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
☒	Securities Exchange Act of 1934

For the fiscal year ended December 31, 2021

OR

☐	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	Trading Symbol(s)	Name of each exchange on which registered
Common Units representing limited partnership interests	MMLP	The 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  ☐                     No ☒

    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 ☐                        No ☒

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 ☒                        No ☐

Indicate by check mark whether the Registrant has submitted electronically, every Interactive Data File required to be submitted 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 such files).

 Yes ☒                        No ☐

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

Large accelerated filer	☐	Accelerated filer	☒
Non-accelerated filer	☐	Smaller reporting company	☐
Emerging growth company	☐

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

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.

Yes ☒      No ☐

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

Yes ☐                        No ☒

    As of June 30, 2021, 38,802,750 common units were outstanding.  The aggregate market value of the common units held by non-affiliates of the registrant as of such date approximated $95,996,227 based on the closing sale price on that date.  There were 38,836,950 of the registrant’s common units outstanding as of March 1, 2022.

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	45
Item 2.	Properties	45
Item 3.	Legal Proceedings	45
Item 4.	Mine Safety Disclosures	45
PART II		46
Item 5.	Market for Our Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	46
Item 6.	Selected Financial Data	46
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	47
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	110
Item 9A.	Controls and Procedures	110
Item 9B.	Other Information	111
PART III		112
Item 10.	Directors, Executive Officers and Corporate Governance	112
Item 11.	Executive Compensation	116
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	126
Item 13.	Certain Relationships and Related Transactions, and Director Independence	129
Item 14.	Principal Accounting Fees and Services	134
PART IV		135
Item 15.	Exhibits, Financial Statement Schedules	135
Item 16.	Form 10-K Summary	139

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PART I

Item 1. Business

    References in this annual report to "we," "ours," "us" or like terms when used in a historical context refer to the assets and operations of Martin Resource Management Corporation'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 Corporation" 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 (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). 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 primarily in the Gulf Coast region of the United States ("U.S."). Our four primary business lines include:

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

•Land and marine transportation services for petroleum products and by-products, chemicals, and specialty products;

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

•Natural gas liquids ("NGL") marketing, distribution, and transportation services.

    Our vertically integrated services have created long-standing relationships with a diversified customer base that includes major and independent oil and gas companies, independent refiners, chemical companies, and other wholesale purchasers of certain petroleum products and by-products, with significant business concentrated around the U.S. Gulf Coast refinery complex, which is a major hub for petroleum refining, natural gas gathering and processing, and support services for the exploration and production industry. The petroleum products and by-products we gather, transport, store and market are produced primarily by major and independent oil and gas companies who often rely on third parties, such as us, for the transportation and disposition of these products.

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    We believe that we have become an integral part of the value chain for our customers by providing them with high value, niche services. We generate a significant amount of our cash flow from fee-based businesses with a significant amount of the working capital demands and margin risk associated with the collective services that we and our sponsor, Martin Resource Management Corporation, provide to customers mainly assumed under contracts between such customers and Martin Resource Management Corporation. Our fixed fee and margin business provides a combination of long-term, spot and evergreen contracts.

    We were formed in 2002 by Martin Resource Management Corporation, 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 Corporation 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 Corporation is an important supplier and customer of ours. As of December 31, 2021, Martin Resource Management Corporation owned 15.8% of our total outstanding common limited partner units. Furthermore, on December 28, 2021, Martin Resource Management Corporation indirectly acquired, through its wholly owned subsidiary, Martin Resource LLC, the remaining 49% voting interest (50% economic interest) in MMGP Holdings, LLC ("Holdings"), which is the sole member of Martin Midstream GP LLC ("MMGP"), our general partner. Such interests were previously held by certain affiliated investment funds managed by Alinda Capital Partners, which sold the interests to Senterfitt Holdings Inc. (“Senterfitt”) on November 23, 2021. At such time, Senterfitt granted Martin Resource LLC the right to purchase such interests for a period of ten years, which right was exercised on December 28, 2021. As a result, Martin Resource Management Corporation indirectly owns 100% of MMGP. Martin Resource Management Corporation directs our business operations through its ownership of our general partner. MMGP owns a 2.0% general partner interest in us, and, until November 23, 2021, MMGP owned all of our incentive distribution rights. On November 23, 2021, MMGP contributed to us all of our incentive distribution rights for no consideration, whereupon the incentive distribution rights were cancelled and cease to exist.

    We entered into an omnibus agreement dated November 1, 2002, with Martin Resource Management Corporation (the "Omnibus Agreement") that governs, among other things, potential competition and indemnification obligations among the parties to the agreement, related party transactions, the provision to us of general administration and support services by Martin Resource Management Corporation and our use of certain of Martin Resource Management Corporation’s trade names and trademarks. Under the terms of the Omnibus Agreement, the employees of Martin Resource Management Corporation are responsible for conducting our business and operating our assets.

    Martin Resource Management Corporation has operated our business since the Partnership's inception in 2002.  Martin Resource Management Corporation began operating our NGL business in the 1950s and our sulfur business in the 1960s. It began our land transportation business in the early 1980s and our marine transportation business in the late 1980s. It entered into our fertilizer and terminalling and storage businesses in the early 1990s.

Primary Business Segments

Our primary business segments can be generally described as follows:

•Terminalling and Storage.  We own or operate 15 marine shore-based terminal facilities and 13 specialty terminal facilities located primarily in the Gulf Coast region of the U.S. with aggregate storage capacity of 2.6 million barrels. We 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 through our shore-based terminals. We provide these terminalling and storage services on a fixed-fee basis and a significant portion of the contracts in this segment provide for minimum fee arrangements that are not based on the volumes handled. We believe that our terminalling, processing, storage and packaging services for petroleum products and by-products would be difficult for our customers or competitors to replicate.

•Transportation.  We operate a fleet of both land transportation and marine transportation assets that transport petroleum products and by-products, petrochemicals, and chemicals. Our land transportation assets include approximately 570 trucks and 1,200 tank trailers which are based across 24 terminals strategically located throughout the U.S. Gulf Coast and southeastern U.S. Our marine transportation assets include 29inland marine tank barges, 14 inland push boats and one articulated offshore tug and barge unit that primarily operate coastwise

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along the Gulf of Mexico and on the U.S. inland waterway system, primarily between domestic ports along the Gulf of Mexico, the Intracoastal Waterway, the Mississippi River system and the Tennessee-Tombigbee Waterway system. Our "refinery and petrochemical services" model is focused on transportation of heavy tank bottoms (by-products) and other petroleum products, hauling NGLs, molten sulfur, sulfuric acid, paper mill liquids, chemicals, and numerous other bulk liquid commodities from refineries and petrochemical production locations to end markets. We provide these transportation services on a fee basis, and many of our customers have long standing contractual relationships with us. We believe our modernized asset base is attractive both to our existing customers as well as potential new customers. In addition, our marine fleet contains several vessels that reflect our focus on specialty products.

•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 Gulf Coast region of the U.S. We purchase and sell molten sulfur on contracts that are tied to sulfur indices to minimize margin fluctuations. We process molten sulfur into prilled or pelletized sulfur at our facilities in Beaumont, Texas and Port of Stockton, California on contracts that traditionally 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. These plants are located in Texas and Illinois and manufacture primarily sulfur-based fertilizer products for wholesale distributors and industrial users. Demand for our sulfur products exists across the globe, and our asset base provides additional opportunities to handle increases in U.S. supply and access to foreign demand.

•Natural Gas Liquids.  We sell and distribute NGLs that we primarily purchase from refineries and natural gas processors. We store and transport NGLs for wholesale deliveries to refineries, industrial NGL users and propane retailers in the southeastern U.S. We own approximately 2.1 million barrels of underground storage capacity for NGLs. This segment is primarily driven by the purchase of butane in the summer months, when demand is typically low, and sale in the winter months, when demand is typically higher.

Significant Developments in 2021

Hurricane Ida. On August 29, 2021, Hurricane Ida ("Ida") made landfall in Southeast Louisiana as a category 4 hurricane. Ida impacted our transportation and sulfur services segments due to the effects on refinery utilization in the Lake Charles, Louisiana area resulting from the storm. We did not experience any material storm-related damage. We spent approximately $0.1 million on restoration and recovery costs as a result of Ida.

Winter Storm Uri. In February 2021, we experienced Winter Storm Uri ("Uri"), an unprecedented storm bringing extreme cold temperatures to Texas and the surrounding areas, which resulted in Gulf Coast refineries running at reduced rates or halting operations entirely. The majority of the impact we experienced was centered around our transportation and sulfur services segments, where we saw reduced activity due to Uri's impact on Gulf Coast refinery utilization. Additionally, our Smackover Refinery was down approximately nine days due to Uri, during which time we began preparations for the previously scheduled turnaround in March of 2021. This allowed us to minimize the amount of downtime at the Smackover Refinery, which was back in operation by March 9, 2021.

COVID-19. We continue to monitor the impacts of the COVID-19 pandemic (including variants of the virus) on all aspects of our business. Travel restrictions and stay-at-home orders in place during much of 2020 that were implemented by governments in many regions and countries across the globe, including the U.S., have greatly impacted the demand for refined products resulting in a significant reduction in refinery utilization, which impacted our 2020 performance and continued to impact our marine transportation business in 2021.

Looking forward, we expect to continue to experience some adverse impacts of COVID-19 in our marine transportation segment, but we believe that refinery utilization will continue to increase as a result of widespread vaccinations and a rebounding economy. This should ultimately improve refined product demand as people continue to return to in-person work and resume travel. We expect this will positively impact our marine transportation business as demand for our services improves.

Overall, the extent to which the duration and severity of the pandemic impacts our business, results of operations, and financial condition will depend on future developments, which are highly uncertain and cannot be predicted at this time. Accordingly, it is possible that the impact of the pandemic, including the impact of variants of COVID-19, could have a material adverse effect on the Partnership's results of operations, financial position and cash flows in 2022, including the recoverability of long-lived assets and goodwill, the valuation of inventory, and the amount of expected credit losses.

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Management considered the impact of the pandemic on the assumptions and estimates used in the preparation of the financial statements. A sustained reduction in refinery demand and utilization could lead to future asset impairments as well as adversely affect access to capital and financing to be able to meet future obligations. Management also assessed the extent to which the current macroeconomic events brought about by the pandemic and significant declines in refined product demand impacted the valuation of expected credit losses on accounts receivable and certain inventory items or resulted in modifications to any significant contracts. Ultimately the results of these assessments did not have a material impact on our results as of December 31, 2021.

Subsequent Events

Quarterly Distribution. On January 25, 2022, we declared a quarterly cash distribution of $0.005 per common unit for the fourth quarter of 2021, or $0.02 per common unit on an annualized basis, which was paid on February 14, 2022 to unitholders of record as of February 7, 2022.

Our Growth Strategy

The key components of our growth strategy are:

•Establish 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 challenges or to achieve operational synergies. We intend to utilize our industry knowledge, network of customers and suppliers, and strategic asset base to expand commercial alliances to drive revenue and cash flow growth in the future.

•Maintain a Disciplined Financial Policy. We intend to continue pursuing a disciplined financial policy that includes continuing to evaluate the sale of non-core assets and conservative capital spending to pay down debt, and prudent control of distributions.

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

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

Competitive Strengths

We believe we are well positioned to execute our business strategy because of the following competitive strengths:

    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, our land transportation assets are based out of terminals located to serve refineries and chemical companies across the U.S. Gulf Coast. Many of our sulfur services assets are located to source sulfur from the largest refinery sources in the U.S. Finally, our terminalling and storage assets are located in areas across the U.S. Gulf Coast to support our refinery-based customers.

Specialized Transportation Equipment and Storage Facilities. We have the assets and expertise to handle and transport an array of 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 (between approximately -30 to +400 degrees Fahrenheit) to remain in liquid form, which our facilities are designed to accommodate. These capabilities help us enhance relationships with our customers by offering them services to handle their unique product requirements.

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Strong Industry Reputation and Established Relationships with Suppliers and Customers. We have established a reputation in our industry as a reliable and cost-effective supplier of services to our customers and have a track record of a 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. We provide specialized value-added services to our customers and believe we have become an integral part of their value chain.

Fee-Based Contracts. We generate a significant amount of our cash flow from fee-based contracts with our customers, many of which are major and independent oil and gas companies with whom we have long-standing customer relationships. A majority of our fee-based contracts consist of reservation charges or minimum fee arrangements, which reduce the volatility of our cash flows due to volume fluctuations.

Vertically Integrated Services Provided for U.S. Gulf Coast-Centric Asset and Operational Footprint. We own and operate a diversified asset base that enables us to offer our customers an integrated distribution network consisting of terminalling, storage, packaging and other midstream logistical services for petroleum products and by-products in one of the world’s most active refining and petrochemical regions.

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's experience and familiarity with our industry and businesses are important assets that assist us in implementing our business strategies. In addition, members of our senior management hold significant limited and general partner interests in us, which we believe aligns incentives with our investors.

    Strong Parent Support. Martin Resource Management Corporation, owner of our general partner, which is privately owned, assumes a significant amount of the working capital demands and margin risk, providing stable fee-based cash flows to our limited partners.

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 of the U.S. 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 of the U.S., 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 of the U.S. as shore bases that provide them logistical support services as well as 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 and regulatory requirements.

Specialty Petroleum Terminals.  We own or operate 13 terminalling facilities providing storage, handling and transportation of various petroleum products and by-products as well as the blending and packaging of naphthenic lubricants and automotive, commercial, industrial, and post-tension greases. 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 primarily organic growth.

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At the Neches, Stanolind, and Tampa terminals, our customers are primarily energy and petrochemical companies. In addition, Martin Resource Management Corporation pays us for terminalling and storage of asphalt at these facilities through a terminalling service agreement that includes a provision for minimum volume throughput requirements. We charge either a fixed monthly fee or a throughput fee for the use of services we perform at 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 Smackover, Arkansas, we own a refinery where we process naphthenic crude oil into finished products that include naphthenic lubricants, distillates, asphalt and other intermediates.  This process is dedicated to a subsidiary of Martin Resource Management Corporation 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 production, packaging and distribution of automotive, commercial and industrial greases. In Houston, Texas, we own and operate a plant that specializes in the production and distribution of commercial and industrial greases. In Phoenix, Arizona, we lease and operate a plant that specializes in the production and distribution of commercial and industrial greases.

We own asphalt terminals in each of Hondo, South Houston, and Port Neches, Texas and Omaha, Nebraska, each dedicated to a subsidiary of Martin Resource Management Corporation through a terminalling service agreement based on throughput rates.

In Beaumont, Texas, we own a terminal ("Spindletop 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 under an arrangement that includes a provision for minimum volume throughput requirements.

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

Terminal	Location	Aggregate Capacity (in barrels)	Products	Description
Tampa 1	Tampa, Florida	662,000	Asphalt, crude oil, and diesel	Marine terminal, loading/unloading for vessels, barges, railcars and trucks
Stanolind	Beaumont, Texas	619,000	Asphalt, crude oil, sulfur, sulfuric acid and fuel oil	Marine terminal, marine dock for loading/unloading of vessels, barges, railcars and trucks
Neches 2	Beaumont, Texas	551,000	Molten sulfur, formed sulfur, ammonia, asphalt, fuel oil, crude oil and sulfur-based fertilizer	Marine terminal, loading/unloading for vessels, barges, railcars and trucks

1 The terminal is located on land owned by the Tampa Port Authority that was leased to us under a lease that expires in December 2026.

2 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.

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

Terminal	Location	Aggregate Capacity	Products	Description
Smackover Refinery	Smackover, Arkansas	7,700 barrels per day; 275,000 barrels of crude bulk storage; 647,000 barrels of lubricant storage	Naphthenic lubricants, distillates, asphalt, crude oil	Naphthenic rude refining facility
Martin Lubricants	Smackover, Arkansas	4.0 million gallons bulk storage	Agricultural, automotive, and industrial lubricants and grease	Lubricants packaging facility
Martin Specialty Products 1	Kansas City, Missouri	14 million pounds of production capacity	Automotive, commercial and industrial greases	Grease manufacturing and packaging facility
Martin Specialty Products	Houston, Texas	16 million pounds of production capacity	Commercial and industrial greases	Grease manufacturing and packaging facility
Martin Specialty Products 2	Phoenix, Arizona	6 million pounds of production capacity	Commercial and industrial greases	Grease manufacturing and packaging facility
Hondo Asphalt	Hondo, Texas	182,000 barrels	Asphalt	Asphalt processing and storage
South Houston Asphalt	Houston, Texas	95,000 barrels	Asphalt	Asphalt processing and storage
Port Neches Asphalt	Port Neches, Texas	17,500 barrels	Asphalt	Asphalt processing and storage
Omaha Asphalt	Omaha, Nebraska	112,000 barrels	Asphalt	Asphalt processing and storage
Spindletop	Beaumont, Texas	90,000 barrels	Natural gasoline	Pipeline receipts and shipments

1 This terminal contains a warehouse owned by third parties and leased under a lease that expires in December 2025 and can be extended by us for one five-year period.

2 This terminal contains a warehouse owned by third parties and leased under a lease that expires in October 2024 and can be extended by us for one five-year period.

Marine Shore-Based Terminals.  We own or operate 15 marine shore-based terminals along the U.S. Gulf Coast from Theodore, Alabama to Corpus Christi, Texas.   Our terminalling assets are located at strategic distribution points for the products we handle and are in close proximity to our customers. We are one of the largest operators of marine shore-based terminals in the Gulf Coast region of the U.S. 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 storage 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. 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 Corporation, 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 three 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.

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

Terminal	Location	Aggregate Capacity (barrels)	End of Lease (Including Options)
Harbor Island 1	Port Aransas, Texas	6,800	December 2039
Pelican Island	Galveston, Texas	87,600	Own
Theodore	Theodore, Alabama	19,900	Own

1 A portion of this terminal is owned.

Fuel and Lubricant Terminals.  We own or operate 12 fuel and lubricant terminals located in the Gulf Coast region of the U.S. that provide storage and handling services for lubricants and fuel oil.

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

Terminal	Location	Aggregate Capacity (barrels)	End of Lease (Including Options)
Amelia	Amelia, Louisiana	13,000	August 2023
Dock 193 3	Gueydan, Louisiana	11,000	May 2022
Fourchon	Fourchon, Louisiana	80,900	May 2027
Fourchon 16	Fourchon, Louisiana	15,200	July 2048
Galveston T 2	Galveston, Texas	10,500	Own
Intracoastal City 2	Intracoastal City, Louisiana	—	Own
Jennings Bulk Plant	Jennings, Louisiana	9,100	Own
Lake Charles T	Lake Charles, Louisiana	1,000	April 2023
Pascagoula 2	Pascagoula, Mississippi	10,100	Own
Port Arthur	Port Arthur, Texas	16,300	November 2025
Port O'Connor 1	Port O'Connor, Texas	6,700	March 2028
Sabine Pass 2	Sabine Pass, Texas	16,100	September 2036

1 This terminal is currently in caretaker status and the lease will not be renewed at the end of the current option.

2 This terminal is currently in caretaker status.

3 A portion of this terminal is owned.

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 U.S. 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

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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 operators as well as major companies that maintain their own similarly equipped marine terminals, shore bases and fuel and lubricant supply sources.

Transportation Segment

Land Transportation

    Industry Overview. The U.S. tank trucking industry is segmented into fleet type, capacity, and product category. The energy and chemical sector relies heavily on the transportation industry to assist in moving mass quantities of petroleum products and by-products, petrochemicals, and chemicals.

Land Fleet.  We operate a fleet of land transportation assets comprising approximately 570 trucks and 1,200 tank trailers that transport petroleum products and by-products, petrochemicals, and chemicals. Our land transportation assets operate out of 24 strategically located terminals throughout the U.S. Gulf Coast and Southeastern U.S.

    The following is a listing of our terminals utilized in our land transportation business:

Terminal Locations
Texas	Louisiana	Arkansas	Other
Baytown	Arcadia	Marion	Theodore, Alabama
Beaumont	Baton Rouge	Smackover	Tampa, Florida
Beaumont Lube	Bossier City	Stephens	Hattiesburg, Mississippi
Channelview	Jennings		Kenova, West Virginia
Corpus Christi	Lake Charles	Tennessee	Pace, Florida
Kilgore	Reserve	Chattanooga
Longview		Kingsport
Plainview

Our largest land transportation customers include petroleum, petrochemical, and chemical companies and Martin Resource Management Corporation. We conduct our land transportation services under fee-based transportation agreements with customers in which we have long term relationships.

We are a party to a master transportation services agreement under which we provide land transportation services to Martin Resource Management Corporation on a demand basis at applicable market rates.  The agreement will continue unless either party terminates the agreement by giving at least 30 days' written notice to the other party.  The rates under this agreement are subject to any adjustments which are mutually agreed upon or in accordance with a price index. Additionally, 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.

    Competition. The U.S. tank trucking market is highly competitive and fragmented, due to the presence of many small and medium-sized market participants. Driver availability plays a major role in each market participant's ability to generate revenue.  We compete primarily with other tank truck transportation companies. Competition in our service regions is based primarily on freight rates, service, efficiency, and available capacity.

Marine Transportation

Industry Overview.  The U.S. 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 of the U.S. 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.

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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. Our marine transportation business operates coastwise along the Gulf of Mexico and east coast of the U.S., as well as 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. 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 :

Class of Equipment	Number in Class	Capacity/Horsepower	Products Transported
Inland tank barges	5	Under 20,000 barrels	Asphalt, crude oil, fuel oil, gasoline and sulfur
Inland tank barges	24	20,000 - 31,000 barrels	Asphalt, crude oil, fuel oil and gasoline
Inland push boats	14	800 - 2,650 horsepower	N/A
Offshore tank barge	1	59,000 barrels	Diesel fuel
Offshore tugboat	1	5,100 horsepower	N/A

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

We are a party to a marine transportation agreement under which we provide marine transportation services to Martin Resource Management Corporation 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 the age of equipment, safety, environmental compliance, quality of service and the availability of a single source of supply of services.

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-barge tow 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 some 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.

Sulfur Services Segment

Industry Overview.  Sulfur is a natural element and is required to produce a variety of industrial products. Sulfur demand in the U.S. generally averages 8.5 million to 9.0 million tons annually, and is concentrated around large phosphate fertilizer operations primarily located in the southeastern parts of the country. 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 U.S. Gulf Coast, along major inland waterways and in some areas of the western U.S.

Sulfur has long been recognized as essential for plant and animal growth and various 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 ammonia and phosphate rock to manufacture phosphate as well as ammonium sulfate and ammonium thiosulfate 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

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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 U.S. 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 two 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 Beaumont, Texas and the Port of Stockton, California, which are used to convert molten sulfur into solid form (prills/granules). 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. The Stockton facility is equipped with one wet prill unit capable of processing 1,000 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.

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

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

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

•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. Our ammonium sulfate plant produces approximately 400 tons per day of quality ammonium sulfate and is marketed to our customers throughout the U.S.  

•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.

•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.

•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

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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.

•Sulfuric acid. 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 sulfuric acid produced and not consumed by the captive ammonium sulfate production is sold to third parties.

Our Sulfur Services Facilities. 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:

Class of Equipment	Number in Class	Capacity/Horsepower	Products Transported
Offshore tank barge	1	10,500 long tons	Molten sulfur
Offshore tugboat	1	5,100 horsepower	N/A
Inland push boat	1	1,200 horsepower	N/A
Inland tank barge	2	2,500 long tons	Molten sulfur

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

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

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

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

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Natural Gas Liquids 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 Transport Inc.'s ("MTI") land transportation fleet or by contracting with common carriers, owner-operators and railroad tank car transportation companies. 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:

•term purchase contracts;

•storage of NGLs;

•the transportation fleet owned by MTI; and

•product management expertise to obtain supplies when needed.

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

NGL Facility	Location	Capacity	Description
Wholesale terminals	Arcadia, Louisiana	2,200,000 barrels	Underground and above ground NGL storage terminal
Rail terminal	Arcadia, Louisiana	24 railcars per day	Railcar loading and unloading facility
Spindletop storage facility	Beaumont, Texas	90,695 barrels	Above ground storage tank and pipeline connections

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

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

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. In September, demand for normal butane typically increases with refineries entering the winter gasoline-blending season, resulting in upward pressure on prices. Abnormally cold weather can put extra upward pressure on propane prices during the winter.

    Competition.  We compete with large integrated NGL producers and marketers as well as small local independent marketers, primarily with respect to location, rates, terms and flexibility of service and supply.

Our Relationship with Martin Resource Management Corporation

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

•distributing asphalt, marine fuel and other liquids;

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

•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;

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

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

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

Ownership

    Martin Resource Management Corporation owns approximately 15.8% of the outstanding limited partner units. In addition, following its acquisition of the remaining 49% voting interest (50% economic interest) in Holdings, which is the sole member of MMGP, Martin Resource Management Corporation indirectly owns 100% of MMGP, our general partner. MMGP owns a 2% general partner interest in us.

    Management

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

Related Party Agreements

The Omnibus Agreement with Martin Resource Management Corporation requires us to reimburse Martin Resource Management Corporation 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 Corporation for $134.7 million, $125.3 million and $138.7 million of direct costs and expenses for the years ended December 31, 2021, 2020 and 2019, respectively.  There is no monetary limitation on the amount we are required to reimburse Martin Resource Management Corporation for direct expenses.

