, Texas	1,400	Own
Intracoastal City (2)	Intracoastal City, Louisiana	0	Own
Lake Charles T	Lake Charles, Louisiana	1,000	April 2018
Morgan City DWC 31	Morgan City, Louisiana	7,100	December 2019
Pascagoula	Pascagoula, Mississippi	10,400	Own
Port Arthur	Port Arthur, Texas	16,300	November 2025
Port O'Connor (2)	Port O'Connor, Texas	6,800	March 2017
River Ridge	River Ridge, Louisiana	8,700	April 2019
Sabine Pass (2)	Sabine Pass, Texas	16,500	September 2036


(1)	These terminals are 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.

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

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

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

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

Natural Gas Services Segment

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

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

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


•	storage of NGLs purchased in off-peak months;


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


•	product management expertise to obtain supplies when needed.

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



NGL Facility	Location	Capacity	Description
Wholesale terminals	Arcadia, Louisiana	2,400,000 barrels	Underground storage
	Breaux Bridge, Louisiana (1)	420,000 barrels	Underground storage
	Napoleonville, Louisiana (1)	370,000 barrels	Underground storage
	Hattiesburg, Mississippi (1)	240,000 barrels	Underground storage
	Mont Belvieu, Texas (1)	60,000 barrels	Underground storage
Retail terminals	Kilgore, Texas	90,000 gallons	Retail propane distribution
	Longview, Texas	30,000 gallons	Retail propane distribution
	Henderson, Texas	12,000 gallons	Retail propane distribution
Rail terminal	Arcadia, Louisiana	24 railcars per day	NGL rail loading and unloading capabilities


(1)	We lease our underground storage at Breaux Bridge, Louisiana, Hattiesburg, Mississippi, Napoleonville, Louisiana, and Mont Belvieu, Texas, from third parties under one-year lease agreements.

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

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

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

are also significantly influenced by operational imbalances, near term seasonal spreads, shorter term spreads and basis differentials.

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

Cardinal facilities are summarized below:



Facility Name / Location	Facility Type	Storage Capacity	Percent of Capacity Contracted (1)	Weighted Average Life of Remaining Contract Term
Arcadia Gas Storage, LLC Bienville Parish, Louisiana	Salt dome	16.3 billion cubic feet (bcf)	89%	2.6 years
Cadeville Gas Storage, LLC Ouachita Parish, Louisiana	Depleted reservoir	17.0 bcf	100%	6.4 years
Perryville Gas Storage, LLC Franklin Parish, Louisiana	Salt dome	9.0 bcf	94%	2.0 years
Monroe Gas Storage Company, LLC Monroe County, Mississippi	Depleted reservoir	7.4 bcf	89%	3.3 years

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

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

LPG Pipeline Investment. We own a 20% interest in WTLPG. WTLPG owns an approximate 2,300 mile common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. This asset enables us to participate in the transportation of NGL production originating in the Permian and other basins along the WTLPG pipeline route.

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

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

Sulfur Services Segment

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

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

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

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

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

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

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

Our sulfuric acid production facility at our Plainview, Texas location processes molten sulfur to produce a dedicated supply of raw material sulfuric acid to our ammonium sulfate production plant. The ammonium sulfate plant produces approximately 400 tons per day of quality ammonium sulfate and is marketed to our customers throughout the U.S. The sulfuric acid produced and not consumed by the captive ammonium sulfate production is sold to Martin Resource Management, which markets the excess production to third parties.

Fertilizer and related sulfur products are a natural extension of our molten sulfur business because of our access to sulfur and our distribution capabilities. These products allow us to leverage the Sulfur Services segment of our business. Our annual fertilizer and industrial sulfur products sales have grown significantly as a result of acquisitions and internal growth.

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

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

•

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


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

•

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

•

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

Our Sulfur Services Facilities. We own 35 railcars and lease 94 railcars equipped to transport molten sulfur. We own the following marine assets and use them to transport molten sulfur between U.S. gulf coast storage terminals (including our terminal in Beaumont, Texas) under third-party marine transportation agreements:



Asset	Class of Equipment	Capacity/Horsepower	Products Transported
Margaret Sue	Offshore tank barge	10,500 long tons	Molten sulfur
M/V Martin Explorer	Offshore tugboat	7,130 horsepower	N/A
M/V Martin Express	Inland push boat	1,200 horsepower	N/A
MGM 101	Inland tank barge	2,500 long tons	Molten sulfur
MGM 102	Inland tank barge	3,400 long tons	Molten sulfur

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



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

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



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

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

Our sulfuric acid products compete with regional producers and importers in the South and Southwest portion of the U.S. from Louisiana to California.

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

Marine Transportation Segment

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

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

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

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



Class of Equipment	Number in Class	Capacity/Horsepower	Description of Products Carried
Inland tank barges	9	Under 20,000 barrels	Asphalt, crude oil, fuel oil, gasoline and sulfur
Inland tank barges	26	20,000 - 31,000 barrels	Asphalt, crude oil, fuel oil and gasoline
Inland push boats	19	800 - 3,800 horsepower	N/A
Offshore tank barge	1	58,000 barrels	Diesel fuel
Offshore tugboat	1	5,100 horsepower	N/A

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

We are a party to a marine transportation agreement under which we provide marine transportation services to Martin Resource Management on a spot contract basis at applicable market rates. Effective each January 1, this agreement automatically renews for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at least 60 days prior to the expiration of the then-applicable term.

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

In addition to competitors that provide marine transportation services, we also compete with providers of other modes of transportation, such as rail, trucks and, to a lesser extent, pipelines. For example, a typical two inland barge unit carries a

volume of product equal to approximately 80 railcars or 250 tanker trucks. Pipelines generally provide a less expensive form of transportation than marine transportation. However, pipelines are not able to transport most of the products we transport and are generally a less flexible form of transportation because they are limited to the fixed point-to-point distribution of commodities in high volumes over extended periods of time.

Our Relationship with Martin Resource Management

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


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


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


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


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


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


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


•	operating an environmental consulting company;


•	operating an engineering services company;


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


•	operating a crude oil, natural gas, natural gas liquids, and biofuels optimization business; and


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

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

Ownership

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

Management

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

Related Party Agreements

The Omnibus Agreement with Martin Resource Management requires us to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes on our behalf or in connection with the operation of our business. We reimbursed Martin Resource Management for $135.8 million, $149.3 million and $183.2 million of direct costs and expenses for the years ended December 31, 2016, 2015 and 2014, respectively. There is no monetary limitation on the amount we are required to reimburse Martin Resource Management for direct expenses.

In addition to the direct expenses, under the Omnibus Agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. For the years ended December 31, 2016, 2015, and 2014, the conflicts committee of our general partner ("Conflicts Committee") approved reimbursement amounts of $13.0 million, $13.7 million and $12.5 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually. These indirect expenses covered the centralized corporate functions Martin Resource Management provides for us, such as accounting, treasury, clerical, engineering, legal, billing, information technology, administration of insurance, environmental and safety compliance, general office expenses and employee benefit plans and other general corporate overhead functions we share with Martin Resource Management’s retained businesses. The Omnibus Agreement also contains significant non-compete provisions and indemnity obligations. Martin Resource Management also licenses certain of its trademarks and trade names to us under the Omnibus Agreement.

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

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

Commercial

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

In the aggregate, our purchases from Martin Resource Management accounted for approximately 11%, 9%, and 7% of our total cost of products sold during for the years ended December 31, 2016, 2015 and 2014, respectively. We also purchase marine fuel from Martin Resource Management, which we account for as an operating expense.

Correspondingly, Martin Resource Management is one of our significant customers. Our sales to Martin Resource Management accounted for approximately 13%, 11%, 6% of our total revenues for each of the years ended December 31, 2016, 2015 and 2014, respectively. We have entered into certain agreements with Martin Resource Management pursuant to which we provide terminalling and storage and marine transportation services to its subsidiary, Martin Energy Services LLC ("MES"), and MES provides terminal services to us to handle lubricants, greases and drilling fluids. Additionally, we have entered into a long-term, fee for services-based tolling agreement with Martin Resource Management where Martin Resource Management agrees to pay us for the processing of its crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts.

Approval and Review of Related Party Transactions

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

Insurance

Our deductible for onshore physical damage resulting from named windstorms is 5% of the total value located at an individual location subject to an overall minimum deductible of $3.5 million for damage caused by the named windstorm at all locations. Our onshore program currently provides $40.0 million per occurrence for named windstorm events. For non-windstorm events, our deductible applicable to onshore physical damage is $1.0 million per occurrence. Business interruption coverage in connection with a windstorm event is subject to the same $40.0 million per occurrence and aggregate limit as the property damage coverage and a waiting period of 45 days. For non-windstorm events, our waiting period applicable to business interruption is 30 days.

Our deductible for physical damage at our refining, blending and packaging division in Smackover, Arkansas is $0.5 million per occurrence. The waiting period applicable to business interruption is 30 days.

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

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

For marine claims, our insurance covers up to $1.0 billion of liability per accident or occurrence. We believe our current insurance coverage is adequate to protect us against most accident related risks involved in the conduct of our business. However, there can be no assurance that all risks are adequately insured against, that any particular claim will be paid by the insurer, or that we will be able to procure adequate insurance coverage at commercially reasonable rates in the future.

Environmental and Regulatory Matters

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

Environmental

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

The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and, thus, any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and financial position. Moreover, there is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum products and by-products, chemical substances, and wastes as well as the accidental release or spill of such materials into the environment. Consequently, we cannot provide assurance that

we will not incur significant costs and liabilities as result of such handling practices, releases or spills, including those relating to claims for damage to property and persons. In the event of future increases in costs, we may be unable to pass on those increases to our customers. While we believe that we are in substantial compliance with current environmental laws and regulations and that continued compliance with existing requirements would not have a material adverse impact on us, we cannot provide any assurance that our environmental compliance expenditures will not have a material adverse effect on us in the future.

Superfund

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

Solid Waste

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

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

Clean Air Act

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

Global Warming and Climate Change. Recent scientific studies have suggested that emissions of certain gases, commonly referred to as "greenhouse gases" and including carbon dioxide and methane, may be contributing to warming of the

Earth’s atmosphere. In response to such studies, the U.S. Congress has from time to time considered climate change-related legislation to restrict greenhouse gas emissions. Many states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007, in Massachusetts, et al. v. EPA, the EPA eventually concluded that it is required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court's holding in Massachusetts that greenhouse gases fall under the federal CAA's definition of air pollutant has also led the EPA to determine that regulation of greenhouse gas emissions from stationary sources under various Clean Air Act programs is required. To that end, EPA promulgated regulations, referred to as the Tailoring Rule, 75 Fed. Red. 31514, to begin gradually subjecting stationary greenhouse gas emission sources to various Clean Air Act programs, including permitting programs applicable to new and existing major sources of greenhouse gas emissions. To date, such requirements have not had a substantial effect upon our operations. Still, new legislation or regulatory programs that restrict emissions of greenhouse gases in areas in which we conduct business could adversely affect our operations and demand for our services.

Clean Water Act

The Federal Water Pollution Control Act of 1972, as amended, also known as Clean Water Act and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including hydrocarbon-bearing wastes, into state waters and waters of the U.S.. Pursuant to the Clean Water Act and similar state laws, a National Pollutant Discharge Elimination System, or state permit, or both, must be obtained to discharge pollutants into federal and state waters. In addition, the Clean Water Act and comparable state laws require that individual permits or coverage under general permits be obtained by subject facilities for discharges of storm water runoff. We believe that we are in substantial compliance with Clean Water Act permitting requirements as well as the conditions imposed thereunder, and that our continued compliance with such existing permit conditions will not have a material adverse effect on our business, financial condition or results of operations.

Oil Pollution Act

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

Safety Regulation

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

Occupational Health Regulations

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

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

Jones Act

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

Merchant Marine Act of 1936

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

Employees

We do not have any employees. Under our Omnibus Agreement with Martin Resource Management, Martin Resource Management provides us with corporate staff and support services. These services include centralized corporate functions, such as accounting, treasury, engineering, information technology, insurance, administration of employee benefit plans and other corporate services. Martin Resource Management employs approximately 784 individuals, including 55 employees represented by labor unions, who provide direct support to our operations as of December 31, 2016.

Financial Information about Segments

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

Access to Public Filings

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



Item 1A.	Risk Factors

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a business similar to ours. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In this case, we might not be able to pay distributions on our common units, the trading price of our

common units could decline and unitholders could lose all or part of their investment. These risk factors should be read in conjunction with the other detailed information concerning us set forth herein.

Risks Relating to Our Business

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

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

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

•the costs of acquisitions, if any;


•	the prices of petroleum products and by-products;


•	fluctuations in our working capital;


•	the level of capital expenditures we make;


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


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


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

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

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

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

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

Our indebtedness could have important consequences, including the following:


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


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


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


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

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

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

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

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

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

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

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


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


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


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

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

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

may be at higher rates than our current interest rate protection agreements, which could have a material adverse effect on our business, financial condition and results of operations.

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

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

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

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


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


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


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


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

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

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

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

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

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

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


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


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


•	fires and explosions;


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


•	terrorist attacks or sabotage.

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

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

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

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

Increasing energy prices could adversely affect our results of operations.

Increasing energy prices could adversely affect our results of operations. Diesel fuel, natural gas, chemicals and other supplies are recorded in operating expenses. An increase in price of these products would increase our operating expenses, which could adversely affect our results of operations including net income and cash flows. We cannot assure unitholders that we will be able to pass along increased operating expenses to our customers.

Decreasing energy prices could adversely affect our results of operations.

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

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

Our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows could be adversely affected by activities of other interstate and intrastate pipelines and storage facilities that may expand or construct competing transportation and storage systems. In addition, future pipeline transportation and storage capacity could be

constructed in excess of actual demand and with lower fuel requirements, operating and maintenance costs than our facilities, which could reduce the demand for and the rates that we receive for our services in particular areas. Further, natural gas also competes with alternative energy sources available to our customers that are used to generate electricity, such as hydroelectric power, solar, wind, nuclear, coal and fuel oil.

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

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


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


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


•	worldwide demand for oil and natural gas;


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


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


•	local and international political and economic conditions and policies;


•	technological advances affecting energy production and consumption;


•	weather conditions;


•	environmental regulation; and


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

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

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

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

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

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

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

Our business is subject to federal, state and local environmental laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of human health, natural resources and the environment. These laws and regulations may impose numerous obligations that are applicable to our operations, such as: requiring the acquisition of permits to conduct regulated activities; restricting the manner in which we can release materials into the environment; requiring remedial activities or capital expenditures to mitigate pollution from former or current operations; and

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

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

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

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

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

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

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

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


•	catastrophic events, including hurricanes;


•	environmental remediation;


•	labor difficulties; and


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

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

Political, regulatory and economic factors could significantly affect our operations, the manner in which we conduct our business and slow our rate of growth.

Due to changes in the political climate as a result of the outcome of recent state elections and the Congressional election in the U.S., we cannot predict with any certainty the nature and extent of the changes in federal, state and local laws, regulations and policy we will face, or the effect of such elections on any pending legislation. Any increased regulation, new policy initiatives, increased taxes or any other changes in federal law may have an adverse effect on our business, financial condition and results of operations.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Risks Relating to an Investment in the Common Units

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

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

Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders. Our general partner may also cause us to issue an unlimited number of additional common units or other equity securities of equal rank with the common units, without unitholder approval, in a number of circumstances such as:


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


•	the conversion of subordinated units into common units;


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


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

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

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

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

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

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

If unitholders are dissatisfied with the performance of our general partner, they will have a limited ability to remove our general partner. Our general partner generally may not be removed except upon the vote of the holders of at least 66 2/3% of the outstanding units voting together as a single class. As of December 31, 2016, Martin Resource Management owned 17.7% of our total outstanding common limited partner units.

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

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

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

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

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

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


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


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

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

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

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


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


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


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


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

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

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

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


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


•	the conversion of subordinated units into common units;


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


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

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

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


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


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


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


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


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


•	the ratio of taxable income to distributions may increase.

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

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

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

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

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

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

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

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

Risks Relating to Our Relationship with Martin Resource Management

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

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

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

As of December 31, 2016, Martin Resource Management owned 17.7% of our total outstanding common limited partner units and a 51% voting interest in Holdings, the sole member of MMGP. MMGP owns a 2.0% general partnership interest in us and all of our incentive distribution rights. Conflicts of interest may arise between Martin Resource Management and our general partner, on the one hand, and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of Martin Resource Management over the interests of our unitholders. Potential conflicts of interest between us, Martin Resource Management and our general partner could occur in many of our day-to-day operations including, among others, the following situations:


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

•

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


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


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

•

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


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


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


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


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


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


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


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

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

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

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

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

Tax Risks

The IRS could treat us as a corporation for tax purposes, which would substantially reduce the cash available for distribution to unitholders.

The anticipated after-tax economic benefit of an investment in us depends largely on our classification as a partnership for federal income tax purposes. We have not requested a ruling from the U.S. Internal Revenue Service (“IRS”) on this matter.

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

Although we intend to meet this gross income requirement, we may not find it possible, regardless of our efforts, to meet this gross income requirement or may inadvertently fail to meet this gross income requirement. If we do not meet this gross income requirement for any taxable year and the IRS does not determine that such failure was inadvertent, we would be treated as a corporation for such taxable year and each taxable year thereafter. If we were treated as a corporation for federal income tax purposes, we would owe federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%, and would likely owe state income tax at varying rates. Distributions would generally be taxed again to unitholders as corporate distributions and no income, gains, losses, or deductions would flow through to unitholders. Because a tax would be imposed upon us as an entity, cash available for distribution to unitholders would be reduced. Treatment of us as a corporation would result in a reduction in the anticipated cash flow and after-tax return to unitholders and therefore would likely result in a reduction in the value of the common units.

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

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

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

At the federal level, members of Congress have considered substantive changes to the existing U.S. tax laws that would have affected certain publicly traded partnerships. Although the legislation considered would not have appeared to affect our tax treatment, we are unable to predict whether any such change or other proposals will ultimately be enacted. Moreover, any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Any such changes could negatively impact the value of an investment in our common units.

At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay a Texas margin tax at a maximum effective rate of 0.525% of our gross income apportioned to Texas in the prior year. Imposition of any such tax on us by any other state will reduce the cash available for distribution to you.

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

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

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

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

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

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

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

The rules discussed above are not applicable to us for taxable years beginning on or prior to December 31, 2017. In addition, on January 20, 2017, White House Chief of Staff Reince Priebus issued a Memorandum for the Heads of Executive Departments and Agencies (the “Regulatory Freeze Memorandum”) that prevents regulations from being sent to the Federal Register for publication until such regulations have been reviewed and approved by a department or agency head appointed or designed by the new administration. The Proposed Audit Regulations are subject to the Regulatory Freeze Memorandum and, as such, are subject to review and approval by a department or agency head appointed or designated by the new administration.

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

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

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

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

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

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

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

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

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

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

In addition to federal income taxes, unitholders may be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. Unitholders may be required to file state, local and foreign income tax returns and pay state and local income taxes in some or all of the various jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. We own property and/or conduct business in Alabama, Arizona, Arkansas, California, Florida, Georgia, Illinois, Indiana, Kansas, Louisiana, Minnesota, Mississippi, Missouri,

Nebraska, Nevada, New Mexico, Oklahoma, Pennsylvania, Tennessee, Texas, Utah, and West Virginia. We may do business or own property in other states or foreign countries in the future. It is the unitholder's responsibility to file all federal, state, local and foreign tax returns. Our counsel has not rendered an opinion on the state, local or foreign tax consequences of an investment in our common units.

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

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

The sale or exchange of 50% or more of our capital and profits interests during any 12-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one fiscal year. For purposes of determining whether the 50% threshold is met, multiple sales of the same units are counted only once. Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS announced a relief procedure whereby, if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership will be allowed to provide only a single Schedule K-1 to unitholders for the tax year in which the termination occurred.

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

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

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

and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.



Item 1B.	Unresolved Staff Comments

None.



Item 2.	Properties

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

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



Item 3.	Legal Proceedings

From time to time, we are subject to certain legal proceedings, claims and disputes that arise in the ordinary course of our business. Although we cannot predict the outcomes of these legal proceedings, we do not believe these actions, in the aggregate, will have a material adverse impact on our financial position, results of operations or liquidity. A description of our legal proceedings is included in "Item 8. Financial Statements and Supplementary Data, Note 21. Commitments and Contingencies", and is incorporated herein by reference.



Item 4.	Mine Safety Disclosures

Not applicable.

PART II



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

Market Information and Holders

Our common units are traded on the NASDAQ under the symbol "MMLP." As of January 24, 2017 there were approximately 288 holders of record and approximately 23,305 beneficial owners of our common units. The following table sets forth the high and low sale prices of our common units for the periods indicated, based on the daily composite listing of stock transactions for NASDAQ during those periods:



	Year Ended December 31, 2016				Year Ended December 31, 2015
	High		Low		High		Low
First Quarter	$	22.22	$	14.05	$	35.44	$	24.97
Second Quarter	$	23.77	$	19.40	$	38.03	$	30.95
Third Quarter	$	25.12	$	18.99	$	32.83	$	23.43
Fourth Quarter	$	21.63	$	15.80	$	29.44	$	18.62

Cash Distributions

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



Declared for Quarter Ended	Distribution Per Common Unit		Date Declared	Date Paid
December 31, 2016	$	0.5000	January 19, 2017	February 14, 2017
September 30, 2016	$	0.5000	October 20, 2016	November 14, 2016
June 30, 2016	$	0.8125	July 21, 2016	August 12, 2016
March 31, 2016	$	0.8125	April 21, 2016	May 13, 2016
December 31, 2015	$	0.8125	January 21, 2016	February 12, 2016
September 30, 2015	$	0.8125	October 22, 2015	November 13, 2015
June 30, 2015	$	0.8125	July 23, 2015	August 14, 2015
March 31, 2015	$	0.8125	April 23, 2015	May 15, 2015

Cash Distribution Policy

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

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



Item 6.	Selected Financial Data

The following table sets forth selected financial data and other operating data of the Partnership for the years ended December 31, 2016, 2015, 2014, 2013 and 2012 and is derived from the audited consolidated financial statements of the Partnership.

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



	2016		2015		2014			2013			2012
	(Dollars in thousands, except per unit amounts)

Revenues	$	827,391	$	1,036,844	$	1,642,141		$	1,612,739		$	1,490,361

Income (loss) from continuing operations	$	31,652	$	37,165	$	(6,367	)	$	(14,562	)	$	37,122
Income (loss) from discontinued operations, net of tax	—		1,215		(5,338		)	1,208			64,865
Net income (loss)	$	31,652	$	38,380	$	(11,705	)	$	(13,354	)	$	101,987
Net income (loss) attributable to limited partners	$	23,143	$	21,902	$	(15,176	)	$	(13,047	)	$	92,617

Net income (loss) per limited partner unit – continuing operations	$	0.65	$	0.60	$	(0.27	)	$	(0.54	)	$	1.32
Net income (loss) per limited partner unit – discontinued operations	—		0.02		(0.22		)	0.04			2.64
Net income (loss) per limited partner unit	$	0.65	$	0.62	$	(0.49	)	$	(0.50	)	$	3.96

Total assets	$	1,246,363	$	1,380,473	$	1,553,919		$	1,097,919		$	1,012,996
Long-term debt	$	808,107	$	865,003	$	902,005		$	658,695		$	474,992

Cash dividends per common unit (in dollars)	$	2.94	$	3.25	$	3.18		$	3.11		$	3.06



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

Overview

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


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


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


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


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

We were formed in 2002 by Martin Resource Management, a privately-held company whose initial predecessor was incorporated in 1951 as a supplier of products and services to drilling rig contractors. Since then, Martin Resource Management has expanded its operations through acquisitions and internal expansion initiatives as its management identified and capitalized on the needs of producers and purchasers of petroleum products and by-products and other bulk liquids. Martin Resource Management is an important supplier and customer of ours. As of December 31, 2016, Martin Resource Management owned 17.7% of our total outstanding common limited partner units. Furthermore, Martin Resource Management controls Martin Midstream GP LLC ("MMGP"), our general partner, by virtue of its 51% voting interest in MMGP Holdings, LLC ("Holdings"), the sole member of MMGP. MMGP owns a 2.0% general partner interest in us and all of our incentive distribution rights. Martin Resource Management directs our business operations through its ownership interests in and control of our general partner.