In addition to the direct expenses, under the Omnibus Agreement, we are required to reimburse Martin Resource Management Corporation for indirect general and administrative and corporate overhead expenses.  For the years ended December 31, 2021, 2020, and 2019, the board of directors of our general partner approved reimbursement amounts of $14.4 million, $16.4 million and $16.7 million, respectively, reflecting our allocable share of such expenses. The board of directors of our general partner 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 Corporation 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 Corporation’s retained businesses.  The Omnibus Agreement also contains significant non-compete provisions and indemnity obligations.  Martin Resource Management Corporation also licenses certain of its trademarks and trade names to us under the Omnibus Agreement.

Other agreements include, but are not limited to, a master transportation services agreement, marine transportation agreements, terminal services agreements, and a tolling agreement.  Pursuant to the terms of the Omnibus Agreement, we are prohibited from entering into certain material agreements with Martin Resource Management Corporation without the approval of the conflicts committee of our general partner ("Conflicts Committee").

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For a more comprehensive discussion concerning the Omnibus Agreement and the other agreements that we have entered into with Martin Resource Management Corporation, 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 Corporation. In the aggregate, our purchases from Martin Resource Management Corporation accounted for approximately 16%, 19%, and 17% of our total costs and expenses during for the years ended December 31, 2021, 2020 and 2019, respectively. 

Correspondingly, Martin Resource Management Corporation is one of our significant customers. Our sales to Martin Resource Management Corporation accounted for approximately 9%, 13%, and 11% of our total revenues for each of the years ended December 31, 2021, 2020 and 2019, respectively. 

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

Approval and Review of Related Party Transactions

If we contemplate entering into a transaction, other than a routine or in the ordinary course of business transaction, in which a related person will have a direct or indirect material interest, the proposed transaction is submitted for consideration to the board of directors of our general partner or to our management, as appropriate. If the board of directors is involved in the approval process, it determines whether to refer the matter to the Conflicts Committee, as provided under our limited partnership agreement (the "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 of affected properties. Excluding Neches Industrial Park, the overall minimum deductible ranges from $1.0 million to $5.0 million for damage caused by the named windstorm. Neches Industrial Park has a specific minimum deductible of $3.0 million. Our onshore program currently provides $40.0 million per occurrence and annual aggregate for named windstorm events, including business interruption coverage in connection with a named windstorm event and has a waiting period of 45 to 60 days.

For non-named windstorms or events, our onshore physical damage deductible is $1.0 million per occurrence for all properties. Business interruption coverage in connection with a non-named windstorm or event is subject to a $200.0 million per occurrence as the property damage coverage and has a waiting period of 30 days, excluding the Smackover Refinery which has a waiting period of 45 to 60 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, commonly referred to as a P&I Club, which provides protection and indemnity insurance, and other insurance arrangements. Such membership potentially exposes us to assessments, and/or calls, in the event claims by us or other members exceed available funds and insurance. 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.

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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 continuing 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 pollutant control or 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

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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. The CAA contains 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.

Climate Change. Scientific studies suggest that emissions of certain gases, commonly referred to as greenhouse gases ("GHGs") 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 GHG emissions. Many states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Additionally, as a result of the April 2007 U.S. Supreme Court ruling in Massachusetts, et al. v. EPA deciding that the EPA has authority to regulate carbon dioxide emissions under the CAA, the EPA has taken several steps towards implementing regulations regarding the emission of GHGs. In 2009, the EPA issued a final rule declaring that six GHGs "endanger both the public health and the public welfare of current and future generations." The issuance of this "endangerment finding" allows the EPA to regulate GHG emissions under existing provisions of the federal CAA.

Further, in December 2015, over 190 countries, including the U.S., reached an agreement to reduce global GHG emissions ("Paris Agreement"). The Paris Agreement entered into force in November 2016, after over 70 countries, including the U.S., ratified or otherwise consented to be bound by the agreement. In November 2020, the U.S. formally withdrew from the Paris Agreement. However, on January 20, 2021, President Biden signed an “Acceptance on Behalf of the United States of America” that will allow the U.S. to rejoin the Paris Agreement. The newly signed acceptance, deposited with the United Nations on January 20, 2021, reverses the prior withdrawal. The U.S. officially rejoined the Paris Agreement on February 19, 2021. As part of rejoining the Paris Agreement, President Biden announced that the U.S. would commit to a 50 to 52 percent reduction from 2005 levels of GHG emissions by 2030 and set the goal of reaching net-zero GHG emissions by 2050. In addition, shortly after taking office in January 2021, President Biden issued a series of executive orders designed to address climate change, and new legislation to regulate GHG emissions has been periodically introduced into the U.S. Congress, but none have passed. Reentry into the Paris Agreement, new legislation, or President Biden’s executive orders may result in the development of additional regulations or changes to existing regulations, which could have a material adverse effect on our business and that of our customers. Several states and local governments have also stated their commitment to the principles of the Paris Agreement in their effectuation of policy and regulations. To date, such applicable requirements have not had a substantial effect upon our operations. Still, new legislation or regulatory programs that restrict emissions of GHGs in areas in which we conduct business could adversely affect our operations and demand for our services.

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

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

Clean Water Act

The Federal Water Pollution Control Act of 1972, as amended, also known the 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 permit, or a state permit, or both, must be obtained to discharge pollutants into federal and state waters. In addition, the Clean Water Act and comparable state laws require that individual permits or coverage under general permits be obtained by subject facilities for discharges of storm water runoff. Furthermore, the Clean Water Act potentially requires individual permits or qualification for nationwide permits for activities that involve the discharge of dredged or fill material into waters of the U.S. In June 2015, the EPA and the U.S. Army Corps of Engineers (the “Corps”) finalized a rule intended to clarify the meaning of the term "waters of the U.S.," which established the scope of regulated waters under the Clean Water Act. However, in October 2019, the subject rule was repealed and the pre-2015 regulatory text was re-codified. In April 2020, the EPA and the Army Corps of Engineers issued the final Navigable Waters Protection Rule (“NWPR”) amending the definition of "water of the U.S." and replacing the EPA's October 2019 final rule. Judicial challenges to EPA’s October 2019 and April 2020 final rules are currently before multiple federal district courts. Additionally, the rules are among agency actions listed for review in accordance with President Biden’s January 20, 2021 Executive Order: "Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis." On December 7, 2021, EPA and the Corps published a proposed rule titled the “Revised Definition of ‘Waters of the U.S.’” The proposed rule provides that EPA and the Corps will begin interpreting the WOTUS definition consistent with the Pre-2015 regulatory regime, generally referred to as the “1986 definition,” subject to some amendments that reflect the agencies’ interpretation of the statutory limits on the WOTUS definition and Supreme Court precedent. The proposed rule, if finalized, would be expected to significantly expand federal jurisdiction as compared to the NWPR, and as such, we could face increased costs and delays with respect to obtaining permits for activities in jurisdictional waters, including wetlands. On January 24, 2022, however, the Supreme Court granted certiorari in the case of Sackett v. EPA to determine whether the Ninth Circuit set forth the proper test for determining whether wetlands are “waters of the U.S.” under the Clean Water Act. The Court’s decision to take up this jurisdictional question will undoubtedly impact the agencies’ current rulemaking process addressing the same question. To the extent that any future Supreme Court decisions or final rules expand the scope of the Clean Water Act's jurisdiction, we could face increased costs and delays with respect to permitting. 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. OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages including natural resource damages. Under 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 OPA, and similar legislation.  Any such changes in law affecting areas where we conduct business could materially affect our operations.

Safety Regulation

The Partnership’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 recognized classification society, 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 Safety and Health Regulations

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The workplaces associated with our manufacturing, processing, terminal and storage facilities are subject to the requirements of the federal Occupational Safety and Health Act ("OSH Act") and comparable state statutes. We believe we have conducted our operations in substantial compliance with OSH Act 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 a stringent regimen of vessel inspections, 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.

    Transportation Regulations

    Our trucking operations are subject to regulation by the U.S. Department of Transportation and by various state agencies under the Federal Motor Carrier Safety Act and the Hazardous Materials Transportation Act and analogous state laws. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations, regulatory safety, driver licensing and insurance requirements, and the shipment and packaging of hazardous materials. Additional regulations apply specifically to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations; changes in the hours of service regulations which govern the amount of time a driver may drive or work in any specific period; onboard black box recorder device requirements; or limits on vehicle weight and size. Moreover, various legislative proposals are occasionally introduced, including proposals to increase federal, state, or local taxes on motor fuels, among other things, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.

Human Capital

We do not have any employees.  Under our Omnibus Agreement with Martin Resource Management Corporation, Martin Resource Management Corporation 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 Corporation has approximately 1,450

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employees of which 1,130 individuals, including 59 individuals represented by labor unions, provide direct support to our operations as of December 31, 2021. Martin Resource Management Corporation employees are responsible for conducting our business and operating our assets on our behalf. In addition, we benefit from our relationship with Martin Resource Management Corporation through access to a significant pool of management expertise and established relationships throughout the energy industry.

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 U.S. Securities and Exchange Commission (the "SEC") under the Exchange Act.  These documents may be accessed free of charge on our website at the following address: www.MMLP.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, including our accompanying financial statements and notes and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included herein.

Risk Factor Summary

The following is a summary of risk factors that could adversely impact our business, financial condition, results of operations or our ability to make quarterly distributions to our unitholders:

The reduction in demand for refined products resulting from measures taken to prevent the spread of the COVID-19 virus has and is likely to continue to adversely affect our results of operations, cash flows and financial condition for an indeterminate amount of time.

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 a distribution each quarter.

Restrictions in our debt instruments could prevent us from making distributions to our unitholders or limit our ability to pursue opportunities that would increase our distributions to unitholders.

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

We have a significant amount of indebtedness. Debt we owe or incur in the future could limit our flexibility to obtain financing, to pursue other business opportunities, and to pay distributions to our unitholders.

We have significant capital needs, and our ability to access the capital and credit markets to raise capital on favorable terms is limited by our debt level, industry conditions, and financial covenants in our debt instruments.

Fluctuations in interest rates could materially affect our financial results, and the phase-out of LIBOR may increase interest expense related to our floating rate debt.

We are exposed to counterparty risk in our credit facility and related interest rate protection agreements and we may not be able to access funds under our credit facility if there is a default.

We are exposed to counterparty credit risk. Nonpayment and nonperformance by our customers, suppliers or vendors could reduce our revenues, increase our expenses and otherwise have a negative impact on our ability to conduct our business, operating results, cash flows and ability to make distributions to our unitholders.

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

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Our and our customers’ operations are subject to a series of risks arising out of the threat of climate change that could result in increased operating costs and reduced demand for our services.

Subsidence and coastal erosion could damage our facilities along the U.S. Gulf Coast and offshore and the facilities of our customers, which could adversely affect our operations and financial condition.

Adverse weather conditions, including droughts, hurricanes, tropical storms, ice storms, extreme cold weather and other severe weather, could reduce our results of operations and 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.

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 could incur losses due to impairment in the carrying value of our long-lived assets

Increasing energy prices could adversely affect our results of operations.

Decreasing energy prices could adversely affect our results of operations.

The natural decline in production in our operating regions and in other regions from which we source NGL supplies means our long-term success depends on our ability to obtain new sources of supplies of natural gas, NGLs and crude oil, which depends on certain factors beyond our control. Any decrease in supplies of natural gas, NGLs or crude oil could adversely affect our business and operating results.

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

The highly competitive nature of our industry 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.

Increasing scrutiny and changing expectations from stakeholders with respect to our environmental, social and governance practices may impose additional costs on us or expose us to new or additional risks.

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

Our loss of significant commercial relationships with Martin Resource Management Corporation could adversely impact our results of operations 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.

If third-party pipelines and other facilities interconnected to our terminals become partially or fully unavailable to transport natural gas, NGLs and crude oil, our revenues could be adversely affected.

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.

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.

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.

Changes in transportation regulations may increase our costs and negatively impact our results of operations.

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

A downgrade of our credit ratings could impact our liquidity, access to capital and costs of doing business, and maintaining credit ratings is under the control of independent third parties.

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

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

Our business is subject to complex and evolving U.S. laws and regulations regarding privacy and data protection (“data protection laws”). Many of these laws and regulations are subject to change and uncertain interpretation, and could result in claims, increased cost of operations, or otherwise harm our business.

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.

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 consent of Martin Resource Management Corporation and its affiliates.

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

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.

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.

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

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

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

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.

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

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

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

If Martin Resource Management Corporation 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.

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

The 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.

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.

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, in which case our cash available for distribution to our unitholders might be substantially reduced.

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.

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

Unitholders may be subject to limitations on their ability to deduct interest expenses incurred by us.

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.

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.

Entity level taxes on income from C Corporation subsidiaries will reduce cash available for distribution, and an individual unitholder's share of dividend and interest income from such subsidiaries would constitute portfolio income that could not be offset by the unitholder's share of our other losses or deductions.

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

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

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

We have adopted certain valuation methodologies and monthly conventions for U.S. federal income tax purposes that may result in a shift of income, gain, loss and deduction among our unitholders. The IRS may challenge this treatment, which could adversely affect the value of our units.

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Risks Relating to Our Business

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

The reduction in demand for refined products resulting from measures taken to prevent the spread of the COVID-19 virus has and is likely to continue to adversely affect our results of operations, cash flows and financial condition for an indeterminate amount of time.

The markets experienced a decline in oil prices in response to oil demand concerns due to the economic impacts of the COVID-19 pandemic, greatly impacting the demand for refined products resulting in a significant reduction in refinery utilization. As demand for our services and products decline, we could experience a reduction in the utilization of our assets. The continued spread of COVID-19 (including its variants) or a similar pandemic could result in further instability in the markets and decreases in commodity prices resulting in further adverse impacts on our results of operations, cash flows, and financial condition. In addition, the continued spread of the COVID-19 virus (including its variants), or similar pandemic, and the continuation of the measures to try to contain the virus, such as travel bans and restrictions, quarantines, shelter in place orders, and shutdowns, may further impact our workforce and operations, the operations of our customers, and those of our vendors and suppliers. There is considerable uncertainty regarding such measures and potential future measures, which would have a material adverse effect on our results of operations, cash flows, and financial condition.

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 a distribution each quarter.

    We may not have sufficient available cash each quarter in the future to pay distributions on 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. Other than the requirement in our Partnership Agreement to distribute all of our available cash each quarter, we have no legal obligation to declare quarterly cash distributions, and our general partner has considerable discretion to determine the amount of our available cash each quarter. 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 debt instruments could prevent us from making distributions to our unitholders or limit our ability to pursue opportunities that would increase our distributions to unitholders.

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The payment of principal and interest on our indebtedness reduces the cash available for distribution to our unitholders. In addition, our credit facility and the indentures governing our secured notes severely restrict our ability to make distributions until our total leverage ratio (as defined in the applicable debt instruments) is less than 3.75 to 1.0. After deleveraging, the covenants in our debt instruments will continue to restrict our ability to make distributions, including a prohibition in 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 debt instruments may reduce our ability to incur additional debt, engage in certain transactions, and capitalize on acquisition or other business opportunities that could increase cash flows and distributions to our unitholders.

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

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

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

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

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

•worldwide demand for oil and natural gas (e.g., the reduced demand following the recent COVID-19 pandemic;

•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

    As a result of the decline in commodity prices over the last several years, offshore development activity in the Gulf of Mexico declined substantially, diminishing demand for our terminalling and storage services. We can offer no assurance whether or when those activity levels will improve. Even if such activity levels improve, we expect such activity to continue to be volatile and affect demand for our terminalling and storage services.

We have a significant amount of indebtedness. Debt we owe or incur in the future could limit our flexibility to obtain financing, to pursue other business opportunities, and to pay distributions to our unitholders.

As of December 31, 2021, we had approximately $505.5 million in principal amount of debt outstanding (including $159.5 million outstanding under our credit facility). 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;

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•we may be placed at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size, or those that have less restrictive terms governing their indebtedness, thereby enabling competitors to take advantage of opportunities that our indebtedness may prevent us from pursuing; 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 current or future indebtedness, we will be forced to take actions such as further 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. Further, agreements we may enter into in the future governing our indebtedness could further restrict our ability to make quarterly distributions to our unitholders.

We have significant capital needs, and our ability to access the capital and credit markets to raise capital on favorable terms is limited by our debt level, industry conditions, and financial covenants in our debt instruments.

Our primary sources of liquidity to meet operating expenses, service our indebtedness, pay distributions to our unitholders and fund capital expenditures have historically been provided by cash flows generated by our operations, borrowings under our credit facility and access to the debt and equity capital markets. Accessing capital in the capital markets has become difficult for many companies in the energy industry, in particular leveraged companies similar to us. Low and volatile commodity prices have also caused and may continue to cause lenders to increase interest rates, enact tighter lending standards, refuse to refinance existing debt around maturity on favorable terms or at all and may reduce or cease to provide funding to borrowers. Our inability to access the capital or credit markets on favorable terms could have a material adverse effect on our business, financial condition, results of operations, cash flows and liquidity and our ability to repay or refinance our debt.

The covenants in our debt instruments restrict our ability to incur additional indebtedness. For instance, while our credit facility has $275.0 million in lender commitments, the amount we are able to borrow is limited by the financial covenants contained therein. However, as of December 31, 2021, we had the ability to borrow approximately $92.9 million under our credit facility and were not constrained by such financial covenants.

Fluctuations in interest rates could materially affect our financial results, and the phase-out of LIBOR may increase interest expense related to our floating rate debt.

    Borrowings under our credit facility are at variable rates and include a LIBOR floor of 1.00%. Because a significant portion of our debt bears interest at variable rates, increases in interest rates could materially increase our interest expense. Based on our debt outstanding as of December 31, 2021, if LIBOR exceeds the 1.00% floor 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 $1.6 million annually.

    Further, on March 5, 2021, the Financial Conduct Authority in the U.K. issued an announcement on the future cessation or loss of representativeness of LIBOR benchmark settings currently published by ICE Benchmark Administration. That announcement confirmed that LIBOR will either cease to be provided by any administrator or will no longer be representative after December 31, 2021 for all non-USD LIBOR reference rates, and for certain short-term USD LIBOR reference rates, and after June 30, 2023 for other reference rates. It is uncertain whether LIBOR will be available as a benchmark for pricing our floating rate indebtedness until, or after, June 30, 2023. Our credit facility includes a mechanism to amend the facility to reflect the establishment of an alternative rate of interest upon the occurrence of certain events related to the phase-out of LIBOR. However, we have not yet pursued any technical amendment or other contractual alternative to address this matter and are currently evaluating the impact of the potential replacement of LIBOR. If no such amendment or other contractual alternative is established on or prior to the phase-out of LIBOR, interest under our credit facility will bear interest at higher rates based on the prime rate until such amendment or other contractual amendment is established. Even where we have entered into interest rate swaps or other derivative instruments for purposes of managing our interest rate exposure, our hedging strategies may not be effective as a result of the replacement or phasing out of LIBOR, and our earnings may be subject to volatility. In addition, the overall financial markets may be disrupted as a result of the phase-out or replacement of LIBOR. The potential increase in our interest expense as a result of the phase-out of LIBOR and uncertainty as to the nature of such potential phase-out and alternative references rates or disruption in the financial market could have an adverse effect on our financial condition, results of operations and cash flows.

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We are exposed to counterparty risk in our credit facility and related interest rate protection agreements and we may not be able to access funds under our credit facility if there is a default.

    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. 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.

We are exposed to counterparty credit risk. Nonpayment and nonperformance by our customers, suppliers or vendors could reduce our revenues, increase our expenses and otherwise have a negative impact on our ability to conduct our business, operating results, cash flows and ability to make distributions to our unitholders.

Weak economic conditions and widespread financial distress could reduce the liquidity of our customers, suppliers or vendors, making it more difficult for them to meet their obligations to us. We are therefore subject to risks of loss resulting from nonpayment or nonperformance by our customers. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements. In the event that any of our customers was to enter into bankruptcy, we could lose all or a portion of the amounts owed to us by such customer, and we may be forced to cancel all or a portion of our contracts with such customer at significant expense to us.

In addition, nonperformance by suppliers or vendors who have committed to provide us with critical products or services could raise our costs or interfere with our ability to successfully conduct our business.

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

    We may not be able to successfully integrate 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

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

    If 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.

Our and our customers’ operations are subject to a series of risks arising out of the threat of climate change that could result in increased operating costs and reduced demand for our services.

The threat of climate change continues to attract considerable attention in the U.S. and in foreign countries. Numerous proposals have been made and could continue to be made at the international, national, regional, and state levels to monitor and limit existing emissions of GHGs as well as to restrict or eliminate such future emissions. As a result, our operations, as well as the operations of our customers, are subject to a series of regulatory, political, financial, and litigation risks associated with the processing, terminalling, storage, and transportation of fossil fuels, petroleum products, and emission of GHGs.

In the U.S., no comprehensive climate change legislation has been implemented at the federal level. However, the EPA has adopted rules that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the U.S., and implement New Source Performance Standards directing the reduction of methane from certain new, modified, or reconstructed facilities in the oil and natural gas sector, including midstream sources. Despite potential changes with respect to the federal regulation of GHGs, various states and groups of states have adopted or are considering adopting legislation, regulations, or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and various other measures that would restrict emissions of GHGs from different industrial sectors. At the international level, pursuant to the Paris Agreement, over 190 countries have committed to limiting their GHG emissions through individually-determined reduction goals every five years after 2020. In November 2020, the U.S. formally withdrew from the Paris Agreement. However, on January 20, 2021, President Biden signed an “Acceptance on Behalf of the U.S.,” and the U.S. officially rejoined the Paris Agreement on February 19, 2021. As part of rejoining the Paris Agreement, President Biden announced that the U.S. would commit to a 50 to 52 percent reduction from 2005 levels of GHG emissions by 2030 and set the goal of reaching net-zero GHG emissions by 2050. State, federal, and international regulatory measures have the potential to increase our operating costs through direct regulation of GHG emissions resulting from our operations, and could also indirectly adversely affect our operations by decreasing demand for our services and products.

For example, our business could be impacted by initiatives to address greenhouse gases and climate change and incentives to conserve energy or use alternative energy sources. For example, the Build Back Better Act, passed by the U.S. House of Representatives and supported by President Biden, includes incentives to increase wind and solar electric generation and encourage consumers to use these alternative energy sources. At this time, it is uncertain whether, and in what form, the Build Back Better Act may become law. However, the Build Back Better Act or similar state or federal initiatives to incentivize a shift away from fossil fuels could reduce demand for hydrocarbons, thereby reducing demand for our products and services and negatively impacting our business.

Additionally, there are increasing potential financial risks for fossil fuel energy companies as environmental activists concerned about the potential effects of climate change are focusing intensive lobbying efforts on institutional lenders, including financial institutions and institutional investors, not to provide funding to such companies. Institutional lenders may, of their own accord, elect not to provide funding to fossil fuel energy companies based on climate change concerns. Limitation of investments in fossil fuel energy companies could result in the restriction, delay, or cancellation of drilling programs or development or production activities of our customers, and, consequently, reduce their demand for our services.

Separately, increased attention to climate change risks has increased the possibility of claims brought by public and private entities against energy companies in connection with their GHG emissions and alleged damages resulting from the alleged physical impacts of climate change, such as flooding, coastal erosion, and severe weather events. While courts have generally declined to assign direct liability for climate change to large sources of GHG emissions, new claims for damages and increased government scrutiny, especially from state and local governments, will likely continue. While we are not currently party to any such private litigation, we could be named in future actions making similar claims of liability. Moreover, societal pressures or political or other factors may shape the success of such claims, without regard to the company’s causation of or contribution to the asserted damage, or to other mitigating factors.

The adoption and implementation of new or more stringent international, federal, or state legislation, regulations, or other regulatory initiatives that impose more stringent standards for GHG emissions from oil and natural gas producers or their

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midstream services providers such as ourselves could result in increased costs of compliance or costs of consuming, and thereby reduce demand for or erode value for, the petroleum products and by-products that we process, store and transport. Additionally, political, financial, and litigation risks may result in our customers restricting or cancelling oil and natural gas production activities, which could result in reduced demand for our services. We may also suffer claims for infrastructure damages allegedly caused by climactic changes or be unable to continue to operate in an economic manner. One or more of these developments could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Subsidence and coastal erosion could damage our facilities along the U.S. Gulf Coast and offshore and the facilities of our customers, which could adversely affect our operations and financial condition.

Our assets and operations along the U.S. Gulf Coast and offshore could be impacted by subsidence and coastal erosion. Such processes potentially could cause serious damage to our terminal facilities, which could affect our ability to provide our processing, terminalling, storage and transportation services in the manner presently provided or in a manner consistent with our present plans. Additionally, such processes could impact our customers who operate along the U.S. Gulf Coast, and they may be unable to utilize our services. Subsidence and coastal erosion could also expose our operations to increased risk associated with severe weather conditions, such as hurricanes, flooding, and rising sea levels. As a result, we may incur significant costs to repair and preserve our facilities. Such costs could adversely affect our business, financial condition, results of operations, and cash flows.

Adverse weather conditions, including droughts, hurricanes, tropical storms, ice storms, extreme cold weather 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 of the U.S. 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.

In addition, our assets are vulnerable to winter storms and extreme cold weather. For example, in February 2021, we experienced Winter Storm Uri ("Uri"), an unprecedented storm bringing extreme cold temperatures to Texas and the surrounding areas, which resulted in gulf coast refineries running at reduced rates or halting operations entirely. The majority of the impact we experienced was centered around our transportation and sulfur services segments, where we saw reduced activity due to Uri's impact on Gulf Coast refinery utilization. Additionally, our Smackover Refinery was down approximately nine days due to Uri, during which time we began preparations for the previously scheduled turnaround in March of 2021. .