Recent Developments

barges in our predominantly Gulf Coast market has had a direct impact on our utilization as well as decreased transportation rates.

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

Subsequent Events

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based on the historical consolidated financial statements included elsewhere herein. We prepared these financial statements in conformity with United States generally accepted accounting principles ("U.S. GAAP" or "GAAP"). The preparation of these financial statements required us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. We based our estimates on historical experience and on various other assumptions we believe to be reasonable under the circumstances. We routinely

evaluate these estimates, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Our results may differ from these estimates, and any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Changes in these estimates could materially affect our financial position, results of operations or cash flows. You should also read Note 2, "Significant Accounting Policies" in Notes to Consolidated Financial Statements. The following table evaluates the potential impact of estimates utilized during the periods ended December 31, 2016 and 2015:



Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
Allowance for Doubtful Accounts
We evaluate our allowance for doubtful accounts on an ongoing basis and record adjustments when, in management's judgment, circumstances warrant it. Reserves are recorded to reduce receivables to the amount ultimately expected to be collected.	We evaluate the collectability of our accounts receivable based on factors such as the customer's ability to pay, the age of the receivable and our historical collection experience. A deterioration in any of these factors could result in an increase in the allowance for doubtful accounts balance.	If actual collection results are not consistent with our judgments, we may experience an increase in uncollectible receivables. A 10% increase in our allowance for doubtful accounts would result in a decrease in net income of approximately $0.4 million.
Depreciation
Depreciation expense is computed using the straight-line method over the useful life of the assets.	Determination of depreciation expense requires judgment regarding estimated useful lives and salvage values of property, plant and equipment. As circumstances warrant, estimates are reviewed to determine if any changes in the underlying assumptions are needed.	The lives of our fixed assets range from 3 - 50 years. If the depreciable lives of our assets were decreased by 10%, we estimate that annual depreciation expense would increase approximately $8.0 million, resulting in a corresponding reduction in net income.
Impairment of Long-Lived Assets
We periodically evaluate whether the carrying value of long-lived assets has been impaired when circumstances indicate the carrying value of the assets may not be recoverable. These evaluations are based on undiscounted cash flow projections over the remaining useful life of the asset. The carrying value is not recoverable if it exceeds the sum of the undiscounted cash flows. Any impairment loss is measured as the excess of the asset's carrying value over its fair value.	Our impairment analyses require management to use judgment in estimating future cash flows and useful lives, as well as assessing the probability of different outcomes.	Applying this impairment review methodology, in 2016 we recorded an impairment charge of $15.3 million in our Terminalling and Storage segment and $11.7 million in our Marine Transportation segment. In 2015 we recorded an impairment charge of $9.3 million in our Terminalling and Storage segment and $1.3 million in our Marine Transportation segment. During 2014, we recorded an impairment charge of $3.4 million in our Marine Transportation segment.
Impairment of Goodwill



Goodwill is subject to a fair-value based impairment test on an annual basis, or more frequently if events or changes in circumstances indicate that the fair value of any of our reporting units is less than its carrying amount. When assessing the recoverability of goodwill , we may first assess qualitative factors in determining whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. After assessing qualitative factors, if we determine that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then performing a quantitative assessment is not required. If an initial qualitative assessment indicates that it is more likely than not the carrying amount exceeds the fair value of a reporting unit , a quantitative analysis will be performed. We may also elect to bypass the qualitative assessment and proceed directly to a quantitative analysis depending on the facts and circumstances.	As part of the quantitative evaluation, we determine fair value using accepted valuation techniques, including discounted cash flow, the guideline public company method and the guideline transaction method. These analyses require management to make assumptions and estimates regarding industry and economic factors, future operating results and discount rates. We conduct impairment testing using present economic conditions, as well as future expectations.	During the second quarter of 2016, we determined that based on a continued decrease in the demand for utilization and transportation day rates forecasted in our Marine Transportation reporting unit, an impairment of goodwill may exist. Based on the results of our impairment analysis, we determined that a $4.1 million impairment loss of all goodwill in the Marine Transportation reporting unit was incurred during the year ended December 31, 2016. See note 2 for more information. Based on the most recent annual review as of August 31, 2016, no impairment exists with the remaining goodwill.
Purchase Price Allocations
We allocate the purchase price of an acquired business to its identifiable assets (including identifiable intangible assets) and liabilities based on their fair values at the date of acquisition. Any excess of purchase price in excess of amounts allocated to identifiable assets and liabilities is recorded as goodwill. As additional information becomes available, we may adjust the preliminary allocation for a period of up to one year.	The determination of fair values of acquired assets and liabilities requires a significant level of management judgment. Fair values are estimated using various methods as deemed appropriate. For significant transactions, third party assessments may be utilized to assist in the valuation process.	If subsequent factors indicate that estimates and assumptions used to allocate costs to acquired assets and liabilities differ from actual results, the allocation between goodwill, other intangible assets and fixed assets could significantly differ. Any such differences could impact future earnings through depreciation and amortization expense. Additionally, if estimated results supporting the valuation of goodwill or other intangible assets are not achieved, impairments could result.
Asset Retirement Obligations
Asset retirement obligations ("AROs") associated with a contractual or regulatory remediation requirement are recorded at fair value in the period in which the obligation can be reasonably estimated and depreciated over the life of the related asset or contractual term. The liability is determined using a credit-adjusted risk-free interest rate and is accreted over time until the obligation is settled.	Determining the fair value of AROs requires management judgment to evaluate required remediation activities, estimate the cost of those activities and determine the appropriate interest rate.	If actual results differ from judgments and assumptions used in valuing an ARO, we may experience significant changes in ARO balances. The establishment of an ARO has no initial impact on earnings.
Environmental Liabilities
We estimate environmental liabilities using both internal and external resources. Activities include feasibility studies and other evaluations management considers appropriate. Environmental liabilities are recorded in the period in which the obligation can be reasonably estimated.	Estimating environmental liabilities requires significant management judgment as well as possible use of third party specialists knowledgeable in such matters.	Environmental liabilities have not significantly affected our results of operations or financial condition in the past, and we do not anticipate that they will in the future.

Our Relationship with Martin Resource Management

Martin Resource Management directs our business operations through its ownership and control of our general partner and under the Omnibus Agreement. In addition to the direct expenses, under the Omnibus Agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. For the years ended December 31, 2016, 2015 and 2014, the conflicts committee of our general partner ("Conflicts Committee") approved reimbursement amounts of $13.0 million, $13.7 million and $12.5 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.

We are required to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes on our behalf or in connection with the operation of our business. Martin Resource Management also licenses certain of its trademarks and trade names to us under the Omnibus Agreement.

We are both an important supplier to and customer of Martin Resource Management. Among other things, we sell sulfuric acid and provide marine transportation and terminalling and storage services to Martin Resource Management. We purchase land transportation services and marine fuel from Martin Resource Management. All of these services and goods are purchased and sold pursuant to the terms of a number of agreements between us and Martin Resource Management.

How We Evaluate Our Operations

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

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

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

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

Non-GAAP Financial Measures

The following table reconciles the non-GAAP financial measurements used by management to our most directly comparable GAAP measures for the years ended December 31, 2016, 2015, and 2014, which represents EBITDA, Adjusted EBITDA and Distributable Cash Flow from continuing operations.

Reconciliation of EBITDA, Adjusted EBITDA, and Distributable Cash Flow



	Year Ended December 31,
	2016			2015			2014

Net income (loss)	$	31,652		$	38,380		$	(11,705	)
Less: (Income) loss from discontinued operations, net of income taxes	—			(1,215		)	5,338
Income (loss) from continuing operations	31,652			37,165			(6,367		)
Adjustments:
Interest expense	46,100			43,292			42,203
Income tax expense	726			1,048			1,137
Depreciation and amortization	92,132			92,250			68,830
EBITDA	170,610			173,755			105,803
Adjustments:
Equity in earnings of unconsolidated entities	(4,714		)	(8,986		)	(5,466		)
(Gain) loss on sale of property, plant and equipment	(33,400		)	2,149			1,353
Gain on retirement of senior unsecured notes	—			(1,242		)	—
Impairment of long lived assets	26,953			10,629			3,445
Impairment of goodwill	4,145			—			—
Unrealized mark to market on commodity derivatives	4,579			(675		)	818
Reduction in fair value of investment in Cardinal due to purchase of the controlling interest	—			—			30,102
Debt prepayment premium	—			—			7,767
Distributions from unconsolidated entities	7,500			11,200			4,323
Unit-based compensation	904			1,429			817
Adjusted EBITDA	176,577			188,259			148,962
Adjustments:
Interest expense	(46,100		)	(43,292		)	(42,203		)
Income tax expense	(726		)	(1,048		)	(1,137		)
Amortization of deferred debt issuance costs	3,684			4,859			6,263
Amortization of debt discount	—			—			1,305
Amortization of debt premium	(306		)	(324		)	(245		)
Non-cash mark to market on interest rate derivatives	(206		)	206			—
Payments for plant turnaround costs	(2,061		)	(1,908		)	(3,974		)
Maintenance capital expenditures	(17,163		)	(12,902		)	(14,556		)
Distributable Cash Flow	$	113,699		$	133,850		$	94,415

Results of Operations

The results of operations for the years ended December 31, 2016, 2015, and 2014 have been derived from our consolidated financial statements.

We evaluate segment performance on the basis of operating income, which is derived by subtracting cost of products sold, operating expenses, selling, general and administrative expenses, and depreciation and amortization expense from revenues. The following table sets forth our operating revenues and operating income by segment for the years ended December 31, 2016, 2015, and 2014.

Our consolidated results of operations are presented on a comparative basis below. There are certain items of income and expense which we do not allocate on a segment basis. These items, including equity in earnings (loss) of unconsolidated

entities, interest expense, and indirect selling, general and administrative expenses, are discussed after the comparative discussion of our results within each segment.

The Natural Gas Services segment information below excludes the discontinued operations of the Floating Storage Assets disposed of on February 12, 2015 for the years ended December 31, 2015 and 2014. See Item 8, Note 5.



	Operating Revenues		Revenues Intersegment Eliminations			Operating Revenues after Eliminations		Operating Income (loss)			Operating Income Intersegment Eliminations			Operating Income (loss) after Eliminations
	(In thousands)
Year Ended December 31, 2016:
Terminalling and storage	$	242,363	$	(5,653	)	$	236,710	$	44,143		$	(3,483	)	$	40,660
Natural gas services	391,333		—			391,333		38,382			3,056			41,438
Sulfur services	141,058		—			141,058		26,815			(3,422		)	23,393
Marine transportation	61,233		(2,943		)	58,290		(19,888		)	3,849			(16,039		)
Indirect selling, general and administrative	—		—			—		(16,794		)	—			(16,794		)
Total	$	835,987	$	(8,596	)	$	827,391	$	72,658		$	—		$	72,658

Year Ended December 31, 2015:
Terminalling and storage	$	270,440	$	(5,670	)	$	264,770	$	18,750		$	(3,046	)	$	15,704
Natural gas services	523,160		—			523,160		38,611			2,609			41,220
Sulfur services	170,161		—			170,161		27,113			(3,509		)	23,604
Marine transportation	81,784		(3,031		)	78,753		4,630			3,946			8,576
Indirect selling, general and administrative	—		—			—		(18,951		)	—			(18,951		)
Total	$	1,045,545	$	(8,701	)	$	1,036,844	$	70,153		$	—		$	70,153

Year Ended December 31, 2014:
Terminalling and storage	$	326,654	$	(5,191	)	$	321,463	$	27,007		$	(2,014	)	$	24,993
Natural gas services	1,013,835		—			1,013,835		30,610			3,964			34,574
Sulfur services	215,471		—			215,471		25,656			(6,191		)	19,465
Marine transportation	97,049		(5,677		)	91,372		3,310			4,241			7,551
Indirect selling, general and administrative	—		—			—		(18,712		)	—			(18,712		)
Total	$	1,653,009	$	(10,868	)	$	1,642,141	$	67,871		$	—		$	67,871

Terminalling and Storage Segment

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



	Year Ended December 31,					Variance			Percent Change
	2016		2015			Variance			Percent Change
	(In thousands)
Revenues:
Services	$	128,783	$	138,614		$	(9,831	)	(7)%
Products	113,580		131,826			(18,246		)	(14)%
Total revenues	242,363		270,440			(28,077		)	(10)%

Cost of products sold	96,344		115,460			(19,116		)	(17)%
Operating expenses	71,831		83,917			(12,086		)	(14)%
Selling, general and administrative expenses	4,677		3,804			873			23%
Impairment of long-lived assets	15,252		9,305			5,947			64%
Depreciation and amortization	45,484		38,731			6,753			17%
	8,775		19,223			(10,448		)	(54)%
Other operating income (loss), net	35,368		(473		)	35,841			(7,577)%
Operating income	$	44,143	$	18,750		$	25,393		135%

Lubricant sales volumes (gallons)	17,995		23,045			(5,050		)	(22)%
Shore-based throughput volumes (gallons)	103,903		157,074			(53,171		)	(34)%
Smackover refinery throughput volumes (barrels per day)	5,641		6,162			(521		)	(8)%
Corpus Christi crude terminal throughput volumes (barrels per day)	66,167		154,381			(88,214		)	(57)%

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

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

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

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

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

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

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

Comparative Results of Operations for the Twelve Months Ended December 31, 2015 and 2014



	Year Ended December 31,					Variance			Percent Change
	2015			2014		Variance			Percent Change
	(In thousands)
Revenues:
Services	$	138,614		$	135,697	$	2,917		2%
Products	131,826			190,957		(59,131		)	(31)%
Total revenues	270,440			326,654		(56,214		)	(17)%

Cost of products sold	115,460			175,246		(59,786		)	(34)%
Operating expenses	83,917			83,504		413			—%
Selling, general and administrative expenses	3,804			3,565		239			7%
Impairment of long-lived assets	9,305			—		9,305
Depreciation and amortization	38,731			37,622		1,109			3%
	19,223			26,717		(7,494		)	(28)%
Other operating income (loss), net	(473		)	290		(763		)	(263)%
Operating income	$	18,750		$	27,007	$	(8,257	)	(31)%

Lubricant sales volumes (gallons)	23,045			32,418		(9,373		)	(29)%
Shore-based throughput volumes (gallons)	157,074			253,262		(96,188		)	(38)%
Smackover refinery throughput volumes (barrels per day)	6,162			6,159		3			—%
Corpus Christi crude terminal (barrels per day)	154,381			164,223		(9,842		)	(6)%

Services revenues. Services revenue increased $2.9 million attributable to increased throughput rates at our Smackover Refinery. In addition, $1.5 million of the increase is due to revenues generated by our shore-based terminals primarily related to increased consigned lube revenue and increased throughput rates. Service revenues at our specialty terminals decreased $0.9 million overall resulting from increased revenues at several of our terminals offset by decreased throughput fees of $2.6 million at our crude terminal in Corpus Christi, Texas.

Products revenues. A 43% decrease in sales volumes at our blending and packaging facilities resulted in a $53.6 million decrease to products revenues. Product sales volumes from our shore-based terminals increased 1%, resulting in a $0.6 million increase in products revenues. The average sales price at our blending and packaging facilities increased 1%, resulting in a $0.8 million increase in product revenues. The average sales price at our shore-based terminals decreased 10%, resulting in a $6.9 million decrease to product revenues.

Cost of products sold. A 43% decrease in sales volumes at our blending and packaging facilities resulted in a $44.4 million reduction in cost of products sold. Product sales volumes from our shore-based terminals increased 1%, resulting in a

$0.5 million increase in cost of products sold. The average cost per gallon at our blending and packaging facilities decreased 8% resulting in a reduction of $9.2 million in cost of products sold. The average cost per gallon at our shore-based terminals decreased 11%, resulting in a reduction of $6.7 million in cost of products sold.

Operating expenses. Increased expenses at our specialty terminals accounted for $2.0 million of the total increase, primarily attributable to the Corpus Christi crude terminal. This is offset by a $1.6 million reduction of expenses at our Smackover Refinery primarily attributable to decreased natural gas expense.

Selling, general and administrative expenses. The increase in selling, general and administrative expenses is primarily attributable to increased compensation expense.

Impairment of long-lived assets. Impairment of long-lived assets represents the write-off of certain organic growth project costs during 2015.

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

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

Natural Gas Services Segment

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



	Year Ended December 31,						Variance			Percent Change
	2016			2015			Variance			Percent Change
	(In thousands)
Revenues:
Services	$	61,133		$	64,858		$	(3,725	)	(6)%
Products	330,200			458,302			(128,102		)	(28)%
Total revenues	391,333			523,160			(131,827		)	(25)%

Cost of products sold	292,573			416,404			(123,831		)	(30)%
Operating expenses	23,152			23,979			(827		)	(3)%
Selling, general and administrative expenses	9,035			9,791			(756		)	(8)%
Depreciation and amortization	28,081			34,072			(5,991		)	(18)%
	38,492			38,914			(422		)	(1)%
Other operating loss, net	(110		)	(303		)	193			(64)%
Operating income	$	38,382		$	38,611		$	(229	)	(1)%

Distributions from unconsolidated entities	$	7,500		$	11,200		$	(3,700	)	(33)%

NGLs Volumes (barrels)	9,532			14,340			(4,808		)	(34)%

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

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

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

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

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

Depreciation and amortization. Depreciation and amortization decreased primarily due to a $6.8 million decrease in amortization related to contracts acquired during the purchase of Cardinal Gas Storage, 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.

Comparative Results of Operations for the Twelve Months Ended December 31, 2015 and 2014



	Year Ended December 31,					Variance			Percent Change
	2015			2014		Variance			Percent Change
	(In thousands)
Revenues:
Services	$	64,858		$	22,991	$	41,867		182%
Products	458,302			990,844		(532,542		)	(54)%
Total revenues	523,160			1,013,835		(490,675		)	(48)%

Cost of products sold	416,404			950,742		(534,338		)	(56)%
Operating expenses	23,979			10,797		13,182			122%
Selling, general and administrative expenses	9,791			8,596		1,195			14%
Depreciation and amortization	34,072			13,090		20,982			160%
	38,914			30,610		8,304			27%
Other operating loss, net	(303		)	—		(303		)
Operating income	$	38,611		$	30,610	$	8,001		26%

Distributions from unconsolidated entities	$	11,200		$	4,323	$	6,877		159%

NGLs Volumes (barrels)	14,340			16,448		(2,108		)	(13)%

Services Revenues. The increase in services revenue is a result of the 2015 period including a full year of natural gas storage revenue related to the acquisition of Cardinal Gas Storage Partners LLC ("Cardinal"), which occurred August 29, 2014.

Products Revenues. Our NGL average sales price per barrel decreased $28.28, or 47%, resulting in a decrease to products revenues of $465.2 million. The decrease in average sales price per barrel was a result of a decline in market prices. Product sales volumes decreased 13%, decreasing revenues $67.4 million.

Cost of products sold. Our average cost per barrel decreased $28.77, or 50%, decreasing cost of products sold by $473.1 million. The decrease in average cost per barrel was a result of a decline in market prices. The decrease in sales volume of 13%, resulted in a $61.2 million decrease to cost of products sold. Our margins increased $0.48 per barrel, or 20% during the period.

Operating expenses. Operating expenses increased $13.2 million, $11.0 million of which is related to the acquisition of Cardinal, $1.1 million is a result of the acquisition of NGL storage assets from Martin Resource Management in May 2014, $0.6 million is a result of expenses associated with the hydrostatic test of our 200 mile NGL Pipeline, and $0.5 million is related to the rail operations at our Arcadia facility which was placed into service in June 2015.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $1.4 million as a result of the acquisition of Cardinal. Offsetting this increase was a decrease to property taxes of $0.2 million.

Depreciation and amortization. Depreciation and amortization increased $20.2 million due to the acquisition of Cardinal and $0.9 million is related to increased capital expenditure activity.

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

Sulfur Services Segment

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



	Year Ended December 31,						Variance			Percent Change
	2016			2015			Variance			Percent Change
	(In thousands)
Revenues:
Services	$	10,800		$	12,270		$	(1,470	)	(12)%
Products	130,258			157,891			(27,633		)	(18)%
Total revenues	141,058			170,161			(29,103		)	(17)%

Cost of products sold	88,325			115,133			(26,808		)	(23)%
Operating expenses	13,771			15,279			(1,508		)	(10)%
Selling, general and administrative expenses	3,861			3,805			56			1%
Depreciation and amortization	7,995			8,455			(460		)	(5)%
	27,106			27,489			(383		)	(1)%
Other operating loss, net	(291		)	(376		)	85			(23)%
Operating income	$	26,815		$	27,113		$	(298	)	(1)%

Sulfur (long tons)	797.0			856.0			(59.0		)	(7)%
Fertilizer (long tons)	262.0			274.0			(12.0		)	(4)%
Sulfur services volumes (long tons)	1,059.0			1,130.0			(71.0		)	(6)%

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

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

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

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

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

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

Comparative Results of Operations for the Twelve Months Ended December 31, 2015 and 2014



	Year Ended December 31,					Variance			Percent Change
	2015			2014		Variance			Percent Change
	(In thousands)
Revenues:
Services	$	12,270		$	12,149	$	121		1%
Products	157,891			203,322		(45,431		)	(22)%
Total revenues	170,161			215,471		(45,310		)	(21)%

Cost of products sold	115,133			160,144		(45,011		)	(28)%
Operating expenses	15,279			17,136		(1,857		)	(11)%
Selling, general and administrative expenses	3,805			4,359		(554		)	(13)%
Depreciation and amortization	8,455			8,176		279			3%
	27,489			25,656		1,833			7%
Other operating loss, net	(376		)	—		(376		)
Operating income	$	27,113		$	25,656	$	1,457		6%

Sulfur (long tons)	856.0			848.0		8.0			1%
Fertilizer (long tons)	274.0			306.0		(32.0		)	(10)%
Sulfur services volumes (long tons)	1,130.0			1,154.0		(24.0		)	(2)%

Revenues. Products revenues decreased $42.1 million as a result of a 21% decrease in sales prices for both sulfur and fertilizer products. Further, products revenues decreased an additional $3.3 million due to a 2% decrease in sales volumes, primarily related to decreased fertilizer volumes.

Cost of products sold. A 27% decrease in prices reduced our cost by $42.6 million. A 2% decrease in sales volumes decreased cost of products sold by $2.4 million. Margin per ton remained consistent.