    National weather conditions have a substantial impact on the demand for our products. Extreme weather conditions (either wet or dry) have in recent years decreased 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. Likewise, unusually warm weather during the winter months can cause a significant decrease in the demand for NGL products. 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 and other petroleum products and by-products;

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•fires and explosions;

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

•terrorist attacks or sabotage.

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

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

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 (including normal butane), 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.

We could incur losses due to impairment in the carrying value of our long-lived assets.

We periodically evaluate goodwill and long-lived assets for impairment. Our impairment analyses for long-lived assets require management to apply judgment in evaluating whether events and circumstances are present that indicate an impairment may have occurred. If we believe an impairment may have occurred judgments are then applied in estimating future cash flows and useful lives, as well as assessing the probability of different outcomes. To perform the impairment assessment for goodwill, we use a discounted cash flow analysis, supplemented by a market approach analysis. Key assumptions in the analysis include industry and economic factors, future operating results and discount rates. In estimating cash flows, we use present economic conditions, as well as future expectations. If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may be exposed to impairment charges. Adverse changes in our business or the overall operating environment may affect our estimate of future operating results, which could result in future impairment due to the potential impact on our operations and cash flows.

Increasing energy prices could adversely affect our results of operations.

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

Decreasing energy prices could adversely affect our results of operations.

    Decreasing energy prices could adversely affect our results of operations. If commodity prices remain weak for a sustained period, our 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.

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For example, due to the economic impacts of the COVID-19 pandemic in 2020, the markets experienced a decline in oil prices in response to oil demand concerns. These concerns were further exacerbated by the price war among members of the Organization of Petroleum Exporting Countries (“OPEC”) and other non-OPEC producer nations during the first quarter of 2020 and global storage considerations. Travel restrictions and stay-at-home orders implemented by governments in many regions and countries across the globe, including the U.S., greatly impacted the demand for refined products resulting in a significant reduction in refinery utilization, which impacted our 2020 performance and continued to impact our marine transportation business in 2021. This impact started in February of 2020 and continued through the end of 202, during which time we saw unfavorable trends in certain key metrics across several of our business lines compared to historical periods. The significant reduction in refinery utilization as a result of reduced refined products demand significantly impacted our Transportation and NGL segments. As the volume of products produced or purchased by refineries reduced, demand for our services decreased.

The natural decline in production in our operating regions and in other regions from which we source NGL supplies means our long-term success depends on our ability to obtain new sources of supplies of natural gas, NGLs and crude oil, which depends on certain factors beyond our control. Any decrease in supplies of natural gas, NGLs or crude oil could adversely affect our business and operating results.

Our terminalling and storage, transportation and NGL services depend on crude oil and natural gas wells from which production will naturally decline over time, which means that the cash flows associated with these sources of natural gas and crude oil will likely also decline over time. To maintain or increase our levels of operation, we must continually obtain new natural gas, NGL and crude oil supplies. A material decrease in natural gas or crude oil production from producing areas on which we rely, as a result of depressed commodity prices or otherwise, could result in a decline in the volume of petroleum products for which we provide terminalling, storage and transportation service or NGL products delivered to our facilities. Our ability to obtain additional sources of natural gas, NGLs and crude oil depends, in part, on the level of successful drilling and production activity near our terminals and other areas from which we source NGL and crude oil supplies. We have no control over the level of such activity in the areas of our operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, we have no control over producers or their drilling, completion or production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations, the availability of drilling rigs, other production and development costs and the availability and cost of capital.

Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling and production activity generally decreases as crude oil and natural gas prices decrease. Prices of crude oil and natural gas have been historically volatile, and we expect this volatility to continue. Consequently, even if new natural gas or crude oil reserves are discovered in areas served by our assets, producers may choose not to develop those reserves. For example, current low prices for natural gas combined with relatively high levels of natural gas in storage could result in curtailment or shut-in of natural gas production similar to the production shut-ins we experienced in 2020 due to the impacts of the COVID-19 pandemic. Furthermore, in response to depressed commodity prices, many operators have announced substantial reductions in their estimated capital expenditures, rig count and completion crews. Reductions in exploration and production activity, competitor actions or shut-ins by producers in the areas in which we operate may prevent us from obtaining supplies of natural gas or crude oil to replace the natural decline in volumes from existing wells, which could result in reduced volumes through our facilities and reduced utilization of our assets.

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

    The demand for NGLs is highest in the winter. Therefore, revenue from our NGL 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.

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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 EPA 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 continuing 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.

Increasing scrutiny and changing expectations from stakeholders with respect to our environmental, social and governance practices may impose additional costs on us or expose us to new or additional risks.

Companies across all industries are facing increasing scrutiny from stakeholders related to their environmental, social, and governance (“ESG”) practices. Investor advocacy groups, certain institutional investors, investment funds, and other influential investors are also increasingly focused on ESG practices and in recent years have placed increasing importance on the implications and social cost of their investments. Regardless of the industry, investors’ increased focus and activism related to ESG and similar matters may hinder access to capital, as investors may decide to reallocate capital or to not commit capital as a result of their assessment of a company’s ESG practices. Companies that do not adapt to or comply with investor or stakeholder expectations and standards, which are evolving, or which are perceived to have not responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, may suffer from reputational damage and the business, financial condition, and/or stock price of such a company could be materially and adversely affected.

Our stakeholders may require us to implement ESG procedures or standards in order to remain invested in us or before they may make further investments in us. Additionally, we may face reputational challenges in the event our ESG procedures or standards do not meet the standards set by certain constituencies. If we do not meet our stakeholders’ expectations, our business, ability to access capital, and/or our common unit price could be harmed.

Additionally, adverse effects upon the oil and gas industry related to the worldwide social and political environment, including uncertainty or instability resulting from climate change, changes in political leadership and environmental policies, changes in geopolitical-social views toward fossil fuels and renewable energy, concern about the environmental impact of climate change and investors’ expectations regarding ESG matters, may also adversely affect demand for our services. Any long-term material adverse effect on the oil and gas industry could have a significant financial and operational adverse impact on our business.

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 Corporation. 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 Corporation to operate and manage our business. Martin Resource Management Corporation 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.

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

    Martin Resource Management Corporation 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 Corporation 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 Corporation to support its businesses under various commercial contracts. The loss of Martin Resource Management Corporation 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.

If third-party pipelines and other facilities interconnected to our terminals become partially or fully unavailable to transport natural gas, NGLs and crude oil, our revenues could be adversely affected.

We depend upon third-party pipelines, storage and other facilities that provide delivery options to and from our terminals. Since we do not own or operate these pipelines or other facilities, their continuing operation in their current manner is not within our control. If any of these third-party facilities become partially or fully unavailable, or if the quality specifications for their facilities change so as to restrict our ability to utilize them, our revenues could be adversely affected.

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.

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    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 U.S. President 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.

Changes in transportation regulations may increase our costs and negatively impact our results of operations.

    We are subject to various transportation regulations by the U.S. Department of Transportation and analogous state agencies, whose regulations include certain permit requirements of highway and safety authorities. These regulatory authorities exercise broad powers over our trucking operations, generally governing such matters as the authorization to engage in motor carrier operations, safety, equipment testing, driver requirements and specifications, and insurance requirements. The trucking industry is subject to possible regulatory and legislative changes that may impact our operations, such as changes in fuel emissions limits, hours of service regulations that govern the amount of time a driver may drive or work in any specific period, and limits on vehicle weight and size. As the federal government continues to develop and propose regulations relating to fuel quality, engine efficiency and GHG emissions, we may experience an increase in costs related to truck purchases and maintenance, impairment of equipment productivity, a decrease in the residual value of vehicles, and an increase in operating expenses. Increased truck traffic may contribute to deteriorating road conditions in some areas where we operate. Our operations could also be affected by road construction, road repairs, detours and state and local regulations and ordinances restricting access to certain roads. Proposals to increase federal, state, or local taxes, including taxes on motor fuels, are also made from time to time, and any such increase could increase our operating costs. Additionally, state and local regulation of permitted routes and times on specific roadways could adversely affect our operations. We cannot predict whether, or in what form, any legislative or regulatory changes or municipal ordinances applicable to our trucking operations will be enacted or to what extent any such legislation or regulations could increase our costs or otherwise adversely affect our business or operations.

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.

A downgrade of our credit ratings could impact our liquidity, access to capital and costs of doing business, and maintaining credit ratings is under the control of independent third parties.

A downgrade of our credit ratings may increase our cost of borrowing and could require us to post collateral with third parties, negatively impacting our available liquidity. Our and our subsidiaries’ ability to access capital markets could also be limited by a downgrade of our credit ratings.

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Credit rating agencies perform independent analysis when assigning credit ratings. The analysis includes a number of criteria including, but not limited to, business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are not recommendations to buy, sell or hold investments in the rated entity. Ratings are subject to revision or withdrawal at any time by the rating agencies, and we cannot assure you that we will maintain our current credit ratings.

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. 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 and those of our third-party providers with whom we are connected. 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. Dependence on automated systems may increase the risks related to operational systems failures and breaches of critical operational or financial controls, and tampering or deliberate manipulation of such systems may result in losses that are difficult to detect. While we take the utmost precautions, we cannot guarantee safety from all threats and attacks. Some individuals and groups, including criminal organizations and state-sponsored groups, have attempted to gain unauthorized access to computer networks of U.S. businesses and mounted so-called “cyberattacks” to disable or disrupt computer systems, disrupt operations, and steal funds or data including through so-called “phishing” schemes, which are attempts to obtain unauthorized access by targeted acts of deception against individuals with legitimate access to physical locations or information. For example, in 2021, a company in the midstream industry suffered a ransomware cyberattack that impacted computerized equipment managing a pipeline and resulted in the halt of the pipeline’s operations in order to contain the attack.

Any successful breach of security with respect to us or our third-party providers 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 effect on our business, financial conditions and operations. Due to COVID-19 protocols, many of our employees and those of our service providers, vendors and customers have been accessing computer systems remotely where their cybersecurity protections may be less robust and our cybersecurity procedures and safeguards may be less effective. While we make significant investments in technology security and we carefully evaluate the security of selected cloud system providers and cloud storage providers, there can be no guarantee that information security efforts will be totally effective.

Moreover, as cyberattacks continue to evolve, we may be required to expend significant additional resources to further enhance our digital security or to remediate vulnerabilities. In addition, cyberattacks against us or others in our industry could result in additional regulations, which could lead to increased regulatory compliance costs, insurance coverage cost, or capital expenditures and any failure by us to comply with these additional regulations could result in significant penalties and liability to us. In May and July 2021, following ransomware attacks on a major petroleum pipeline, the Department of Homeland Security issued security directives to certain midstream pipeline companies that require such companies to appoint cybersecurity personnel, perform cybersecurity assessments and complete specific network enhancements, and report incidents and other information to the Department’s Cybersecurity and Infrastructure Security Agency. We cannot predict the potential impact to our business or the energy industry resulting from additional regulations.

Our business is subject to complex and evolving U.S. laws and regulations regarding privacy and data protection (“data protection laws”). Many of these laws and regulations are subject to change and uncertain interpretation, and could result in claims, increased cost of operations, or otherwise harm our business.

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The regulatory environment surrounding data privacy and protection is constantly evolving and can be subject to significant change. New data protection laws pose increasingly complex compliance challenges and potentially elevate our costs. Complying with varying jurisdictional requirements could increase the costs and complexity of compliance, and violations of applicable data protection laws can result in significant penalties. Any failure, or perceived failure, by us to comply with applicable data protection laws could result in proceedings or actions against us by governmental entities or others, subject us to significant fines, penalties, judgments, and negative publicity, require us to change our business practices, increase the costs and complexity of compliance, and adversely affect our business. As noted above, we are also subject to the possibility of cyberattacks, which themselves may result in a violation of these laws.

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 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.

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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 Corporation 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, 2021, Martin Resource Management Corporation owned 15.8% of our total outstanding common limited partner units and all of the ownership interests in MMGP, our general partner.

    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.

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    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 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.

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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 Corporation, 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 Corporation

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

    Under our Omnibus Agreement with Martin Resource Management Corporation, Martin Resource Management Corporation 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 Corporation for the costs and expenses it incurs in rendering these services, including an overhead allocation to us of Martin Resource Management Corporation's indirect general and administrative expenses from its corporate allocation pool. These payments may be substantial. Payments to Martin Resource Management Corporation will reduce the amount of available cash for distribution to our unitholders.

Martin Resource Management Corporation 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, 2021, Martin Resource Management Corporation owned 15.8% of our total outstanding common limited partner units and 100% of the ownership interests in MMGP. MMGP owns a 2% general partnership interest in us.

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Conflicts of interest may arise between Martin Resource Management Corporation 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 Corporation over the interests of our unitholders. Potential conflicts of interest between us, Martin Resource Management Corporation 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 Corporation who provide services to us also devote significant time to the businesses of Martin Resource Management Corporation and are compensated by Martin Resource Management Corporation for that time;

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

•Martin Resource Management Corporation 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 Corporation, 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 Corporation 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 Corporation;

•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 Corporation and its affiliates may engage in limited competition with us.

    Martin Resource Management Corporation 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 Corporation 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 unitholder allocations.

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If Martin Resource Management Corporation 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 Corporation 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 Corporation or a bankruptcy filing by or against Martin Resource Management Corporation 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 Corporation could also result in the termination or material breach of some or all of the various commercial contracts between us and Martin Resource Management Corporation, which could have a material adverse impact on our results of operations, cash flow and ability to make distributions to our unitholders.

Tax Risks

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

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

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

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

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

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

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

    At the federal level, members of Congress and the President of the U.S. have periodically considered substantive changes to the existing U.S. tax laws that would have affected certain publicly traded partnerships, including the elimination of partnership tax treatment for publicly traded partnerships. At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay a Texas margin tax at a maximum effective

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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 our unitholders.

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

On January 24, 2017, the U.S. Department of the Treasury issued final regulations (the "Final Regulations") regarding qualifying income under Section 7704(d)(1)(E) of the Code which relates to the qualifying income exception upon which we rely for partnership tax treatment. The Final Regulations apply to income earned in a taxable year beginning on or after January 19, 2017. The Final Regulations include "reserved" paragraphs for fertilizer and hedging, which the U.S. Department of the Treasury plans to address in future proposed and final Treasury regulations ("Treasury regulations"). We are unable to predict how such future regulations may treat fertilizer or hedging activities, but such regulations could impact our ability to treat certain activities as generating qualifying income. 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, 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.

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, 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.

    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. 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, we are required to designate a partner, or other person, with a substantial presence in the U.S. 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. We have designated our general partner as our Partnership Representative. Further, any actions taken by us or by the Partnership Representative on our behalf with respect to, among other things, federal income tax audits and judicial review of administrative adjustments by the IRS, will be binding on us and all of our unitholders.

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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.

A unitholder’s share of our taxable income, and its relationship to any distributions we make, may be affected by a variety of factors, including our economic performance, which may be affected by numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Additionally, 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.

Unitholders may be subject to limitations on their ability to deduct interest expenses incurred by us.

In general, the Partnership is entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during its taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, the deduction for "business interest" is limited to the sum of the Partnership’s business interest income and 30% of its "adjusted taxable income." For the purposes of this limitation, the Partnership’s adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion to the extent such depreciation, amortization, or depletion is not capitalized into cost of goods sold with respect to inventory. For our 2020 tax year only, the Coronavirus Aid, Relief, and Economic Security Act increased the 30% adjusted taxable income limitation to 50%. If the Partnership’s "business interest" is subject to limitation under these rules, unitholders will be limited in their ability to deduct their share of any interest expense that has been allocated to them. As a result, unitholders may be subject to limitation on their ability to deduct interest expenses incurred by the Partnership.

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 taxable income (“UBTI”) and will be taxable to them. An exempt organization is required to independently compute its UBTI from each separate unrelated trade or business which may prevent an exempt organization from utilizing losses we allocate to the organization against the organization’s UBTI from other sources and vice versa.

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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. In addition, if a unitholder sells or otherwise disposes of a unit, the transferee is required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person, and we are required to deduct and withhold from the transferee amounts that should have been withheld by the transferee but were not withheld. However, the U.S. Treasury and the IRS have suspended these rules for transfers of certain publicly traded partnership interests, including transfers of our common units that occur before January 1, 2023. Under recently finalized Treasury Regulations and a recent IRC Notice, in the case of transfers of our common units occurring on or after January 1, 2023, such withholding will be required on open market transactions, but in the case of a transfer made through a broker, the obligation to withhold will be imposed on the broker instead of the transferee (and we will generally not be required to withhold from the transferee amounts that should have been withheld by the transferee but were not withheld).

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.

Entity level taxes on income from C corporation subsidiaries will reduce cash available for distribution, and an individual unitholder’s share of dividend and interest income from such subsidiaries would constitute portfolio income that could not be offset by the unitholder’s share of our other losses or deductions.

A portion of our taxable income is earned through MTI, which is a C corporation for federal tax purposes. C corporations are subject to federal income tax on their taxable income at the corporate tax rate, which is currently 21%, and will likely pay state (and possibly local) income tax at varying rates on their taxable income. Any such entity level taxes will reduce the cash available for distribution to our unitholders. Distributions from any such C corporation are generally taxed again to unitholders as dividend income to the extent of current and accumulated earnings and profits of such C corporation. As of December 31, 2021, the maximum federal income tax rate applicable to such qualified dividend income that is allocable to individuals was 20% (plus a 3.8% net investment income tax that applies to certain net investment income earned by individuals, estates and trusts). An individual unitholders’ share of dividend and interest income from MTI or other C corporation subsidiaries would constitute portfolio income that could not be offset by the unitholders’ share of our other losses or deductions.

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, 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

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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, the excess loss limitation rules for non-corporate unitholders that applies until January 1, 2026, and the prohibition against loss allocations in excess of the unitholder's tax basis in its units.

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

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

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

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

We have adopted certain valuation methodologies and monthly conventions for U.S. federal income tax purposes that may result in a shift of income, gain, loss and deduction among our unitholders. The IRS may challenge this treatment, which could adversely affect the value of our units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

A successful IRS challenge to these methods or allocations could adversely affect the amount, character and timing of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders' sale of units and could have a negative impact on the value of the units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.

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Item 1B. Unresolved Staff Comments

None. 

Item 2. Properties

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

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

Item 3. Legal Proceedings

    From time to time, we are subject to certain legal proceedings, claims and disputes that arise in the ordinary course of our business. Although we cannot predict the outcomes of these legal proceedings, these actions, in the aggregate, could 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 20. Commitments and Contingencies", and is incorporated herein by reference.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

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

Market Information and Holders

Our common units are traded on the NASDAQ under the symbol "MMLP." As of March 1, 2022, there were approximately 211 holders of record and approximately 10,711 beneficial owners of our common units.  

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 made 98% to unitholders and 2% to our general partner.

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."

    Quarterly Distribution. On January 25, 2022, we declared a quarterly cash distribution of $0.005 per common unit for the fourth quarter of 2021, or $0.02 per common unit on an annualized basis, which was paid on February 14, 2022 to unitholders of record as of February 7, 2022.

Item 6. [Reserved]

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

Overview

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

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

•Land and marine transportation services for petroleum products and by-products, chemicals, and specialty products;

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

•NGL marketing, distribution, and transportation services.

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, and other wholesale purchasers of these products. We operate primarily in the Gulf Coast region of the U.S. This region is a major hub for petroleum refining, natural gas gathering and processing, and support services for the exploration and production industry.

Significant Recent Developments

Hurricane Ida. On August 29, 2021, Ida made landfall in Southeast Louisiana as a category 4 hurricane. Ida impacted our transportation and sulfur services segments due to the effects on refinery utilization in the Lake Charles, Louisiana area resulting from the storm. We did not experience any material storm-related damage. We spent approximately $0.1 million on restoration and recovery costs as a result of Ida.

Winter Storm Uri. In February 2021, we experienced Winter Storm Uri ("Uri"), an unprecedented storm bringing extreme cold temperatures to Texas and the surrounding areas, which resulted in Gulf Coast refineries running at reduced rates or halting operations entirely. The majority of the impact we experienced was centered around our transportation and sulfur services segments, where we saw reduced activity due to Uri's impact on Gulf Coast refinery utilization. Additionally, our Smackover Refinery was down approximately nine days due to Uri, during which time we began preparations for the previously scheduled turnaround in March of 2021. This allowed us to minimize the amount of downtime at the Smackover Refinery, which was back in operation by March 9, 2021.

COVID-19. We continue to monitor the impacts of the COVID-19 pandemic (including variants of the virus) on all aspects of our business. Travel restrictions and stay-at-home orders in place during much of 2020 that were implemented by governments in many regions and countries across the globe, including the U.S., have greatly impacted the demand for refined products resulting in a significant reduction in refinery utilization, which impacted our 2020 performance and continued to impact our marine transportation business in 2021.

Looking forward, we expect to continue to experience some adverse impacts of COVID-19 in our marine transportation segment, but we believe that refinery utilization will continue to increase as a result of widespread vaccinations and a rebounding economy. This should ultimately improve refined product demand as people continue to return to in-person work and resume travel. We expect this will positively impact our marine transportation business as demand for our services improves.

Overall, the extent to which the duration and severity of the pandemic impacts our business, results of operations, and financial condition will depend on future developments, which are highly uncertain and cannot be predicted at this time. Accordingly, it is possible that the impact of the pandemic, including the impact of variants of COVID-19, could have a material adverse effect on the Partnership's results of operations, financial position and cash flows in 2022, including the recoverability of long-lived assets and goodwill, the valuation of inventory, and the amount of expected credit losses.

Management considered the impact of the pandemic on the assumptions and estimates used in the preparation of the financial statements. A sustained reduction in refinery demand and utilization could lead to future asset impairments as well as

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adversely affect access to capital and financing to be able to meet future obligations. Management also assessed the extent to which the current macroeconomic events brought about by the pandemic and significant declines in refined product demand impacted the valuation of expected credit losses on accounts receivable and certain inventory items or resulted in modifications to any significant contracts. Ultimately the results of these assessments did not have a material impact on our results as of December 31, 2021.

Regulatory Developments. On January 20, 2021, the Biden Administration came into office and immediately issued a number of executive orders related to climate change and the production of oil and gas that could affect our operations and those of our customers. On his first day in office, President Biden signed an instrument reentering the U.S. into the Paris Agreement, effective February 19, 2021, and issued an executive order on “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis” seeking to adopt new regulations and policies to address climate change and suspend, revise, or rescind prior agency actions that are identified as conflicting with the Biden Administration’s climate policies. In addition, on January 27, 2021, President Biden issued an executive order indefinitely suspending new oil and natural gas leases on public lands or in offshore waters pending completion of an ongoing comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. On June 15, 2021, however, a judge in the U.S. District Court for the Western District of Louisiana issued a nationwide temporary injunction blocking the suspension. The Department of the Interior appealed the U.S. District Court’s ruling but resumed oil and gas leasing pending resolution of the appeal. In November 2021, the Department of the Interior completed its review and issued a report on the federal oil and gas leasing program. The Department of the Interior’s report recommends several changes to federal leasing practices, including changes to royalty payments, bidding, and bonding requirements. Furthermore, on April 22, 2021, at a global summit on climate change, President Biden committed the U.S. to target emissions reductions of 50-52% of 2005 levels by 2030. Lastly, on June 30, 2021, President Biden signed into law a reinstatement of regulations put in place during the Obama administration regarding methane emissions. The Company had previously complied with these regulations during the Obama administration and does not expect the reinstatement to have a material effect on the Company or its operations. The Biden Administration could also seek, in the future, to put into place additional executive orders, policy and regulatory reviews, or seek to have Congress pass legislation that could adversely affect the production of oil and natural gas, and our operations and those of our customers.

For more information about the potential physical effects of climate change and environmental regulation on our business, see our environmental and climate change related risk factors in Section 1A “Risk Factors.”

Subsequent Events

Quarterly Distribution. On January 25, 2022, we declared a quarterly cash distribution of $0.005 per common unit for the fourth quarter of 2021, or $0.02 per common unit on an annualized basis, which was paid on February 14, 2022 to unitholders of record as of February 7, 2022.

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 U.S. 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, 2021 and 2020:

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Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
Impairment of Long-Lived Assets
We periodically evaluate whether the carrying value of long-lived assets has been impaired when circumstances indicate the carrying value of the assets may not be recoverable. These evaluations are based on undiscounted cash flow projections over the remaining useful life of the asset. The carrying value is not recoverable if it exceeds the sum of the undiscounted cash flows. Any impairment loss is measured as the excess of the asset's carrying value over its fair value.	Our impairment analyses require management to use judgment in estimating future cash flows and useful lives, as well as assessing the probability of different outcomes.	Applying this impairment review methodology, no impairment was recorded during the year ended December 31, 2021. We recorded an impairment charge of $3.1 million and $1.3 million in our Terminalling and Storage and Transportation segments, respectively, during the year ended December 31, 2020. No impairment of long-lived assets was recorded during the year ended December 31, 2019.
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.	Applying this impairment review methodology, we considered the impact that COVID-19 had on our cash flows and the value our unit price during 2021 and 2020 and elected to bypass the qualitative assessment and perform a quantitative assessment during each of those years. Based upon the most recent annual review as of August 31, 2021, no goodwill impairment exists within our reporting units for the year ended December 31, 2021. No goodwill impairment was recorded during the years ended December 31, 2020 or 2019.