Operating expenses. Our operating expenses decreased due to a reduction in repairs and maintenance on marine vessels of $1.3 million and a decrease in fuel expense of $0.6 million.

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

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

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

Marine Transportation Segment

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



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

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

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

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

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

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

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

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

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

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

Comparative Results of Operations for the Twelve Months Ended December 31, 2015 and 2014



	Year Ended December 31,						Variance			Percent Change
	2015			2014			Variance			Percent Change
	(In thousands)
Revenues	$	81,784		$	97,049		$	(15,265	)	(16)%
Operating expenses	63,412			77,964			(14,552		)	(19)%
Selling, general and administrative expenses	417			1,084			(667		)	(62)%
Impairment of long lived assets	1,324			3,445			(2,121		)	(62)%
Depreciation and amortization	10,992			9,942			1,050			11%
	5,639			4,614			1,025			22%
Other operating loss, net	(1,009		)	(1,304		)	295			(23)%
Operating income	$	4,630		$	3,310		$	1,320		40%

Inland Revenues. A $6.4 million decrease in inland revenues is primarily attributable to decreased utilization of the inland fleet. Additionally, $4.9 million related to a decrease in pass-through revenues.

Offshore Revenues. Revenue from offshore operations decreased $1.9 million due to a decrease in utilization of the offshore fleet. Additionally, $1.2 million related to a decrease in pass-through revenues.

Operating expenses. Operating expenses decreased $6.4 million due to decreased pass-through expenses, primarily fuel. Additionally, there were decreases in repairs and maintenance of $4.5 million, compensation expense of $1.5 million, insurance premiums of $0.5 million, operating supplies of $0.4 million, property taxes of $0.5 million, and Jones Act claims of $0.4 million.

Selling, general and administrative expenses. Selling, general and administrative expenses decreased as a result of a decrease in a legal contingency reserve established during the purchase of Talen's Marine & Fuel, LLC of $1.4 million, offset by an increase in the reserve for an uncollectible customer receivable of $0.9 million.

Impairment of long-lived assets. Impairment of long-lived assets for the 2015 period represents the write-down of four assets as a result of the inability to generate cash flows in recent quarters and going forward. Impairment of long-lived assets for the 2014 period represents the write-down of one offshore tow which was the result of the decision to remove that asset from service and ultimately dispose of it.

Depreciation and amortization. Depreciation and amortization decreased as a result of the disposal of equipment, offset by increases in depreciable assets related to recent capital expenditures.

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

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



	Year Ended December 31,				Variance		Percent Change
	2016		2015		Variance		Percent Change
	(In thousands)
Equity in earnings of WTLPG	$	4,715	$	8,986	(4,271	)	(48)%



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

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

Equity in Earnings of and Distributions from Unconsolidated Entities for the Twelve Months Ended December 31, 2015 and 2014



	Year Ended December 31,				Variance			Percent Change
	2015		2014		Variance			Percent Change
	(In thousands)
Equity in earnings of WTLPG	$	8,986	$	3,076	$	5,910		192%
Equity in earnings of Cardinal	—		892		(892		)	(100)%
Equity in earnings of MET	—		1,498		(1,498		)	(100)%
Equity in earnings of unconsolidated entities	$	8,986	$	5,466	$	3,520		64%



	Year Ended December 31,				Variance			Percent Change
	2015		2014		Variance			Percent Change
	(In thousands)
Distributions from WTLPG	$	11,200	$	2,600	$	8,600		331%
Distributions from Cardinal	—		225		(225		)	(100)%
Distributions from MET	—		1,498		(1,498		)	(100)%
Distributions from unconsolidated entities	$	11,200	$	4,323	$	6,877		159%

The investment in WTLPG was made in May 2014. Equity in earnings from WTLPG increased primarily due to 2015 representing a full year invested in the asset.

On August 29, 2014, the Partnership acquired the remaining 57.8% Category A interest in Cardinal it did not previously own and began consolidating Cardinal's results.

Equity in earnings of Martin Energy Trading LLC ("MET") represents dividends on our 100% investment in its preferred interests. The MET investment was acquired in March 2013. In August 2014, MET converted its preferred equity to subordinated debt, resulting in a Partnership note receivable from MET. Subsequent to this conversion, we recorded interest on the note receivable in "Interest expense, net" in the Consolidated Statements of Operations.

Interest Expense

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



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

Comparative Components of Interest Expense, Net for the Twelve Months Ended December 31, 2015 and 2014



	Year Ended December 31,						Variance			Percent Change
	2015			2014			Variance			Percent Change
	(In thousands)
Revolving loan facility	$	16,270		$	12,684		$	3,586		28%
8.875 % senior unsecured notes	—			3,882			(3,882		)	(100)%
7.250 % senior unsecured notes	28,583			26,252			2,331			9%
Amortization of deferred debt issuance costs	4,859			6,263			(1,404		)	(22)%
Amortization of debt discount and premium	(324		)	1,059			(1,383		)	(131)%
Cash settlements on interest rate swaps	(2,289		)	(6,692		)	4,403			(66)%
Other	387			944			(557		)	(59)%
Capitalized interest	(1,944		)	(1,437		)	(507		)	35%
Interest income	(2,250		)	(752		)	$	(1,498	)	199%
Total interest expense, net	$	43,292		$	42,203		$	1,089		3%

Indirect Selling, General and Administrative Expenses



	Year Ended December 31,				Variance			Percent Change	Year Ended December 31,				Variance		Percent Change
	2016		2015		Variance			Percent Change	2015		2014		Variance		Percent Change
	(In thousands)								(In thousands)
Indirect selling, general and administrative expenses	$	16,795	$	18,951	$	(2,156	)	(11)%	$	18,951	$	18,712	$	239	1%

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

Indirect selling, general and administrative expenses remained consistent from 2014 to 2015.

Martin Resource Management allocates to us a portion of its indirect selling, general and administrative expenses for services such as accounting, treasury, clerical, engineering, legal, billing, information technology, administration of insurance, general office expenses and employee benefit plans and other general corporate overhead functions we share with Martin

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

Under the Omnibus Agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. The Conflicts Committee approved the following reimbursement amounts:



	Year Ended December 31,				Variance			Percent Change	Year Ended December 31,				Variance		Percent Change
	2016		2015		Variance			Percent Change	2015		2014		Variance		Percent Change
	(In thousands)								(In thousands)
Conflicts Committee approved reimbursement amount	$	13,033	$	13,679	$	(646	)	(5)%	$	13,679	$	12,535	$	1,144	9%

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

Liquidity and Capital Resources

General

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

Our ability to satisfy our working capital requirements, to fund planned capital expenditures and to satisfy our debt service obligations will also depend upon our future operating performance, which is subject to certain risks. Please read "Item 1A. Risk Factors - Risks related to Our Business" for a discussion of such risks.

Recent Debt Financing Activity

Due to the foregoing, we believe that cash generated from operations and our borrowing capacity under our credit facility will be sufficient to meet our working capital requirements and anticipated maintenance capital expenditures in 2017.

Finally, our ability to satisfy our working capital requirements, to fund planned capital expenditures and to satisfy our debt service obligations will depend upon our future operating performance, which is subject to certain risks. Please read "Item 1A. Risk Factors - Risks Relating to Our Business" for a discussion of such risks.

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

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



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

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

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

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

Cash Flows - Twelve Months Ended December 31, 2015 Compared to Twelve Months Ended December 31, 2014

The following table details the cash flow changes between the twelve months ended December 31, 2015 and 2014:



	Years Ended December 31,						Variance			Percent Change
	2015			2014			Variance			Percent Change
	(In thousands)
Net cash provided by (used in):
Operating activities	$	182,572		$	115,580		$	66,992		58%
Investing activities	(23,805		)	(324,663		)	300,858			93%
Financing activities	(158,778		)	192,583			(351,361		)	182%
Net decrease in cash and cash equivalents	$	(11	)	$	(16,500	)	$	16,489		(100)%

Net cash provided by operating activities. The change in net cash provided by operating activities includes an increase in operating results from continuing operations of $43.5 million, distributions from WTLPG of $8.6 million, and a $21.7 million favorable variance in working capital. Offsetting the increase in cash flows provided by operating activities was a decrease in other non-cash charges of $6.9 million. Changes in working capital are primarily affected by the timing of payments of trade and other accounts payable as well as the collections of trade and other accounts receivable. In addition, cash used in discontinued operations increased $2.1 million in 2015.

Net cash used in investing activities. Acquisition expenditures decreased $102.7 million. Investments in unconsolidated entities and capital expenditures decreased $134.0 million and $18.5 million in 2015, respectively. Net cash provided by discontinued investing activities of $41.3 million in 2015 is attributable to the sale of the six pressure barges which occurred in February 2015. There was no cash provided by or used in discontinued investing activities in 2014.

Net cash (used in) provided by financing activities. Net cash (used in) provided by financing activities decreased for the year ended December 31, 2015 as a result of: (i) a decrease of $339.3 million in equity offering proceeds, including $7.0 million from the general partner; (ii) a $13.0 million increase in net proceeds from long-term debt (borrowings less repayments); (iii) a $35.9 million increase in cash distributions; (iv) a $3.4 million reduction in the payment of debt issuance costs; and (v) an increase of $7.2 million related to excess purchase price over the carrying value of acquired assets in common control transactions.

Capital Expenditures

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

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

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

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

The following table summarizes maintenance and expansion capital expenditures, excluding amounts paid for acquisitions, for the periods presented:



	Three Months Ended December 31,				Years Ended December 31,
	2016		2015		2016		2015
	(In thousands)				(In thousands)
Expansion capital expenditures	$	4,977	$	17,026	$	19,107	$	53,917
Maintenance capital expenditures	4,345		5,281		17,163		12,902
Plant turnaround costs	447		154		2,061		1,908
Total	$	9,769	$	22,461	$	38,331	$	68,727

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

Expansion capital expenditures were made primarily in our Terminalling and Storage and Natural Gas Services segments during the three and twelve months ended December 31, 2015. Within our Terminalling and Storage segment, expenditures were made primarily at our Smackover refinery, and on certain organic growth projects ongoing in our specialty terminalling operations. Within our Natural Gas Services segment, expenditures were made primarily on certain organic growth projects ongoing in our Natural Gas Services operations. Maintenance capital expenditures were made primarily in our Terminalling and Storage, Marine Transportation, and Natural Gas Services segments to maintain our existing assets and operations during the three and twelve months ended December 31, 2015.

Capital Resources

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

Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of December 31, 2016, is as follows (dollars in thousands):



	Payments due by period
Type of Obligation	Total Obligation		Less than One Year		1-3 Years		3-5 Years		Due Thereafter
Revolving credit facility	$	443,000	$	—	$	—	$	443,000	$	—
2021 senior unsecured notes	373,800		—		—		373,800		—
Throughput commitment	28,008		6,153		12,790		9,065		—
Operating leases	33,006		10,458		9,669		4,430		8,449
Interest payable on fixed long-term obligations	111,790		27,101		54,201		30,488		—
Total contractual cash obligations	$	989,604	$	43,712	$	76,660	$	860,783	$	8,449

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

Letter of Credit. At December 31, 2016, we had outstanding irrevocable letters of credit in the amount of $1.4 million, which were issued under our revolving credit facility.

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

Description of Our Long-Term Debt

2021 Senior Notes

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

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

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

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

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

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

Revolving Credit Facility

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

As of December 31, 2016, we had $443.0 million outstanding under the revolving credit facility and $1.4 million of letters of credit issued, leaving a maximum available to be borrowed under our credit facility for future revolving credit borrowings and letters of credit of $220.1 million. Subject to the financial covenants contained in our credit facility and based on our existing EBITDA (as defined in our credit facility) calculations, as of December 31, 2016, we have the ability to borrow approximately $55.5 million of that amount. We were in compliance with all financial covenants at December 31, 2016.

The revolving credit facility is used for ongoing working capital needs and general partnership purposes, and to finance permitted investments, acquisitions and capital expenditures. During the year ended December 31, 2016, the level of outstanding draws on our credit facility has ranged from a low of $443.0 million to a high of $586.0 million.

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

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

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

debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) and are as follows as of December 31, 2016:



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

At December 31, 2016, the applicable margin for revolving loans that are LIBOR loans ranges from 2.00% to 3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 1.00% to 2.00%. The applicable margin for LIBOR borrowings at December 31, 2016 is 3.00%.

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

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

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

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

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

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

The Partnership is in compliance with all debt covenants as of December 31, 2016 and expects to be in compliance for the next twelve months.

Seasonality

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

Impact of Inflation

Inflation did not have a material impact on our results of operations in 2016, 2015 or 2014. Although the impact of inflation has been insignificant in recent years, it is still a factor in the U.S. economy and may increase the cost to acquire or replace property, plant and equipment. It may also increase the costs of labor and supplies. In the future, increasing energy prices could adversely affect our results of operations. Diesel fuel, natural gas, chemicals and other supplies are recorded in operating expenses. An increase in price of these products would increase our operating expenses which could adversely affect net income. We cannot provide assurance that we will be able to pass along increased operating expenses to our customers.

Environmental Matters

Our operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. We incurred no material environmental costs, liabilities or expenditures to mitigate or eliminate environmental contamination during 2016, 2015 or 2014.



Item 7A.	Quantitative and Qualitative Disclosures about Market Risk

Commodity Risk. The Partnership from time to time uses derivatives to manage the risk of commodity price fluctuation. Commodity risk is the adverse effect on the value of a liability or future purchase that results from a change in commodity price. We have established a hedging policy and monitor and manage the commodity market risk associated with potential commodity risk exposure. In addition, we focus on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction.

We have entered into hedging transactions as of December 31, 2016 to protect a portion of our commodity price risk exposure. These hedging arrangements are in the form of swaps for NGLs. We have instruments totaling a net notional quantity of 731,000 barrels settling during the period from January 31, 2017 through June 30, 2017. These instruments settle against the applicable pricing source for each grade and location. These instruments are recorded on our Consolidated and Condensed Balance Sheets at December 31, 2016 in "Fair value of derivatives" as a current liability of $3.9 million. Based on the current net notional volume hedged as of December 31, 2016, a $0.10 change in the expected settlement price of these contracts would result in an impact of $3.1 million to the Partnership's net income.

Interest Rate Risk. We are exposed to changes in interest rates as a result of our credit facility, which had a weighted-average interest rate of 3.76% as of December 31, 2016. Based on the amount of unhedged floating rate debt owed by us on December 31, 2016, the impact of a 100 basis point increase in interest rates on this amount of debt would result in an increase in interest expense and a corresponding decrease in net income of approximately $4.4 million annually.

We are not exposed to changes in interest rates with respect to our senior unsecured notes as these obligations are fixed rate. The estimated fair value of the senior unsecured notes was approximately $377.9 million as of December 31, 2016, based on market prices of similar debt at December 31, 2016. Market risk is estimated as the potential decrease in fair value of our long-term debt resulting from a hypothetical increase of a 100 basis point increase in interest rates. Such an increase in interest rates would result in approximately a $11.7 million decrease in fair value of our long-term debt at December 31, 2016.



Item 8.	Financial Statements and Supplementary Data

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



	Page
Reports of Independent Registered Public Accounting Firm	68
Consolidated Balance Sheets as of December 31, 2016 and 2015	70
Consolidated Statements of Operations for the years ended December 31, 2016, 2015 and 2014	71
Consolidated Statements of Changes in Capital for the years ended December 31, 2016, 2015 and 2014	74
Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015 and 2014	75
Notes to Consolidated Financial Statements	76

Report of Independent Registered Public Accounting Firm

The Board of Directors

Martin Midstream GP LLC:

We have audited the accompanying consolidated balance sheets of Martin Midstream Partners L.P. and subsidiaries as of December 31, 2016 and 2015, 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, 2016. These consolidated financial statements are the responsibility of Martin Midstream’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Martin Midstream Partners L.P. and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for the each of the years in the three-year period ended December 31, 2016 in conformity with U.S. generally accepted accounting principles.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Martin Midstream Partners L.P. and subsidiaries’ internal control over financial reporting as of December 31, 2016, based on criteria establish in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 15, 2017 expressed an unqualified opinion on the effectiveness of Martin Midstream Partners L.P. and subsidiaries’ internal control over financial reporting.

/s/ KPMG LLP

Dallas, Texas

February 15, 2017

Report of Independent Registered Public Accounting Firm

The Board of Directors

Martin Midstream GP LLC:

We have audited Martin Midstream Partners L.P. and subsidiaries’ internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Martin Midstream’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting in Item 9A(b). Our responsibility is to express an opinion on Martin Midstream’s internal control over financial reporting based on our audit.

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

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

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

In our opinion, Martin Midstream Partners L.P. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Martin Midstream Partners L.P. and subsidiaries as of December 31, 2016 and 2015, 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, 2016, and our report dated February 15, 2017 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Dallas, Texas

February 15, 2017

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)



	December 31,
	2016			2015
Assets
Cash	$	15		$	31
Trade and accrued accounts receivable, less allowance for doubtful accounts of $372 and $430 respectively	80,508			74,355
Product exchange receivables	207			1,050
Inventories	82,631			75,870
Due from affiliates	11,567			10,126
Fair value of derivatives	—			675
Other current assets	3,296			5,718
Assets held for sale	15,779			—
Total current assets	194,003			167,825

Property, plant and equipment, at cost	1,224,277			1,387,814
Accumulated depreciation	(378,593		)	(404,574		)
Property, plant and equipment, net	845,684			983,240

Goodwill	17,296			23,802
Investment in unconsolidated entities	129,506			132,292
Notes receivable - Martin Energy Trading LLC	15,000			15,000
Intangibles and other assets, net	44,874			58,314
	$	1,246,363		$	1,380,473
Liabilities and Partners’ Capital
Trade and other accounts payable	$	70,249		$	81,180
Product exchange payables	7,360			12,732
Due to affiliates	8,474			5,738
Income taxes payable	870			985
Fair value of derivatives	3,904			—
Other accrued liabilities	26,717			18,533
Total current liabilities	117,574			119,168

Long-term debt, net	808,107			865,003
Fair value of derivatives	—			206
Other long-term obligations	8,676			2,217
Total liabilities	934,357			986,594
Commitments and contingencies
Partners’ capital	312,006			393,879
	$	1,246,363		$	1,380,473

See accompanying notes to consolidated financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands, except per unit amounts)



	Year Ended December 31,
	2016			2015			2014
Revenues:
Terminalling and storage *	$	123,132		$	132,945		$	130,506
Marine transportation *	58,290			78,753			91,372
Natural gas storage services *	61,133			64,858			22,991
Sulfur services	10,800			12,270			12,149
Product sales: *
Natural gas services	330,200			458,302			990,844
Sulfur services	130,258			157,891			203,322
Terminalling and storage	113,578			131,825			190,957
	574,036			748,018			1,385,123
Total revenues	827,391			1,036,844			1,642,141

Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas services *	289,516			413,795			948,765
Sulfur services *	87,963			114,766			159,782
Terminalling and storage *	94,175			112,836			172,069
	471,654			641,397			1,280,616
Expenses:
Operating expenses *	158,864			183,466			184,049
Selling, general and administrative *	34,385			36,788			36,316
Impairment of long-lived assets	26,953			10,629			3,445
Impairment of goodwill	4,145			—			—
Depreciation and amortization	92,132			92,250			68,830
Total costs and expenses	788,133			964,530			1,573,256
Other operating income (loss), net	33,400			(2,161		)	(1,014		)
Operating income	72,658			70,153			67,871

Other income (expense):
Equity in earnings of unconsolidated entities	4,714			8,986			5,466
Debt prepayment premium	—			—			(7,767		)
Interest expense, net	(46,100		)	(43,292		)	(42,203		)
Gain on retirement of senior unsecured notes	—			1,242			—
Reduction in fair value of investment in Cardinal due to the purchase of the controlling interest	—			—			(30,102		)
Other, net	1,106			1,124			1,505
Total other income (expense)	(40,280		)	(31,940		)	(73,101		)
Net income (loss) before taxes	32,378			38,213			(5,230		)
Income tax expense	(726		)	(1,048		)	(1,137		)
Income (loss) from continuing operations	31,652			37,165			(6,367		)
Income (loss) from discontinued operations, net of income taxes	—			1,215			(5,338		)
Net income (loss)	31,652			38,380			(11,705		)
Less general partner's interest in net (income) loss	(8,419		)	(16,338		)	(3,503		)
Less (income) loss allocable to unvested restricted units	(90		)	(140		)	32
Limited partner's interest in net income (loss)	$	23,143		$	21,902		$	(15,176	)

*Related Party Transactions Shown Below

See accompanying notes to consolidated financial statements.

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

See accompanying notes to consolidated financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands, except per unit amounts)



	Year Ended December 31,
	2016		2015		2014
Allocation of net income (loss) attributable to:
Limited partner interest:
Continuing operations	$	23,143	$	21,208	$	(8,255	)
Discontinued operations	—		694		(6,921		)
	$	23,143	$	21,902	$	(15,176	)
General partner interest:
Continuing operations	$	8,419	$	15,821	$	1,906
Discontinued operations	—		517		1,597
	$	8,419	$	16,338	$	3,503

Net income (loss) per unit attributable to limited partners:
Basic:
Continuing operations	$	0.65	$	0.60	$	(0.27	)
Discontinued operations	—		0.02		(0.22		)
	$	0.65	$	0.62	$	(0.49	)

Weighted average limited partner units - basic	35,347		35,309		30,785

Diluted:
Continuing operations	$	0.65	$	0.60	$	(0.27	)
Discontinued operations	—		0.02		(0.22		)
	$	0.65	$	0.62	$	(0.49	)

Weighted average limited partner units - diluted	35,375		35,372		30,785

See accompanying notes to consolidated financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CHANGES IN CAPITAL

(Dollars in thousands)



	Partners’ Capital
	Common					General Partner
	Units		Amount			Amount			Total
Balances – December 31, 2013	26,625,026		$	254,028		$	6,389		$	260,417

Net loss	—		(15,208		)	3,503			(11,705		)
Issuance of common units, net	8,743,386		331,728			—			331,728
Issuance of restricted units	8,900		—			—			—
Forfeiture of restricted units	(5,000	)	—			—			—
General partner contribution	—		—			7,007			7,007
Cash distributions	—		(95,197		)	(2,171		)	(97,368		)
Excess purchase price over carrying value of acquired assets	—		(4,948		)	—			(4,948		)
Unit-based compensation	—		817			—			817
Purchase of treasury units	(6,400	)	(277		)	—			(277		)
Balances – December 31, 2014	35,365,912		470,943			14,728			485,671

Net income	—		22,042			16,338			38,380
Issuance of common units, net	—		(590		)	—			(590		)
Issuance of restricted units	91,950		—			—			—
Forfeiture of restricted units	(1,250	)	—			—			—
General partner contribution	—		—			55			55
Cash distributions	—		(115,229		)	(18,087		)	(133,316		)
Reimbursement of excess purchase price over carrying value of acquired assets	—		2,250			—			2,250
Unit-based compensation	—		1,429			—			1,429
Balances – December 31, 2015	35,456,612		380,845			13,034			393,879

Net income	—		23,233			8,419			31,652
Issuance of common units, net	—		(29		)	—			(29		)
Issuance of restricted units	13,800		—			—			—
Forfeiture of restricted units	(2,250	)	—			—			—
Cash distributions	—		(104,137		)	(14,041		)	(118,178		)
Reimbursement of excess purchase price over carrying value of acquired assets	—		4,125			—			4,125
Unit-based compensation	—		904			—			904
Purchase of treasury units	(16,100	)	(347		)	—			(347		)
Balances – December 31, 2016	35,452,062		$	304,594		$	7,412		$	312,006

See accompanying notes to consolidated financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)



	Year Ended December 31,
	2016			2015			2014
Cash flows from operating activities:
Net income (loss)	$	31,652		$	38,380		$	(11,705	)
Less: (Income) loss from discontinued operations	—			(1,215		)	5,338
Net income (loss) from continuing operations	31,652			37,165			(6,367		)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	92,132			92,250			68,830
Amortization of deferred debt issue costs	3,684			4,859			6,263
Amortization of discount on notes payable	—			—			1,305
Amortization of premium on notes payable	(306		)	(324		)	(245		)
(Gain) loss on disposition or sale of property, plant, and equipment	(33,400		)	2,149			1,353
Gain on retirement of senior unsecured notes	—			(1,242		)	—
Impairment of long lived assets	26,953			10,629			3,445
Impairment of goodwill	4,145			—			—
Equity in earnings unconsolidated entities	(4,714		)	(8,986		)	(5,466		)
Reduction in fair value of investment in Cardinal due to the purchase of the controlling interest	—			—			30,102
Derivative (income) loss	4,133			(3,107		)	(5,877		)
Net cash received for commodity derivatives	(550		)	143			3
Net cash received for interest rate derivatives	160			—			—
Net premiums received on derivatives that settled during the year on interest rate swaption contracts	630			2,495			6,692
Unit-based compensation	904			1,429			817
Preferred dividends from Martin Energy Trading	—			—			1,498
Return on investment	7,500			11,200			2,600
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables	(6,153		)	59,479			29,025
Product exchange receivables	843			1,996			(319		)
Inventories	(6,761		)	12,799			5,680
Due from affiliates	(1,441		)	4,386			(2,413		)
Other current assets	2,478			891			4,123
Trade and other accounts payable	3,254			(44,153		)	(26,349		)
Product exchange payables	(5,372		)	2,336			801
Due to affiliates	2,736			866			2,276
Income taxes payable	(115		)	(189		)	(30		)
Other accrued liabilities	686			(2,802		)	1,084
Change in other non-current assets and liabilities	(12,230		)	(345		)	181
Net cash provided by continuing operating activities	110,848			183,924			119,012
Net cash used in discontinued operating activities	—			(1,352		)	(3,432		)
Net cash provided by operating activities	110,848			182,572			115,580
Cash flows from investing activities:
Payments for property, plant, and equipment	(40,455		)	(65,791		)	(84,307		)
Acquisitions, net of cash acquired	(2,150		)	—			(102,696		)
Payments for plant turnaround costs	(2,061		)	(1,908		)	(3,974		)
Proceeds from sale of property, plant, and equipment	108,505			2,644			1,030
Proceeds from involuntary conversion of property, plant and equipment	—			—			2,475
Investments in unconsolidated entities	—			—			(134,030		)
Return of investments from unconsolidated entities	—			—			225
Contributions to unconsolidated entities for operations	—			—			(3,386		)
Net cash provided by (used in) continuing investing activities	63,839			(65,055		)	(324,663		)
Net cash provided by discontinued investing activities	—			41,250			—
Net cash provided by (used in) investing activities	63,839			(23,805		)	(324,663		)
Cash flows from financing activities:
Payments of long-term debt	(386,700		)	(308,836		)	(1,533,087		)
Proceeds from long-term debt	331,700			282,000			1,493,250
Net proceeds from issuance of common units	(29		)	(590		)	331,728
General partner contributions	—			55			7,007
Excess purchase price over carrying value of acquired assets	—			—			(4,948		)
Reimbursement of excess purchase price over carrying value of acquired assets	4,125			2,250			—
Purchase of treasury units	(347		)	—			(277		)
Payments of debt issuance costs	(5,274		)	(341		)	(3,722		)
Cash distributions paid	(118,178		)	(133,316		)	(97,368		)
Net cash provided by (used in) financing activities	(174,703		)	(158,778		)	192,583

Net decrease in cash	(16		)	(11		)	(16,500		)
Cash at beginning of year	31			42			16,542
Cash at end of year	$	15		$	31		$	42

See accompanying notes to consolidated financial statements.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)


(1)	Organization and Description of Business

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

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

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


(2)	Significant Accounting Policies

(a) Principles of Presentation and Consolidation

The consolidated financial statements include the financial statements of the Partnership and its wholly-owned subsidiaries and equity method investees. In the opinion of the management of the Partnership’s general partner, all adjustments and elimination of significant intercompany balances necessary for a fair presentation of the Partnership’s results of operations, financial position and cash flows for the periods shown have been made. All such adjustments are of a normal recurring nature. In addition, the Partnership evaluates its relationships with other entities to identify whether they are variable interest entities under certain provisions of the Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC"), 810-10 and to assess whether it is the primary beneficiary of such entities. If the determination is made that the Partnership is the primary beneficiary, then that entity is included in the consolidated financial statements in accordance with ASC 810-10. No such variable interest entities exist as of December 31, 2016 or 2015.

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

(b) Product Exchanges

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

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

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

(d) Revenue Recognition

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

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

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

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

(e) Equity Method Investments

The Partnership uses the equity method of accounting for investments in unconsolidated entities where the ability to exercise significant influence over such entities exists. Investments in unconsolidated entities consist of capital contributions and advances plus the Partnership’s share of accumulated earnings as of the entities’ latest fiscal year-ends, less capital withdrawals and distributions. Investments in excess of the underlying net assets of equity method investees, specifically identifiable to property, plant and equipment, are amortized over the useful life of the related assets. Excess investment representing equity method goodwill is not amortized but is evaluated for impairment, annually. Under certain provisions of ASC 350-20, related to goodwill, this goodwill is not subject to amortization and is accounted for as a component of the investment. Equity method investments are subject to impairment under the provisions of ASC 323-10, which relates to the equity method of accounting for investments in common stock. No portion of the net income from these entities is included in the Partnership’s operating income.

(f) Property, Plant, and Equipment

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

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

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

(g) Goodwill and Other Intangible Assets

Goodwill is subject to a fair-value based impairment test on an annual basis, or more often if events or circumstances indicate there may be impairment. The Partnership is required to identify its reporting units and determine the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets. The Partnership is required to determine the fair value of each reporting unit and compare it to the carrying amount of the reporting unit. To the extent the carrying amount of a reporting unit exceeds the fair value of the reporting unit, the Partnership would be

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

required to perform the second step of the impairment test, as this is an indication that the reporting unit goodwill may be impaired.

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

Of the Partnership's four reporting units, the terminalling and storage, natural gas services, and sulfur services reporting units contain goodwill. During the second quarter of 2016, the Partnership experienced an impairment of all the goodwill in the Partnership's marine transportation reporting unit. See Note 8 for more information.

In performing a quantitative analysis, recoverability of goodwill for each reporting unit is measured using a weighting of the discounted cash flow method and two market approaches (the guideline public company method and the guideline transaction method). The discounted cash flow model incorporates discount rates commensurate with the risks involved. Use of a discounted cash flow model is common practice in assessing impairment in the absence of available transactional market evidence to determine the fair value. The key assumptions used in the discounted cash flow valuation model include discount rates, growth rates, cash flow projections and terminal value rates. Discount rates, growth rates and cash flow projections are the most sensitive and susceptible to change as they require significant management judgment. Discount rates are determined by using a weighted average cost of capital ("WACC"). The WACC considers market and industry data as well as company-specific risk factors for each reporting unit in determining the appropriate discount rate to be used. The discount rate utilized for each reporting unit is indicative of the return an investor would expect to receive for investing in such a business. Management, considering industry and company specific historical and projected data, develops growth rates and cash flow projections for each reporting unit. Terminal value rate determination follows common methodology of capturing the present value of perpetual cash flow estimates beyond the last projected period assuming a constant WACC and low long-term growth rates. If the calculated fair value is less than the current carrying amount, impairment of the reporting unit may exist. If the recoverability test indicates potential impairment, the Partnership calculates an implied fair value of goodwill for the reporting unit. The implied fair value of goodwill is determined in a manner similar to how goodwill is calculated in a business combination. If the implied fair value of goodwill exceeds the carrying amount of goodwill assigned to the reporting unit, there is no impairment. If the carrying amount of goodwill assigned to a reporting unit exceeds the implied fair value of the goodwill, an impairment loss is recorded to write down the carrying amount. An impairment loss cannot exceed the carrying amount of goodwill assigned to a reporting unit but may indicate certain long-lived and amortizable intangible assets associated with the reporting unit may require additional impairment testing

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

Other intangible assets that have finite lives are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable. An impairment is indicated if the carrying amount of a long-lived intangible asset exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If impairment is indicated, the Partnership would record an impairment loss equal to the difference between the carrying value and the fair value of the asset. There were no intangible asset impairments in 2016, 2015 or 2014.

(h) Debt Issuance Costs

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

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

In connection with the issuance, amendment, expansion and restatement of debt arrangements, the Partnership incurred debt issuance costs of $5,274, $341 and $3,722 in the years ended December 31, 2016, 2015 and 2014, respectively.

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

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

Due to the redemption of the remaining $175,000 of 8.875% senior unsecured notes in 2014 and a reduction in the number of lenders under the Partnership’s multi-bank credit agreement, $3,078 of the existing debt issuance costs were determined not to have continuing benefit and were expensed during the year ended December 31, 2014.

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

Amortization and write-off of debt issuance costs, which is included in interest expense, totaled $3,684, $4,859 and $6,263 for the years ended December 31, 2016, 2015 and 2014, respectively. Accumulated amortization amounted to $14,265 and $10,581 at December 31, 2016 and 2015, respectively.

(i) Impairment of Long-Lived Assets

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

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

In the fourth quarter of 2015, the Partnership identified a triggering event related to the condensate splitter project in the specialty terminals division of the Partnership's Terminalling and Storage segment. The triggering event was the decision to not move forward with the project due to the evaporation of the economic viability of the project. As a result, an impairment charge of $9,305 was recorded in the Terminalling and Storage segment results of operations for the year ended December 31, 2015. In the fourth quarter of 2015, the Partnership identified a triggering event related to one inland push boat and three inland tank barges in the Marine Transportation segment. The triggering event was the assets' inability to generate cash flows in recent quarters and going forward. As a result, an impairment charge of $1,324 was recorded in the Marine Transportation segment results of operations in the fourth quarter of 2015.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

In the third quarter of 2014, the Partnership identified a triggering event related to one offshore tow in the Marine Transportation segment. The triggering event was the tow's inability to generate cash flows in recent quarters. As a result, an impairment charge of $3,445 was recorded in the Marine Transportation segment results of operations in the third quarter of 2014. No other triggering events occurred in 2015, 2014 or 2013 that would require an additional assessment for impairment of long-lived assets.

(j) Asset Retirement Obligations

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

(k) Derivative Instruments and Hedging Activities

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

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

(l) Use of Estimates

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

(m) Indirect Selling, General and Administrative Expenses

Indirect selling, general and administrative expenses are incurred by Martin Resource Management and allocated to the Partnership to cover costs of centralized corporate functions such as accounting, treasury, engineering, information technology, risk management and other corporate services. Such expenses are based on the percentage of time spent by Martin Resource Management’s personnel that provide such centralized services. Under an omnibus agreement with Martin Resource Management, the Partnership is required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. For the years ended December 31, 2016, 2015 and 2014, the conflicts committee of the Partnership's general partner ("Conflicts Committee") approved reimbursement amounts of $13,033, $13,679 and $12,535, respectively, reflecting the Partnership's allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.

(n) Environmental Liabilities and Litigation

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

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

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

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

(p) Deferred Catalyst Costs

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

(q) Deferred Turnaround Costs

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

(r) Income Taxes

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

(s) Comprehensive Income

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


(3)	Recent Accounting Pronouncements

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

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

In July 2015, the FASB issued ASU No. 2015-11, Inventory: Simplifying the Measurement of Inventory, which applies only to inventory for which cost is determined by methods other than last-in, first-out and the retail inventory method. This includes inventory that is measured using first-in, first-out or average cost. Inventory within the scope of this standard is required to be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The new standard will be effective on January 1, 2017. The Partnership does not anticipate that ASU 2015-11 will have a material effect on its consolidated financial statements and related disclosures.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective. The new standard is effective for the Partnership on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method. The Partnership is currently determining the overall impacts that ASU 2014-09 will have on its contract

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

portfolio and consolidated financial statements, and anticipate testing its new controls and processes designed to comply with ASU 2014-09 throughout 2017 to permit adoption by January 1, 2018. The Partnership's approach will include performing a detailed review of key contracts representative of its different businesses and comparing historical accounting policies and practices to the new standard. The Partnership currently intends on adopting the new standard utilizing the cumulative effect method which will result in the cumulative effect of the adoption being recorded as of January 1, 2018. The Partnership is currently in the process of evaluating the effect the adoption of ASU 2014-09 will have on its consolidated financial statements.


(4)	Acquisitions

Cardinal Gas Storage Partners LLC

On August 29, 2014, the Partnership acquired from Energy Capital Partners ("ECP") all of ECP’s approximate 57.8% Category A membership interests in Cardinal Gas Storage Partners LLC ("Cardinal") for cash consideration of approximately $120,973, subject to certain post-closing adjustments. Prior to the acquisition, the Partnership owned an approximate 42.2% interest in the Category A membership interests in Cardinal. Based on the application of purchase accounting, the Partnership reduced the carrying value of its existing investment in Cardinal at the acquisition date by $30,102, which was recognized in the Partnership's Consolidated Statements of Operations for the year ended December 31, 2014. Concurrent with the closing of the transaction, the Partnership retired all of the project level financing of various Cardinal subsidiaries. The Partnership funded the acquisition and repayment of the project financings with borrowings under its revolving credit facility and the use of restricted cash acquired.

The total purchase price is as follows:



Cash payment for 57.8% interest in Cardinal	$	120,973
Fair value of the Partnership's previously owned 42.2% interest in Cardinal	87,613
Total	$	208,586

Assets acquired and liabilities assumed were recorded in the Natural Gas Services segment at fair value in the following purchase price allocation which was finalized in the fourth quarter of 2014:



Restricted cash	$	17,566
Other current assets	9,385
Property, plant and equipment	390,895
Intangible and other assets	80,135
Project level finance debt	(282,087		)
Other current liabilities	(6,713		)
Other non-current liabilities	(595		)
Total	$	208,586

Intangible assets consist of above-market gas storage customer contracts which are amortized based upon the terms of the individual contracts. At the acquisition date, the weighted average life of these contracts, based upon contracted volumes, was 5.1 years.

The Partnership’s results of operations from the Cardinal acquisition include revenues and net income of $61,233 and $16,157, respectively, for the year ended December 31, 2016, $64,881 and $11,899, respectively, for the year ended December 31, 2015, and revenues and net income of $22,991 and $1,916, respectively, for the period from August 29, 2014 to December 31, 2014.

Natural Gas Liquids ("NGL") Storage Assets

On May 31, 2014, the Partnership acquired certain NGL storage assets, located in Arcadia, Louisiana, from a subsidiary of Martin Resource Management for $7,388. This acquisition is considered a transfer of net assets between entities under common control. The acquisition of these assets was recorded at the historical carrying value of the assets at the acquisition date. The Partnership recorded the purchase in the following allocation:

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)



Property, plant and equipment	$	2,453
Current liabilities	(13		)
	$	2,440

The excess of the purchase price over the carrying value of the assets of $4,948 was recorded as an adjustment to "Partners' capital." This transaction was funded with borrowings under the Partnership's revolving credit facility. As no individual line item of the historical financial statements of the assets was in excess of 3% of the Partnership's relative financial statement captions, the Partnership elected not to retrospectively recast the historical financial information to include these assets.

West Texas LPG Pipeline L.P.

On May 14, 2014, the Partnership acquired from a subsidiary of Atlas Pipeline Partners L.P. ("Atlas"), all of the outstanding membership interests in Atlas Pipeline NGL Holdings, LLC and Atlas Pipeline NGL Holdings II, LLC (collectively, "Atlas Holdings") for cash of approximately $134,400. The purchase price was subsequently reduced $501 due to a post-closing working capital adjustment. This transaction was recorded in "Investments in unconsolidated entities" in the Partnership's Consolidated Balance Sheet. Atlas Holdings owned a 19.8% limited partnership interest and a 0.2% general partnership interest in West Texas LPG Pipeline L.P. ("WTLPG"). At the time of the purchase, WTLPG was operated by Chevron Pipe Line Company. The 80% interest was subsequently sold to ONEOK Partners, L.P. who assumed operational responsibility. WTLPG owns an approximate 2,300 mile common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. This acquisition will enable the Partnership to participate in the transportation of NGL production in West Texas and other basins along the WTLPG pipeline route. This acquisition of the WTLPG business complements the Partnership's existing East Texas NGL pipeline that delivers Y-grade NGLs from East Texas production areas into Beaumont, Texas on a smaller scale. This transaction was funded with borrowings under the Partnership's revolving credit facility.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

Pro Forma Unaudited Financial Information for Cardinal and WTLPG

The following pro forma unaudited consolidated results of operations have been prepared as if the acquisitions of Cardinal and WTLPG occurred at the beginning of fiscal 2014:



	Year Ended December 31, 2014
Revenue:
As reported	$	1,642,141
Pro forma	$	1,688,629
Net income (loss) from continuing operations attributable to limited partners:
As reported	$	(8,255	)
Pro forma	$	1,676
Net loss from discontinued operations attributable to limited partners:
As reported	$	(6,921	)
Pro forma	$	(6,921	)
Net income (loss) from continuing operations per unit attributable to limited partners - basic
As reported	$	(0.27	)
Pro forma	$	0.05
Net loss from discontinued operations per unit attributable to limited partners - basic
As reported	$	(0.22	)
Pro forma	$	(0.22	)
Net income (loss) from continuing operations per unit attributable to limited partners - diluted
As reported	$	(0.27	)
Pro forma	$	0.05
Net loss from discontinued operations per unit attributable to limited partners - diluted
As reported	$	(0.22	)
Pro forma	$	(0.22	)

Pro forma adjustments included above are based upon currently available information which includes certain estimates and assumptions. Although actual results could differ from the pro forma results, the Partnership believes the pro forma results provide a reasonable basis for presenting the the significant effects of the transactions. However, the pro forma results are not necessarily indicative of the results that would have occurred if the transactions had occurred at the beginning of fiscal 2014.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)


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

Long-Lived Assets Held for Sale

In the fourth quarter of 2016, the Partnership identified certain assets that were no longer deemed core to the operations of the Partnership in the Smackover refinery and Martin Lubricants divisions of the Terminalling and Storage segment as well as the inland and offshore divisions of the Marine Transportation segment. These assets were deemed non-core due to the each asset's inability to generate cash flows in recent quarters as well as the expected cash flows in future quarters. As a result, an impairment charge of $15,252 and $11,701 was recorded in the Terminalling and Storage and Marine Transportation segments, respectively, for the year ended December 31, 2016 and was presented as "Impairment of long-lived assets" in the Partnership's Consolidated Statements of Operations. At December 31, 2016, the assets met the criteria to be classified as held for sale in accordance with ASC 360-10 and are presented at the assets' fair value less cost to sell by segment in current assets as follows:



	December 31, 2016

Terminalling and storage	$	10,852
Marine transportation	4,927
Assets held for sale	$	15,779

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

Divestitures

Divestiture of Terminalling Assets. On December 21, 2016, the Partnership sold its 900,000 barrel crude oil storage terminal, refined product barge terminal, certain pipelines and related easements as well as dockage and trans-loading assets located in Corpus Christi, Texas (collectively the "CCCT Assets") to NuStar Logistics, L.P. (“NuStar”) for gross consideration of $107,000 plus the reimbursement of certain capital expenditures and prepaid items of $2,057. The Partnership received net proceeds of approximately $93,347 after transaction fees and expenses as well as the application of certain net cash payments previously received by us in conjunction with its mandated relocation of certain dockage assets to the purchase price in the amount of $13,400. Proceeds from the sale were used to reduce outstanding borrowings under the Partnership's revolving credit facility. The Partnership recorded a gain from the divestiture of $37,345, which was included in "Other operating income, net on the Partnership's Consolidated Statements of Operations for the year ended December 31, 2016. Net income attributable to the CCCT Assets included in the Partnership's Consolidated Statements of Operations was $43,804, $10,880, and $16,241 for the years ended December 31, 2016, 2015, and 2014, respectively.

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

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

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

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



	Year Ended December 31,
	2016		2015		2014

Total revenues from third parties¹	$	—	$	791	$	51,264
Total costs and expenses and other, net, excluding depreciation and amortization	—		1,038		55,068
Depreciation and amortization	—		—		1,534
Other operating income, net ²	—		1,462		—
Income (loss) from discontinued operations before income taxes	—		1,215		(5,338		)
Income tax expense	—		—		—
Income (loss) from discontinued operations, net of income taxes	$	—	$	1,215	$	(5,338	)

¹ Total revenues from third parties excludes intercompany revenues of $0 and $0 and $5,241 for the years ended December 31, 2016, 2015 and 2014, respectively.

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


(6)	Inventories

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



	2016		2015
Natural gas liquids	$	33,656	$	20,959
Sulfur	8,521		13,812
Sulfur based products	19,107		19,400
Lubricants	18,276		18,675
Other	3,071		3,024
	$	82,631	$	75,870


(7)	Property, Plant and Equipment

At December 31, 2016 and 2015, property, plant and equipment consisted of the following:



	Depreciable Lives	2016		2015
Land	—	$	20,679	$	23,931
Improvements to land and buildings	10-25 years	135,852		159,160
Storage equipment	5-50 years	168,839		191,095
Marine vessels	4-25 years	181,659		257,858
Operating plant and equipment	3-50 years	620,303		631,728
Base Gas	—	43,799		43,799
Furniture, fixtures and other equipment	3-20 years	19,034		4,375
Transportation equipment	3-7 years	1,738		2,237
Construction in progress		32,374		73,631
		$	1,224,277	$	1,387,814

Depreciation expense for the years ended December 31, 2016, 2015 and 2014 was $72,405, $67,134 and $56,309.

Additions to property, plant and equipment included in accounts payable at December 31, 2016 and 2015 were $1,819 and $6,004, respectively.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

(8) Goodwill

The following table represents the goodwill balance at December 31, 2015, changes during the year, and the resulting balances at December 31, 2016:



	2015		Impairment¹			CCCT Assets²			2016
Carrying amount of goodwill:
Terminalling and storage	$	14,229	$	—		$	(2,361	)	$	11,868
Natural gas services	79		—			—			$	79
Sulfur services	5,349		—			—			$	5,349
Marine transportation	4,145		(4,145		)	—			$	—
Total goodwill	$	23,802	$	(4,145	)	$	(2,361	)	$	17,296

¹ During the second quarter of 2016, the Partnership determined that the state of market conditions in the Marine Transportation reporting unit, including the demand for utilization, day rates and the current oversupply of inland tank barges, indicated that an impairment of goodwill may exist. As a result, the Partnership assessed qualitative factors and determined that the Partnership could not conclude it was more likely than not that the fair value of goodwill exceeded its carrying value. In turn, the Partnership prepared a quantitative analysis of the fair value of the goodwill as of June 30, 2016, based on the weighted average valuation of the aforementioned income and market based valuation approaches. The underlying results of the valuation were driven by our actual results during the six months ended June 30, 2016 and the pricing and market conditions existing as of June 30, 2016, which were below our forecasts at the time of the previous goodwill assessments. Other key estimates, assumptions and inputs used in the valuation included long-term growth rates, discounts rates, terminal values, valuation multiples and relative valuations when comparing the reporting unit to similar businesses or asset bases. Upon completion of the analysis, a $4,145 impairment of all goodwill in the Marine Transportation reporting unit was incurred during the second quarter of 2016. The Partnership did not recognize any other goodwill impairment losses for the year ended December 31, 2016.