Our Relationship with Martin Resource Management Corporation

Martin Resource Management Corporation directs our business operations through its ownership of our general partner and under the Omnibus Agreement. In addition to the direct expenses payable to Martin Resource Management Corporation under the Omnibus Agreement, we are required to reimburse Martin Resource Management Corporation for indirect general and administrative and corporate overhead expenses. For the years ended December 31, 2021, 2020 and 2019, the board of directors of our general partner approved reimbursement amounts of $14.4 million, $16.4 million and $16.7 million, respectively, reflecting our allocable share of such expenses. The board of directors of our general partner will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.

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

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Non-GAAP Financial Measures

To assist management in assessing our business, we use the following non-GAAP financial measures: earnings before interest, taxes, and depreciation and amortization ("EBITDA"), adjusted EBITDA (as defined below), distributable cash flow available to common unitholders (“Distributable Cash Flow”), and free cash flow after growth capital expenditures and principal payments under finance lease obligations ("Adjusted Free Cash Flow"). 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.

Certain items excluded from EBITDA and Adjusted EBITDA are significant components in understanding and assessing an entity's financial performance, such as cost of capital and historical costs of depreciable assets.

EBITDA and Adjusted EBITDA. We define Adjusted EBITDA as EBITDA before unit-based compensation expenses, gains and losses on the disposition of property, plant and equipment, impairment and other similar non-cash adjustments. Adjusted EBITDA is used as a supplemental performance and liquidity measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts, and others, to assess:

•the financial performance of our assets without regard to financing methods, capital structure, or historical cost basis;

•the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, and make cash distributions to our unitholders; and

•our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing methods or capital structure.

The GAAP measures most directly comparable to adjusted EBITDA are net income (loss) and net cash provided by operating activities. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss), operating income (loss), net cash provided by operating activities, or any other measure of financial performance presented in accordance with GAAP. Adjusted EBITDA may not be comparable to similarly titled measures of other companies because other companies may not calculate Adjusted EBITDA in the same manner.

Adjusted EBITDA does not include interest expense, income tax expense, and depreciation and amortization. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate cash available for distribution. Because we have capital assets, depreciation and amortization are also necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider net income (loss) and net cash provided by operating activities as determined under GAAP, as well as adjusted EBITDA, to evaluate our overall performance.

Distributable Cash Flow. We define Distributable Cash Flow as Net Cash Provided by (Used in) Operating Activities less cash received (plus cash paid) for closed commodity derivative positions included in Accumulated Other Comprehensive Income (Loss), plus changes in operating assets and liabilities which (provided) used cash, less maintenance capital expenditures and plant turnaround costs. 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 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.

Adjusted Free Cash Flow. We define Adjusted Free Cash Flow as Distributable Cash Flow less growth capital expenditures and principal payments under finance lease obligations. Adjusted Free Cash Flow is a significant performance measure used by our management and by external users of our financial statements and represents how much cash flow a business generates during a specified time period after accounting for all capital expenditures, including expenditures for growth and maintenance capital projects. We believe that Adjusted Free Cash Flow is important to investors, lenders, commercial banks and research analysts since it reflects the amount of cash available for reducing debt, investing in additional capital projects, paying distributions, and similar matters. Our calculation of Adjusted Free Cash Flow may or may not be comparable to similarly titled measures used by other entities.

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The GAAP measure most directly comparable to Distributable Cash Flow and Adjusted Free Cash Flow is Net Cash Provided by (Used in) Operating Activities. Distributable Cash Flow and Adjusted Free Cash Flow should not be considered alternatives to, or more meaningful than, Net Income (Loss), Operating Income (Loss), Net Cash Provided by (Used in) Operating Activities , or any other measure of liquidity presented in accordance with GAAP. Distributable Cash Flow and Adjusted Free Cash Flow have important limitations because they exclude some items that affect Net Income (Loss), Operating Income (Loss), and Net Cash Provided by (Used in) Operating Activities. Distributable Cash Flow and Adjusted Free Cash Flow may not be comparable to similarly titled measures of other companies because other companies may not calculate these non-GAAP metrics in the same manner. To compensate for these limitations, we believe that it is important to consider Net Cash Provided by (Used in) Operating Activities determined under GAAP, as well as Distributable Cash Flow and Adjusted Free Cash Flow, to evaluate our overall liquidity.

Non-GAAP Financial Measures

The following tables reconcile the non-GAAP financial measurements used by management to our most directly comparable GAAP measures for the years ended December 31, 2021 and 2020, which represents EBITDA, Adjusted EBITDA, Distributable Cash Flow, and Adjusted Free Cash Flow

Reconciliation of Net Income (Loss) to EBITDA and Adjusted EBITDA

	Year Ended December 31,
	2021		2020
	(in thousands)
Net loss	$	(211)	$	(6,771)
Adjustments:
Interest expense	54,107		46,210
Income tax expense	3,380		1,736
Depreciation and amortization	56,751		61,462
EBITDA	114,027		102,637
Adjustments:
(Gain) loss on disposition of property, plant and equipment	534		(9,788)
Gain on involuntary conversion of property, plant and equipment	(196)		(4,907)
Gain on retirement of senior unsecured notes	—		(3,484)
Loss on exchange of senior unsecured notes	—		8,817
Unrealized mark-to-market on commodity derivatives	(207)		(460)
Non-cash insurance related accruals	—		250
Lower of cost or market adjustments	—		370
Unit-based compensation	384		1,422
Adjusted EBITDA	114,542		94,857

51

Reconciliation of Net Cash provided by Operating Activities to Adjusted EBITDA, Distributable Cash Flow, and Adjusted Free Cash Flow

	Year Ended December 31,
	2021		2020
	(in thousands)
Net cash provided by operating activities	$	35,729	$	64,785
Interest expense 1	50,740		42,979
Current income tax expense	948		567
Lower of cost or market adjustments	—		370
Loss on exchange of senior unsecured notes	—		8,817
Non-cash impact related to exchange of senior unsecured notes	—		749
Non-cash insurance related accrual	—		250
Net cash (received) paid for closed commodity derivative positions included in AOCI	(816)		—
Changes in operating assets and liabilities which (provided) used cash:
Accounts and other receivables, inventories, and other current assets	42,936		(33,204)
Trade, accounts and other payables, and other current liabilities	(14,346)		8,074
Other	(649)		1,470
Adjusted EBITDA	114,542		94,857
Adjustments:
Interest expense	(54,107)		(46,210)
Income tax expense	(3,380)		(1,736)
Deferred income taxes	2,432		1,169
Amortization of debt premium	—		(191)
Amortization of deferred debt issuance costs	3,367		3,422
Payments for plant turnaround costs	(4,109)		(1,478)
Maintenance capital expenditures	(14,115)		(10,138)
Distributable Cash Flow	44,630		39,695
Principal payments under finance lease obligations	(2,707)		(4,562)
Expansion capital expenditures	(4,705)		(10,828)
Adjusted Free Cash Flow	37,218		24,305

1 Net of amortization of debt issuance costs and discount and premium, which are included in interest expense but not included in net cash provided by operating activities.

52

Results of Operations

    The results of operations for the years ended December 31, 2021, 2020, and 2019 have been derived from our consolidated financial statements. Discussions of the year ended December 31, 2019 that are not included in this Annual Report on Form 10-K and year-to-year comparisons of the year ended December 31, 2020 and the year ended December 31, 2019 can be found in “Management’s Discussion and Analysis of Financial Condition and the Results of Operations” in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2020.

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.  

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

The Natural Gas Liquids segment information below excludes the discontinued operations of the Natural Gas Storage Assets disposed of on June 28, 2019, for the year ended December 31, 2019. See Item 8, Note 5.

The following table sets forth our operating revenues and operating income by segment for the years ended December 31, 2021, 2020, and 2019.  

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	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, 2021:
Terminalling and storage	$	185,629	$	(6,597)	$	179,032	$	15,462	$	(4,677)	$	10,785
Natural gas liquids	414,043		—		414,043		25,566		12,532		38,098
Sulfur services	145,042		—		145,042		23,965		9,007		32,972
Transportation	161,180		(16,866)		144,314		8,416		(16,862)		(8,446)
Indirect selling, general and administrative	—		—		—		(16,129)		—		(16,129)
Total	$	905,894	$	(23,463)	$	882,431	$	57,280	$	—	$	57,280
Year Ended December 31, 2020:
Terminalling and storage	$	191,041	$	(6,877)	$	184,164	$	23,969	$	(1,816)	$	22,153
Natural gas liquids	247,484		(5)		247,479		9,660		12,444		22,104
Sulfur services	108,020		(13)		108,007		29,001		7,255		36,256
Transportation	150,285		(17,793)		132,492		1,781		(17,883)		(16,102)
Indirect selling, general and administrative	—		—		—		(17,909)		—		(17,909)
Total	$	696,830	$	(24,688)	$	672,142	$	46,502	$	—	$	46,502
Year Ended December 31, 2019:
Terminalling and storage	$	216,313	$	(6,659)	$	209,654	$	17,670	$	(938)	$	16,732
Natural gas liquids	366,502		—		366,502		27,596		16,424		44,020
Sulfur services	111,340		—		111,340		13,989		8,732		22,721
Transportation	183,740		(24,118)		159,622		16,830		(24,218)		(7,388)
Indirect selling, general and administrative	—		—		—		(17,981)		—		(17,981)
Total	$	877,895	$	(30,777)	$	847,118	$	58,104	$	—	$	58,104

54

Terminalling and Storage Segment

Comparative Results of Operations for the Years Ended December 31, 2021 and 2020

	Year Ended December 31,				Variance		Percent Change
	2021		2020
	(In thousands)
Revenues:
Services	$	81,762	$	87,661	$	(5,899)	(7)%
Products	103,867		103,380		487		—%
Total revenues	185,629		191,041		(5,412)		(3)%
Cost of products sold	83,081		87,495		(4,414)		(5)%
Operating expenses	52,972		50,421		2,551		5%
Selling, general and administrative expenses	6,052		6,159		(107)		(2)%
Depreciation and amortization	28,210		29,489		(1,279)		(4)%
	15,314		17,477		(2,163)		(12)%
Other operating income (loss), net	(48)		6,429		(6,477)		(101)%
Gain on involuntary conversion of property, plant and equipment	196		63		133		211%
Operating income	$	15,462	$	23,969	$	(8,507)	(35)%
Shore-based throughput volumes (guaranteed minimum) (gallons)	80,000		80,000		—		—%
Smackover refinery throughput volumes (guaranteed minimum BBL per day)	6,500		6,500		—		—%

Services revenues. Services revenues decreased $5.9 million, of which $4.6 million was primarily a result of the disposition of the consigned lube business as part of the Mega Lubricants sale as well as a $1.0 million decrease related to contract termination fees and $0.2 million in decreased throughput fees at our shore-based terminals. In addition, revenue at the Smackover refinery decreased $1.1 million primarily due to the expiring capital recovery fees of $2.6 million, offset by contractually prescribed, index-based fee adjustments of $1.1 million and natural gas surcharge revenue of $0.3 million. Offsetting these decreases were increases at our specialty terminals related to storage revenue of $0.5 million, service revenue of $0.3 million and throughput revenue of $0.3 million.

Products revenues. A 22% increase in average sales price combined with a 4% increase in sales volumes at our blending and packaging facilities resulted in a $22.2 million increase in products revenues. Offsetting these increases, the disposition of our Mega Lubricants business resulted in a $21.3 million decrease in products revenues at our shore-based terminals.

Cost of products sold. The disposition of our Mega Lubricants business resulted in a $24.3 million decrease in cost of products sold at our shore-based terminals. Offsetting this decrease, a 26% increase in average cost per gallon combined with a 4% increase in sales volume at our blending and packaging facilities resulted in a $20.3 million increase in cost of products sold.

Operating expenses. Operating expenses increased primarily as a result of increased natural gas utilities across all of our terminals.

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

Depreciation and amortization. The decrease in depreciation and amortization is due to recent disposals, offset by 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.

55

Gain on involuntary conversion of property, plant and equipment. The $0.2 million gain for the year ended December 31, 2021 is due to insurance proceeds received related to structural damage at one of our shore-based terminals. The $0.1 million gain for the year ended December 31, 2020 is due to insurance proceeds received related to structural damage at one of our specialty terminals during a weather incident at our Neches Terminal in May of 2019.

Transportation Segment

Comparative Results of Operations for the Years Ended December 31, 2021 and 2020

	Year Ended December 31,				Variance		Percent Change
	2021		2020
	(In thousands)
Revenues	$	161,180	$	150,285	$	10,895	7%
Operating expenses	129,449		122,064		7,385		6%
Selling, general and administrative expenses	7,670		8,245		(575)		(7)%
Depreciation and amortization	15,719		17,505		(1,786)		(10)%
	8,342		2,471		5,871		238%
Other operating income (loss), net	74		(690)		764		111%
Operating income	$	8,416	$	1,781	$	6,635	373%

Marine Transportation Revenues. Inland revenues decreased $13.1 million, primarily related to a reduction in marine equipment. In addition, offshore revenue decreased $0.6 million due to decreased utilization related to regulatory inspections. Revenue was also impacted by an increase in pass-through revenue (primarily fuel) of $0.3 million.

Land Transportation Revenues. Transportation rates increased 14%, resulting in an increase of $13.1 million. A 3% increase in miles of product transported resulted in an additional increase to freight revenue of $3.4 million. Additionally, fuel surcharge revenue increased $7.9 million.

Operating expenses. The increase in operating expenses is primarily a result of increased pass through expenses (primarily fuel) of $4.4 million and compensation expense of $2.9 million.

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

Depreciation and amortization. Depreciation and amortization decreased as a result of recent disposals, offset by recent capital expenditures.

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

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Sulfur Services Segment

Comparative Results of Operations for the Years Ended December 31, 2021 and 2020

	Year Ended December 31,				Variance		Percent Change
	2021		2020
	(In thousands)
Revenues:
Services	$	11,799	$	11,659	$	140	1%
Products	133,243		96,361		36,882		38%
Total revenues	145,042		108,020		37,022		34%
Cost of products sold	95,287		62,920		32,367		51%
Operating expenses	10,203		10,891		(688)		(6)%
Selling, general and administrative expenses	5,284		4,791		493		10%
Depreciation and amortization	10,432		12,012		(1,580)		(13)%
	23,836		17,406		6,430		37%
Other operating income, net	129		6,751		(6,622)		(98)%
Gain on involuntary conversion of property, plant and equipment	—		4,844		(4,844)		(100)%
Operating income	$	23,965	$	29,001	$	(5,036)	(17)%
Sulfur (long tons)	456.0		642.0		(186.0)		(29)%
Fertilizer (long tons)	301.0		275.0		26.0		9%
Sulfur services volumes (long tons)	757.0		917.0		(160.0)		(17)%

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

Products Revenues.  Products revenues increased $65.0 million as a result of a 68% rise in average sulfur services sales prices. Products revenues decreased an offsetting $28.2 million due to a 17% decrease in sales volumes, primarily related to a 29% decrease in sulfur volumes.

Cost of products sold.  An 83% increase in product cost impacted cost of products sold by $52.5 million, resulting from an increase in commodity prices. A 17% decrease in sales volumes resulted in an offsetting decrease in cost of products sold of $20.1 million. Margin per ton increased $13.67, or 37%.

Operating expenses. Operating expenses decreased due to a decrease in outside towing of $0.3 million, repairs and maintenance of marine assets and railcars of $0.2 million, insurance premiums and claims of $0.2 million, employee related expenses of $0.1 million, assist tugs of $0.1 million, and lease expense of $0.1 million. Offsetting was an increase in utilities of $0.2 million, contract labor of $0.1 million and harbor agency fees of $0.1 million.

Selling, general and administrative expenses.   Selling, general and administrative expenses increased $0.3 million in employee related expenses and $0.2 million in corporate overhead.

Depreciation and amortization.  Depreciation and amortization decreased as a result of certain assets being fully depreciated in the prior period as well as a transfer of assets between segments during the three months ended June 30, 2021. A further decline was attributable to reduced amortization of turnaround costs.

    Other operating income, net.  Other operating income, net decreased $2.7 million as a result of business interruption recoveries related to downtime associated with the Neches ship-loader insurance claim received in the first quarter of 2020. An additional $4.1 million decrease is related to a net gain from the disposition of property, plant and equipment during 2020.

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Gain on involuntary conversion of property, plant and equipment.  The $4.8 million gain for the year ended December 31, 2020 is primarily due to insurance proceeds received related to structural damage of our ship-loader assets during a weather incident at our Neches Terminal in May of 2019.

Natural Gas Liquids Segment

    Comparative Results of Operations for the Years Ended December 31, 2021 and 2020

	Year Ended December 31,				Variance		Percent Change
	2021		2020
	(In thousands)
Products Revenues	$	414,043	$	247,484	166,559		67%
Cost of products sold	375,239		228,345		146,894		64%
Operating expenses	4,061		3,008		1,053		35%
Selling, general and administrative expenses	6,098		4,013		2,085		52%
Depreciation and amortization	2,390		2,456		(66)		(3)%
	26,255		9,662		16,593		172%
Other operating loss, net	(689)		(2)		(687)		(34,350)%
Operating income	$	25,566	$	9,660	$	15,906	165%
NGLs Volumes (barrels)	7,121		7,878		(757)		(10)%

    Products Revenues. Our NGL average sales price per barrel increased $26.73, or 85%, resulting in an increase to products revenues of $210.6 million. The increase in average sales price per barrel was a result of an increase in market prices. Product sales volumes decreased 10%, decreasing revenues $44.0 million.

    Cost of products sold.   Our average cost per barrel increased $23.71, or 82%, increasing cost of products sold by $186.8 million.  The increase in average cost per barrel was a result of an increase in market prices.  The decrease in sales volume of 10% resulted in a $39.9 million decrease to cost of products sold. Our margins increased $3.02 per barrel, or 124% during the period.

    Operating expenses.  Operating expenses increased $1.1 million related to the 2020 settlement of an insurance claim for less than anticipated with no corresponding transaction in 2021.

    Selling, general and administrative expenses.  Selling, general and administrative expenses increased $2.1 million as a result of increased compensation expense.

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

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Interest Expense

    Comparative Components of Interest Expense, Net for the Years Ended December 31, 2021 and 2020    

	Year Ended December 31,				Variance		Percent Change
	2021		2020
	(In thousands)
Credit facility	$	9,498	$	8,719	$	779	9%
Senior notes	39,303		32,225		7,078		22%
Amortization of deferred debt issuance costs	3,367		3,422		(55)		(2)%
Amortization of debt premium	—		(191)		191		100%
Other	1,915		1,787		128		7%
Finance leases	23		291		(268)		(92)%
Capitalized interest	—		(43)		43		100%
Total interest expense, net	$	54,106	$	46,210	$	7,896	17%

Indirect Selling, General and Administrative Expenses

	Year Ended December 31,				Variance		Percent Change
	2021		2020
	(In thousands)
Indirect selling, general and administrative expenses	$	16,129	$	17,909	$	(1,780)	(10)%

    Indirect selling, general and administrative decreased primarily due to a decrease in the indirect expenses allocated from Martin Resource Management Corporation.

    Martin Resource Management Corporation 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 Corporation's retained businesses. This allocation is based on the percentage of time spent by Martin Resource Management Corporation 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 Corporation 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 Corporation for indirect general and administrative and corporate overhead expenses. The board of directors of our general partner approved the following reimbursement amounts:

	Year Ended December 31,				Variance		Percent Change
	2021		2020
	(In thousands)
Board approved reimbursement amount	$	14,386	$	16,410	$	(2,024)	(12)%

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

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Liquidity and Capital Resources

General

    Our primary sources of liquidity to meet operating expenses, service our indebtedness, pay distributions to our unitholders and fund capital expenditures have historically been cash flows generated by our operations, borrowings under our credit facility, and access to debt and equity capital markets, both public and private. Set forth below is a description of our cash flows for the periods indicated.

Cash Flows - Year Ended December 31, 2021 Compared to Year Ended December 31, 2020

    The following table details the cash flow changes between the years ended December 31, 2021 and 2020:

	Years Ended December 31,				Variance		Percent Change
	2021		2020
	(In thousands)
Net cash provided by (used in):
Operating activities	$	35,729	$	64,785	$	(29,056)	(45)%
Investing activities	(19,241)		2,604		(21,845)		(839)%
Financing activities	(21,394)		(65,287)		43,893		67%
Net increase (decrease) in cash and cash equivalents	$	(4,906)	$	2,102	$	(7,008)	(333)%

    Net cash provided by operating activities. The decrease in net cash provided by operating activities for the year ended December 31, 2021 includes an unfavorable variance in working capital of $53.7 million, primarily related to a decrease in accounts receivable when comparing the year ended December 31, 2019 to the year ended December 31, 2020, offset by an increase in accounts receivable when comparing the year ended December 31, 2020 to the year ended December 31, 2021. Offsetting this decrease was an increase in operating results of $6.6 million and a favorable variance in other non-current assets and liabilities of $2.1 million. An additional $16.0 million increase in other non-cash charges was primarily due to a $10.3 million gain on sale of property, plant and equipment and a $4.7 million gain on involuntary conversion of property, plant and equipment, both during year ended December 31, 2020.

    Net cash provided by (used in) investing activities. Net cash provided by investing activities for the year ended December 31, 2021 decreased $21.8 million. Net proceeds from the sale of property, plant and equipment decreased $24.5 million and proceeds received from the involuntary conversion of property, plant and equipment decreased $7.3 million. A reduction in cash used of $9.9 million resulted from higher payments for capital expenditures and plant turnaround costs in 2020.

    Net cash used in financing activities. Net cash used in financing activities for the year ended December 31, 2021 decreased primarily as a result of a $34.3 million increase in net proceeds from long-term debt. Further, cash distributions paid decreased $4.5 million, costs associated with the credit facility decreased $3.2 million, and payments of finance lease obligations decreased $1.9 million.

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Total Contractual Obligations  

A summary of our total contractual obligations as of December 31, 2021 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
Credit facility	$	159,500	$	—	$	159,500	$	—	$	—
11.5% senior secured notes, due 2025	291,970		—		—		291,970		—
10.0% senior secured notes, due 2024	53,750		—		53,750		—		—
Throughput commitment	3,118		3,118		—		—		—
Operating leases	26,192		7,501		7,809		4,062		6,820
Finance lease obligations	289		280		9		—		—
Interest payable on finance lease obligations	9		9		—		—		—
Interest payable on fixed long-term debt obligations	117,972		38,952		73,424		5,596		—
Total contractual cash obligations	$	652,800	$	49,860	$	294,492	$	301,628	$	6,820

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

Letters of Credit.  At December 31, 2021, we had outstanding irrevocable letters of credit in the amount of $22.6 million, which were issued under our credit facility.

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

Description of Our Indebtedness

Credit Facility

At December 31, 2021, we maintained a $275.0 million credit facility that matures on August 31, 2023. As of December 31, 2021, we had $159.5 million outstanding under the credit facility and $22.6 million of outstanding irrevocable letters of credit, leaving a maximum available to be borrowed under our credit facility for future credit borrowings and letters of credit of $92.9 million. After giving effect to our then current borrowings, outstanding letters of credit and the financial covenants contained in our credit facility, we had the ability to borrow approximately $92.9 million in additional amounts thereunder as of December 31, 2021.

The 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, 2021, the outstanding balance of our credit facility has ranged from a low of $148.0 million to a high of $230.5 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.

    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 excess cash that exceeds $25.0 million and 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 (LIBOR), with a floor for LIBOR of 1%, 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 credit commitments 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 Total 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, 2021:

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Leverage Ratio	Base Rate Loans		Eurodollar Rate Loans		Letters of Credit
Less than 3.00 to 1.00	1.75	%	2.75	%	2.75	%
Greater than or equal to 3.00 to 1.00 and less than 3.50 to 1.00	2.00	%	3.00	%	3.00	%
Greater than or equal to 3.50 to 1.00 and less than 4.00 to 1.00	2.25	%	3.25	%	3.25	%
Greater than or equal to 4.00 to 1.00 and less than 4.50 to 1.00	2.50	%	3.50	%	3.50	%
Greater than or equal to 4.50 to 1.00 and less than 5.00 to 1.00	2.75	%	3.75	%	3.75	%
Greater than or equal to 5.00 to 1.00	3.00	%	4.00	%	4.00	%

    The applicable margin for LIBOR borrowings at December 31, 2021 is 4.00%, with a 1% floor for LIBOR.  

    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. On July 16, 2021, the credit facility was amended to, among other things:

•require us to maintain a minimum Interest Coverage Ratio (as defined in the credit facility) of 1.75:1.0 with respect to the fiscal quarter ended in December of 2021, 1.85:1.0 with respect to the fiscal quarters ending in March and June of 2022, and 2.0:1.0 with respect to each fiscal quarter thereafter;

•require us to maintain a maximum Total Leverage Ratio (as defined in the credit facility) of not more than 5.25:1.0 with respect to the fiscal quarter ended in December of 2021, and 5.0:1.0 with respect to each fiscal quarter thereafter; and

•require us to maintain a maximum First Lien Leverage Ratio (as defined in the credit facility) of not more than 2.25:1.0 with respect to the fiscal quarter ended in December of 2021, 1.75:1.0 with respect to each fiscal quarter ending in 2022, and 1.5:1.0 with respect to each fiscal quarter thereafter.

    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 (including a limit on our ability to make quarterly distributions to unitholders in excess of $0.005 per unit unless our Total Leverage Ratio (as defined in the credit facility) is below 3.75:1:00) and certain other restricted payments; (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; and (xi) 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 Corporation. If Martin Resource Management Corporation 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 Corporation under its credit facility could independently result in an event of default under our credit facility if it is deemed to have a material adverse effect on us.