² This change represents goodwill disposed of as part of the Partnership's divestiture of the CCCT Assets. See Note 5.

(9) Leases

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

The Partnership’s future minimum lease obligations as of December 31, 2016 consist of the following:



Fiscal year	Operating Leases

2017	$	10,458
2018	5,633
2019	4,036
2020	3,389
2021	1,041
Thereafter	8,449
Total	$	33,006

Rent expense for continuing operating leases for the years ended December 31, 2016, 2015 and 2014 was $19,005, $18,831 and $18,724, respectively.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

(10) Investments in Unconsolidated Entities and Joint Ventures

On August 29, 2014, the Partnership acquired ECP's approximate 57.8% Category A interest in Cardinal. Prior to the acquisition, the Partnership owned an approximate 42.2% Category A interest in Cardinal which was accounted for by the equity method. See Note 4 for discussion of the acquisition of the remaining interests.

On May 14, 2014, the Partnership acquired from a subsidiary of Atlas, all of the outstanding membership interests in Atlas Holdings for cash of approximately $134,400 at closing. The purchase price was subsequently reduced $501 due to a post-closing working capital adjustment. Atlas Holdings owned a 19.8% limited partner interest and a 0.2% general partner interest in WTLPG. At the time of the purchase, WTLPG was operated by Chevron Pipe Line Company. The 80% interest was subsequently sold to ONEOK Partners, L.P. who assumed operational responsibility. WTLPG owns an approximate 2,300 mile common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. The Partnership recognizes its combined 20% interest in WTLPG as "Investment in unconsolidated entities" on its Consolidated Balance Sheet. The Partnership accounts for its ownership interest in WTLPG under the equity method of accounting with recognition of its ownership interest in the income of WTLPG as "Equity in earnings of unconsolidated entities" on its Consolidated Statement of Operations.

In March 2013, the Partnership acquired 100% of the preferred interests in Martin Energy Trading LLC ("MET"), a subsidiary of Martin Resource Management for $15,000. On August 31, 2014, MET converted its preferred equity to subordinated debt. The resulting $15,000 note receivable from MET bears an annual interest rate of 15% and matures August 31, 2026. MET may prepay any or all of the note balance after September 1, 2016. See Note 13.

These investments are accounted for by the equity method. Selected financial information for significant unconsolidated equity method investees is as follows:



	As of December 31,						Years ended December 31,
	Total Assets		Long-Term Debt		Members’ Equity/Partners' Capital		Revenues		Net Income
2016
WTLPG	$	812,464	$	—	$	790,406	$	88,468	$	23,883
2015
WTLPG	$	819,342	$	—	$	804,023	$	100,708	$	46,294
2014
WTLPG	$	827,697	$	—	$	818,546	$	95,315	$	38,698

Cardinal¹	$	—	$	—	$	—	$	46,488	$	1,911

¹Financial information for Cardinal includes revenues and net income for the 2014 period prior to the Partnership's acquisition of the 57.8% interest not previously owned.

As of December 31, 2016 and 2015, the Partnership’s interest in cash of the unconsolidated equity method investees was $631 and $1,060, respectively.

(11) Fair Value Measurements

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

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

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

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

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

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



	Level 2
	December 31,
	2016			2015
Commodity derivative contracts, net	$	(3,904	)	$	675
Interest rate derivative contracts	—			(206		)

The Partnership is required to disclose estimated fair values for its financial instruments. Fair value estimates are set forth below for these financial instruments. The following methods and assumptions were used to estimate the fair value of each class of financial instrument:

•

Accounts and other receivables, trade and other accounts payable, accrued interest payable, other accrued liabilities, income taxes payable and due from/to affiliates: The carrying amounts approximate fair value due to the short maturity and highly liquid nature of these instruments, and as such these have been excluded from the table below. There is negligible credit risk associated with these instruments.


•	Note receivable and long-term debt including current portion: The carrying amount of the revolving credit facility approximates fair value due to the debt having a variable interest rate and is in Level 2. The Partnership has not had any indicators which represent a change in the market spread associated with its variable interest rate debt.


•	The estimated fair value of the senior unsecured notes is based on market prices of similar debt. The estimated fair value of the note receivable from Martin Energy Trading was determined by calculating the net present value of the payments over the life of the note. The note is considered Level 3 due to the lack of observable inputs for similar transactions between related parties.



	December 31, 2016				December 31, 2015
	Carrying Value		Fair Value		Carrying Value		Fair Value
Note receivable - MET	$	15,000	$	15,797	$	15,000	$	15,830
2021 Senior unsecured notes	372,239		377,882		371,861		318,000

(12) Derivative Instruments and Hedging Activities

The Partnership’s revenues and cost of products sold are materially impacted by changes in NGL prices. Additionally, the Partnership's results of operations are materially impacted by changes in interest rates. In an effort to manage its exposure to these risks, the Partnership periodically enters into various derivative instruments, including commodity and interest rate hedges. All of the Partnership's derivatives are non-hedge derivatives and therefore all changes in fair values are recognized as gains and losses in the earnings of the periods in which they occur.

(a) Commodity Derivative Instruments

The Partnership from time to time has used derivatives to manage the risk of commodity price fluctuation. Commodity risk is the adverse effect on the value of a liability or future purchase that results from a change in commodity price. The Partnership has established a hedging policy and monitors and manages the commodity market risk associated with potential commodity risk exposure. In addition, the Partnership has focused on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction. The Partnership has entered into hedging transactions as of December 31, 2016 to protect a portion of its commodity price risk exposure. These hedging arrangements are in the form of swaps for NGLs. The Partnership has instruments totaling a notional quantity of 731,000 barrels settling during the period from January 31, 2017 through June 30, 2017. These instruments settle against the applicable pricing source for each grade and location. MET serves as the counterparty for all positions outstanding at December 31, 2016.

Due to the acquisition of the remaining interests of Cardinal on August 29, 2014, the Partnership acquired a notional quantity of 3,631,740 MMBtu of natural gas call options with a strike price of $4.50 per MMBtu. These options managed the

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

purchase of base gas at Monroe Gas Storage Company, LLC for the portion of base gas that was leased with Credit Suisse at the acquisition date and was scheduled to be returned in January and February 2015. The options were set to settle in two increments of 2,345,498 MMBtu and 1,286,242 MMBtu on January 31, 2015 and February 28, 2015, respectively. On December 31, 2014, the Partnership terminated these options, resulting in a termination benefit of $3, which was recorded in "Other, net" in the Partnership's Consolidated Statement of Operations for the year ended December 31, 2014.

(b) Interest Rate Derivative Instruments

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

As of December 31, 2015, the Partnership had a fixed-to-variable interest rate swap agreement with a notional principal amount of $50,000, effectively converting the interest expense associated with a portion of the Partnership's 2021 senior unsecured notes from fixed rate to variable rate based on the LIBOR interest rate. The Partnership's swap agreement has a termination date that corresponds to the maturity date of the 2021 senior unsecured notes. As of December 31, 2015, the maximum length of time over which the Partnership has hedged a portion of its exposure to the variability in the value of this debt due to interest rate risk is through December of 2020. This instrument is recorded on the Partnership's Consolidated Balance Sheets at December 31, 2015 in "Fair value of derivatives" as a non current liability of $206. This position terminated on January 7, 2016, resulting in a benefit of $160.

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

On April 1, 2014, the Partnership entered into two fixed-to-variable interest rate swap agreements with an aggregate notional amount of $100,000 each to hedge its exposure to changes in the fair value of its senior unsecured notes. On May 14, 2014 the Partnership terminated these swaps and received a termination benefit of $2,380 upon cancellation of these swap agreements. This amount was recorded in "Interest expense, net" in the Partnership's Consolidated Statement of Operations for the year ended December 31, 2014. Additionally, subsequent to the termination on May 14, 2014, the Partnership entered into two fixed-to-variable interest rate swap agreements on May 14, 2014 with an aggregate notional amount of $100,000 each to hedge its exposure to changes in the fair value of its senior unsecured notes. In August 2014, the Partnership received a scheduled swap settlement related to these agreements totaling $976. This amount was recorded in "Interest expense, net" in the Partnership's Consolidated Statement of Operations for the year ended December 31, 2014.

On September 18, 2014, the Partnership entered into a fixed-to-variable interest rate swap agreement, with an aggregate notional amount of $50,000, to hedge its exposure to changes in the fair value of its senior unsecured notes.

On October 9, 2014, the Partnership terminated each of its three outstanding swaps, receiving a termination benefit of $2,125, which was recorded in "Interest expense, net" in the Partnership's Consolidated Statement of Operations for the year ended December 31, 2014.

Subsequent to the termination on October 9, 2014, the Partnership entered into two fixed-to-variable interest rate swap agreements, each with an aggregate notional amount of $50,000 to hedge its exposure to changes in the fair value of its senior unsecured notes. On October 14, 2014, the Partnership terminated each of these two swaps, receiving a termination benefit of $500, which was recorded in "Interest expense, net" in the Partnership's Consolidated Statement of Operations for the year ended December 31, 2014.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

Subsequent to the termination on October 14, 2014, the Partnership entered into two fixed-to-variable interest rate swap agreements, each with an aggregate notional amount of $50,000 to hedge its exposure to changes in the fair value of its senior unsecured notes. On October 14, 2014, the Partnership terminated each of these two swaps, receiving a termination benefit of $711, which was recorded in "Interest expense, net" in the Partnership's Consolidated Statement of Operations for the year ended December 31, 2014.

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

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



	Fair Values of Derivative Instruments in the Consolidated Balance Sheet
	Derivative Assets					Derivative Liabilities
		Fair Values					Fair Values
	Balance Sheet Location	December 31, 2016		December 31, 2015		Balance Sheet Location	December 31, 2016		December 31, 2015
Derivatives not designated as hedging instruments:	Current:
Commodity contracts	Fair value of derivatives	$	—	$	675	Fair value of derivatives	$	3,904	$	—
Derivatives not designated as hedging instruments:	Non Current:					Non Current:
Interest rate contracts	Fair value of derivatives	—		—		Fair value of derivatives	—		206
Total derivatives not designated as hedging instruments		$	—	$	675		$	3,904	$	206

Effect of Derivative Instruments on the Consolidated Statement of Operations For the Twelve Months Ended December 31, 2016, 2015, and 2014



	Location of Gain or (Loss) Recognized in Income on Derivatives	Amount of Gain or (Loss) Recognized in Income on Derivatives
		2016			2015			2014
Derivatives not designated as hedging instruments:
Interest rate swaption contracts	Interest expense	$	(630	)	$	2,495		$	—
Interest rate contracts	Interest expense	(366		)	(206		)	6,692
Commodity contracts	Cost of products sold	5,129			818			—
Commodity contracts	Other income	—			—			(815		)
Total derivatives not designated as hedging instruments		$	4,133		$	3,107		$	5,877

(13) Related Party Transactions

As of December 31, 2016, Martin Resource Management owned 6,264,532 of the Partnership’s common units representing approximately 17.7% of the Partnership’s outstanding limited partnership units. Martin Resource Management controls the Partnership's general partner by virtue of its 51% voting interest in Holdings, the sole member of the Partnership's general partner. The Partnership’s general partner, MMGP, owns a 2% general partner interest in the Partnership and the Partnership’s incentive distribution rights. The Partnership’s general partner’s ability, as general partner, to manage and operate the Partnership, and Martin Resource Management’s ownership as of December 31, 2016, of approximately 17.7% of the

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

Partnership’s outstanding limited partnership units, effectively gives Martin Resource Management the ability to veto some of the Partnership’s actions and to control the Partnership’s management.

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

Omnibus Agreement

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

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


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

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

•distributing NGLs; and

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

This restriction does not apply to:


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


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


◦	providing land transportation of various liquids;


◦	distributing fuel oil, sulfuric acid, marine fuel and other liquids;


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


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


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


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


◦	operating an environmental consulting company;


◦	operating an engineering services company;


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

◦


◦	operating a crude oil, natural gas, natural gas liquids, and biofuels optimization business; and

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)


◦	operating, solely for the Partnership's account, the asphalt facilities in Omaha, Nebraska, Port Neches, Texas and South Houston, Texas.


•	any business that Martin Resource Management acquires or constructs that has a fair market value of less than $5,000;


•	any business that Martin Resource Management acquires or constructs that has a fair market value of $5,000 or more if the Partnership has been offered the opportunity to purchase the business for fair market value and the Partnership declines to do so with the concurrence of the Conflicts Committee; and

•

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

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

Effective January 1, 2017, through December 31, 2017, the Conflicts Committee approved an annual reimbursement amount for indirect expenses of $16,416. The Partnership reimbursed Martin Resource Management for $13,033, $13,679 and $12,535 of indirect expenses for the years ended December 31, 2016, 2015 and 2014, respectively. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.

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

Related Party Transactions. The Omnibus Agreement prohibits the Partnership from entering into any material agreement with Martin Resource Management without the prior approval of the Conflicts Committee. For purposes of the Omnibus Agreement, the term material agreements means any agreement between the Partnership and Martin Resource Management that requires aggregate annual payments in excess of then-applicable agreed upon reimbursable amount of indirect general and administrative expenses. Please read "Services" above.

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

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

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

Motor Carrier Agreement

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

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

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

Marine Agreements

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

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

Terminal Services Agreements

Diesel Fuel Terminal Services Agreement. Effective January 1, 2016, the Partnership entered into a new terminalling services agreement under which the Partnership provides terminal services to Martin Resource Management for marine fuel distribution. The per gallon throughput fee the Partnership charges under this agreement was increased when compared to the previous agreement and may be adjusted annually based on a price index. This agreement was amended on January 1, 2017 to reduce the minimum throughput requirements under such agreement.

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

Other Agreements

Cross Tolling Agreement. The Partnership is a party to an amended and restated tolling agreement with Cross Oil Refining and Marketing, Inc. ("Cross") dated October 28, 2014, under which the Partnership processes crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts for Cross. The tolling agreement expires November 25, 2031. Under this tolling agreement, Cross agreed to process a minimum of 6,500 barrels per day of

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

crude oil at the facility at a fixed price per barrel. Any additional barrels are processed at a modified price per barrel. In addition, Cross agreed to pay a monthly reservation fee and a periodic fuel surcharge fee based on certain parameters specified in the tolling agreement. All of these fees (other than the fuel surcharge) are subject to escalation annually based upon the greater of 3% or the increase in the Consumer Price Index for a specified annual period. In addition, on the third, sixth and ninth anniversaries of the agreement, the parties can negotiate an upward or downward adjustment in the fees subject to their mutual agreement.

Sulfuric Acid Sales Agency Agreement. The Partnership is party to a second amended and restated sulfuric acid sales agency agreement dated August 5, 2013, under which Martin Resource Management purchases and markets the sulfuric acid produced by the Partnership’s sulfuric acid production plant at Plainview, Texas, that is not consumed by the Partnership’s internal operations. This agreement, as amended, will remain in place until the Partnership terminates it by providing 180 days’ written notice. Under this agreement, the Partnership sells all of its excess sulfuric acid to Martin Resource Management. Martin Resource Management then markets such acid to third-parties and the Partnership shares in the profit of Martin Resource Management’s sales of the excess acid to such third parties.

Other Miscellaneous Agreements. From time to time the Partnership enters into other miscellaneous agreements with Martin Resource Management for the provision of other services or the purchase of other goods.

The tables below summarize the related party transactions that are included in the related financial statement captions on the face of the Partnership’s Consolidated Statements of Operations. The revenues, costs and expenses reflected in these tables are tabulations of the related party transactions that are recorded in the corresponding caption of the Consolidated Statements of Operations and do not reflect a statement of profits and losses for related party transactions.

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



Revenues:	2016		2015		2014
Terminalling and storage	$	82,437	$	78,233	$	74,467
Marine transportation	21,767		27,724		24,389
Natural gas services	699		878		—
Product sales:
Natural gas services	8		196		3,064
Sulfur services	2,006		3,639		3,921
Terminalling and storage	1,020		1,836		676
	3,034		5,671		7,661
	$	107,937	$	112,506	$	106,517

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



Cost of products sold:
Natural gas services	$	22,886	$	25,797	$	37,703
Sulfur services	15,339		16,579		18,390
Terminalling and storage	13,838		17,718		36,341
	$	52,063	$	60,094	$	92,434

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



Operating expenses:
Marine transportation	$	28,107	$	32,373	$	37,703
Natural gas services	9,258		8,639		4,870
Sulfur services	5,995		6,928		7,479
Terminalling and storage	27,481		29,931		29,525
	$	70,841	$	77,871	$	79,577

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

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



Selling, general and administrative:
Marine transportation	$	30	$	29	$	30
Natural gas services	7,566		6,216		6,039
Sulfur services	2,732		2,760		3,201
Terminalling and storage	2,526		2,284		1,874
Indirect overhead allocation, net of reimbursement	13,036		13,679		12,535
	$	25,890	$	24,968	$	23,679

Other Related Party Transactions

As discussed in Note 10, during March 2013, the Partnership acquired 100% of the preferred interests in MET, a subsidiary of Martin Resource Management, for $15,000. On August 31, 2014, MET converted its preferred equity to subordinated debt. The resulting $15,000 note receivable from MET bears an annual interest rate of 15% and matures August 31, 2026. MET may prepay any or all of the note balance on or after September 1, 2016. The note is recorded in "Note receivable - Martin Energy Trading LLC" on the Partnership's Consolidated Balance Sheet. Interest income for the years ended December 31, 2016, 2015, and 2014 was $2,256, $2,250 and $752, respectively, and is included in "Interest expense, net" in the Consolidated Statements of Operations.

As discussed in Note 12, during the twelve months ended December 31, 2016 and 2015, the Partnership entered into certain derivative financial instruments through June 30, 2017 to protect a portion of its commodity price risk exposure related to NGLs. MET served as counterparty to the outstanding positions at December 31, 2016 and 2015.


(14)	Supplemental Balance Sheet Information

Components of "Intangibles and other assets, net" at December 31, 2016 and 2015 were as follows:



	2016		2015
Customer contracts and relationships, net	$	36,528	$	50,452
Other intangible assets	2,280		1,818
Other	6,066		6,044
	$	44,874	$	58,314

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

Aggregate amortization expense for customer contracts and other intangible assets included in continuing operations was $19,548, $22,115, and $9,772, for the years ended December 31, 2016, 2015 and 2014, respectively, and accumulated amortization amounted to $48,876 and $32,842 at December 31, 2016 and 2015, respectively.

Estimated amortization expense for customer contract and relationships and other intangible assets for the years subsequent to December 31, 2016 are as follows: 2017 - $11,804; 2018 - $7,472; 2019 - $4,471; 2020 - $4,440; 2021 - $4,319; subsequent years - $6,302.

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

Components of "Other accrued liabilities" at December 31, 2016 and 2015 were as follows:



	2016		2015
Accrued interest	$	10,629	$	10,365
Asset retirement obligations	7,953		—
Property and other taxes payable	6,443		6,668
Accrued payroll	1,672		1,389
Other	20		111
	$	26,717	$	18,533

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



	Year Ended December 31,
	2016			2015
	(In thousands)

Beginning asset retirement obligations	$	2,163		$	2,052
Revisions to existing liabilities¹	14,379			—
Accretion	178			111
Liabilities settled	(302		)	—
Ending asset retirement obligations	16,418			2,163
Current portion of asset retirement obligations²	(7,953		)	—
Long-term portion of asset retirement obligations³	$	8,465		$	2,163

¹Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, discount rates, and the estimated remaining useful life of the assets. The 2016 revisions reflect changes in removal cost estimates and the estimated remaining useful life of assets.

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

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

(15) Long-Term Debt

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



	2016		2015
$664,444¹ Revolving credit facility at variable interest rate (3.76%² weighted average at December 31, 2016), due March 2020 secured by substantially all of the Partnership’s assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in the Partnership’s operating subsidiaries and equity method investees, net of unamortized debt issuance costs of $7,132 and $4,858, respectively³	$	435,868	$	493,142
$400,000 Senior notes, 7.25% interest, including unamortized premium of $1,262 and $1,568, respectively, also net of unamortized debt issuance costs of $2,823 and $3,507 respectively, issued $250,000 February 2013 and $150,000 April 2014, $26,200 repurchased during 2015, due February 2021, unsecured^3,4	372,239		371,861
Total long-term debt	$	808,107	$	865,003

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

¹ On April 27, 2016, the Partnership made certain strategic amendments to its credit facility which, among other things, decreased its borrowing capacity from $700,000 to $664,444 and extended the maturity date of the facility from March 28, 2018 to March 28, 2020. The reduction in capacity resulted in the write-off of $820 of deferred debt costs.

² Interest rate fluctuates based on the LIBOR rate plus an applicable margin set on the date of each advance. The margin above LIBOR is set every three months. Indebtedness under the credit facility bears interest at LIBOR plus an applicable margin or the base prime rate plus an applicable margin. All amounts outstanding at December 31, 2016 and December 31, 2015 were at LIBOR plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 2.00% to 3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 1.00% to 2.00%. The applicable margin for LIBOR borrowings at December 31, 2016 is 3.00%. The credit facility contains various covenants which limit the Partnership’s ability to make certain investments and acquisitions; enter into certain agreements; incur indebtedness; sell assets; and make certain amendments to the Omnibus Agreement. The Partnership is permitted to make quarterly distributions so long as no event of default exists.

³ The Partnership is in compliance with all debt covenants as of December 31, 2016.

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

The Partnership paid cash interest, net of proceeds received from interest rate swaptions, in the amount of $46,046, $43,376, and $37,112 for the years ended December 31, 2016, 2015 and 2014, respectively. Capitalized interest was $1,126, $1,944, and $1,437 for the years ended December 31, 2016, 2015 and 2014, respectively.

(16) Partners' Capital

As of December 31, 2016, partners’ capital consisted of 35,452,062 common limited partner units, representing a 98% partnership interest and a 2.0% general partner interest. Martin Resource Management, through subsidiaries, owned 6,264,532 of the Partnership's common limited partnership units representing approximately 17.7% of the Partnership's outstanding common limited partnership units. MMGP, the Partnership's general partner, owns the 2.0% general partnership interest.

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

Issuance of Common Units

On September 29, 2014, the Partnership completed a public offering of 3,450,000 common units at a price of $36.91 per common unit, before the payment of underwriters' discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 3,450,000 common units, net of underwriters' discounts, commissions and offering expenses, were $122,176. The Partnership's general partner contributed $2,599 in cash to the Partnership in conjunction with the issuance in order to maintain its 2.0% general partner interest in the Partnership. All of the net proceeds were used to pay down outstanding amounts under the Partnership's revolving credit facility.

On August 29, 2014, the Partnership closed a private equity sale with Martin Resource Management, under which Martin Resource Management invested $45,000 in cash in exchange for 1,171,265 common units. The pricing of $38.42 per common unit was based on the 10-day weighted average price of the Partnership's common units for the 10 trading days ending August 8, 2014. In connection with the issuance of these common units, the Partnership's general partner contributed $918 in order to maintain its 2.0% general partner interest in the Partnership. All of the net proceeds were used to pay down outstanding amounts under the Partnership's revolving credit facility.

On May 12, 2014, the Partnership completed a public offering of 3,600,000 common units at a price of $41.51 per common unit, before the payment of underwriters' discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 3,600,000 common units, net of underwriters' discounts, commissions and

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

offering expenses, were $143,431. The Partnership's general partner contributed $3,049 in cash to the Partnership in conjunction with the issuance in order to maintain its 2.0% general partner interest in the Partnership. All of the net proceeds were used to pay down outstanding amounts under the Partnership's revolving credit facility.

In March 2014, the Partnership entered into an equity distribution agreement with multiple underwriters (the "Sales Agents") for the ongoing distribution of the Partnership's common units. Pursuant to this program, the Partnership offered and sold common unit equity through the Sales Agents for aggregate proceeds of $0 and $21,501 for the years ended December 31, 2015 and 2014, respectively. The Partnership paid $591 and $380 in equity issuance related costs for the years ended December 31, 2015 and 2014, respectively. Under the the program, the Partnership issued 522,121 common units during the year ended December 31, 2014. Common units issued were at market prices prevailing at the time of the sale. The Partnership also received capital contributions from the Partnership's general partner of $441 during the year ended December 31, 2014 related to these issuances to maintain its 2.0% general partner interest in the Partnership. The net proceeds from the common unit issuances were used to pay down outstanding amounts under the Partnership's revolving credit facility.

Incentive Distribution Rights

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

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

For the years ended December 31, 2016, 2015 and 2014, the general partner was allocated $7,786, $15,571, and $0 in incentive distributions.

Distributions of Available Cash

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

Net Income per Unit

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

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

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



	Years Ended December 31,
	2016			2015			2014
Continuing operations:
Income (loss) from continuing operations	$	31,652		$	37,165		$	(6,367	)
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	7,786			15,078			2,033
Distributions payable on behalf of general partner interest	2,058			2,585			1,181
General partner interest in undistributed loss	(1,425		)	(1,842		)	(1,308		)
Less income (loss) allocable to unvested restricted units	90			136			(18		)
Limited partners’ interest in net income (loss)	$	23,143		$	21,208		$	(8,255	)



	Years Ended December 31,
	2016		2015			2014
Discontinued operations:
Income (loss) from discontinued operations	$	—	$	1,215		$	(5,338	)
Less general partner’s interest in net income:
Distributions payable on behalf of IDRs	—		493			1,704
Distributions payable on behalf of general partner interest	—		84			990
General partner interest in undistributed loss	—		(60		)	(1,097		)
Less income (loss) allocable to unvested restricted units	—		4			(14		)
Limited partners’ interest in net income (loss)	$	—	$	694		$	(6,921	)

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

The weighted average units outstanding for basic net income per unit were 35,347,032, 35,308,649 and 30,785,035 for the years ended December 31, 2016, 2015 and 2014, respectively. All outstanding units were included in the computation of diluted earnings per unit and weighted based on the number of days such units were outstanding during the period presented. For diluted net income per unit, the weighted average units outstanding were increased by 28,231 and 62,880 for the years ended December 31, 2016 and 2015, respectively, due to the dilutive effect of restricted units granted under the Partnership’s long-term incentive plan. All common unit equivalents were antidilutive for the year ended December 31, 2014 because the limited partners were allocated a net loss in this period.

100

(17) Unit Based Awards

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



	For the Year Ended December 31,
	2016		2015		2014
Employees	$	783	$	1,338	$	537
Non-employee directors	121		91		280
Total unit-based compensation expense	$	904	$	1,429	$	817

Long-Term Incentive Plans

The Partnership's general partner has a long term incentive plan for employees and directors of the general partner and its affiliates who perform services for the Partnership.

The plan consists of two components, restricted units and unit options. The plan currently permits the grant of awards covering an aggregate of 725,000 common units, 241,667 of which may be awarded in the form of restricted units and 483,333 of which may be awarded in the form of unit options. The plan is administered by the compensation committee of the general partner’s board of directors ("Compensation Committee").

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

The restricted units are valued at their fair value at the date of grant which is equal to the market value of common units on such date. A summary of the restricted unit activity for the year ended December 31, 2016 is provided below:



	Number of Units			Weighted Average Grant-Date Fair Value Per Unit
Non-vested, beginning of year	150,474			$	28.89
Granted	13,800			$	15.13
Vested	(58,224		)	$	30.61
Forfeited	(2,250		)	$	28.50
Non-Vested, end of year	103,800			$	26.54

Aggregate intrinsic value, end of year	$	1,905

A summary of the restricted units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) during the years ended December 31, 2016, 2015 and 2014 is provided below:

101



	For the Year Ended December 31,
	2016		2015		2014
Aggregate intrinsic value of units vested	$	1,233	$	110	$	514
Fair value of units vested	$	1,773	$	128	$	450

As of December 31, 2016, there was $1,058 of unrecognized compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 1.5 years.

Unit Options. The plan currently permits the grant of options covering common units. As of December 31, 2016, the Partnership has not granted any common unit options to directors or employees of the Partnership's general partner, or its affiliates. In the future, the Compensation Committee may determine to make grants under the plan to employees and directors containing such terms as the Compensation Committee shall determine. Unit options will have an exercise price that, in the discretion of the Compensation Committee, may not be less than the fair market value of the units on the date of grant. In addition, the unit options will become exercisable upon a change in control of the Partnership's general partner, Martin Resource Management or if the general partner ceases to be an affiliate of Martin Resource Management or upon the achievement of specified financial objectives.

(18) Income Taxes

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

A current income tax liability of $870, and $985 existed at December 31, 2016 and 2015, respectively.

Cash paid for income taxes was $841, $1,237, and $1,167 for the years ended December 31, 2016, 2015 and 2014, respectively.

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

As of December 31, 2016, the tax years that remain open to assessment by federal and state jurisdictions are 2013-2015.

(19) Business Segments

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

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

102

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 and 2014. See Note 5.



	Operating Revenues		Intersegment Eliminations			Operating Revenues After Eliminations		Depreciation and Amortization		Operating Income (Loss) after Eliminations			Capital Expenditures and Plant Turnaround Costs

Year Ended December 31, 2016:
Terminalling and storage	$	242,363	$	(5,653	)	$	236,710	$	45,484	$	40,660		$	26,097
Natural gas services	391,333		—			391,333		28,081		41,438			4,807
Sulfur services	141,058		—			141,058		7,995		23,393			5,093
Marine transportation	61,233		(2,943		)	58,290		10,572		(16,039		)	2,334
Indirect selling, general, and administrative	—		—			—		—		(16,794		)	—
Total	$	835,987	$	(8,596	)	$	827,391	$	92,132	$	72,658		$	38,331

Year Ended December 31, 2015:
Terminalling and storage	$	270,440	$	(5,670	)	$	264,770	$	38,731	$	15,704		$	40,421
Natural gas services	523,160		—			523,160		34,072		41,220			24,330
Sulfur services	170,161		—			170,161		8,455		23,604			1,201
Marine transportation	81,784		(3,031		)	78,753		10,992		8,576			2,775
Indirect selling, general, and administrative	—		—			—		—		(18,951		)	—
Total	$	1,045,545	$	(8,701	)	$	1,036,844	$	92,250	$	70,153		$	68,727

Year Ended December 31, 2014:
Terminalling and storage	$	326,654	$	(5,191	)	$	321,463	$	37,622	$	24,993		$	53,450
Natural gas services	1,013,835		—			1,013,835		13,090		34,574			24,194
Sulfur services	215,471		—			215,471		8,176		19,465			4,115
Marine transportation	97,049		(5,677		)	91,372		9,942		7,551			11,498
Indirect selling, general, and administrative	—		—			—		—		(18,712		)	—
Total	$	1,653,009	$	(10,868	)	$	1,642,141	$	68,830	$	67,871		$	93,257

Revenues from two customers in the Natural Gas Services segment were $122,381, $148,273 and $265,434 for the years ended December 31, 2016, 2015 and 2014, respectively.

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



	2016		2015
Total assets:
Terminalling and storage	$	328,098	$	417,202
Natural gas services	684,722		694,333
Sulfur services	125,356		134,108
Marine transportation	108,187		134,830
Total assets	$	1,246,363	$	1,380,473

103

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

(20) Quarterly Financial Information

Consolidated Quarterly Income Statement Information



	(Unaudited)
	First Quarter		Second Quarter			Third Quarter			Fourth Quarter
	(Dollar in thousands, except per unit amounts)
2016
Revenues	$	225,605	$	190,348		$	174,537		$	236,901
Operating income	24,338		10,256			9,176			28,888
Equity in earnings of unconsolidated entities	1,677		805			1,120			1,112
Net income (loss)	$	15,914	$	(1,211	)	$	(933	)	$	17,882
Limited partners' interest in net income (loss) per limited partner unit	$	0.33	$	(0.14	)	(0.03		)	$	0.49

	First Quarter		Second Quarter			Third Quarter			Fourth Quarter
	(Dollar in thousands, except per unit amounts)
2015
Revenues	$	305,353	$	251,099		$	226,021		$	254,371
Operating income	24,702		19,630			12,034			13,787
Equity in earnings of unconsolidated entities	1,740		1,649			2,363			3,234
Income from continuing operations	16,033		10,961			3,330			6,841
Income from discontinued operations	1,215		—			—			—
Net income	$	17,248	$	10,961		$	3,330		$	6,841
Limited partners' interest in net income (loss) per limited partner unit	$	0.37	0.19			(0.02		)	0.08

(21) Commitments and Contingencies

From time to time, the Partnership is subject to various claims and legal actions arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Partnership.

Pursuant to a Purchase Price Reimbursement Agreement between the Partnership and Martin Resource Management related to the Partnership’s acquisition of the Redbird Gas Storage LLC ("Redbird") Class A interests on October 2, 2012, beginning in the second quarter of 2015, Martin Resource Management will reimburse the Partnership $750 each quarter for four consecutive quarters as a reduction in the purchase price of the Redbird Class A interests. These payments are a result of Cardinal not achieving certain financial targets set forth in the Purchase Price Reimbursement Agreement. These payments are considered a reduction of the excess of the purchase price over the carrying value of the assets transferred to the Partnership from Martin Resource Management and will be recorded as an adjustment to "Partners' capital" in each quarter the payments are made. The agreement further provided for purchase price reimbursements of up to $4,500 related to 2016 in the event certain financial conditions are not met. For the years ended December 31, 2016 and 2015, the Partnership received $4,125 and $2,250, respectively, related to the Purchase Price Reimbursement Agreement. The Partnership expects to receive the final payment of $1,125 under this agreement during the first quarter of 2017.

In 2015, the Partnership was named as a defendant in the cause J. A. Davis Properties, LLC v. Martin Operating Partnership L.P., in the 38th Judicial District Court, Cameron Parish, Louisiana. The plaintiff alleges that the Partnership has breached a lease agreement by failing to perform work to the plaintiff's property as required under the lease agreement. The plaintiff originally sought to evict the Partnership from the leased property and to recover damages. Presently, the plaintiff is only pursuing damages. The Partnership intends to vigorously defend this matter and has asserted appropriate counterclaims against the plaintiff. At this time, the Partnership is unable to ascertain the damages, if any, that could ultimately be awarded against it. A trial on the merits is scheduled for July 10, 2017.

On December 31, 2015, the Partnership received a demand from a customer in its lubricants packaging business for defense and indemnity in connection with at least five lawsuits filed against it in the United States District Courts, which

104

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

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

(22) Condensed Consolidating Financial Information

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

(23) Subsequent Events

Repayment of Note Receivable. On February 14, 2017, the Partnership notified Martin Resource Management that it would be requesting voluntary repayment of the Note Receivable due from MET of $15,000 plus accrued interest and MET has agreed to do so in a timely manner.

Acquisition of Terminalling Assets. On February 14, 2017, the Partnership entered into a Membership Interests Purchase Agreement (the “Purchase Agreement”) with Martin Resource Management and MRMC Equipment Holdings LLC, a wholly-owned subsidiary of Martin Resource Management, to acquire 100% of the membership interests of MEH South Texas Terminals LLC (“MEH”) for a purchase price of $27,420 (the “Hondo Acquisition”). MEH is currently constructing in Hondo, Texas an asphalt terminal facility (“the Hondo Terminal”), which will serve the asphalt market in San Antonio, Texas and surrounding areas. The Hondo Acquisition is expected to close on or about February 28, 2017. After closing, the Partnership will spend $8,580 to finalize construction of the Hondo Terminal with substantial completion expected to be on or about July 1, 2017. Martin Resource Management is obligated to pay us the amount required to complete the construction of the Hondo Terminal in excess of $8,580, if any.

Quarterly Distribution. On January 19, 2017, the Partnership declared a quarterly cash distribution of $0.50 per common unit for the fourth quarter of 2016, or $2.00 per common unit on an annualized basis, which was paid on February 14, 2017 to unitholders of record as of February 7, 2017.

105



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

None.



Item 9A.	Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures. In accordance with Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), we, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of our general partner, carried out an evaluation of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15(d)-15(e) of the Exchange Act) as of December 31, 2016. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of our general partner concluded that our disclosure controls and procedures were effective as of December 31, 2016.

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

Our management, including the Chief Executive Officer and Chief Financial Officer of our general partner, conducted an evaluation of the effectiveness of our internal control over financial reporting based on criteria established in the Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in Internal Control — Integrated Framework (2013), our management concluded that our internal control over financial reporting was effective as of December 31, 2016. The effectiveness of our internal control over financial reporting as of December 31, 2016 has been audited by KPMG LLP, our independent registered public accounting firm, as stated in their report appearing in "Item 8 - Financial Statements and Supplementary Data."

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

106



Item 9B.	Other Information

None.

107

PART III



Item 10.	Directors, Executive Officers and Corporate Governance

Management of Martin Midstream Partners L.P.

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

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

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

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

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

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

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Directors and Executive Officers of Martin Midstream GP LLC

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



Name	Age	Position with the General Partner
Ruben S. Martin	65	President, Chief Executive Officer and Director
Robert D. Bondurant	58	Executive Vice President and Chief Financial Officer and Director
Randall L. Tauscher	51	Executive Vice President and Chief Operating Officer
Chris H. Booth	47	Executive Vice President, Chief Legal Officer, General Counsel and Secretary
Scot A. Shoup	56	Senior Vice President of Operations
C. Scott Massey	64	Director
James M. Collingsworth	62	Director
Byron R. Kelley	69	Director
Sean P. Dolan	43	Director
Zachary S. Stanton	41	Director

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

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

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

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

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

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

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

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

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

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

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

Independence of Directors

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

Board Meetings and Committees

From January 1, 2016 to December 31, 2016, the board of directors of our general partner held 15 meetings. All directors then in office attended each of these meetings, either in person, by teleconference or by videoconference with the exception of: Sean Dolan, who was not in attendance at the meetings of the board of directors on the dates of March 2, 2016 and October 13, 2016. Additionally, the board of directors undertook action four times during 2016 without a meeting by acting through written unanimous consent. We have standing conflicts, audit, compensation and nominating committees of the board of directors of our general partner. The board of directors of our general partner appoints the members of the Audit,

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Compensation, Nominating and Conflicts Committees. Each member of the Audit Committee is an independent director in accordance with NASDAQ and applicable securities laws. Each of the board committees has a written charter approved by the board. Copies of each charter are posted on our website at ww.martinmidstream.com under the "Corporate Governance" section. The current members of the committees, the number of meetings held by each committee from January 1, 2016 to December 31, 2016, and a brief description of the functions performed by each committee are set forth below:

Conflicts Committee (3 meetings). The members of the Conflicts Committee are: Messrs. Kelley (chairman), Massey and Collingsworth. All of the members of the Conflicts Committee attended all meetings of the committee for the period noted above. The primary responsibility of the Conflicts Committee is to review matters that the directors believe may involve conflicts of interest. The Conflicts Committee determines if the resolution of the conflict of interest is fair and reasonable to us. The members of the Conflicts Committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates and must meet the independence standards to serve on an audit committee of a board of directors established by NASDAQ. Any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders.

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

Compensation Committee (1 meeting). The members of the Compensation Committee are Messrs. Collingsworth (chairman), Massey and Kelley. All members attended the meeting of the Compensation Committee for the period noted above. The primary responsibility of the Compensation Committee is to oversee compensation decisions for the outside directors of our general partner and executive officers of our general partner (in the event they are to be paid by our general partner) as well as our long-term incentive plan.

Nominating Committee (1 meeting). The members of the Nominating Committee are Messrs. Collingsworth (chairman), Massey, and Kelley. All of the members attended the meeting of the Nominating Committee for the period noted above. The primary responsibility of the nominating committee is to select and recommend nominees for election to the board of directors of our general partner.

Code of Ethics and Business Conduct

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

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Section 16(a) Beneficial Ownership Reporting Compliance

Our general partner's directors and officers and beneficial owners of more than 10% of a registered class of our equity securities are required to file reports of ownership and reports of changes in ownership with the SEC and NASDAQ. Directors, officers and beneficial owners of more than 10% of our equity securities are also required to furnish us with copies of all such reports that are filed. Based solely on our review of copies of such forms and amendments previously provided to us, we believe directors, officers and greater than 10% beneficial owners complied with all filing requirements during the year ended December 31, 2016.

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Item 11.	Executive Compensation

Compensation Discussion and Analysis

Background

We are required to provide information regarding the compensation program in place as of December 31, 2016, for the CEO, CFO and the three other most highly-compensated executive officers of our general partner as reflected in the summary compensation table set forth below (the "Named Executive Officers"). This section should be read in conjunction with the detailed tables and narrative descriptions regarding compensation below.

We are a master limited partnership and have no employees. We are managed by the executive officers of our general partner. These executive officers are employed by Martin Resource Management, a private corporation that has significant operations that are separate from ours. The executive officers of our general partner are also the executive officers of Martin Resource Management and devote significant time to the management of Martin Resource Management’s operations. We reimburse Martin Resource Management for a portion of the indirect general and administrative expenses, including compensation expense relating to the service of these individuals that are allocated to us pursuant to the omnibus agreement between us and our general partner, as amended on October 1, 2012 ("Omnibus Agreement"). Under the Omnibus Agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. For the years ended December 31, 2016, 2015 and 2014, the conflicts committee of our general partner ("Conflicts Committee") approved reimbursement amounts of $13.0 million, $13.7 million and $12.5 million, respectively, reflecting our allocable share of such expenses. Please see "Item 13. Certain Relationships and Related Transactions, and Director Independence — Agreements — Omnibus Agreement" for a discussion of the Omnibus Agreement.

Compensation Objectives

As we do not directly compensate the executive officers of our general partner, we do not have any set compensation programs. The elements of Martin Resource Management’s compensation program discussed below, along with Martin Resource Management’s other rewards, are intended to provide a total rewards package designed to yield competitive total cash compensation, drive performance and reward contributions in support of the businesses of Martin Resource Management and other Martin Resource Management affiliates, including us, for which the Named Executive Officers perform services. Although we bear an allocated portion of Martin Resource Management’s costs of providing compensation and benefits to the Named Executive Officers, we do not have control over such costs and do not establish or direct the compensation policies or practices of Martin Resource Management. During 2016, Martin Resource Management paid compensation based on the performance of Martin Resource Management but did not set any specific performance-based criteria and did not have any other specific performance-based objectives.

Elements of Compensation

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

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

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

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

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

Other Compensation. Martin Resource Management generally does not pay for perquisites for any of the Named Executive Officers, other than general recreational activities at certain Martin Resource Management’s properties located in Texas, including aircraft. No perquisites are paid for services rendered to us. Martin Resource Management provides an executive life insurance policy and long term disability policy for the Named Executive Officers with the annual premiums being paid by Martin Resource Management. Martin Resource Management does not provide any greater allocation toward employee health insurance premiums than is provided for all other employees covered on the health benefits plan.

Compensation Methodology

The compensation policies and philosophy of Martin Resource Management govern the types and amount of compensation granted to each of the Named Executive Officers. The board of directors and Conflicts Committee have responsibility for evaluating and determining the reasonableness of the total amount we are charged under the Omnibus Agreement for managerial, administrative and operational support, including compensation of the Named Executive Officers, provided by Martin Resource Management.

Our allocation for the costs incurred by Martin Resource Management in providing compensation and benefits to its employees who serve as the Named Executive Officers is governed by the Omnibus Agreement. In general, this allocation is based upon estimates of the relative amounts of time that these employees devote to the business and affairs of our general partner and to the business and affairs of Martin Resource Management. We bear substantially less than a majority of Martin Resource Management’s costs of providing compensation and benefits to the Named Executive Officers.

When setting compensation for the Named Executive Officers, the elements of compensation above are considered holistically to provide an appropriate combination of compensation. Annual base salaries for the Named Executive Officers are determined by Mr. Ruben Martin, Chief Executive Officer, Mr. Robert Bondurant, Chief Financial Officer, Mr. Randall Tauscher, Chief Operating Officer, and Mrs. Melanie Mathews, Vice President-Human Resources (collectively, the "Management Compensation Committee of Martin Resource Management") based on a periodic performance review of each Named Executive Officer. Except in the case of an exceptional amount of time devoted to us, discretionary annual cash awards are based on the performance of Martin Resource Management. Annual discretionary cash awards, if any, are calculated first by allocating a portion of Martin Resource Management’s earnings as determined by the Management Compensation Committee of Martin Resource Management for distribution to key employees of Martin Resource Management. Upon such allocation, the Management Compensation Committee of Martin Resource Management, with input from appropriate business leaders determines the allocation and distribution of the bonus pool among such employees, including the Named Executive Officers. All decisions of the Management Compensation Committee of Martin Resource Management concerning the compensation of the Named Executive Officers are reviewed and approved by the Compensation Committee of the Board of Directors of Martin Resource Management, which is made up of Mr. Cullen M. Godfrey, an independent director of Martin Resource Management and Mr. Ruben Martin. With respect to employee benefit plan awards pursuant to plans maintained by the Partnership, the Management Compensation Committee of Martin Resource Management makes a recommendation as to whether such awards should be awarded to any employees. Any such employee plan awards are then considered and must be approved by the Compensation Committee and then are distributed to the employees, including Named Executive Officers, accordingly. Further, Martin Resource Management, with the approval of the Compensation Committee of the Board of Directors of Martin Resource Management or the Compensation Committee regularly reviews market data and relevant compensation surveys when setting base compensation and, when appropriate, engages compensation consultants. Because he serves on both the Management Compensation Committee of Martin Resource Management and on the Compensation Committee of the Board of Directors of Martin Resource Management, Mr. Martin, as Chief Executive Officer, has significant authority in setting base salaries, discretionary annual cash award allocations and amounts and employee benefit award distributions.

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Any awards granted under our long-term incentive plan, which to date have consisted of the grant of restricted common units and options to the independent directors and employees of our general partner, are approved by the Compensation Committee.

Determination of 2016 Compensation Amounts

During 2016, 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 Martin Resource Management employee benefit plans; and (4) other compensation, including limited perquisites. With respect to the Named Executive Officers, they were paid an allocated portion of their base salaries.