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

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2025 Senior Secured Notes and Indenture

General

Pursuant to our exchange offer (the “the Exchange Offer”) to certain eligible holders of our 7.25% senior unsecured notes due 2021 (the “2021 Notes”), we and Martin Midstream Finance Corp., our wholly owned subsidiary (collectively the "Issuers") issued $292.0 million in aggregate principal amount of the Issuers’ 11.50% senior secured second lien notes due 2025 (the "2025 Notes"). The 2025 Notes were issued to eligible holders that participated in the Exchange Offer pursuant to an indenture, dated as of August 12, 2020 (the "2025 Notes Indenture"), among the Issuers, the guarantors party thereto, U.S. Bank National Association, as trustee, and U.S. Bank National Association as collateral trustee.

The 2025 Notes are guaranteed on a full, joint and several basis by each of the Partnership’s existing domestic restricted subsidiaries (other than Martin Midstream Finance Corp. and Talen’s Marine & Fuel, LLC) and will be guaranteed in the future by any domestic restricted subsidiaries, in each case, if and so long as such entity guarantees (or is an obligor with respect to) any other indebtedness for borrowed money of either the Issuers or any guarantor. The 2025 Notes and the guarantees thereof are secured on a third-priority basis by a lien on substantially all assets of the Issuers and the guarantors, subject to the terms of an intercreditor agreement (the "Intercreditor Agreement") and certain other exceptions.

The 2025 Notes and the guarantees thereof are, pursuant to the Intercreditor Agreement, secured by third-priority liens and thus are effectively junior to any obligations under our credit facility, which are secured on a "first-lien" basis, and effectively junior to any obligations under the 2024 Notes Indenture (as defined below), which are secured on a "second-lien" basis, in each case, to the extent of the value of the collateral securing such first-lien obligations, second-lien obligations and third-lien obligations. The 2025 Notes and the guarantees thereof rank effectively senior to all of our existing and future unsecured indebtedness to the extent of the value of the collateral securing the 2025 Notes and such guarantees.

Maturity and Interest

The 2025 Notes will mature on February 28, 2025. Interest on the 2025 Notes accrues at a rate of 11.50% per annum and is payable semi-annually in cash in arrears on February 15 and August 15 of each year, commencing on February 15, 2021.

Redemption

At any time prior to August 12, 2022, the Issuers may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2025 Notes issued under the 2025 Notes Indenture at a redemption price of 111.5% of the principal amount of the 2025 Notes, plus accrued and unpaid interest to the redemption date, with an amount of cash equal to the net cash proceeds of certain equity offerings. On or after August 12, 2022, the Issuers may redeem all or part of the 2025 Notes at redemption prices equal to 100%, plus accrued and unpaid interest up to, but not including, the redemption date. In addition, at any time prior to August 12, 2022, the Issuers may redeem all or a part of the 2025 Notes at a redemption price equal to 100% of the principal amount of the 2025 Notes to be redeemed plus a make-whole premium, plus accrued and unpaid interest up to, but not including, the redemption date.

Also, if at the end of any fiscal year (commencing with the fiscal year ended December 31, 2021) the Total Leverage Ratio (as defined in the Credit Facility Amendment) is greater than 3.75:1:00, the Issuers will use 25% of any excess annual cash flow (as defined in the 2025 Notes Indenture) to make an offer to all holders of the 2025 Notes to purchase the 2025 Notes at 100% of the principal amount thereof; provided, however, the Issuers, in their sole discretion, can allocate up to 100% of excess cash flow to offer to repurchase the 2025 Notes at 100% of the principal amount thereof, subject to restrictions in the credit facility on prepaying junior debt.

Certain Covenants and Events of Default

The 2025 Notes Indenture contains customary covenants restricting the Partnership’s ability and the ability of its restricted subsidiaries to: (i) pay distributions on, purchase or redeem its common units or purchase or redeem its subordinated debt; (ii) incur or guarantee additional indebtedness or issue certain kinds of preferred equity securities; (iii) create or incur certain liens securing indebtedness; (iv) sell assets, including dispositions of the collateral securing the 2025 Notes; (v) consolidate, merge or transfer all or substantially all of its assets; (vi) enter into transactions with affiliates; and (vii) enter into agreements that restrict distributions or other payments from its restricted subsidiaries to the Partnership. The 2025 Notes Indenture also contains customary events of default and acceleration provisions relating to such events of default, which provide that upon an event of default under the 2025 Notes Indenture, U.S. Bank National Association, as trustee, or the holders

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of at least 25% in aggregate principal amount of the then outstanding 2025 Notes may declare all of the 2025 Notes to be due and payable immediately and, subject to the terms of the Intercreditor Agreement, foreclose upon the collateral for the 2025 Notes.

2024 Senior Secured Notes and Indenture

General

Pursuant to the rights offering in connection with the Exchange Offer, the Issuers issued $53.8 million aggregate principal amount of the Issuers’ 10.00% senior secured 1.5 lien notes due 2024 (the "2024 Notes"). The 2024 Notes were issued to eligible holders that participated in the Exchange Offer pursuant to an indenture, dated as of August 12, 2020 (the "2024 Notes Indenture"), among the Issuers, the guarantors party thereto, U.S. Bank National Association, as trustee, and U.S. Bank National Association as collateral trustee.

The 2024 Notes are guaranteed on a full, joint and several basis by the guarantors of the 2025 Notes and will be guaranteed in the future by any domestic restricted subsidiaries, in each case, if and so long as such entity guarantees (or is an obligor with respect to) any other indebtedness for borrowed money of either the Issuers or any guarantor. The 2024 Notes and the guarantees thereof are secured on a second-priority basis by a lien on substantially all assets of the Issuers and the guarantors, subject to the terms of the Intercreditor Agreement and certain other exceptions.

The 2024 Notes and the guarantees thereof are, pursuant to the Intercreditor Agreement, secured by second-priority liens and thus are effectively junior to any obligations under our credit facility, which are secured on a "first-lien" basis, and are effectively senior to the obligations under the 2025 Notes Indenture, which are secured on a "third-lien" basis, in each case, to the extent of the value of the collateral securing such first-lien, second-lien obligations and third-lien obligations. The 2024 Notes and the guarantees thereof rank effectively senior to all of the Issuers’ existing and future unsecured indebtedness to the extent of the value of the collateral securing the 2024 Notes and such guarantees.

Maturity and Interest

The 2024 Notes will mature on February 29, 2024. Interest on the 2024 Notes accrues at a rate of 10.00% per annum and is payable semi-annually in cash in arrears on February 15 and August 15 of each year, commencing on February 15, 2021.

Redemption

At any time prior to August 12, 2021, the Issuers may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2024 Notes issued under the 2024 Notes Indenture at a redemption price of 110% of the principal amount of the 2024 Notes, plus accrued and unpaid interest to the redemption date, with an amount of cash equal to the net cash proceeds of certain equity offerings. On or after August 12, 2021, the Issuers may redeem all or part of the 2024 Notes at redemption prices (expressed as percentages of the principal amount) equal to (i) 102% for the twelve-month period beginning on August 12, 2021; (ii) 101% for the twelve-month period beginning on August 12, 2022 and (iii) 100% at any time thereafter, plus accrued and unpaid interest up to, but not including, the redemption date. In addition, at any time prior to August 12, 2021, the Issuers may redeem all or a part of the 2024 Notes at a redemption price equal to 100% of the principal amount of the 2024 Notes to be redeemed plus a make-whole premium, plus accrued and unpaid interest up to, but not including, the redemption date.

Certain Covenants and Events of Default

The 2024 Notes Indenture contains covenants that are substantially the same as those contained in the 2025 Notes Indenture described above.

    Capital Resources and Liquidity

Historically, we have generally satisfied our working capital requirements and funded our debt service obligations and capital expenditures with cash generated from operations and borrowings under our revolving credit facility.

    At December 31, 2021, we had cash and cash equivalents of $0.1 million and available borrowing capacity of $92.9 million under our credit facility with $159.5 million of borrowings outstanding.  Our credit facility matures on August 31, 2023.

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    We expect that our primary sources of liquidity to meet operating expenses, service our indebtedness, pay distributions to our unitholders and fund capital expenditures will be provided by cash flows generated by our operations, borrowings under our credit facility and access to the debt and equity capital markets.  Our ability to generate cash from operations will depend upon our future operating performance, which is subject to certain risks.  For a discussion of such risks, please read "Item 1A. Risk Factors" of this Form 10-K. In addition, due to the covenants in our credit facility, our financial and operating performance impacts the amount we are permitted to borrow under that facility. 

    The Partnership is in compliance with all debt covenants as of December 31, 2021 and expects to be in compliance for the next twelve months.

    Interest Rate Risk

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.

Seasonality

A substantial portion of our revenues is 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 refinery blending season. The demand for fertilizers is strongest during the early spring planting season. However, our Terminalling and Storage and Transportation business 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 Services and Transportation business segments. Further, extraordinary weather events, such as hurricanes, have in the past, and could in the future, impact our Terminalling and Storage, Sulfur Services, and Transportation business segments.

Impact of Inflation

Inflation did not have a material impact on our results of operations in 2021, 2020 or 2019.   Inflation 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 2021, 2020 or 2019.

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Item 7A. Quantitative and Qualitative Disclosures about Market Risk

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

Our hedging strategy is designed to protect us from excessive pricing volatility. However, since we do not typically hedge 100% of our exposure, abnormal price volatility in any of these commodity markets could influence operating income.

For derivatives designated in cash flow hedging relationships, we record the gains and losses from the use of these instruments in accumulated other comprehensive income (loss) on the consolidated balance sheets and subsequently recognize the accumulated gains and losses into cost of products sold in the same period when the associated underlying transactions occur. At December 31, 2021, accumulated other comprehensive income (loss) included $0.8 million in unrealized gains for these derivative instruments. All other commodity derivatives are marked-to-market and recognized into cost of products sold with the offset recognized as an asset or accrued liability. See Note 12, "Derivative Instruments and Hedging Activities," in Item 8 for further information on our outstanding derivatives.    

All outstanding commodity derivative positions were closed prior to December 31, 2021.

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 5.00% as of December 31, 2021.  Based on the amount of unhedged floating rate debt owed by us on December 31, 2021, assuming that LIBOR exceeds the 1.0% floor in our credit facility, 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 $1.6 million annually.

We are not exposed to changes in interest rates with respect to our 2024 Notes and 2025 Notes as these obligations are fixed rate.  Based on the quoted prices for identical liabilities in markets that are not active at December 31, 2021, the estimated fair value of the 2024 Notes and 2025 Notes was $55.2 million and $307.1 million, respectively.   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 at December 31, 2021 would result in a $0.05 million decrease in the fair value of our 2024 Notes and a $2.3 million decrease in the fair value of our 2025 Notes. On February 15, 2021, our 2021 Notes matured and we retired the outstanding balance of $28.8 million using our credit facility.

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Item 8. Financial Statements and Supplementary Data

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

	Page
Report of Independent Registered Public Accounting Firm (KPMG LLP, Dallas, TX, Auditor Firm ID 185)	68
Consolidated Balance Sheets as of December 31, 2021 and 2020	71
Consolidated Statements of Operations for the years ended December 31, 2021, 2020 and 2019	72
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2021, 2020 and 2019	75
Consolidated Statements of Changes in Capital (Deficit) for the years ended December 31, 2021, 2020 and 2019	76
Consolidated Statements of Cash Flows for the years ended December 31, 2021, 2020 and 2019	77
Notes to Consolidated Financial Statements	78

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Report of Independent Registered Public Accounting Firm

To the Unitholders and Board of Directors

Martin Midstream Partners L.P. and Martin Midstream GP LLC:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Martin Midstream Partners L.P. and subsidiaries (the Partnership) as of December 31, 2021 and 2020, the related consolidated statements of operations, comprehensive income (loss), changes in capital (deficit), and cash flows for each of the years in the three-year period ended December 31, 2021, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2021, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 1, 2022 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.

Basis for Opinion

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

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

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Evaluation of the recoverability of certain long-lived assets

As discussed in Note 2 to the consolidated financial statements, the Partnership reviews long-lived assets, such as property, plant and equipment and intangible assets with definite lives, 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, the Partnership measures the amount of the impairment by comparing the carrying amount to its estimated fair value. The carrying value of property, plant and equipment at December 31, 2021 was $345,470 thousand.

We identified the evaluation of the recoverability of a certain long-lived asset group in the transportation segment as a critical audit matter. A higher degree of subjective auditor judgement was required to evaluate the forecasted revenue used in the asset group’s future undiscounted cash flows. Specifically, the forecasted revenue was challenging to evaluate as the

68

future undiscounted cash flows were sensitive to minor changes in certain assumptions in the development of forecasted revenue that could have a significant effect on the Partnership’s assessment of the recoverability of the long-lived asset group.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the Partnership’s long-lived asset impairment assessment process. This included controls related to the development of the certain asset group’s future undiscounted cash flows, including the development of forecasted revenue. We performed sensitivity analyses to assess the impact of reasonably possible changes to certain revenue assumptions. We assessed the Partnership’s forecasted revenue by comparing to historical results, existing long-term contracts, and industry forecasts. We examined quarterly trends of actual financial results within the most recent fiscal year and compared those trends with the asset group’s forecasted financial results.

/s/ KPMG LLP 

We have served as the Partnership’s auditor since 2002.

Dallas, Texas

March 1, 2022

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Report of Independent Registered Public Accounting Firm

To the Unitholders and Board of Directors

Martin Midstream Partners L.P. and Martin Midstream GP LLC:

Opinion on Internal Control Over Financial Reporting

We have audited Martin Midstream Partners L.P. and subsidiaries' (the Partnership) internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Partnership as of December 31, 2021 and 2020, the related consolidated statements of operations, comprehensive income (loss), changes in capital (deficit), and cash flows for each of the years in the three-year period ended December 31, 2021, and the related notes (collectively, the consolidated financial statements), and our report dated March 1, 2022 expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

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

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

Definition and Limitations of Internal Control Over Financial Reporting

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

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

/s/ KPMG LLP 

Dallas, Texas

March 1, 2022

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MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

	December 31,
	2021		2020
Assets
Cash	$	52	$	4,958
Trade and accrued accounts receivable, less allowance for doubtful accounts of $311 and $261, respectively	84,199		52,748
Inventories	62,120		54,122
Due from affiliates	14,409		14,807
Other current assets	12,908		8,991
Total current assets	173,688		135,626
Property, plant and equipment, at cost	898,770		889,108
Accumulated depreciation	(553,300)		(509,237)
Property, plant and equipment, net	345,470		379,871
Goodwill	16,823		16,823
Right-of-use assets	21,861		22,260
Deferred income taxes, net	19,821		22,253
Intangibles and other assets, net	2,198		2,805
	$	579,861	$	579,638
Liabilities and Partners’ Capital (Deficit)
Current portion of long term debt and finance lease obligations	$	280	$	31,497
Trade and other accounts payable	70,342		51,900
Product exchange payables	1,406		373
Due to affiliates	1,824		435
Income taxes payable	385		556
Fair value of derivatives	—		207
Other accrued liabilities	29,850		34,407
Total current liabilities	104,087		119,375
Long-term debt, net	498,871		484,597
Finance lease obligations	9		289
Operating lease liabilities	15,704		15,181
Other long-term obligations	9,227		7,067
Total liabilities	627,898		626,509
Commitments and contingencies
Partners’ capital (deficit)	(48,853)		(46,871)
Accumulated other comprehensive income	816		—
Total partners’ capital (deficit)	(48,037)		(46,871)
	$	579,861	$	579,638

See accompanying notes to consolidated financial statements.

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MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands, except per unit amounts)

	Year Ended December 31,
	2021		2020		2019
Revenues:
Terminalling and storage *	$	75,223	$	80,864	$	87,397
Transportation *	144,314		132,492		159,622
Sulfur services	11,799		11,659		11,434
Product sales: *
Natural gas liquids	414,043		247,479		366,502
Sulfur services	133,243		96,348		99,906
Terminalling and storage	103,809		103,300		122,257
	651,095		447,127		588,665
Total revenues	882,431		672,142		847,118
Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Natural gas liquids *	362,706		215,895		325,376
Sulfur services *	89,134		58,515		65,893
Terminalling and storage *	81,258		82,516		101,526
	533,098		356,926		492,795
Expenses:
Operating expenses *	193,952		183,747		209,313
Selling, general and administrative *	41,012		40,900		41,433
Depreciation and amortization	56,751		61,462		60,060
Total costs and expenses	824,813		643,035		803,601
Other operating income (loss), net	(534)		12,488		14,587
Gain on involuntary conversion of property, plant and equipment	196		4,907		—
Operating income	57,280		46,502		58,104
Other income (expense):
Interest expense, net	(54,107)		(46,210)		(51,690)
Gain on retirement of senior unsecured notes	—		3,484		—
Loss on exchange of senior unsecured notes	—		(8,817)		—
Other, net	(4)		6		6
Total other income (expense)	(54,111)		(51,537)		(51,684)
Net income (loss) before taxes	3,169		(5,035)		6,420
Income tax expense	(3,380)		(1,736)		(1,900)
Income (loss) from continuing operations	(211)		(6,771)		4,520
Loss from discontinued operations, net of income taxes	—		—		(179,466)
Net loss	(211)		(6,771)		(174,946)
Less general partner's interest in net loss	4		135		3,499
Less (income) loss allocable to unvested restricted units	—		21		(41)
Limited partners' interest in net loss	$	(207)	$	(6,615)	$	(171,488)

*Related Party Transactions Shown Below

See accompanying notes to consolidated financial statements.

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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,
	2021		2020		2019
Revenues:
Terminalling and storage	$	62,677	$	63,823	$	71,733
Transportation	20,046		21,997		24,243
Product sales	479		317		931
Costs and expenses:
Cost of products sold: (excluding depreciation and amortization)
Sulfur services	9,980		10,519		10,765
Terminalling and storage	27,866		18,429		23,859
Expenses:
Operating expenses	78,607		80,075		88,194
Selling, general and administrative	32,924		32,886		32,622

See accompanying notes to consolidated financial statements.

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MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands, except per unit amounts)

	Year Ended December 31,
	2021		2020		2019
Allocation of net income (loss) attributable to:
Limited partner interest:
Continuing operations	$	(207)	$	(6,615)	$	4,430
Discontinued operations	—		—		(175,918)
	$	(207)	$	(6,615)	$	(171,488)
General partner interest:
Continuing operations	$	(4)	$	(135)	$	91
Discontinued operations	—		—		(3,590)
	$	(4)	$	(135)	$	(3,499)
Net income (loss) per unit attributable to limited partners:
Basic:
Continuing operations	$	(0.01)	$	(0.17)	$	0.11
Discontinued operations	—		—		(4.55)
	$	(0.01)	$	(0.17)	$	(4.44)
Weighted average limited partner units - basic	38,689		38,657		38,659
Diluted:
Continuing operations	$	(0.01)	$	(0.17)	$	0.11
Discontinued operations	—		—		(4.55)
	$	(0.01)	$	(0.17)	$	(4.44)
Weighted average limited partner units - diluted	38,689		38,657		38,659

See accompanying notes to consolidated financial statements.

74

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

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

	Year Ended December 31,
	2021		2020		2019
Net loss	$	(211)	$	(6,771)	$	(174,946)
Changes in fair values of commodity cash flow hedges	$	816	$	—	$	—
Comprehensive income (loss)	$	605	$	(6,771)	$	(174,946)

See accompanying notes to consolidated financial statements.

75

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CHANGES IN CAPITAL (DEFICIT)

(Dollars in thousands)

			Partners’ Capital (Deficit)
	Parent Net Investment		Common			General Partner Amount		Accumulated Other Comprehensive Income
			Units	Amount						Total
Balances – December 31, 2018	$	23,720	39,032,237	$	258,085	$	6,627	$	—	288,432
Net loss	—		—	(171,447)		(3,499)		—		(174,946)
Issuance of common units, net	—		—	(289)		—		—		(289)
Issuance of time-based restricted units	—		16,944	—		—		—		—
Forfeiture of restricted units	—		(154,288)	—		—		—		—
Cash distributions	—		—	(48,111)		(982)		—		(49,093)
Excess carrying value of the assets over the purchase price paid by Martin Resource Management	—		—	(102,393)		—		—		(102,393)
Deferred taxes on acquired assets and liabilities	—		—	24,781				—		24,781
Unit-based compensation	—		—	1,424		—		—		1,424
Purchase of treasury units	—		(31,504)	(392)		—		—		(392)
Contribution to parent	(23,720)		—	—		—		—		(23,720)
Balances – December 31, 2019	—		38,863,389	(38,342)		2,146		—		(36,196)
Net loss	—		—	(6,636)		(135)		—		(6,771)
Issuance of time-based restricted units	—		81,000	—		—		—		—
Forfeiture of restricted units	—		(85,467)	—		—		—		—
Cash distributions	—		—	(5,211)		(106)		—		(5,317)
Unit-based compensation	—		—	1,422		—		—		1,422
Purchase of treasury units	—		(7,748)	(9)		—		—		(9)
Balances – December 31, 2020	—		38,851,174	(48,776)		1,905		—		(46,871)
Net loss	—		—	(207)		(4)		—		(211)
Issuance of time-based restricted units	—		42,168	—		—		—		—
Forfeiture of restricted units	—		(83,436)	—		—		—		—
General partner contribution	—		—	—		3		—		3
Cash distributions	—		—	(775)		(16)		—		(791)
Changes in fair values of commodity cash flow hedges	—		—	—		—		816		816
Excess purchase price over carrying value of acquired assets	—		—	(1,350)		—		—		(1,350)
Unit-based compensation	—		—	384		—		—		384
Purchase of treasury units	—		(7,156)	(17)		—		—		(17)
Balances – December 31, 2021	$	—	38,802,750	$	(50,741)	$	1,888	$	816	$	(48,037)

See accompanying notes to consolidated financial statements.

76

MARTIN MIDSTREAM PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

	Year Ended December 31,
	2021		2020		2019
Cash flows from operating activities:
Net loss	$	(211)	$	(6,771)	$	(174,946)
Less: Loss from discontinued operations	—		—		179,466
Net income (loss) from continuing operations	(211)		(6,771)		4,520
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	56,751		61,462		60,060
Amortization and write-off of deferred debt issue costs	3,367		3,422		4,041
Amortization of premium on notes payable	—		(191)		(306)
Deferred income tax expense	2,432		1,169		1,360
(Gain) loss on disposition or sale of property, plant, and equipment	534		(9,788)		(13,332)
Gain on involuntary conversion of property, plant and equipment	(196)		(4,907)		—
Gain on retirement of senior unsecured notes	—		(3,484)		—
Non-cash impact related to exchange of senior unsecured notes	—		(749)		—
Derivative income	5,593		8,209		5,137
Net cash paid for commodity derivatives	(4,984)		(8,669)		(4,466)
Unit-based compensation	384		1,422		1,424
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables	(31,448)		30,741		62
Product exchange receivables	—		—		166
Inventories	(8,334)		5,264		21,493
Due from affiliates	398		2,932		1,822
Other current assets	(3,552)		(5,733)		(254)
Trade and other accounts payable	14,331		(7,318)		(898)
Product exchange payables	1,033		(3,949)		(7,781)
Due to affiliates	1,389		(1,035)		(1,469)
Income taxes payable	(171)		84		27
Other accrued liabilities	(2,236)		4,144		(3,017)
Change in other non-current assets and liabilities	649		(1,470)		(543)
Net cash provided by continuing operating activities	35,729		64,785		68,046
Net cash provided by discontinued operating activities	—		—		7,769
Net cash provided by operating activities	35,729		64,785		75,815
Cash flows from investing activities:
Payments for property, plant, and equipment	(16,059)		(28,622)		(30,621)
Acquisitions, net of cash acquired	—		—		(23,720)
Payments for plant turnaround costs	(4,109)		(1,478)		(5,677)
Proceeds from sale of property, plant, and equipment	643		25,154		20,660
Proceeds from involuntary conversion of property, plant and equipment	284		7,550		5,031
Net cash provided by (used in) continuing investing activities	(19,241)		2,604		(34,327)
Net cash provided by discontinued investing activities	—		—		209,155
Net cash provided by (used in) investing activities	(19,241)		2,604		174,828
Cash flows from financing activities:
Payments of long-term debt	(333,790)		(333,637)		(724,000)
Payments under finance lease obligations	(2,707)		(4,562)		(5,514)
Proceeds from long-term debt	316,500		282,019		638,000
Proceeds from issuance of common units, net of issuance related costs	—		—		(289)
General partner contributions	3		—		—
Excess purchase price over carrying value of acquired assets	—		—		(102,393)
Purchase of treasury units	(17)		(9)		(392)
Payments of debt issuance costs	(592)		(3,781)		(4,406)
Cash distributions paid	(791)		(5,317)		(49,093)
Net cash used in financing activities	(21,394)		(65,287)		(248,087)
Net increase (decrease) in cash	(4,906)		2,102		2,556
Cash at beginning of year	4,958		2,856		300
Cash at end of year	$	52	$	4,958	$	2,856

See accompanying notes to consolidated financial statements.

77

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

NOTE 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 Gulf Coast region of the U.S. Its four primary business lines include: terminalling, processing, storage and packaging services for petroleum products and by-products including the refining of naphthenic crude oil; land and marine transportation services for petroleum products and by-products, chemicals, and specialty products; sulfur and sulfur-based products processing, manufacturing, marketing and distribution; and NGL marketing, distribution, and transportation services.

    The Partnership provides specialty services to major and independent oil and gas companies, independent refiners, large chemical companies, and other wholesale purchasers of certain petroleum products and by-products, with significant business concentrated around the U.S. Gulf Coast refinery complex, which is a major hub for petroleum refining, natural gas gathering and processing, and support services for the exploration and production industry. The petroleum products and by-products the Partnership gathers, transports, stores and markets are produced primarily by major and independent oil and gas companies who often rely on third parties, such as the Partnership, for the transportation and disposition of these products.

    On December 28, 2021, Martin Resource Management Corporation indirectly acquired, through its wholly owned subsidiary, Martin Resource LLC, the remaining 49% voting interest (50% economic interest) in MMGP Holdings, LLC ("Holdings"), which is the sole member of Martin Midstream GP LLC ("MMGP"), the general partner of the Partnership. As a result, Martin Resource Management Corporation indirectly owns 100% of MMGP. On November 23, 2021, MMGP contributed to the Partnership all of the outstanding incentive distribution rights for no consideration, whereupon the incentive distribution rights were cancelled and cease to exist.

NOTE 2. SIGNIFICANT ACCOUNTING POLICIES AND PRACTICES

(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 existed as of December 31, 2021 or 2020.

Divestiture of Natural Gas Storage Assets. On June 28, 2019, the Partnership completed the sale of its membership interests in Arcadia Gas Storage, LLC, Cadeville Gas Storage LLC, Monroe Gas Storage Company, LLC and Perryville Gas Storage LLC (the "Natural Gas Storage Assets") to Hartree Cardinal Gas, LLC ("Hartree"), a subsidiary of Hartree Bulk Storage, LLC. The Natural Gas Storage Assets consist of approximately 50 billion cubic feet of working capacity located in northern Louisiana and Mississippi. In consideration of the sale of the Natural Gas Storage Assets, the Partnership received cash proceeds of $210,067 after transaction fees and expenses. The net proceeds were used to reduce outstanding borrowings under the Partnership's credit facility. The Partnership concluded the disposition represents a strategic shift and will have a major effect on its financial results going forward. As a result, the Partnership has presented the results of operations and cash flows relating to the Natural Gas Storage Assets as discontinued operations for the year ended December 31, 2019. See Note 5 for more information.

78

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

    (b)       Product Exchanges

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

(c)       Inventories

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

(d)      Revenue Recognition

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

Natural Gas Liquids – Revenue is recognized when product is delivered by truck, rail, or pipeline to the Partnership's NGL customers. Revenue is recognized on title transfer of the product to the customer. Delivery of product is invoiced as the transaction occurs and is generally paid within a month.

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

Transportation – Revenue related to land transportation is recognized for line hauls based on a mileage rate. For contracted trips, revenue is recognized upon completion of the particular trip. The performance of the service is invoiced as the transaction occurs and is generally paid within a month. Revenue related to marine transportation is recognized for time charters based on a per day rate. For contracted trips, revenue is recognized upon completion of the particular trip. The performance of the service is invoiced as the transaction occurs and is generally paid within a month.

(e)       Equity Method Investments

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

    (f)      Property, Plant, and Equipment

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

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

79

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

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

(g)      Goodwill and Other Intangible Assets

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

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

Of the Partnership's four reporting units, the terminalling and storage, transportation, and sulfur services reporting units contain goodwill.

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

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

Applying this impairment review methodology, the Partnership considered the impact that COVID-19 had on our cash flows and the value our unit price during both 2021 and 2020 and elected to bypass the qualitative assessment and perform a quantitative assessment. Based upon the most recent annual review as of August 31, 2021, no goodwill impairment exists within the Partnership's reporting units for the year ended December 31, 2021. No goodwill impairment was recorded for the years ended December 31, 2020 or 2019.

80

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

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 for the years ended December 31, 2021, 2020 or 2019.

(h)      Debt Issuance Costs

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

In connection with the issuance, amendment, expansion and restatement of debt arrangements, the Partnership incurred debt issuance costs of $592, $3,781 and $4,406 in the years ended December 31, 2021, 2020 and 2019, respectively.

Amortization and write-off of debt issuance costs, which is included in interest expense, totaled $3,367, $3,422 and $4,041 for the years ended December 31, 2021, 2020 and 2019, respectively.  Accumulated amortization amounted to $26,022 and $22,655 at December 31, 2021 and 2020, 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.  

The Partnership identified triggering events related to a certain asset group in its transportation segment in 2021. The Partnership performed a recoverability test and concluded the estimated undiscounted cash flows expected to be generated by the asset group exceeded the carrying value of the asset group and no impairment was recorded.

(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 at present value based upon estimated costs to retire the asset 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.  

81

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

(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)      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.

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

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

(o)      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.

(p)      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.

(q)      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.

MTI is a wholly owned subsidiary of the Partnership. Prior to the acquisition of MTI on January 2, 2019, MTI was a Qualified Subchapter S subsidiary (“QSub”) of Martin Resource Management Corporation, a qualifying S Corporation. A QSub is disregarded and not treated as a corporation separate from its S Corporation parent for federal income tax purposes. S Corporations are generally not subject to income taxes because income and losses flow through to shareholders and are reported on their individual returns. Three states in which MTI was subject to taxation prior to the acquisition - Louisiana, New Jersey and Tennessee - do not recognize the federal S Corporation status and, therefore, taxed MTI on a C Corporation basis. Subsequent to the acquisition, the QSub election terminated resulting in MTI being taxed as a stand-alone C Corporation.

The Partnership's financial statements recognize the current and deferred income tax consequences that result from MTI’s activities during the current period pursuant to the provisions of the FASB ASC 740 related to income taxes. As a result of the common control transaction with the Partnership, the deferred tax consequences of the changes in the tax bases of MTI’s assets and liabilities were included in equity under the provisions of ASC 740-20-45-11.

With respect to the Partnership’s taxable subsidiary (MTI), income taxes are accounted for under the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to

82

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

apply to taxable income in the years those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

In the ordinary course of business, there may be many transactions and calculations where the ultimate tax outcome is uncertain. The calculation of tax liabilities involves dealing with uncertainties in the application of complex tax laws. In accordance with the provisions of ASC 740, we use a two-step approach for recognizing and measuring tax benefits taken or expected to be taken in a tax return. In the first step, “recognition”, the Partnership determines whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the Partnership presumes that the position will be examined by the appropriate taxing authority that has full knowledge of all relevant information. In the second step, “measurement”, a tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement based upon management’s intent regarding negotiation and litigation. In evaluating all income tax positions for all open years, management has determined all positions are more likely than not to be sustained at full benefit based upon their technical merit under applicable tax laws.

(r)      Comprehensive Income

Comprehensive income includes net income and other comprehensive income. Other comprehensive income for the Partnership includes unrealized gains and losses on derivative instruments. In accordance with ASC 815-10, the Partnership records deferred hedge gains and losses on its derivative instruments that qualify as cash flow hedges as other comprehensive income.

NOTE 3. RECENT ACCOUNTING PRONOUNCEMENTS

On January 1, 2021, the Partnership adopted FASB Accounting Standards Update (“ASU”) 2019-12, Income Taxes (Accounting Standards Codification (“ASC”) Topic 740): Simplifying the Accounting for Income Taxes, which removes certain exceptions to general principles in ASC 740 and clarifies and amends existing guidance within U.S. GAAP. Adoption of the new standard did not have a material impact on the Partnership’s consolidated financial statements.    

On January 1, 2020, the Partnership adopted ASU 2016-13, "Financial Instruments - Credit Losses," which required the Partnership to measure all expected credit losses for financial instruments held at the reporting date based on historical experience, current conditions, and reasonable supportable forecasts. This replaced the existing incurred loss model and is applicable to the measurement of credit losses on financial assets, including trade receivables. Adoption of the new standard did not have a material impact on the Partnership’s consolidated financial statements.

In June 2018, the FASB issued ASU 2018-07, Compensation - Stock Compensation: Improvements to Non-employee Share-Based Payment Accounting, which will expand the scope of FASB ASC 718 to include share-based payment transactions for acquiring goods and services from non-employees. The standard is effective for the Partnership's financial statements issued for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. The Partnership adopted this standard effective January 1, 2019. The result of this adoption did not have a material impact on the Partnership's consolidated financial statements.

    In February 2016, the FASB issued ASU 2016-02, Leases, which introduces the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous guidance. Lessor accounting under the new standard is substantially unchanged and substantially all of our leases will continue to be classified as operating leases under the new standard. Additional qualitative and quantitative disclosures, including significant judgments made by management are required.  The update is effective for annual reporting periods beginning after December 15, 2018, including interim periods within those reporting periods, with early adoption permitted. The original guidance required application on a modified retrospective basis with the earliest period presented. In August 2018, the FASB issued ASU 2018-11, Targeted Improvements to FASB ASC 842, which includes an option to not restate comparative periods in transition and elect to use the effective date of ASC 842, Leases, as the date of initial application of transition. The Partnership adopted this ASU on January 1, 2019, electing the transition option provided under ASU 2018-11.

83

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

    The new standard provides a number of optional practical expedients in transition. The Partnership elected the "package of practical expedients", which permits the Partnership not to reassess under the new standard our prior conclusions about lease identification, lease classification and initial direct costs. The new standard also provides practical expedients for an entity’s ongoing accounting. The Partnership elected the short-term lease recognition exemption for all leases that qualify. This means, for those assets that qualify, the Partnership did not recognize Right-of-Use ("ROU") assets or lease liabilities, and this includes not recognizing ROU assets or lease liabilities for existing short-term leases of those assets in transition. See Note 10 for more information.

NOTE 4. ACQUISITIONS

    Martin Transport, Inc. Stock Purchase Agreement. On January 2, 2019, the Partnership acquired all of the issued and outstanding equity interests of MTI, a wholly-owned subsidiary of Martin Resource Management Corporation, which operates a fleet of trucks providing transportation of petroleum products, liquid petroleum gas, chemicals, sulfur and other products, as well as owns 24 terminals located throughout the U.S. Gulf Coast and Southeastern U.S. for total consideration as follows:

Purchase price 1	$	135,000
Plus: Working Capital Adjustment	2,795
Less: Finance lease obligations assumed	(11,682)
Cash consideration paid	$	126,113

    1 The stock purchase agreement also includes a $10,000 earn-out based on certain performance thresholds. The performance threshold related to financial results for the years ended December 31, 2020 and 2019 was not achieved, which resulted in a reduction in the potential earn-out by $6,666. For the year ended December 31, 2021, the performance threshold related to financial results was exceeded, resulting in an earn-out payment of $1,350, which, pursuant to the terms of the stock purchase agreement, will be paid in the second quarter of 2022.

    The transaction closed on January 2, 2019 and was effective as of January 1, 2019 and was funded with borrowings under the Partnership's credit facility.

    This acquisition is considered a transfer of net assets between entities under common control. The acquisition of MTI was recorded at the historical carrying value of the assets at the acquisition date, which were as follows:

Accounts receivable, net	$	11,724
Inventories	1,138
Due from affiliates	1,042
Other current assets	897
Property, plant and equipment, net	25,383
Goodwill	489
Other noncurrent assets	362
Current installments of finance lease obligations	(5,409)
Accounts payable	(2,564)
Due to affiliates	(482)
Other accrued liabilities	(2,588)
Finance lease obligations, net of current installments	(6,272)
Historical carrying value of assets acquired	$	23,720

    The excess purchase price over the historical carrying value of the assets at the acquisition date was $102,393 and was recorded as an adjustment to "Partners' capital (deficit)". The earn out-payment discussed above was recorded as additional excess purchase price over the historical carrying value of the assets, resulting in an adjustment to "Partners' capital (deficit)" of $1,350.

84

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

NOTE 5. DISCONTINUED OPERATIONS AND DIVESTITURES

    Divestitures

Divestiture of Mega Lubricants. On December 22, 2020, the Partnership completed the sale of its Mega Lubricants shored-based terminals business (“Mega Lubricants”) for $22,400. Mega Lubricants is engaged in the business of blending, manufacturing and delivering various marine application lubricants, sub-sea specialty fluids, and proprietary developed commercial and industrial products. The Partnership recorded a gain on the disposition of $10,101, which was included in "Other operating income, net" on the Partnership's Consolidated Statements of Operations. The proceeds from the transaction were used to reduce outstanding borrowings under the Partnership’s credit facility. The divestiture of Mega Lubricants did not qualify for discontinued operations presentation under the guidance of ASC 205-20.

Divestiture of East Texas Pipeline. On August 12, 2019, the Partnership completed the sale of its East Texas Pipeline for $17,500. The Partnership recorded a gain on the disposition of $16,154, which was included in "Other operating income, net" on the Partnership's Consolidated Statements of Operations. The net proceeds were used to reduce outstanding borrowings under the Partnership's credit facility. The divestiture of the East Texas Pipeline assets did not qualify for discontinued operations presentation under the guidance of ASC 205-20.

Divestiture of Natural Gas Storage Assets. On June 28, 2019, the Partnership completed the sale of the Natural Gas Storage Assets to Hartree, a subsidiary of Hartree Bulk Storage, LLC. The Natural Gas Storage Assets consist of approximately 50 billion cubic feet of working capacity located in northern Louisiana and Mississippi. In consideration of the sale of these assets, the Partnership received cash proceeds of $210,067 after transaction fees and expenses. The net proceeds were used to reduce outstanding borrowings under the Partnership's credit facility. The Partnership concluded the disposition represents a strategic shift and will have a major effect on its financial results going forward. As a result, the Partnership has presented the results of operations and cash flows relating to the Natural Gas Storage Assets as discontinued operations for the year ended December 31, 2019.

    The operating results, which are included in income (loss) from discontinued operations, were as follows:

	For the Year Ended December 31,
	2019
Total revenues	$	22,836
Total costs and expenses and other, net, excluding depreciation and amortization	(15,360)
Depreciation and amortization	(8,161)
Other operating loss, net 1	(178,781)
Other, net	—
Income (loss) from discontinued operations before income taxes	(179,466)
Income tax expense	—
Income (loss) from discontinued operations, net of income taxes	$	(179,466)

    1 The year ended December 31, 2019 includes a loss on the disposition of the Natural Gas Storage Assets of $178,781.

85

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

NOTE 6. REVENUE

    The following table disaggregates our revenue by major source:

	2021		2020		2019
Terminalling and storage segment
Lubricant product sales	$	103,809	$	103,300	$	122,257
Throughput and storage	75,223		80,864		87,397
	$	179,032	$	184,164	$	209,654
Transportation segment
Land transportation	$	111,611	$	88,652	$	98,895
Inland transportation	29,536		40,507		54,834
Offshore transportation	3,167		3,333		5,893
	$	144,314	$	132,492	$	159,622
Sulfur service segment
Sulfur product sales	$	32,416	$	24,176	$	30,135
Fertilizer product sales	100,827		72,172		69,771
Sulfur services	11,799		11,659		11,434
	$	145,042	$	108,007	$	111,340
Natural gas liquids segment
Natural gas liquids product sales	$	414,043	$	247,479	$	366,502
	$	414,043	$	247,479	$	366,502

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

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

Terminalling and Storage Segment

    Revenue is recognized for storage contracts based on the contracted monthly tank fixed fee.  For throughput contracts, revenue is recognized based on the volume moved through the Partnership’s terminals at the contracted rate.  For the Partnership’s tolling agreement, revenue is recognized based on the contracted monthly reservation fee and throughput volumes moved through the facility.  When lubricants and drilling fluids are sold by truck or rail, revenue is recognized when title is transferred, which is either upon delivering product to the customer or when the product leaves the Partnership's facility, depending on the specific terms of the contract. Delivery of product is invoiced as the transaction occurs and is generally paid within a month. Throughput and storage revenue in the table above includes non-cancelable revenue arrangements that are under the scope of ASC 842, whereby the Partnership has committed certain Terminalling and Storage assets in exchange for a minimum fee.

Natural Gas Liquids Segment

    NGL revenue is recognized when product is delivered by truck, rail, or pipeline to the Partnership's NGL customers. Revenue is recognized on title transfer of the product to the customer. Delivery of product is invoiced as the transaction occurs and is generally paid within a month.

86

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

Sulfur Services Segment

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

Transportation Segment

    Revenue related to land transportation is recognized for line hauls based on a mileage rate. For contracted trips, revenue is recognized upon completion of the particular trip. The performance of the service is invoiced as the transaction occurs and is generally paid within a month.

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

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

	2022		2023		2024		2025		2026		Thereafter		Total
Terminalling and storage
Throughput and storage	$	43,527	$	42,041	$	43,360	$	44,661	$	45,940	$	251,349	$	470,878
Natural Gas Services
Natural Gas Liquids	$	6,047	$	5,391	$	5,406	$	5,391	$	3,131	$	—	$	25,366
Sulfur services
Sulfur product sales	17,703		16,953		14,493		2,156		1,182		295		52,782
Total	$	67,277	$	64,385	$	63,259	$	52,208	$	50,253	$	251,644	$	549,026

NOTE 7. INVENTORIES

Components of inventories at December 31, 2021 and 2020 were as follows: 

	2021		2020
Natural gas liquids	$	20,034	$	27,878
Sulfur	612		24
Fertilizer	13,005		10,854
Lubricants	23,876		11,002
Other	4,593		4,364
	$	62,120	$	54,122

87

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

NOTE 8. PROPERTY, PLANT, AND EQUIPMENT

At December 31, 2021 and 2020, property, plant and equipment consisted of the following:

	Depreciable Lives	2021		2020
Land	—	$	21,422	$	21,459
Improvements to land and buildings	10-25 years	132,064		135,227
Storage equipment	5-50 years	122,300		121,437
Marine vessels	4-25 years	183,414		179,666
Operating plant and equipment	3-50 years	360,122		356,293
Furniture, fixtures and other equipment	3-20 years	13,727		14,209
Transportation equipment	3-7 years	50,961		49,836
Construction in progress		14,760		10,981
		$	898,770	$	889,108

Depreciation expense for the years ended December 31, 2021, 2020 and 2019 was $52,289, $55,817 and $53,856, respectively, which includes amortization of fixed assets acquired under capital lease obligations of $164, $1,755, and $2,686. Gross assets under capital leases were $1,071 and $10,352 at December 31, 2021 and 2020, respectively. Accumulated amortization associated with capital leases was $364 and $3,703 at December 31, 2021 and 2020, respectively.

Additions to property, plant and equipment included in accounts payable at December 31, 2021, 2020 and 2019 were $3,229, $468, and $3,791, respectively. Equipment purchased under capital lease obligations was $0, $83, and $1,308 for the years ended December 31, 2021, 2020, and 2019, respectively.

In the first quarter of 2020, the Partnership identified a triggering event related to a decline in the fair value related to the assets classified as held for sale at December 31, 2019. As a result, an impairment charge of $3,052 and $1,300 was recorded in the Terminalling and Storage and Transportation segments, respectively, during the year ended December 31, 2020 and was recorded in "Other operating income (loss)" in the Partnership's Consolidated Statements of Operations. At December 31, 2020, the remaining assets previously classified as held for sale in the amount of $700 no longer met the criteria to be classified as held for sale in accordance with ASC 360-10.

NOTE 9. GOODWILL

    The following table represents the goodwill balance by reporting unit at December 31, 2021 and 2020 as follows:

	2021		2020
Carrying amount of goodwill:
Terminalling and storage	$	10,985	$	10,985
Sulfur services	5,349		5,349
Transportation	489		489
Total goodwill	$	16,823	$	16,823

NOTE 10. LEASES

    The Partnership has numerous 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.

    Operating lease ROU assets and operating lease liabilities are recognized based on the present value of lease payments over the lease term at commencement date. Because most of the Partnership's leases do not provide an implicit rate of return, the Partnership uses its imputed collateralized rate based on the information available at commencement date in determining the present value of lease payments. The estimated rate is based on a risk-free rate plus a risk-adjusted margin.

88

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

The Partnership's leases have remaining lease terms of 1 year to 15 years, some of which include options to extend the leases for up to 5 years, and some of which include options to terminate the leases within 1 year. The Partnership includes extension periods and excludes termination periods from its lease term if, at commencement, it is reasonably likely that the Partnership will exercise the option.

    The components of lease expense for the years ended December 31, 2021, 2020, and 2019 were as follows:

	2021		2020		2019
Operating lease cost	$	9,266	$	10,672	$	10,805
Finance lease cost:
Amortization of right-of-use assets	164		1,755		2,686
Interest on lease liabilities	26		294		671
Short-term lease cost	10,290		13,187		13,756
Variable lease cost	115		109		92
Total lease cost	$	19,861	$	26,017	$	28,010

    Supplemental cash flow information for the years ended December 31, 2021, 2020, and 2019 related to leases were as follows:

	2021		2020		2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	19,678	$	23,996	$	24,526
Operating cash flows from finance leases	26		294		671
Financing cash flows from finance leases	2,707		4,562		5,514
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	7,668	$	7,779	$	9,122
Finance leases	0		83		1,309

    

89

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

Supplemental balance sheet information related to leases was as follows at December 31, 2021 and 2020:

	2021			2020
Operating Leases
Operating lease right-of-use assets	$	21,861		$	22,260
Current portion of operating lease liabilities included in "Other accrued liabilities"	$	6,600		$	7,529
Operating lease liabilities	15,704			15,181
Total operating lease liabilities	$	22,304		$	22,710
Finance Leases
Property, plant and equipment, at cost	$	1,071		$	10,352
Accumulated depreciation	(364)			(3,703)
Property, plant and equipment, net	$	707		$	6,649
Current installments of finance lease obligations	$	280		$	2,707
Finance lease obligations	9			289
Total finance lease obligations	$	289		$	2,996
Weighted Average Remaining Lease Term (years)
Operating leases	6.46			5.87
Finance leases	0.97			1.39
Weighted Average Discount Rate
Operating leases	4.96		%	5.04		%
Finance leases	5.74		%	6.04		%

    The Partnership’s future minimum lease obligations as of December 31, 2021 consist of the following:

	Operating Leases		Finance Leases
Year 1	$	7,501	$	289
Year 2	4,672		9
Year 3	3,137		—
Year 4	2,460		—
Year 5	1,602		—
Thereafter	6,820		—
Total	26,192		298
Less amounts representing interest costs	(3,888)		(9)
Total lease liability	$	22,304	$	289

    As of December 31, 2021, we have additional operating leases for land, buildings and equipment that have not yet commenced of $1,184. These operating leases will commence during the first quarter of 2022 with lease terms of 3 to 5 years.

The Partnership has non-cancelable revenue arrangements that are under the scope of ASC 842 whereby we have committed certain terminalling and storage assets in exchange for a minimum fee. Future minimum revenues the Partnership expects to receive under these non-cancelable arrangements as of December 31, 2021 are as follows: 2022 - $17,093; 2023 - $14,425; 2024 - $14,425; 2025 - $13,858; 2026 - $8,173; subsequent years - $30,670.

90

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

NOTE 11. FAIR VALUE MEASUREMENTS

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

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

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

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

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

	Level 2
	December 31,
	2021		2020
Commodity derivative contracts, net	$	—	$	(207)

    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.

•Current and non-current portion of long-term debt: The carrying amount of the credit facility approximates fair value due to the debt having a variable interest rate and is in Level 2. The estimated fair value of the 2021 Notes, 2024 Notes, and 2025 Notes (collectively, the "senior notes") is considered Level 2, as the fair value is based upon quoted prices for identical liabilities in markets that are not active.

	December 31, 2021				December 31, 2020
	Carrying Value		Fair Value		Carrying Value		Fair Value
2021 Notes	$	—	$	—	$	28,790	$	28,581
2024 Notes	$	51,317	$	55,220	$	50,173	$	55,214
2025 Notes	$	290,667	$	307,146	$	290,250	$	288,692
Total	$	341,984	$	362,366	$	369,213	$	372,487

91

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

NOTE 12. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

The Partnership’s results of operations could be materially impacted by changes in commodity prices and 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. At the time derivative contracts are entered into, the Partnership assesses whether the nature of the instrument qualifies for hedge accounting treatment according to the requirements of ASC 815 – Derivatives and Hedging. For those transactions designated as hedging instruments for accounting purposes, the Partnership documents all relationships between hedging instruments and hedged items, as well as our risk-management objective and strategy for undertaking the various hedge transactions. The Partnership also assesses, both at the hedge’s inception and on an ongoing basis, whether the derivatives used in hedging transactions are highly effective in offsetting changes in cash flows or fair value of hedged items. All derivatives and hedging instruments are included on the balance sheet as an asset or a liability measured at fair value. Changes in fair value for hedging instruments are recognized on the balance sheet through Accumulated Other Comprehensive Income ("AOCI"). Settlements related to effective hedging relationships will be reclassified from AOCI to earnings during the period in which the hedged transactions are reflected on the income statement.

From time to time, derivatives designated for hedge accounting may be closed prior to contract expiration. The accounting treatment of closed positions depends on whether the closure occurred due to the hedged transaction occurring early or if the hedged transaction is still expected to occur as originally forecasted. For hedged transactions that occur early, the closure results in the realized gain or loss from closure being recognized in the same period the accelerated hedged transaction affects earnings. For hedged transactions that are still expected to occur as originally forecasted, the closure results in the realized gain or loss being deferred until the hedged transaction affects earnings.

If it is determined that hedged transactions associated with cash flow hedges are no longer probable to occur, the gain or loss associated with the instrument is recognized immediately into earnings.