Annual Base Salary. The portions of the annual base salaries paid by Martin Resource Management to the Named Executive Officers, which are allocable to us under our Omnibus Agreement with Martin Resource Management, are reflected in the summary compensation table below. Based upon the agreement of our general partner with Martin Resource Management, we have reimbursed Martin Resource Management for approximately 52.4% of the aggregate annual base salaries paid to the Named Executive Officers by Martin Resource Management during 2016. The foregoing agreement has been developed based on an assessment of the estimated percentage of the time spent by the Named Executive Officers managing our affairs, relative to the affairs of Martin Resource Management ranging from approximately 45% to 67%. Our Named Executive Officers are Mr. Ruben Martin, the President and Chief Executive Officer of our general partner, Mr. Robert Bondurant, an Executive Vice President and Chief Financial Officer of our general partner, Mr. Randall Tauscher, an Executive Vice President and Chief Operating Officer of our general partner, Mr. Chris Booth, the Executive Vice President, General Counsel and Secretary of our general partner, and Mr. Scot A. Shoup, Senior Vice President of Operations. Aggregate annual base salaries of the Named Executive Officers were not increased during 2016.

Discretionary Annual Cash Awards. Discretionary annual cash awards paid to the Named Executive Officers which are allocable to us are reflected in the summary compensation table below.

Martin Midstream Partners L.P. Long-Term Incentive Plan

Our general partner has adopted the Martin Midstream Partners L.P. Long-Term Incentive Plan ("LTIP") for employees and directors of our general partner and its affiliates who perform services for us. The LTIP was amended in January 2006 to clarify the Partnership’s ability to grant restricted common units under the LTIP and to remove provisions relating to grants of distribution equivalent rights and phantom units.

The LTIP consists of two components, restricted units and unit options. The LTIP currently permits the grant of awards covering an aggregate of 725,000 common units, 241,667 of which may be awarded in the form of restricted units and 483,333 of which may be awarded in the form of unit options. The plan is administered by the Compensation Committee of our general partner’s board of directors.

Our general partner’s board of directors or the Compensation Committee, in their discretion, may terminate or amend the LTIP at any time with respect to any units for which a grant has not yet been made. Our general partner’s board of directors or the Compensation Committee also have the right to alter or amend the LTIP or any part of the plan from time to time, including increasing the number of units that may be reserved for issuance under the plan subject to any applicable unitholder approval. However, no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the participant.

Restricted Units. A restricted unit is a unit that is granted to grantees with certain vesting restrictions. Once these restrictions lapse, the grantee is entitled to full ownership of the unit without restrictions. A phantom unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit, or in the discretion of the Compensation Committee, cash equivalent to the value of a common unit. The Compensation Committee may determine to make grants under the plan to employees and directors containing such terms as the Compensation Committee shall determine under the plan. The Compensation Committee will determine the period over which restricted units or phantom units granted to employees and directors will vest. The committee may base its determination upon the achievement of specified financial objectives. In addition, the restricted units or phantom units will vest upon a change of control of us, our general partner or Martin Resource Management or if our general partner ceases to be an affiliate of Martin Resource Management.

If a grantee’s employment or membership on the board of directors terminates for any reason, the grantee’s restricted units or phantom units will be automatically forfeited unless, and to the extent, the Compensation Committee provides otherwise. Common units to be delivered upon the vesting of restricted units or phantom units may be common units acquired

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by our general partner in the open market, common units already owned by our general partner, common units acquired by our general partner directly from us or any affiliate of our general partner or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units upon vesting of the restricted units or phantom units, the total number of common units outstanding will increase.

We intend the issuance of the common units upon vesting of the restricted units or phantom units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive, and we will receive no remuneration for the units.

On February 23, 2016, we issued 4,600 restricted common units to each of our three independent directors under our LTIP. These restricted common units vest in equal installments of 1,150 units on January 24, 2017, 2018, 2019, and 2020.

On February 24, 2015, we issued 2,400 restricted common units to each of our three independent directors under our LTIP. These restricted common units vest in equal installments of 600 units on January 24, 2016, 2017, 2018, and 2019.

On October 29, 2014, we issued 2,000 restricted common units to a newly appointed independent director under our LTIP. These restricted common units vest in equal installments of 500 units on October 29, 2015, 2016, 2017, and 2018.

On February 25, 2014, we issued 1,600 restricted common units to each of our four independent directors under our LTIP. These restricted common units vest in equal installments of 400 units on January 24, 2015, 2016, 2017, and 2018.

Unit Options. The LTIP currently permits the grant of options covering common units. As of December 31, 2016 , we have not granted any common unit options to directors or employees of our general partner, or its affiliates. In the future, the Compensation Committee may determine to make grants under the plan to employees and directors containing such terms as the committee shall determine. Unit options will have an exercise price that, in the discretion of the committee, may not be less than the fair market value of the units on the date of grant. In general, unit options granted will become exercisable over a period determined by the Compensation Committee. In addition, the unit options will become exercisable upon a change in control of us, our general partner, Martin Resource Management or if our general partner ceases to be an affiliate of Martin Resource Management or upon the achievement of specified financial objectives.

Upon exercise of a unit option, our general partner will acquire common units in the open market or directly from us or any affiliate of our general partner or use common units already owned by our general partner, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the difference between the cost incurred by our general partner in acquiring these common units and the proceeds received by our general partner from an optionee at the time of exercise. Thus, the cost of the unit options will be borne by us. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase, and our general partner will pay us the proceeds it received from the optionee.

Martin Resource Management Employee Benefit Plans

Martin Resource Management has employee benefit plans for its employees who perform services for us. The following summary of these plans is not complete but outlines the material provisions of these plans.

Martin Resource Management Purchase Plan for Units of Martin Midstream Partners L.P. Martin Resource Management maintains a purchase plan for our units to provide employees of Martin Resource Management and its affiliates who perform services for us the opportunity to acquire an equity interest in us through the purchase of our common units. Each individual employed by Martin Resource Management or an affiliate of Martin Resource Management that provides services to us is eligible to participate in the purchase plan. Enrollment in the purchase plan by an eligible employee will constitute a grant by Martin Resource Management to the employee of the right to purchase common units under the purchase plan. The right to purchase common units granted by the Company under the purchase plan is for the term of a purchase period.

During each purchase period, each participating employee may elect to make contributions to his bookkeeping account each pay period in an amount not less than one percent of his compensation and not more than fifteen percent of his compensation. The rate of contribution shall be designated by the employee at the time of enrollment. On each purchase date (the last day of such purchase period), units will be purchased for each participating employee at the fair market value of such units. The fair market value of the Units to be purchased during such purchase period shall mean the closing sales price of a unit on the purchase date.

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Martin Resource Management Employee Stock Ownership Plans.

MRMC Employee Stock Ownership Plan. Martin Resource Management maintains an employee stock ownership plan that covers employees who satisfy certain minimum age and service requirements ("ESOP"). Under the terms of the ESOP, Martin Resource Management has the discretion to make contributions in an amount determined by its board of directors. Those contributions are allocated under the terms of the ESOP and invested primarily in the common stock of Martin Resource Management. Participants in the ESOP become 100% vested upon completing six years of vesting service or upon their attainment of Normal Retirement Age (as defined in the plan document), permanent disability or death during employment. Any forfeitures of non-vested accounts may be used to pay administrative expenses and restore previous forfeitures of employees rehired before incurring five consecutive breaks-in-service. Any remaining forfeitures will be allocated to the accounts of employed participants. Participants are not permitted to make contributions including rollover contributions to the ESOP.

Martin Employee Stock Ownership Plan. Martin Resource Management maintains an employee stock ownership plan that covers employees who satisfied certain minimum age and service requirements but no Employee shall become eligible to participate in the Plan on or after January 1, 2013. This plan is referred to as the "Martin Employee Stock Ownership Plan". Under the terms of the plan, Martin Resource Management has the discretion to make contributions in an amount determined by its board of directors. Those contributions are allocated under the terms of the Martin Employee Stock Ownership Plan and invested primarily in the common stock of Martin Resource Management. No contributions will be made to the Plan for any Plan Year commencing on or after January 1, 2013. The account balances of any participant who was employed by Martin Resource Management on December 31, 2012 shall be fully vested and non-forfeitable. This plan converted to an employee stock ownership plan on January 1, 2013.

Martin Resource Management 401(k) Profit Sharing Plan. Martin Resource Management maintains a profit sharing plan that covers employees who satisfy certain minimum age and service requirements. This profit sharing plan is referred to as the "401(k) Plan." Eligible employees may elect to participate in the 401(k) Plan by electing pre-tax contributions up to 30% of their regular compensation and/or a portion of their discretionary bonuses. Matching contributions are made to the 401(k) Plan equal to 50% of the first 3% of eligible compensation. Martin Resource Management may make annual discretionary profit sharing contributions in an amount at the plan year end as determined by the board of directors of Martin Resource Management. Participants in the 401(k) Plan become 100% vested in matching contributions immediately and become vested in the discretionary contributions made for them upon completing five years of vesting service or upon their attainment of age 65, permanent disability or death during employment.

Martin Resource Management Non-Qualified Option Plan. In September 1999, Martin Resource Management adopted a stock option plan designed to retain and attract qualified management personnel, directors and consultants. Under the plan, Martin Resource Management is authorized to issue to qualifying parties from time to time options to purchase up to 2,000 shares of its common stock with terms not to exceed ten years from the date of grant and at exercise prices generally not less than fair market value on the date of grant. In November 2007, Martin Resource Management adopted an additional stock option plan designed to retain and attract qualified management personnel, directors and consultants. In December 2013, all outstanding options were exercised or redeemed in lieu of redemption. There are no outstanding options under this plan as of December 31, 2016.

Other Compensation

Martin Resource Management generally does not pay for perquisites for any of our named executive officers other than general recreational activities at certain Martin Resource Management’s properties located in Texas and use of Martin Resource Management vehicles, including aircraft.

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SUMMARY COMPENSATION TABLE

The following table sets forth the compensation expense that was allocated to us for the services of the named executive officers for the years ended December 31, 2016, 2015 and 2014.



Name and Principal Position	Year	Salary		Bonus		Stock Awards (1)		Total Compensation
Ruben S. Martin, President and Chief Executive Officer	2016	$	412,500	$	—	$	—	$	412,500
	2015	$	412,500	$	—	$	356,250	$	768,750
	2014	$	412,500	$	—	$	—	$	412,500
Robert D. Bondurant, Executive Vice President and Chief Financial Officer	2016	$	230,000	$	—	$	—	$	230,000
	2015	$	230,000	$	—	$	85,500	$	315,500
	2014	$	230,000	$	—	$	—	$	230,000
Randall L. Tauscher, Executive Vice President and Chief Operating Officer	2016	$	308,200	$	—	$	—	$	308,200
	2015	$	230,000	$	—	$	85,500	$	315,500
	2014	$	308,200	$	—	$	—	$	308,200
Chris H. Booth, Executive Vice President, General Counsel and Secretary	2016	$	165,240	$	—	$	—	$	165,240
	2015	$	146,880	$	—	$	71,250	$	218,130
	2014	$	165,240	$	—	$	—	$	165,240
Scot A. Shoup, Senior Vice President of Operations	2016	$	180,000	$	—	$	—	$	180,000
	2015	$	180,000	$	—	$	57,000	$	237,000
	2014	$	180,000	$	—	$	—	$	180,000

(1) The amounts shown represent the grant date fair value of awards computed in accordance with FASB ASC 718, however, such awards are subject to vesting requirements which have not been met as it relates to the 2015 stock award. See Note 17 included in Item 8 herein for the assumptions made in our valuation of such awards.

Director Compensation

As a partnership, we are managed by our general partner. The board of directors of our general partner performs for us the functions of a board of directors of a business corporation. Directors of our general partner are entitled to receive total quarterly retainer fees of $16,250 each which are paid by the general partner. Martin Resource Management employees who are a member of the board of directors of our general partner do not receive any additional compensation for serving in such capacity. Officers of our general partner who also serve as directors will not receive additional compensation. All directors of our general partner are entitled to reimbursement for their reasonable out-of-pocket expenses in connection with their travel to and from, and attendance at, meetings of the board of directors or committees thereof. Each director will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law.

The following table sets forth the compensation of our board members for the period from January 1, 2016 through December 31, 2016.



Name	Fees Earned Paid in Cash		Stock Awards		Total
Ruben S. Martin	$	—	$	—	$	—
Robert D. Bondurant	$	—	$	—	$	—
C. Scott Massey (1)	$	65,000	$	69,598	$	134,598
Byron R. Kelley (1)	$	65,000	$	69,598	$	134,598
James M. Collingsworth (1)	$	65,000	$	69,598	$	134,598
Alexander W.F Black	$	—	$	—	$	—
Sean P. Dolan	$	—	$	—	$	—

(1) On February 23, 2016, the Partnership issued 4,600 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

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installments of 1,150 units on February 24, 2017, 2018, 2019 and 2020, respectively. In calculating the fair value of the award, we multiplied the closing price of our common units on the NASDAQ on the date of grant by the number of restricted common units granted to each director.

COMPENSATION REPORT OF THE COMPENSATION COMMITTEE

The Compensation Committee of the general partner of Martin Midstream Partners L.P. has reviewed and discussed the Compensation Discussion and Analysis section of this report with management of the general partner of Martin Midstream Partners L.P. and, based on that review and discussions, has recommended that the Compensation Discussion and Analysis be included in this report.

Members of the Compensation Committee:

/s/ James M. Collingsworth

James M. Collingsworth, Committee Chair

/s/ Byron R. Kelley

Byron R. Kelley

/s/ C. Scott Massey

C. Scott Massey

Compensation Committee Interlocks and Insider Participation

Other than these independent directors, no other officer or employee of our general partner or its subsidiaries is a member of the Compensation Committee. Employees of Martin Resource Management, through our general partner, are the individuals who work on our matters.

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Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following table sets forth the beneficial ownership of our units as of February 15, 2017 held by beneficial owners of 5% or more of the units outstanding, by directors of our general partner, by each executive officer and by all directors and executive officers of our general partner as a group.



Name of Beneficial Owner(1)	Common Units Beneficially Owned	Percentage of Common Units Beneficially Owned (3)
MRMC ESOP Trust (4)	6,264,532	17.7%
Martin Resource Management Corporation (5)	6,264,532	17.7%
Martin Resource, LLC (5)	4,203,823	11.9%
Martin Product Sales LLC (5)	1,171,265	3.3%
Cross Oil Refining & Marketing Inc. (5)	889,444	2.5%
OppenheimerFunds, Inc. (2)	6,151,199	17.4%
Ruben S. Martin (6)	6,395,229	18.0%
Robert D. Bondurant	35,437	—%
Randall L. Tauscher	27,196	—%
Chris H. Booth	11,483	—%
Scot A. Shoup	6,378	—%
Sean Dolan	—	—%
Zachary S. Stanton	—	—%
C. Scott Massey (7)	27,000	—%
Byron R. Kelley	12,600	—%
James M. Collingsworth (8)	10,000	—%
All directors and executive officers as a group (10 persons) (9)	6,525,323	18.4%


(1)	The address for Martin Resource Management Corporation and all of the individuals listed in this table, unless otherwise indicated, is c/o Martin Midstream Partners L.P., 4200 Stone Road, Kilgore, Texas 75662.


(2)	The address for OppenheimerFunds, Inc. is 225 Liberty Street, New York, NY 10281.


(3)	The percent of class shown is less than one percent unless otherwise noted.

(4)

By virtue of its ownership of 85.90% of the outstanding common stock of Martin Resource Management Corporation ("Martin Resource Management"), the MRMC ESOP Trust (the "MRMC ESOP") is the controlling shareholder of Martin Resource Management, and may be deemed to beneficially own the 6,264,532 MMLP Common Units held by Martin Resource LLC, Cross Oil Refining & Marketing Inc., and Martin Product Sales LLC. Wilmington Trust Retirement and Institutional Services Company serves as trustee of the MRMC ESOP but all of its voting and investment decisions are directed by the board of directors of Martin Resource Management. The MRMC ESOP expressly disclaims beneficial ownership of the MMLP Common Units as voting and investment decisions are directed by the board of directors of Martin Resource Management.

(5)

Martin Resource Management is the owner of Martin Resource, LLC, Martin Product Sales LLC, and Cross Oil Refining & Marketing Inc., and as such may be deemed to beneficially own the common units held by Martin Resource LLC, Cross Oil Refining & Marketing Inc, and Martin Product Sales LLC. The 4,203,823 common units beneficially owned by Martin Resource Management through its ownership of Martin Resource, LLC have been pledged as security to a third party to secure payment for a loan made by such third party. The 1,171,265 common units beneficially owned by Martin Resource Management through its ownership of Martin Product Sales LLC have been pledged as security to a third party to secure payment for a loan made by such third party. The 889,444 common units beneficially owned by Martin Resource Management through its ownership of Cross Oil Refining & Marketing Inc. have been pledged as security to a third party to secure payment for a loan made by such third party.


(6)	Includes 130,697 common units owned directly by Mr. Martin, 46,477 of which are pledged to third parties to secure payment for loans. By virtue of serving as the Chairman of the Board and President of Martin Resource

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Management, Ruben S. Martin may exercise control over the voting and disposition of the securities owned by Martin Resource Management, and therefore, may be deemed the beneficial owner of the common units owned by Martin Resource Management, which include 6,264,532 common units beneficially owned through its ownership of Martin Resource LLC, Cross Oil Refining & Marketing Inc. and Martin Product Sales LLC.


(7)	Mr. Massey may be deemed to be the beneficial owner of 1,500 common units held by his wife.


(8)	Mr. Collingsworth may be deemed to be the beneficial owner of 775 common units held by his wife.


(9)	The total for all directors and executive officers as a group includes the common units directly owned by such directors and executive officers as well as the common units beneficially owned by Martin Resource Management as Ruben S. Martin may be deemed to be the beneficial owner thereof.

Martin Resource Management owns a 51% voting interest in the holding company that is the sole member of our general partner and, together with our general partner, owns approximately 17.7% of our outstanding common limited partner units as of December 31, 2016. The table below sets forth information as of December 31, 2016 concerning (i) each person owning beneficially in excess of 5% of the voting common stock of Martin Resource Management, and (ii) the beneficial common stock ownership of (a) each director of Martin Resource Management, (b) each executive officer of Martin Resource Management, and (c) all such executive officers and directors of Martin Resource Management as a group. Except as indicated, each individual has sole voting and investment power over all shares listed opposite his or her name.



	Beneficial Ownership of Voting Common Stock
Name of Beneficial Owner(1)	Number of Shares	Percent of Outstanding Voting Stock
MRMC ESOP Trust (2)	180,698.67	85.90	%
Martin ESOP Trust (3)	29,656.69	14.10	%
Robert D. Bondurant (3)	29,656.69	14.10	%
Randall Tauscher (3)	29,656.69	14.10	%


(1)	The business address of each shareholder, director and executive officer of Martin Resource Management Corporation is c/o Martin Resource Management Corporation, 4200 Stone Road, Kilgore, Texas 75662.

(2)

The MRMC ESOP owns 210,355.36 shares of common stock of Martin Resource Management. Wilmington Trust Retirement and Institutional Services Company serves as trustee of the MRMC ESOP but all of its voting and investment decisions related to the unallocated shares of common stock are directed by the board of directors of Martin Resource Management. Of the common stock held by the MRMC ESOP, 98,225 shares of common stock are allocated to participant accounts, and 82,474 shares of common stock are unallocated.

(3)

Robert D. Bondurant and Randall Tauscher (the "Co-Trustees") are co-trustees of the Martin Employee Stock Ownership Trust which converted from a profit sharing plan known as the Martin Employees' Stock Profit Sharing Plan on January 1, 2014. The Co-Trustees exercise shared control over the voting and disposition of the securities owned by this trust. As a result, the Co-Trustees may be deemed to be the beneficial owner of the securities held by such trust; thus, the number of shares of common stock reported herein as beneficially owned by the Co-Trustees includes the 29,657 shares owned by such trust. The Co-Trustees disclaim beneficial ownership of these 29,657 shares.

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The following table sets forth information regarding securities authorized for issuance under our equity compensation plans as of December 31, 2016:

Equity Compensation Plan Information



	Number of securities to be issued upon exercise of outstanding options, Warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Plan Category	(a)	(b)		(c)
Equity compensation plans approved by security holders	N/A	N/A		N/A
Equity compensation plans not approved by security holders (1)	—	$	—	540,200
Total	—	$	—	540,200

(1) Our general partner has adopted and maintains the Martin Midstream Partners L.P. Long-Term Incentive Plan. For a description of the material features of this plan, please see "Item 11. Executive Compensation – Employee Benefit Plans – Martin Midstream Partners L.P. Long-Term Incentive Plan".

In February 2016, we issued 4,600 restricted common units to independent directors under our long-term incentive plan. These restricted common units vest in equal installments of 1,150 units on January 24, 2017, 2018, 2019 and 2020.

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Item 13.	Certain Relationships and Related Transactions, and Director Independence

Martin Resource Management owns 6,264,532 of our common limited partnership units representing approximately 17.7% of our outstanding common limited partnership units as of February 15, 2017. Martin Resource Management controls Martin Midstream GP LLC, our general partner, by virtue of its 51% voting interest in MMGP Holdings, LLC, the sole member of our general partner. Our general partner owns a 2.0% general partner interest in us and all of our incentive distribution rights. Our general partner’s ability to manage and operate us and Martin Resource Management’s ownership of approximately 17.7% of our outstanding common limited partnership units effectively gives Martin Resource Management the ability to veto some of our actions and to control our management.

Distributions and Payments to the General Partner and its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our formation, ongoing operation and liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.



Formation Stage
The consideration received by our general partner and Martin Resource Management for the transfer of assets to us	Ÿ 4,253,362 subordinated units (All of the original 4,253,362 subordinated units issued to Martin Resource Management have been converted into common units on a one-for-one basis since the formation of the Partnership. 850,672 subordinated units were converted on each of November 14, 2005, 2006, 2007 and 2008, respectively, and 850,674 subordinated units were converted on November 14, 2009)
	Ÿ 2.0% general partner interest; and Ÿ the incentive distribution rights.
Operational Stage
Distributions of available cash to our general partner	We will generally make cash distributions 98% to our unitholders, including Martin Resource Management as holder of all of the subordinated units, and 2% to our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target levels, our general partner will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target level as a result of its incentive distribution rights.
	Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner would receive an annual aggregate distribution of approximately $1.4 million on its 2.0% general partner interest.
Payments to our general partner and its affiliates	Martin Resource Management is entitled to reimbursement for all direct expenses it or our general partner incurs on our behalf. The direct expenses include the salaries and benefit costs employees of Martin Resource Management who provide services to us. Our general partner has sole discretion in determining the amount of these expenses. In addition to the direct expenses, Martin Resource Management is entitled to reimbursement for a portion of indirect general and administrative and corporate overhead expenses. Under the omnibus agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. The conflicts committee of our general partner ("Conflicts Committee") will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually. Please read "Agreements — Omnibus Agreement" below.
Withdrawal or removal of our general partner	If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
Liquidation Stage
Liquidation	Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.

Agreements

Omnibus Agreement

We and our general partner are parties to an omnibus agreement with Martin Resource Management (the "Omnibus Agreement") that governs, among other things, potential competition and indemnification obligations among the parties to the

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agreement, related party transactions, the provision of general administration and support services by Martin Resource Management and our use of certain of Martin Resource Management’s trade names and trademarks. The Omnibus Agreement was amended on November 25, 2009, to include processing crude oil into finished products including naphthenic lubricants, distillates, asphalt and other intermediate cuts. The Omnibus Agreement was amended further on October 1, 2012, to permit the Partnership to provide certain lubricant packaging products and services to Martin Resource Management.