From time to time, we may have derivative financial instruments for which we do not elect hedge accounting. Changes in fair value for derivatives not designated as hedges 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 enters into hedging transactions to protect a portion of its commodity price risk exposure. These hedging arrangements are in the form of swaps for NGLs. At December 31, 2021, the Partnership has instruments totaling a gross notional quantity of 0 barrels. At December 31, 2020, the Partnership had instruments totaling a gross notional quantity of 137,000 barrels settling during the period from January 31, 2021 through February 28, 2021. These instruments settle against the applicable pricing source for each grade and location.

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

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

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

92

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

	Derivative Assets					Derivative Liabilities
		Fair Values					Fair Values
	Balance Sheet Location	December 31, 2021		December 31, 2020		Balance Sheet Location	December 31, 2021		December 31, 2020
Derivatives designated as hedging instruments:	Current:
Commodity contracts	Fair value of derivatives	$	—	$	—	Fair value of derivatives	$	—	$	—
Derivatives not designated as hedging instruments:	Current:
Commodity contracts	Fair value of derivatives	$	—	$	—	Fair value of derivatives	$	—	$	207

The following table summarizes the loss recognized in AOCI at December 31, 2021 and the gain (loss) reclassified from accumulated other comprehensive loss into earnings during the year ended December 31, 2021 for derivative financial instruments designated as cash flow hedges:

	Amount of Gain (Loss) Recognized in AOCI				Location of Gain (Loss) Reclassified from AOCI into Income	Amount of Gain (Loss) Reclassified from AOCI into Income
	2021		2020			2021		2020
Commodity contracts	$	816	$	—	Cost of products sold	$	(3,768)	$	—
Total	$	816	$	—		$	(3,768)	$	—

The following tables summarize the loss recognized in earnings for derivative instruments not designated as hedging instruments during the year ended December 31, 2021:

	Location of Gain (Loss) Recognized in Income on  Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives
		2021		2020
Derivatives not designated as hedging instruments:
Commodity contracts	Cost of products sold	$	(1,825)	$	(8,209)
Total effect of derivatives not designated as hedging instruments		$	(1,825)	$	(8,209)

NOTE 13. RELATED PARTY TRANSACTIONS

As of December 31, 2021, Martin Resource Management Corporation owned 6,114,532 of the Partnership’s common units representing approximately 15.8% of the Partnership’s outstanding limited partnership units.  Martin Resource Management Corporation controls the Partnership's general partner by virtue of owning 100% of the membership interests in

93

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

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.  The Partnership’s general partner’s ability, as general partner, to manage and operate the Partnership, and Martin Resource Management Corporation’s ownership as of December 31, 2021 of approximately 15.8% of the Partnership’s outstanding limited partnership units, effectively gives Martin Resource Management Corporation 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 Corporation 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 Corporation and the Partnership’s use of certain Martin Resource Management Corporation 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 Corporation.

    Non-Competition Provisions. Martin Resource Management Corporation 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 land and marine transportation of petroleum products, by-products, and chemicals;

•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 Corporation, including the following:

◦distributing asphalt, marine fuel and other liquids;

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

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

◦providing crude oil gathering 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;

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

◦operating, solely for our account, the asphalt facilities in each of Hondo, South Houston and Port Neches, Texas and Omaha, Nebraska.

94

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

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

•any business that Martin Resource Management Corporation 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 Corporation 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 Corporation 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 Corporation 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 Corporation for direct expenses.  In addition to the direct expenses, under the Omnibus Agreement, the Partnership is required to reimburse Martin Resource Management Corporation for indirect general and administrative and corporate overhead expenses.

    Effective January 1, 2021, through December 31, 2021, the board of directors of our general partner approved an annual reimbursement amount for indirect expenses of $14,386.  The Partnership reimbursed Martin Resource Management Corporation for $14,386, $16,410 and $16,657 of indirect expenses for the years ended December 31, 2021, 2020 and 2019, respectively.  The board of directors of our general partner 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 Corporation provides to 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 Corporation retained businesses. The provisions of the Omnibus Agreement regarding Martin Resource Management Corporation’s services will terminate if Martin Resource Management Corporation 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 Corporation 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 Corporation that requires aggregate annual payments in excess of the then-applicable agreed upon reimbursable amount of indirect general and administrative expenses. Please read "Services" above.

    License Provisions. Under the Omnibus Agreement, Martin Resource Management Corporation 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 Corporation.  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 Corporation.  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 Corporation for general and administrative services performed on its behalf, will terminate if the Partnership is no longer an affiliate of Martin Resource Management Corporation.

95

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

Master Transportation Services Agreement

    Master Transportation Services Agreement.  MTI, a wholly owned subsidiary of the Partnership, is a party to a master transportation services agreement effective January 1, 2019, with certain wholly owned subsidiaries of Martin Resource Management Corporation. Under the agreement, MTI agreed to transport Martin Resource Management Corporation's petroleum products and by-products.

    Term and Pricing.  The agreement will continue unless either party terminates the agreement by giving at least 30 days' written notice to the other party.  The rates under the agreement are subject to any adjustments which are mutually agreed upon or in accordance with a price index. Additionally, 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.  MTI has agreed to indemnify Martin Resource Management Corporation against all claims arising out of the negligence or willful misconduct of MTI and its officers, employees, agents, representatives and subcontractors. Martin Resource Management Corporation has agreed to indemnify MTI against all claims arising out of the negligence or willful misconduct of Martin Resource Management Corporation and its officers, employees, agents, representatives and subcontractors. In the event a claim is the result of the joint negligence or misconduct of MTI and Martin Resource Management Corporation, 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, the Partnership entered into a second amended and restated terminalling services agreement under which the Partnership provides terminal services to Martin Resource Management Corporation for marine fuel distribution.  At such time, the per-gallon throughput fee the Partnership charged under this agreement was increased when compared to the previous agreement and may be adjusted annually based on a price index.  This agreement was further amended on April 1, 2019 and January 1, 2020 to modify its minimum throughput requirements and throughput fees. The term of this agreement is currently evergreen and it will continue on a month to month basis until terminated by either party by giving 60 days’ written notice.  

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

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 Corporation 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 Corporation are based on applicable market rates.

    Marine Fuel.  The Partnership is a party to an agreement with Martin Resource Management Corporation dated November 1, 2002, under which Martin Resource Management Corporation provides the Partnership with marine fuel from its locations in the Gulf of Mexico at a fixed rate in excess of the Platt's U.S. Gulf Coast Index for #2 Fuel Oil.  Under this agreement, the Partnership agreed to purchase all of its marine fuel requirements that occur in the areas serviced by Martin Resource Management Corporation.

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 20, 2021, under which the Partnership processes crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts for Cross.  The tolling agreement

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

expires November 25, 2031.  Under this tolling agreement, Cross agreed to process a minimum of 6,500 barrels per day of crude oil at the facility at a fixed price per barrel.  Any additional barrels are processed at a modified price per barrel.  In addition, Cross agreed to pay a monthly reservation fee and a periodic fuel surcharge fee based on certain parameters specified in the tolling agreement.   Further, certain capital improvements, to the extent requested by Cross, are reimbursed through a capital recovery fee.  As of December 31, 2019, the annual capital recovery fee reimbursement of $2,088 expired. An additional $2,586 of capital recovery fee reimbursement expired on December 31, 2020.  All of these fees (other than the fuel surcharge) are subject to escalation annually based upon two-thirds of any increase in the Consumer Price Index for a specified annual period.  In no event shall the fees charged under the agreement ever decrease below the amounts which existed as of October 20, 2021. Also, the Partnership renegotiated a crude transportation contract set to expire in the first half of 2022 resulting in a reduction in revenue of $2,145 annually beginning January 1, 2020.

East Texas Mack Leases. MTI leases equipment, including tractors and trailers, from East Texas Mack Sales ("East Texas Mack"). Certain of our directors or officers are owners of East Texas Mack, including entities affiliated with Ruben Martin, who owns approximately 46% of the issued and outstanding stock of East Texas Mack. Amounts paid to East Texas Mack for tractor and trailer lease payments and lease residuals for the fiscal years ended December 31, 2021, 2020 and 2019 were approximately $1,089, $650, and $875, respectively.

    Other Miscellaneous Agreements. From time to time the Partnership enters into other miscellaneous agreements with Martin Resource Management Corporation 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:	2021		2020		2019
Terminalling and storage	$	62,677	$	63,823	$	71,733
Transportation	20,046		21,997		24,243
Product sales:
Sulfur services	109		60		54
Terminalling and storage	370		257		877
	479		317		931
	$	83,202	$	86,137	$	96,907

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

Cost of products sold:
Sulfur services	$	9,980	$	10,519	$	10,765
Terminalling and storage	27,866		18,429		23,859
	$	37,846	$	28,948	$	34,624

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

Operating expenses:
Transportation	$	55,382	$	55,786	$	61,376
Natural gas liquids	2,038		2,003		3,446
Sulfur services	4,411		4,489		4,810
Terminalling and storage	16,776		17,797		18,562
	$	78,607	$	80,075	$	88,194

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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:
Transportation	$	6,996	$	7,358	$	7,107
Natural gas liquids	4,590		2,397		2,804
Sulfur services	3,276		3,080		2,850
Terminalling and storage	3,370		3,403		3,083
Indirect overhead allocation, net of reimbursement	14,692		16,648		16,778
	$	32,924	$	32,886	$	32,622

NOTE 14. SUPPLEMENTAL BALANCE SHEET INFORMATION

    Components of "Intangibles and other assets, net" at December 31, 2021 and 2020 were as follows:

	2021		2020
Catalyst and turnaround costs	$	687	$	803
Other intangible assets	358		586
Other	1,153		1,416
	$	2,198	$	2,805

Other intangible assets consist of technology-based assets.

Amortization expense, included in "Depreciation and amortization" on the Partnership's Consolidated Statements of Operations includes amortization of intangible assets, turnaround expenses, and deferred charges. Aggregate amortization expense included in continuing operations was $4,085, $5,235, and $5,797, for the years ended December 31, 2021, 2020 and 2019, respectively.

Estimated amortization expense for the years subsequent to December 31, 2021 are as follows: 2022 - $4,403; 2023 - $661; 2024 - $266; 2025 - $84; 2026 - $1; subsequent years - $0.

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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, 2021 and 2020 were as follows:

	2021		2020
Accrued interest	$	15,135	$	16,104
Asset retirement obligations	261		1,692
Property and other taxes payable	4,631		4,869
Accrued payroll	2,973		3,244
Operating lease liabilities	6,600		7,529
Other	250		969
	$	29,850	$	34,407

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

	Year Ended December 31,
	2021		2020
	(In thousands)
Beginning asset retirement obligations	$	8,759	$	8,936
Revisions to existing liabilities 1	—		918
Accretion expense	375		410
Liabilities settled	(62)		(1,505)
Ending asset retirement obligations	9,072		8,759
Current portion of asset retirement obligations 2	(261)		(1,692)
Long-term portion of asset retirement obligations 3	$	8,811	$	7,067

1 Several 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.

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

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

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

NOTE 15. LONG-TERM DEBT

    At December 31, 2021 and 2020, long-term debt consisted of the following:

	2021		2020
$275,000 1 Credit facility at variable interest rate (5.00% 1 weighted average at December 31, 2021), due August 2023 4 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, net of unamortized debt issuance costs of $2,613 and $3,826, respectively 2	$	156,887	$	144,174
$400,000 Senior notes, 7.25% interest, net of unamortized debt issuance costs of $0 and $— respectively, including unamortized premium of $0 and $344, respectively, issued $250,000 February 2013 and $150,000 April 2014, $26,200 repurchased during 2015, $9,344 repurchased during 2020, and $335,666 refinanced as part of the August 2020 Exchange offer, $28,790 repaid at maturity in February 2021, unsecured 2,3,4,5	—		28,790
$53,750 Senior notes, due February 2024, 10.0% interest, net of unamortized debt issuance costs of $2,433 and $3,577, respectively 2,3	$	51,317	$	50,173
$291,970 Senior notes, due February 2025, 11.5% interest, net of unamortized debt issuance costs of $1,303 and $1,720, respectively 2,3	$	290,667	$	290,250
Total	498,871		513,387
Less: current portion	—		(28,790)
Total long-term debt, net of current portion	$	498,871	$	484,597
Current installments of finance lease obligations	$	280	$	2,707
Finance lease obligations	9		289
Total finance lease obligations	$	289	$	2,996

    1 Interest rate fluctuates based on LIBOR plus an applicable margin set on the date of each advance. The margin above LIBOR is set every three months. All amounts outstanding at December 31, 2021 were at LIBOR plus an applicable margin of 4.00%, with LIBOR having a floor of 1.00%. The applicable margin for revolving loans that are LIBOR loans currently ranges from 2.75% to 4.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 1.75% to 3.00%. The credit facility contains various covenants which limit the Partnership’s ability to make distributions; make certain investments and acquisitions; enter into certain agreements; incur indebtedness; sell assets; and make certain amendments to the Partnership's omnibus agreement with Martin Resource Management Corporation (the "Omnibus Agreement"). The credit facility was amended July 16, 2021 to, among other things, reduce the commitments thereunder from $300,000 to $275,000.

    2 The Partnership was in compliance with all debt covenants as of December 31, 2021.

3 The indentures for each of the outstanding senior notes 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.

4 On February 15, 2021, our 2021 Notes matured and we retired the outstanding balance of $28,790 using proceeds from our credit facility.

5 In March 2020, the Partnership repurchased on the open market an aggregate $9,344 of the 2021 Notes, resulting in a gain on retirement of $3,484.

The Partnership paid cash interest, net of capitalized interest, in the amount of $51,708, $37,678, and $48,025 for the years ended December 31, 2021, 2020 and 2019, respectively. Capitalized interest was $0, $43, and $5 for the years ended December 31, 2021, 2020 and 2019, respectively.

100

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

NOTE 16. PARTNERS' CAPITAL (DEFICIT)

    As of December 31, 2021, partners’ capital consisted of 38,802,750 common limited partner units, representing a 98% partnership interest, and a 2% general partner interest. Martin Resource Management Corporation, through subsidiaries, owned 6,114,532 of the Partnership's common limited partnership units representing approximately 15.8% of the Partnership's outstanding common limited partnership units. MMGP, the Partnership's general partner, owns the 2% general partnership interest.

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.

Impact on Partners' Capital (Deficit) Related to Transactions Between Entities Under Common Control

Under ASC 805, assets and liabilities transferred between entities under common control are accounted for at the historical cost of those entities' ultimate parent, in a manner similar to a pooling of interests. Any difference in the amount paid by the transferee versus the historical cost of the assets transferred is recorded as an adjustment to equity (contribution or distribution) by the transferee. This is in contrast with a business combination between unrelated parties, where assets and liabilities are recorded at their fair values at the acquisition date, with any excess of amounts paid over the fair value representing goodwill. From time to time, the most recent being in 2019, the Partnership has entered into common control acquisitions from Martin Resource Management Corporation. The consideration transferred totaling $552,123 exceeds the historical cost of the net assets received. This excess of the purchase price over the historical cost of the net assets received has resulted in cumulative distributions of $289,084 reflected as reductions to Partners' capital.

    Incentive Distribution Rights

MMGP holds a 2% general partner interest and, until November 23, 2021, MMGP held 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. On November 23, 2021, MMGP contributed to the Partnership all of the outstanding IDRs for no consideration, whereupon the IDRs were cancelled and cease to exist (the “IDR Elimination”). Until the IDR Elimination, the Partnership was required to distribute all of its available cash from operating surplus, as previously defined in the Partnership Agreement.

    For the years ended December 31, 2021, 2020 and 2019, the general partner was allocated no 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

101

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

distributions for the period are to be allocated to the general partner and limited partners based on their respective sharing of losses specified in the Partnership Agreement. Additionally, as required under FASB ASC 260-10-45-61A, unvested share-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities, as defined in FASB ASC 260-10-20, for earnings per unit calculations.

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

	Years Ended December 31,
	2021		2020		2019
Continuing operations:
Income (loss) from continuing operations	$	(211)	$	(6,771)	$	4,520
Less general partner’s interest in net income (loss):
Distributions payable on behalf of IDRs	—		—		—
Distributions payable on behalf of general partner interest	16		61		(20)
General partner interest in undistributed income (loss)	(20)		(196)		111
Less income (loss) allocable to unvested restricted units	—		(21)		(1)
Limited partners’ interest in net income (loss)	$	(207)	$	(6,615)	$	4,430

	Years Ended December 31,
	2021		2020		2019
Discontinued operations:
Loss from discontinued operations	$	—	$	—	$	(179,466)
Less general partner’s interest in net income (loss):
Distributions payable on behalf of IDRs	—		—		—
Distributions payable on behalf of general partner interest	—		—		806
General partner interest in undistributed loss	—		—		(4,396)
Less income allocable to unvested restricted units	—		—		42
Limited partners’ interest in net loss	$	—	$	—	$	(175,918)

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

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

	Years Ended December 31,
	2021	2020	2019
Basic weighted average limited partner units outstanding	38,689,041	38,656,559	38,658,881
Dilutive effect of restricted units issued	—	—	—
Total weighted average limited partner diluted units outstanding	38,689,041	38,656,559	38,658,881

    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. All common unit equivalents were antidilutive for the years ended December 31, 2021, 2020 and 2019 because the limited partners were allocated a net loss in this period.

102

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

NOTE 17. UNIT BASED AWARDS - LONG-TERM INCENTIVE PLANS

    The Partnership recognizes compensation cost related to unit-based awards to both employees and non-employees in its consolidated financial statements in accordance with certain provisions of ASC 718. Amounts recognized in operating expense and selling, general, and administrative expense in the consolidated financial statements with respect to these plans are as follows:

	For the Year Ended December 31,
	2021		2020		2019
Restricted unit awards
Employees	$	194	$	1,204	$	1,226
Non-employee directors	190		—		—
Phantom unit Awards
Employees	415		—		—
Non-employee directors	—		218		198
Total unit-based compensation expense	$	799	$	1,422	$	1,424

    Long-Term Incentive Plans

      The Partnership's general partner has long-term incentive plans for employees and directors of the general partner and its affiliates who perform services for the Partnership.

Phantom Unit Plan

On July 21, 2021, the board of directors of the general partner of the Partnership and the compensation committee of the general partner’s board of directors (the "Compensation Committee") approved the Martin Midstream Partners L.P. 2021 Phantom Unit Plan (the “Plan”), effective as of the same date. The Plan permits the awards of phantom units and phantom unit appreciation rights (collectively, "phantom unit awards") to any employee or non-employee director of the Partnership, including its executive officers. The awards may be time-based or performance-based and will be paid, if at all, in cash.

The award of a phantom unit entitles the participant to a cash payment equal to the value of the phantom unit on the vesting date or dates, which value is the fair market value of a common unit of the Partnership (a “Unit”) on such vesting date or dates. The award of a phantom unit appreciation right entitles the recipient to a cash payment equal to the difference between the value of a phantom unit on the vesting date or dates in excess of the value assigned by the Compensation Committee to the phantom unit as of the grant date. Phantom units and phantom unit appreciation rights granted to participants do not confer upon participants any right to a Unit.

On July 21, 2021, the Compensation Committee approved forms of time-based award agreements for phantom units and phantom unit appreciation rights, both of which awards vest in full on the third anniversary of the grant date. The grant date value of a phantom unit under a phantom unit appreciation right award is equal to the average of the closing price for a Unit during the 20 trading days immediately preceding the grant date of the award.

Generally, vesting of an award is subject to a participant remaining continuously employed with the Partnership through the vesting date. However, if prior to the vesting date (i) a participant is terminated without cause (as defined in the award agreement) or terminates employment after the participant has attained both the age of 65 and ten years of employment (“retirement-eligible”), a prorated portion of the award will vest and be paid in cash no later than the 30th day following such termination date (subject to a six-month delay in payment for certain retirement-eligible participants) or (ii) there is a change in control of the Partnership (as defined in the Plan), the award will vest in full and be paid in cash no later than the 30th day following the date of the change of control; provided, that the participant has been in continuous employment through the termination or change in control date, as applicable.

On July 21, 2021, 620,000 phantom units and 1,245,000 phantom unit appreciation rights were granted to employees of the general partner and its affiliates who perform services for the Partnership.

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

Phantom unit awards are recorded in operating expense and selling, general and administrative expense based on the fair value of the vested portion of the awards on the balance sheet date. The fair value of these awards is updated at each balance sheet date and changes in the fair value of the vested portions of the awards are recorded as increases or decreases to compensation expense within operating expense and selling, general and administrative expense in the Consolidated Statements of Operations. All of the Partnership's outstanding phantom unit awards at December 31, 2021 met the criteria to be treated under liability classification in accordance with ASC 718, given that these awards will settle in cash on the vesting date.

Compensation expense for the phantom awards is based on the fair value of the units as of the balance sheet date as further discussed below, and such costs are recognized ratably over the service period of the awards. As the fair value of liability awards is required to be re-measured each period end, stock compensation expense amounts recognized in future periods for these awards will vary. The estimated future cash payments of these awards are presented as liabilities within "Other current liabilities" and "Other long-term obligations" in the Consolidated Balance Sheets. As of December 31, 2021, there was a total of $1,233 of unrecognized compensation costs related to non-vested phantom unit awards. These costs are expected to be recognized over a remaining life of 2.56 years.

The fair value of the phantom unit awards was estimated using a Monte Carlo valuation model as of the balance sheet date. The Monte Carlo valuation model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility was calculated based on the historical volatility of the Partnership’s common units as well as set of peer companies.

Restricted Unit Plan

    On May 26, 2017, the unitholders of the Partnership approved the Martin Midstream Partners L.P. 2017 Restricted Unit Plan (the “2017 LTIP”). The 2017 LTIP currently permits the grant of awards covering an aggregate of 3,000,000 common units, all of which can be awarded in the form of restricted units. The 2017 LTIP is administered by the Compensation Committee.

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

The restricted units issued to directors generally vest in equal annual installments over a four-year period.

On February 22, 2021, the Partnership issued 14,056 TBRUs to each of the Partnership's three independent directors under the 2017 LTIP.  These restricted common units vest in equal installments of 3,514 units on January 24, 2022, 2023, 2024, and 2025.

On March 1, 2018, the Partnership issued 301,550 TBRUs and 317,925 PBRUs to certain employees of Martin Resource Management Corporation. The TBRUs vested in equal installments over a three-year service period. The PBRUs would have vested at the conclusion of a three-year performance period based on certain performance targets. In addition, the PBRUs awarded on March 1, 2018 would have only vested if the grantee was employed by Martin Resource Management Corporation on March 31, 2021. However, the performance conditions related to the PBRUs awarded on March 1, 2018 were

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

not achieved and the Partnership treated these units as forfeited at expiration on March 31, 2021. As such, the Partnership did not recognize compensation expense related to these units.

     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, 2021 is provided below:

	Number of Units		Weighted Average Grant-Date Fair Value Per Unit
Non-vested, beginning of year	273,424		$	10.52
Granted (TBRU)	42,168		$	2.49
Vested	(117,280)		$	11.96
Forfeited	(83,436)		$	13.90
Non-Vested, end of year	114,876		$	3.65
Aggregate intrinsic value, end of year	$	306

    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, 2021, 2020 and 2019 is provided below:

	For the Year Ended December 31,
	2021		2020		2019
Aggregate intrinsic value of units vested	$	257	$	151	$	1,351
Fair value of units vested	$	1,418	$	1,427	$	1,551

    As of December 31, 2021, there was $248 of unrecognized compensation cost related to non-vested time-based restricted units. That cost is expected to be recognized over a weighted-average period of 2.12 years.

NOTE 18. INCOME TAXES

    The components of income tax expense (benefit) from operations for the years ended December 31, 2021, 2020 and 2019 are as follows:

	2021		2020		2019
Current:
Federal	$	455	$	(174)	$	174
State	493		741		366
	948		567		540
Deferred:
Federal	2,142		1,027		882
State	290		142		478
	2,432		1,169		1,360
Total income tax expense	$	3,380	$	1,736	$	1,900

    The operations of a partnership are generally not subject to income taxes, except for Texas margin tax, because its income is taxed directly to its partners. The Texas margin tax 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 income tax, and therefore, the recognition of deferred taxes applies to the margin tax. The impact on deferred taxes as a result of this provision is immaterial. State income taxes attributable to the Texas margin tax relating to the operation of the Partnership of $300, $468 and $458 were recorded in income tax expense for the years ended December 31, 2021, 2020 and 2019, respectively.

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

MTI, a wholly owned subsidiary of the Partnership, is subject to income taxes due to its corporate structure (“Taxable Subsidiary”). Prior to the acquisition of MTI on January 2, 2019, MTI was a QSub of Martin Resource Management Corporation, a qualifying S Corporation. A QSub is not treated as a separate corporation for federal income tax purposes as it is deemed liquidated into its S Corporation parent. S Corporations are generally not subject to income taxes because income and losses flow through to shareholders and are reported on their individual returns. The principal component of the difference between the expected state tax expense and actual state tax expense relates to taxes incurred in states that do not recognize S corporation status.

Subsequent to the acquisition, the QSub election terminated resulting in MTI being taxed as a stand-alone C Corporation. Total income tax expense relating to the operation of the Taxable Subsidiary of $3,080 and $1,268 was recorded in income tax expense for the years ended December 31, 2021 and 2020, respectively.