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


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

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

•distributing NGLs; and

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

This restriction does not apply to:


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


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


◦	providing land transportation of various liquids;


◦	distributing fuel oil, sulfuric acid, marine fuel and other liquids;


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


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


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


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


◦	operating an environmental consulting company;


◦	operating an engineering services company;


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


◦	operating a crude oil, natural gas, natural gas liquids, and biofuels optimization business; and


◦	operating, solely for the Partnership's account, the asphalt facilities in Omaha, Nebraska, Port Neches, Texas and South Houston, Texas.


•	any business that Martin Resource Management acquires or constructs that has a fair market value of less than $5,000;

•

any business that Martin Resource Management acquires or constructs that has a fair market value of $5,000 or more if the Partnership has been offered the opportunity to purchase the business for fair market value and the Partnership declines to do so with the concurrence of the conflicts committee of the board of directors of the general partner of the Partnership (the "Conflicts Committee"); and


•	any business that Martin Resource Management acquires or constructs where a portion of such business includes a restricted business and the fair market value of the restricted business is $5,000 or more and represents less than 20%

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of the aggregate value of the entire business to be acquired or constructed; provided that, following completion of the acquisition or construction, the Partnership will be provided the opportunity to purchase the restricted business.

Services. Under the Omnibus Agreement, Martin Resource Management provides us with corporate staff and support services that are substantially identical in nature and quality to the services previously provided by Martin Resource Management in connection with its management and operation of our assets during the one-year period prior to the date of the agreement. The Omnibus Agreement requires us to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes on our behalf or in connection with the operation of our business. There is no monetary limitation on the amount we are required to reimburse Martin Resource Management for direct expenses. In addition to the direct expenses, Martin Resource Management is entitled to reimbursement for a portion of indirect general and administrative and corporate overhead expenses.

Under the Omnibus Agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. For the years ended December 31, 2016, 2015 and 2014, the Conflicts Committee approved and we reimbursed Martin Resource Management of $13.0 million, $13.7 million and $12.5 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.

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

Related Party Transactions. The Omnibus Agreement prohibits us from entering into any material agreement with Martin Resource Management without the prior approval of the Conflicts Committee. For purposes of the Omnibus Agreement, the term material agreements means any agreement between us and Martin Resource Management that requires aggregate annual payments in excess of then-applicable limitation on the reimbursable amount of indirect general and administrative expenses. Please read " Services" above.

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

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

Motor Carrier Agreement

We are a party to a motor carrier agreement effective January 1, 2006, as amended, with Martin Transport, Inc., a wholly owned subsidiary of Martin Resource Management through which Martin Resource Management operates its land transportation operations. Under the agreement, Martin Transport, Inc. agrees to ship our NGL shipments as well as other liquid products.

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

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

Terminal Services Agreements

Diesel Fuel Terminal Services Agreement. Effective January 1, 2016, we entered into a new terminalling services agreement under which we provide terminal services to Martin Resource Management for marine fuel distribution. The per gallon throughput fee we charge under this agreement was increased when compared to the previous agreement and may be adjusted annually based on a price index. This agreement was amended on January 1, 2017 to reduce the minimum throughput requirements under such agreement.

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

Marine Agreements

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

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

Other Agreements

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

Sulfuric Acid Sales Agency Agreement. We are a party to a second amended and restated sulfuric acid sales agency agreement dated August 5, 2013 under which Martin Resource Management purchases and markets the sulfuric acid produced by our sulfuric acid production plant at Plainview, Texas, and which is not consumed by our internal operations. This agreement, as amended, will remain in place until we terminate it by providing 180 days’ written notice. Under this agreement, we sell all of our excess sulfuric acid to Martin Resource Management. Martin Resource Management then markets such acid to third-parties and we share in the profit of Martin Resource Management’s sales of the excess acid to such third parties.

Other Miscellaneous Agreements. From time to time we enter into other miscellaneous agreements with Martin Resource Management for the provision of other services or the purchase of other goods.

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Other Related Party Transactions

Related Party Note Receivable

During March 2013, we acquired 100% of the preferred interests in Martin Energy Trading, LLC ("MET"), for $15.0 million. On August 31, 2014, MET converted its preferred equity to subordinated debt. The resulting $15.0 million note receivable from MET bears an annual interest rate of 15% and matures August 31, 2026. MET may prepay any or all of the note balance on or after September 1, 2016. Interest income for the years ended December 31, 2016, 2015 and 2014 was $2.3 million, $2.3 million, and $0.8 million, respectively.

2014 Public Offerings

In conjunction with public offerings, our general partner contributed $7.0 million in order to maintain its 2.0% general partner interest in us.

Transfers of Assets Between Entities Under Common Control

Natural Gas Liquids ("NGL") Storage Assets. On May 31, 2014, we acquired certain NGL storage assets located in Arcadia, Louisiana, from Martin Resource Management for $7.4 million. The excess carrying value of the assets over the purchase price paid by Martin Resource Management at the sales date was $4.9 million and was recorded as an adjustment to partners' capital.

Miscellaneous

Certain of directors, officers and employees of our general partner and Martin Resource Management maintain margin accounts with broker-dealers with respect to our common units held by such persons. Margin account transactions for such directors, officers and employees were conducted by such broker-dealers in the ordinary course of business.

For information regarding amounts of related party transactions that are included in the Partnership's Consolidated Statements of Operations, please see Footnote 13, "Related Party Transactions", in Part II, Item 8.

Approval and Review of Related Party Transactions

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

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Item 14.	Principal Accounting Fees and Services

KPMG, LLP served as our independent auditors for the fiscal years ended December 31, 2016 and 2015. The following fees were paid to KPMG, LLP for services rendered during our last two fiscal years:



	2016			2015
Audit fees	$	1,192,500	(1)	$	1,347,500	(1)
Audit related fees	—			—
Audit and audit related fees	1,192,500			1,347,500
Tax fees	105,070		(2)	253,700		(2)
All other fees	—			—
Total fees	$	1,297,570		$	1,601,200


(1)	2016 audit fees include fees for the annual integrated audit and fees related to services in connection with transactions. 2015 audit fees include fees for the annual integrated audit and fees related to services in connection with filing updated financial statements and in connection with transactions.


(2)	Tax fees are for services related to the review of our partnership K-1's returns, and research and consultations on other tax related matters.

Under policies and procedures established by the Board of Directors and the Audit Committee, the Audit Committee is required to pre-approve all audit and non-audit services performed by our independent auditor to ensure that the provisions of such services do not impair the auditor’s independence. All of the services described above that were provided by KPMG, LLP in years ended December 31, 2016 and December 31, 2015 were approved in advance by the Audit Committee.

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PART IV



Item 15.	Exhibits, Financial Statement Schedules

(a) Financial Statements, Schedules


(1)	The following financial statements of Martin Midstream Partners L.P. are included in Part II, Item 8:

Reports of Independent Registered Public Accounting Firm

Consolidated Balance Sheets as of December 31, 2016 and 2015

Consolidated Statements of Operations for the years ended December 31, 2016, 2015 and 2014

Consolidated Statements of Changes in Capital for the years ended December 31, 2016, 2015 and 2013

Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015 and 2014

Notes to the Consolidated Financial Statements

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(b) Exhibits

INDEX TO EXHIBITS



Exhibit Number	Exhibit Name

3.1	Certificate of Limited Partnership of Martin Midstream Partners L.P. (the "Partnership"), dated June 21, 2002 (filed as Exhibit 3.1 to the Partnership's Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.2	Second Amended and Restated Agreement of Limited Partnership of the Partnership, dated November 25, 2009 (filed as Exhibit 10.1 to the Partnership's Amendment to Current Report on Form 8-K/A (SEC File No. 000-50056), filed January 19, 2010, and incorporated herein by reference).
3.3	Amendment No. 2 to the Second Amended and Restated Agreement of Limited Partnership of the Partnership dated January 31, 2011 (filed as Exhibit 3.1 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed February 1, 2011, and incorporated herein by reference).
3.4	Amendment No. 3 to the Second Amended and Restated Agreement of Limited Partnership of the Partnership dated October 2, 2012 (filed as Exhibit 10.5 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed October 9, 2012, and incorporated herein by reference).
3.5	Certificate of Limited Partnership of Martin Operating Partnership L.P. (the "Operating Partnership"), dated June 21, 2002 (filed as Exhibit 3.3 to the Partnership's Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.6	Amended and Restated Agreement of Limited Partnership of the Operating Partnership, dated November 6, 2002 (filed as Exhibit 3.2 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed November 19, 2002, and incorporated herein by reference).
3.7	Certificate of Formation of Martin Midstream GP LLC (the "General Partner"), dated June 21, 2002 (filed as Exhibit 3.5 to the Partnership's Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.8	Amended and Restated Limited Liability Company Agreement of the General Partner, dated August 30, 2013 (filed as Exhibit 3.1 to the Partnership's Current Report on Form 8-K (Reg. No. 000-50056), filed September 3, 2013, and incorporated herein by reference).
3.9	Certificate of Formation of Martin Operating GP LLC (the "Operating General Partner"), dated June 21, 2002 (filed as Exhibit 3.7 to the Partnership's Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.10	Limited Liability Company Agreement of the Operating General Partner, dated June 21, 2002 (filed as Exhibit 3.8 to the Partnership's Registration Statement on Form S-1 (Reg. No. 333-91706), filed July 1, 2002, and incorporated herein by reference).
3.11	Certificate of Formation of Arcadia Gas Storage, LLC, dated June 26, 2006 (filed as Exhibit 3.11 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.12	Company Agreement of Arcadia Gas Storage, LLC, dated December 27, 2006 (filed as Exhibit 3.12 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.13	Amendment to the Company Agreement of Arcadia Gas Storage, LLC, dated September 5, 2014 (filed as Exhibit 3.13 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.14	Certificate of Formation of Cadeville Gas Storage LLC, dated May 23, 2008 (filed as Exhibit 3.14 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.15	Limited Liability Company Agreement of Cadeville Gas Storage LLC, dated May 23, 2008 (filed as Exhibit 3.15 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.16	First Amendment to the Limited Liability Company Agreement of Cadeville Gas Storage LLC, dated April 16, 2012 (filed as Exhibit 3.16 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.17	Second Amendment to the Limited Liability Company Agreement of Cadeville Gas Storage LLC, dated September 5, 2014 (filed as Exhibit 3.17 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.18	Certificate of Formation of Monroe Gas Storage Company, LLC, dated June 14, 2006 (filed as Exhibit 3.18 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).

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3.19	Amended and Restated Limited Liability Company Agreement of Monroe Gas Storage Company, LLC, dated May 31, 2011 (filed as Exhibit 3.19 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.20	First Amendment to the Amended and Restated Limited Liability Company Agreement of Monroe Gas Storage Company, LLC, dated September 5, 2014 (filed as Exhibit 3.20 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.21	Certificate of Formation of Perryville Gas Storage LLC, dated May 23, 2008.(filed as Exhibit 3.21 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.22	Limited Liability Company Agreement of Perryville Gas Storage LLC, dated June 16, 2008 (filed as Exhibit 3.22 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.23	First Amendment to the Limited Liability Company Agreement of Perryville Gas Storage LLC, dated April 14, 2010 (filed as Exhibit 3.23 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.24	Second Amendment to the Limited Liability Company Agreement of Perryville Gas Storage LLC, dated September 5, 2014 (filed as Exhibit 3.24 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.25	Certificate of Formation of Cardinal Gas Storage Partners LLC, dated April 2, 2008 (filed as Exhibit 3.25 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.26	Third Amended and Restated Limited Liability Company Agreement of Cardinal Gas Storage Partners LLC (F/K/A Redbird Gas Storage LLC) dated October 27, 2014 (filed as Exhibit 3.26 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
3.27	Certificate of Formation of Redbird Gas Storage LLC, dated May 24, 2011 (filed as Exhibit 3.27 to the Partnership's Annual Report on Form 10-K (SEC File No. 000-50056), filed March 2, 2015, and incorporation herein by reference).
3.28	Second Amended and Restated LLC Agreement of Redbird Gas Storage LLC, dated as of October 2, 2012. (filed as Exhibit 10.6 to the Partnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed November 5, 2012, and incorporated herein by reference).
3.29	Certificate of Merger of Cardinal Gas Storage Partners LLC with and into Redbird Gas Storage LLC, dated October 27, 2014 (filed as Exhibit 3.27 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
4.1	Specimen Unit Certificate for Common Units (contained in Exhibit 3.2).
4.2	Specimen Unit Certificate for Subordinated Units (filed as Exhibit 4.2 to Amendment No. 4 to the Partnership’s Registration Statement on Form S-1 (SEC File No. 333-91706), filed October 25, 2002, and incorporated herein by reference).
4.3	Indenture (including form of 7.250% Senior Notes due 2021), dated February 11, 2013, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed February 12, 2013, and incorporated herein by reference).
4.4	Second Supplemental Indenture, to the Indenture dated February 11, 2013 dated September 30, 2014, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Bank National Association, as trustee (filed as Exhibit 4.4 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014 and incorporated herein by reference).
4.5	Third Supplemental Indenture, to the Indenture dated February 11, 2013 dated October 27, 2014, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Bank National Association, as trustee (filed as Exhibit 4.5 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014 and incorporated herein by reference).
10.1	Third Amended and Restated Credit Agreement, dated March 28, 2013, among the Partnership, the Operating Partnership, Royal Bank of Canada and the other Lenders set forth therein (filed as Exhibit 10.1 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed April 3, 2013 and incorporated herein by reference).
10.2	First Amendment to Third Amended and Restated Credit Agreement, dated as of July 12, 2013, among the Partnership, the Operating Partnership, Royal Bank of Canada and the other Lenders as set forth therein (filed as Exhibit 10.2 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed May 5, 2014 and incorporated herein by reference).

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10.3	Second Amendment to Third Amended and Restated Credit Agreement, dated as of May 5, 2014, among the Partnership, the Operating Partnership, Royal Bank of Canada and the other Lenders as set forth therein (filed as Exhibit 10.2 to the Partnership's Current Report on Form 8-K/A (SEC File No. 000-50056), filed May 6, 2014 and incorporated herein by reference)
10.4	Third Amendment to Third Amended and Restated Credit Agreement, dated June 27, 2014, among the Partnership, the Operating Partnership, Royal Bank of Canada and the other Lenders as set forth therein (filed as Exhibit 10.1 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed July 1, 2014, and incorporated herein by reference).
10.5	Fourth Amendment to Third Amended and Restated Credit Agreement, dated June 23, 2015, among the Partnership, the Operating Partnership, Royal Bank of Canada and the other Lenders as set forth therein (filed as Exhibit 10.1 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed June 24, 2015, and incorporated herein by reference).
10.6	Omnibus Agreement, dated November 1, 2002, by and among Martin Resource Management Corporation, the General Partner, the Partnership and the Operating Partnership (filed as Exhibit 10.3 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed November 19, 2002, and incorporated herein by reference).
10.7	Amendment No. 1 to Omnibus Agreement, dated as of November 25, 2009, by and among Martin Resource Management Corporation, the General Partner, the Partnership and the Operating Partnership (filed as Exhibit 10.3 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed December 1, 2009, and incorporated herein by reference).
10.8	Amendment No. 2 to Omnibus Agreement, dated October 1, 2012, by Martin Resource Management Corporation, the General Partner, the Partnership and the Operating Partnership (filed as Exhibit 10.4 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed October 9, 2012, and incorporated herein by reference).
10.9	Motor Carrier Agreement, dated January 1, 2006, by and between the Operating Partnership and Martin Transport, Inc. (filed as Exhibit 10.9 to the Partnership’s Annual Report on Form 10-K (SEC File No. 000-50056), filed March 2, 2011, and incorporated herein by reference).
10.10	Membership Interests Purchase Agreement, dated August 10, 2014, by and among Energy Capital Partners and its affiliated funds and Redbird Gas Storage LLC (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (Sec File No. 000-50056), filed August 12, 2014, and incorporated herein by reference).
10.11	2014 Amended and Restated Tolling Agreement, dated October 28, 2014, by and between the Operating Partnership and Cross Oil Refining & Marketing, Inc. (filed as Exhibit 10.5 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed October 29, 2014, and incorporated herein by reference).
10.12	Marine Transportation Agreement, dated January 1, 2006, by and between the Operating Partnership and Midstream Fuel Service, L.L.C. (filed as Exhibit 10.10 to the Partnership’s Annual Report on Form 10-K (SEC File No. 000-50056), filed March 2, 2011, and incorporated herein by reference).
10.13	Product Storage Agreement, dated November 1, 2002, by and between Martin Underground Storage, Inc. and the Operating Partnership (filed as Exhibit 10.8 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed November 19, 2002, and incorporated herein by reference).
10.14	Marine Fuel Agreement, dated November 1, 2002, by and between Martin Fuel Service LLC and the Operating Partnership (filed as Exhibit 10.9 to the Partnership’s Current Report on Form 8-K (SEC No. 000-50056), filed November 19, 2002, and incorporated herein by reference).
10.15†	Martin Midstream Partners L.P. Amended and Restated Long-Term Incentive Plan (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC No. 000-50056), filed January 26, 2006, and incorporated herein by reference).
10.16†	Form of Restricted Common Unit Grant Notice (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K (SEC No. 000-50056), filed January 26, 2006, and incorporated herein by reference).
10.17	Purchaser Use Easement, Ingress-Egress Easement, and Utility Facilities Easement dated November 1, 2002, by and between MGSLLC and the Operating Partnership (filed as Exhibit 10.13 to the Partnership’s Current Report on Form 8-K/A (SEC No. 000-50056), filed November 19, 2002, and incorporated herein by reference).
10.18	Amended and Restated Terminal Services Agreement by and between the Operating Partnership and Martin Fuel Service LLC ("MFSLLC"), dated October 27, 2004 (filed as Exhibit 10.1 to the Partnership's Current Report on Form 8-K (SEC No. 000-50056), filed October 28, 2004, and incorporated herein by reference).
10.19	Lubricants and Drilling Fluids Terminal Services Agreement by and between the Operating Partnership and MFSLLC, dated December 23, 2003 (filed as Exhibit 10.4 to the Partnership’s Amendment No. 1 to Current Report on Form 8-K/A (SEC No. 000-50056), filed January 23, 2004, and incorporated herein by reference).
10.20(1)	Second Amended and Restated Sales Agency Agreement, dated August 5, 2013, by and between the Operating Partnership and Martin Product Sales LLC (filed as Exhibit 10.2 to the Partnership's Quarterly Report on Form 10-Q (SEC No. 000-50056) filed November 4, 2013).

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10.21†	Amended and Restated Martin Resource Management Corporation Purchase Plan for Units of the Partnership, effective April 1, 2015 (filed as Exhibit 10.1 to the Partnership's registration statement on Form S-8 (SEC File No. 333-203857), filed May 5, 2015, and incorporated herein by reference).
10.22	Form of Partnership Indemnification Agreement (filed as Exhibit 10.1 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed November 6, 2008, and incorporated herein by reference).
10.23	Amended and Restated Common Unit Purchase Agreement, dated as of November 24, 2009, by and between the Partnership and Martin Resource Management (filed as Exhibit 10.4 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed December 1, 2009, and incorporated herein by reference).
10.24	Supply Agreement dated, as of October 2, 2012, by and between the Partnership and Cross Oil & Refining Marketing Inc. (filed as Exhibit 10.7 to the Partnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed November 5, 2012, and incorporated herein by reference).
10.25	Noncompetition Agreement dated, as of October 2, 2012, by and among the Partnership, Cross Oil Refining & Marketing, Inc., and Martin Resource Management Corporation (filed as Exhibit 10.8 to the Partnership's Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed November 5, 2012, and incorporated herein by reference).
10.26	Purchase Price Reimbursement Agreement, dated October 2, 2012, by Martin Resource Management Corporation to and for the benefit of the Operating Partnership (filed as Exhibit 10.2 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed October 9, 2012, and incorporated herein by reference).
10.27	Lubricants Terminalling Services Agreement, dated January 1, 2015, by and between the Operating Partnership and Martin Energy Services LLC (filed as Exhibit 10.26 to the Partnership's Annual Report on Form 10-K (SEC File No. 000-50056), filed March 2, 2015, and incorporated herein by reference).
10.28	Fuel Terminalling Services Agreement, dated January 1, 2015, by and between the Operating Partnership and Martin Energy Services LLC (filed as Exhibit 10.27 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed October 9, 2012, and incorporated herein by reference).
10.29(1)	First Amended and Restated Fuel Terminalling Services Agreement, dated January 1, 2016, by and between the Operating Partnership and Martin Energy Services, LLC (filed as Exhibit 10.29 to the Partnership's Annual Report on Form 10-K (SEC File No. 000-50056), filed February 29, 2016, and incorporated herein by reference).
10.30(2)*	First Amendment to the First Amended and Restated Fuel Terminalling Services Agreement, dated January 1, 2017, by and between the Operating Partnership and Martin Energy Services, LLC.
21.1*	List of Subsidiaries.
23.1*	Consent of KPMG LLP.
31.1*	Certifications of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certifications of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Chief Executive Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be "filed."
32.2*	Certification of Chief Financial Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be "filed."
101	Interactive Data: the following financial information from Martin Midstream Partners L.P.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016, formatted in Extensible Business Reporting Language: (1) the Consolidated Balance Sheets; (2) the Consolidated Statements of Income; (3) the Consolidated Statements of Cash Flows; (4) the Consolidated Statements of Capital; and (6) the Notes to Consolidated Financial Statements.
*	Filed or furnished herewith.
†	As required by Item 15(a)(3) of Form 10-K, this exhibit is identified as a compensatory plan or arrangement.

(1) Material has been redacted from this exhibit and filed separately with the Commission pursuant to a request for confidential treatment pursuant to Rule 24b-2 of the Securities Exchange Act of 1934, as amended, which has been granted.

(2) Material has been redacted from this exhibit and filed separately with the Commission pursuant to a request for confidential treatment pursuant to Rule 24b-2 of the Securities Exchange Act of 1934, as amended.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, we have duly caused this Report to be signed on our behalf by the undersigned, thereunto duly authorized representative.



	Martin Midstream Partners L.P
	(Registrant)

	By:	Martin Midstream GP LLC
		It's General Partner

Date: February 15, 2017	By:	/s/ Ruben S. Martin
		Ruben S. Martin
		President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 15th day of February, 2017.

134



Signature		Title

/s/ Ruben S. Martin		President, Chief Executive Officer and Director of Martin Midstream GP LLC (Principal Executive Officer)
Ruben S. Martin

/s/ Robert D. Bondurant		Executive Vice President, Director, and Chief Financial Officer of Martin Midstream GP LLC (Principal Financial Officer, Principal Accounting Officer)
Robert D. Bondurant

/s/ Zachary S. Stanton		Director of Martin Midstream GP LLC
Zachary S. Stanton

/s/ James M. Collingsworth		Director of Martin Midstream GP LLC
James M. Collingsworth

/s/ Sean P. Dolan		Director of Martin Midstream GP LLC
Sean P. Dolan

/s/ Byron R. Kelley		Director of Martin Midstream GP LLC
Byron R. Kelley

/s/ C. Scott Massey		Director of Martin Midstream GP LLC
C. Scott Massey

135