The income tax expense from the Taxable Subsidiary operations for the years ended December 31, 2021 and 2020 differs from the "expected" tax expense (computed by applying the federal corporate rate of 21% to income before income taxes of the Taxable Subsidiary) as follows:

	2021		2020
"Expected" tax expense	$	2,223	$	361
Increase in income taxes resulting from:
State income taxes, net of federal income tax expense	382		327
Other non-deductible items	384		472
Other, net	91		108
Actual tax expense	$	3,080	$	1,268

Cash paid for income taxes was $1,232, $416 and $515 for the years ended December 31, 2021, 2020 and 2019, respectively.

Deferred taxes are the result of differences between the bases of assets and liabilities for financial reporting and income tax purposes. Significant components of deferred tax assets and liabilities at December 31, 2021 and 2020 are as follows:

	2021		2020
Deferred tax assets:
Bad debt reserves	$	26	$	59
Goodwill and intangibles	12,523		13,893
Employee benefits	57		244
Interest expense	—		—
Tax loss carryforwards	10,676		12,671
Other	129		251
Subtotal	23,411		27,118
Less: Valuation allowance	—		—
Total net deferred tax assets	23,411		27,118
Deferred tax liabilities:
Property and equipment	(3,590)		(4,861)
Operating leases	—		(4)
Other	—		—
Total deferred tax liabilities	(3,590)		(4,865)
Net deferred tax assets	$	19,821	$	22,253

Deferred tax assets are regularly reviewed for recoverability and a valuation allowance is provided when it is more likely than not that some portion or all of a deferred tax asset will not be realized. The ultimate realization of deferred tax assets

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

is dependent upon future taxable income during the periods in which those temporary differences become deductible. In assessing the need for a valuation allowance, management considers all available positive and negative evidence, including the ability to carryback operating losses to prior periods and the expected future utilization of net operating loss carryforwards, the reversal of deferred tax liabilities, projected taxable income, and tax-planning strategies. On the basis of these considerations, as of December 31, 2021, management believes it is more likely than not that the Taxable Subsidiary will realize the benefit of the existing deferred tax assets.

    Federal income taxes refundable related to the operation of the Taxable Subsidiary of $70 and $0 for the years ended December 31, 2021 and 2020, respectively, are included in “Other current assets”."Income taxes payable" includes a state income tax liability related to the operation of the Partnership of $304 and $455 for the years ended December 31, 2021 and 2020, respectively. Also included in "Income taxes payable" are state income tax liabilities related to the operation of the Taxable Subsidiary of $81 and $101 for the years ended December 31, 2021 and 2020, respectively.

    At December 31, 2021, MTI had net operating loss carryforwards for income tax purposes of approximately $67,681 related to federal and state taxes. Of these net operating loss carryforwards, approximately $19,379 will expire between 2024 and 2041 and approximately $48,302 may be carried forward indefinitely.

    The operations of the Partnership are generally not subject to income taxes, except as discussed above, because its income is taxed directly to its partners. The net tax basis in the Partnership's assets and liabilities is greater (less) than the reported amounts on the financial statements by approximately $91,893 and $88,526 as of December 31, 2021 and 2020, respectively.

    As of December 31, 2021, the tax years that remain open to assessment are 2018-2020.

NOTE 19. BUSINESS SEGMENTS

    The Partnership has four reportable segments: terminalling and storage, natural gas liquids, 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 interest expense.

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

	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, 2021:
Terminalling and storage	$	185,629	$	(6,597)	$	179,032	$	28,210	$	10,785	$	9,582
Natural gas liquids	414,043		—		414,043		2,390		38,098		537
Sulfur services	145,042		—		145,042		10,432		32,972		7,813
Transportation	161,180		(16,866)		144,314		15,719		(8,446)		4,997
Indirect selling, general, and administrative	—		—		—		—		(16,129)		—
Total	$	905,894	$	(23,463)	$	882,431	$	56,751	$	57,280	$	22,929
Year Ended December 31, 2020:
Terminalling and storage	$	191,041	$	(6,877)	$	184,164	$	29,489	$	22,153	$	11,619
Natural gas liquids	247,484		(5)		247,479		2,456		22,104		395
Sulfur services	108,020		(13)		108,007		12,012		36,256		7,415
Transportation	150,285		(17,793)		132,492		17,505		(16,102)		7,348
Indirect selling, general, and administrative	—		—		—		—		(17,909)		—
Total	$	696,830	$	(24,688)	$	672,142	$	61,462	$	46,502	$	26,777
Year Ended December 31, 2019:
Terminalling and storage	$	216,313	$	(6,659)	$	209,654	$	30,952	$	16,732	$	12,987
Natural gas liquids	366,502		—		366,502		2,469		44,020		1,870
Sulfur services	111,340		—		111,340		11,332		22,721		14,853
Transportation	183,740		(24,118)		159,622		15,307		(7,388)		8,213
Indirect selling, general, and administrative	—		—		—		—		(17,981)		—
Total	$	877,895	$	(30,777)	$	847,118	$	60,060	$	58,104	$	37,923

Revenues from one customer in the Natural Gas Liquids segment was $140,324, $74,722 and $112,280 for the years ended December 31, 2021, 2020 and 2019, respectively.

The Partnership's assets by reportable segment as of December 31, 2021 and 2020 are as follows:

	2021		2020
Total assets:
Terminalling and storage	$	248,194	$	252,794
Natural gas liquids	78,483		80,737
Sulfur services	108,007		94,154
Transportation	145,177		151,953
Total assets	$	579,861	$	579,638

NOTE 20. COMMITMENTS AND CONTINGENCIES

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MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except where otherwise indicated)

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.

On December 31, 2015, the Partnership received a demand from a customer in its lubricants packaging business for defense and indemnity in connection with various lawsuits filed against it, which generally alleged that the customer engaged in unlawful and deceptive business practices in connection with its marketing and advertising of its private label motor oil (the “Marketing Lawsuits”). The Partnership disputed and continues to dispute that it has any obligation to defend or indemnify the customer for the customer’s conduct. Accordingly, on January 7, 2016, the Partnership filed a Complaint for Declaratory Judgment in the Chancery Court of Davidson County, Tennessee (the “Tennessee Court”), under Case No. 16-0018-BC, requesting a judicial determination that the Partnership did not owe the customer the demanded defense and indemnity obligations (the “Declaratory Judgment Action”). The Marketing Lawsuits pending in federal court against the customer were transferred to the U.S. District Court for the Western District of Missouri under the consolidated case MDL No. 2709 for pretrial proceedings (the “Consolidated Lawsuits”). On March 1, 2017, at the joint request of the customer and the Partnership, the Tennessee Court administratively closed the Declaratory Judgment Action. Recently, the customer settled the Consolidated Lawsuits. On December 17, 2021, at the request of the customer, the Tennessee Court reopened the Declaratory Judgment Action and the customer asserted various counterclaims against the Partnership seeking, among other things, to recover its costs of defending and settling the Consolidated Lawsuits. At this time, we are unable to determine what ultimate exposure we may have in this matter, if any. The Partnership intends to vigorously defend the counterclaims asserted by the customer in the Declaratory Judgment Action.

NOTE 21. 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 notes and any subsidiaries other than the subsidiary guarantors are minor.

NOTE 22. SUBSEQUENT EVENTS

Quarterly Distribution.  On January 25, 2022, the Partnership declared a quarterly cash distribution of $0.005 per common unit for the fourth quarter of 2021, or $0.02 per common unit on an annualized basis, which was paid on February 14, 2022 to unitholders of record as of February 7, 2022.

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

None.

Item 9A. Controls and Procedures

(a)       Evaluation of Disclosure Controls and Procedures. In accordance with Rules 13a-15 and 15d-15 of the 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, 2021.  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, 2021 to provide reasonable assurance that information required to be disclosed by the Partnership in reports that it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms and (ii) accumulated and communicated to the Partnership’s management, including its principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

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

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

Our management, including the Chief Executive Officer and Chief Financial Officer of our general partner, conducted an evaluation of the effectiveness of our internal control over financial reporting based on criteria established in the Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on its evaluation under the framework in Internal Control — Integrated Framework (2013), our management concluded that our internal control over financial reporting was effective as of December 31, 2021.  The effectiveness of our internal control over financial reporting as of December 31, 2021 has been audited by KPMG LLP, our independent registered public accounting firm, as stated in their report appearing in "Item 8 - Financial Statements and Supplementary Data."

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

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Item 9B. Other Information

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

Management of Martin Midstream Partners L.P.

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

    Three directors of our general partner serve on the 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.

    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 Corporation. All of the officers of our general partner will spend a substantial amount of time managing the business and affairs of Martin Resource Management Corporation 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 Corporation. 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

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	70	Chairman of the Board of Directors
Robert D. Bondurant	63	President and Chief Executive Officer and Director
Randall L. Tauscher	56	Executive Vice President and Chief Operating Officer
Chris H. Booth	52	Executive Vice President, Chief Legal Officer, General Counsel and Secretary
Sharon L. Taylor	57	Vice President and Chief Financial Officer
Scot A. Shoup	61	Senior Vice President of Operations
C. Scott Massey	69	Director
James M. Collingsworth	67	Director
Byron R. Kelley	74	Director

    Ruben S. Martin was appointed to Chairman of the board of directors of our general partner effective January 1, 2021. From 2002 to 2020, Mr. Martin served as President and Chief Executive Officer and a member of the board of directors of our general partner. Mr. Martin has served as President of Martin Resource Management Corporation 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 and his business judgment and his previous experience as Chief Executive Officer of the Partnership.

Robert D. Bondurant was appointed to President and Chief Executive Officer of our general partner effective January 1, 2021. Prior to this position, Mr. Bondurant served as Executive Vice President and Chief Financial Officer and has served on the board of directors since 2014. Mr. Bondurant joined Martin Resource Management Corporation 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. Mr. Bondurant 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 and his business judgment, as well as his extensive financial and accounting background.

    Randall L. Tauscher serves as Executive Vice President and Chief Operating Officer of our general partner. Mr. Tauscher has served as an officer of our general partner since September 2007.  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 Corporation in October 2005.  Prior to joining Martin Resource Management Corporation, 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 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.

Sharon L. Taylor was appointed to Vice President and Chief Financial Officer of our general partner effective January 1, 2021. Prior to this position, Ms. Taylor served as Director of Finance and Head of Investor Relations since March 2018. Ms. Taylor was a member of the management group of Prism Gas Systems, Inc. serving as Vice President and Chief Financial Officer, where she continued as Controller after Martin's acquisition of Prism in November 2005. Prior to Prism, Ms. Taylor served as Director of Finance and Investor Relations for Dynamex Inc., a North American logistics company. She has held finance and accounting positions with Union Pacific Resources and UP Fuels. Ms. Taylor holds a Bachelor of Business Administration in accounting from Harding University.

    Scot A. Shoup serves as Senior Vice President of Operations for our general partner. Mr. Shoup joined Martin Resource Management Corporation in May 2011. Prior to joining Martin, Mr. Shoup was employed by Exline, Inc. as

113

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 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 45 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 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 U.S. 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.

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, 2021 to December 31, 2021, the board of directors of our general partner held 6 meetings. All directors then in office attended each of these meetings, either in person or by teleconference. Additionally, the board of directors undertook action one time during 2021 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, 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 www.MMLP.com under the "Corporate Governance" section. The current members of the committees, the number of meetings held by each committee from January 1, 2021 to December 31, 2021, and a brief description of the functions performed by each committee are set forth below:

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Conflicts Committee (2 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 (4 meetings). The members of the Compensation Committee are Messrs. Collingsworth (chairman), Massey and Kelley. All members attended the meeting of the Compensation Committee for the period noted above. The primary responsibility of the Compensation Committee is to oversee compensation decisions for the outside directors of our general partner and executive officers of our general partner (in the event they are to be paid by our general partner) as well as our long-term incentive plans.

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

Code of Ethics and Business Conduct

    Our general partner has adopted a Code of Ethics and Business Conduct applicable to all of our general partner's employees (including any employees of Martin Resource Management Corporation 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 Corporation 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.MMLP.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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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, 2021, 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 Corporation, a private corporation that has significant operations that are separate from ours. With the exception of our President and Chief Executive Officer, the executive officers of our general partner are also the executive officers of Martin Resource Management Corporation and devote significant time to the management of Martin Resource Management Corporation’s operations.  We reimburse Martin Resource Management Corporation 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. Under the Omnibus Agreement, we are required to reimburse Martin Resource Management Corporation for indirect general and administrative and corporate overhead expenses.   For the years ended December 31, 2021, 2020 and 2019 the board of directors of our general partner approved reimbursement amounts of $14.4 million, $16.4 million and $16.7 million, respectively, reflecting our allocable share of such expenses. Please see "Item 13. Certain Relationships and Related Transactions, and Director Independence — Agreements — Omnibus Agreement" for a discussion of the Omnibus Agreement.

Compensation Objectives

As we do not directly compensate the executive officers of our general partner, we do not have any set compensation programs. The elements of Martin Resource Management Corporation’s compensation program discussed below, along with Martin Resource Management Corporation’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 Corporation and other Martin Resource Management Corporation affiliates, including us, for which the Named Executive Officers perform services. Although we bear an allocated portion of Martin Resource Management Corporation’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 Corporation.  During 2021, Martin Resource Management Corporation paid compensation based on the performance of Martin Resource Management Corporation 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 Corporation’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 Corporation consist of the following: (1) annual base salary; (2) discretionary annual cash awards; (3) awards pursuant to the Martin Midstream Partners L.P. 2021 Phantom Unit Plan, Martin Midstream Partners L.P. 2017 Restricted Unit Plan and Martin Resource Management Corporation 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 Corporation 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 generally 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 Corporation’s business objectives.  Named

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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 accordance with the same methodologies as the discretionary annual cash awards for Martin Resource Management Corporation, 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. Phantom Unit Plan, Martin Midstream Partners L.P. 2017 Restricted Unit Plan and Martin Resource Management Corporation 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 Corporation.  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 Corporation.

Other Compensation.   Martin Resource Management Corporation generally does not pay for perquisites for any of the Named Executive Officers, other than general recreational activities at certain Martin Resource Management Corporation’s properties and use of Martin Resource Management Corporation vehicles. No perquisites are paid for services rendered to us.  Martin Resource Management Corporation 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 Corporation.  Martin Resource Management Corporation 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 Corporation govern the types and amount of compensation granted to each of the Named Executive Officers. The board of directors of our general partner has 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 Corporation.

Our allocation for the costs incurred by Martin Resource Management Corporation 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 Corporation.

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, other than our President and Chief Executive Officer, are determined by the Management Compensation Committee of Martin Resource Management Corporation comprised of its Chief Executive Officer, Mr. Ruben Martin, Chief Operating Officer, Mr. Randall Tauscher, and Vice President-Human Resources, Mrs. Melanie Mathews (collectively, the "Management Compensation Committee of Martin Resource Management Corporation") based on a periodic performance review of each Named Executive Officer.

The Compensation Committee of our board of directors is responsible for setting the compensation of our President and Chief Executive Officer. This includes determining the base salary, bonus compensation, long-term incentive compensation and other compensation of our President and Chief Executive Officer. The Compensation Committee's responsibility for the development of the compensation objectives and methodology applicable to the President and Chief Executive Officer are based on objectives, elements and methodologies discussed herein.

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 Corporation. Annual discretionary cash awards, if any, are calculated first by allocating a portion of Martin Resource Management Corporation’s earnings as determined by the Management Compensation Committee of Martin Resource Management Corporation for distribution to key employees of Martin Resource Management Corporation. Upon such allocation, the Management Compensation Committee of Martin Resource Management Corporation, 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 Corporation 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 Corporation, which is made up of Mr. Cullen M. Godfrey, an independent director of Martin Resource Management Corporation, and Mr. Ruben Martin. With respect to employee benefit plan awards pursuant to plans maintained by the Partnership, the Management Compensation

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Committee of Martin Resource Management Corporation 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 Corporation, with the approval of the Compensation Committee of the Board of Directors of Martin Resource Management Corporation 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 Corporation and on the Compensation Committee of the Board of Directors of Martin Resource Management Corporation, Mr. Martin, as Chief Executive Officer of Martin Resource Management Corporation, has significant authority in setting base salaries, discretionary annual cash award allocations and amounts and employee benefit award distributions.

Any awards granted to the independent directors and employees of our general partner under our long-term incentive plans are described in Item 8, Note 17, "Unit Based Awards - Long-Term Incentive Plans," and are approved by the Compensation Committee.

Determination of 2021 Compensation Amounts

During 2021, elements of all compensation paid to the Named Executive Officers by Martin Resource Management Corporation consisted of the following: (1) annual base salary; (2) discretionary annual cash awards; (3) awards pursuant to the Martin Midstream Partners L.P. 2021 Phantom Unit Plan or Martin Midstream Partners L.P. 2017 Restricted Unit Plan and (4) other Martin Resource Management Corporation employee benefit plans; and (5) 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 Corporation to the Named Executive Officers, which are allocable to us under our Omnibus Agreement with Martin Resource Management Corporation, are reflected in the summary compensation table below.  Based upon the agreement of our general partner with Martin Resource Management Corporation, we have reimbursed Martin Resource Management Corporation for approximately 79.6% of the aggregate annual base salaries paid to the Named Executive Officers by Martin Resource Management Corporation during 2021.  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 Corporation ranging from approximately 60% to 100%. During 2021, our Named Executive Officers were Mr. Robert D. Bondurant, the President and Chief Executive Officer of our general partner, Ms. Sharon L. Taylor, a 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.

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 Plans

Phantom Unit Plan

On July 21, 2021, the board of directors of the general partner of the Partnership and the Compensation Committee approved the Martin Midstream Partners L.P. 2021 Phantom Unit Plan (the “Plan”), effective as of the same date. The Plan permits the awards of phantom units and phantom unit appreciation rights (collectively, "phantom unit awards") to any employee or non-employee director of the Partnership, including its executive officers. The awards may be time-based or performance-based and will be paid, if at all, in cash.

The award of a phantom unit entitles the participant to a cash payment equal to the value of the phantom unit on the vesting date or dates, which value is the fair market value of a common unit of the Partnership on such vesting date or dates. The award of a phantom unit appreciation right entitles the recipient to a cash payment equal to the difference between the value of a phantom unit on the vesting date or dates in excess of the value assigned by the Compensation Committee to the phantom unit as of the grant date. Phantom units and phantom unit appreciation rights granted to participants do not confer upon participants any right to a common unit.

On July 21, 2021, the Compensation Committee approved forms of time-based award agreements for phantom units and phantom unit appreciation rights, both of which awards vest in full on the third anniversary of the grant date. The grant

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date value of a phantom unit under a phantom unit appreciation right award is equal to the average of the closing price for a common unit during the 20 trading days immediately preceding the grant date of the award.

Generally, vesting of an award is subject to a participant remaining continuously employed with the Partnership through the vesting date. However, if prior to the vesting date: (i) a participant is terminated without cause (as defined in the award agreement) or terminates employment after the participant has attained both the age of 65 and ten years of employment (“retirement-eligible”), a prorated portion of the award will vest and be paid in cash no later than the 30th day following such termination date (subject to a six-month delay in payment for certain retirement-eligible participants); or (ii) there is a change in control of the Partnership (as defined in the Plan), the award will vest in full and be paid in cash no later than the 30th day following the date of the change of control; provided, that the participant has been in continuous employment through the termination or change in control date, as applicable.

Restricted Unit Plan

On May 26, 2017, the unitholders of the Partnership approved the Martin Midstream Partners L.P. 2017 Restricted Unit Plan (the "2017 LTIP"). The plan currently permits the grant of awards covering an aggregate of 3,000,000 common units, all of which can be awarded in the form of restricted units. The plan is administered by the Compensation Committee of our general partner’s board of directors. The purpose of the 2017 LTIP is designed to enhance our ability to attract, retain, reward and motivate the services of certain key employees, officers, and directors of the general partner and Martin Resource Management Corporation.

Our general partner’s board of directors or the Compensation Committee, in their discretion, may terminate or amend the 2017 LTIP at any time with respect to any units for which a grant has not yet been made. Our general partner’s board of directors or the Compensation Committee also have the right to alter or amend the 2017 LTIP or any part of the plan from time to time, including increasing the number of units that may be reserved for issuance under the plan subject to any applicable unitholder approval. However, no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the participant. In addition, the restricted units will vest upon a change of control of us, our general partner or Martin Resource Management Corporation or if our general partner ceases to be an affiliate of Martin Resource Management Corporation.

Restricted Units.  A restricted unit is a unit that is granted to grantees with certain vesting restrictions, which may be time-based and/or performance-based. Once these restrictions lapse, the grantee is entitled to full ownership of the unit without restrictions. The Compensation Committee may determine to make grants under the plan containing such terms as the Compensation Committee shall determine under the plan. With respect to time-based restricted units ("TBRUs"), the Compensation Committee will determine the time period over which restricted units granted to employees and directors will vest. The Compensation Committee may also award a percentage of restricted units with vesting requirements based upon the achievement of specified pre-established performance targets ("PBRUs"). The performance targets may include, but are not limited to, the following: revenue and income measures, cash flow measures, EBIT, EBITDA, distribution coverage metrics, expense measures, liquidity measures, market measures, corporate sustainability metrics, and other measures related to acquisitions, dispositions, operational objectives and succession planning objectives. PBRUs are earned only upon our achievement of an objective performance measure for the performance period. PBRUs which vest are payable in common units.  The Compensation Committee believes this type of incentive award strengthens the tie between each grantee's pay and our financial performance. We intend the issuance of the common units upon vesting of the restricted units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive, and we will receive no remuneration for the units. Unvested units granted under the 2017 LTIP may or may not participate in cash distributions depending on the terms of each individual award agreement.

If a grantee’s service to the Partnership terminates for any reason, the grantee’s restricted units will be automatically forfeited unless, and to the extent, the Compensation Committee provides otherwise. Common units to be delivered upon the vesting of restricted units may be common units acquired by our general partner in the open market, common units already owned by our general partner, common units acquired by our general partner directly from us or any affiliate of our general partner, newly issued common units under the 2017 LTIP, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units upon vesting of the restricted units, the total number of common units outstanding will increase.

Martin Resource Management Corporation Employee Benefit Plans

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Martin Resource Management Corporation 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 Corporation Purchase Plan for Units of Martin Midstream Partners L.P.  Martin Resource Management Corporation maintains a purchase plan for our units to provide employees of Martin Resource Management Corporation 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 Corporation or an affiliate of Martin Resource Management Corporation 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 Corporation to the employee of the right to purchase common units under the purchase plan. The right to purchase common units granted by the Partnership 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 common units to be purchased during such purchase period shall mean the closing sales price of a unit on the purchase date.

Martin Resource Management Corporation Employee Stock Ownership Plans.

MRMC ESOP Trust ("ESOP"). Martin Resource Management Corporation maintains an employee stock ownership plan that covers employees who satisfy certain minimum age and service requirements. Under the terms of the ESOP, Martin Resource Management Corporation 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 Corporation. 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's Stock Profit Sharing Trust (the "SPS Plan").  Martin Resource Management Corporation 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 SPS Plan is referred to as the "Martin Employee Stock Ownership Plan". Under the terms of the SPS Plan, Martin Resource Management Corporation has the discretion to make contributions in an amount determined by its board of directors. Those contributions are allocated under the terms of the SPS Plan and invested primarily in the common stock of Martin Resource Management Corporation. No contributions will be made to the SPS 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 Corporation on December 31, 2012 are fully vested and non-forfeitable. The SPS Plan converted to an employee stock ownership plan on January 1, 2013.

Martin Resource Management Corporation 401(k) Profit Sharing Plan.  Martin Resource Management Corporation 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. Martin Resource Management Corporation 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 Corporation. Participants in the 401(k) Plan prior to January 1, 2017 are 100% vested in matching contributions, while those employed after January 1, 2017 become vested upon completion of the five years of vesting service schedule or upon their attainment of age 65, permanent disability or death during employment. The five year vesting service schedule is also applicable to discretionary contributions made to the plan.

Martin Resource Management Corporation Non-Qualified Option Plan.  In September 1999, Martin Resource Management Corporation adopted a stock option plan designed to retain and attract qualified management personnel, directors and consultants.  Under the plan, Martin Resource Management Corporation 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 Corporation adopted an additional stock option plan designed to retain and attract qualified management

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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, 2021.

Other Compensation

    Martin Resource Management Corporation generally does not pay for perquisites for any of our Named Executive Officers other than general recreational activities at certain Martin Resource Management Corporation’s properties located in Texas and use of Martin Resource Management Corporation vehicles, including aircraft.

SUMMARY COMPENSATION TABLE

The following table sets forth the compensation expense that was allocated to us for the services of the Named Executive Officers for the years ended December 31, 2021, 2020 and 2019.

Name and Principal Position	Year	Salary		Retention Awards		Discretionary Annual Awards		Phantom Unit Awards (Grant Date Value) (a)		Total Compensation
Robert D. Bondurant, President and Chief Executive Officer	2021	$	575,000	$	—	$	700,000	$	139,600	$	1,414,600
	2020	$	312,000	$	100,000	$	—	$	—	$	412,000
	2019	$	312,000	$	—	$	—	$	—	$	312,000
Randall L. Tauscher, Executive Vice President and Chief Operating Officer	2021	$	336,000	$	—	$	—	$	136,600	$	472,600
	2020	$	336,000	$	100,000	$	—	$	—	$	436,000
	2019	$	336,000	$	—	$	—	$	—	$	336,000
Sharon L. Taylor, Vice President and Chief Financial Officer (b)	2021	$	165,000	$	—	$	—	$	131,200	$	296,200
	2020	$	—	$	—	$	—	$	—	$	—
	2019	$	—	$	—	$	—	$	—	$	—
Chris H. Booth, Executive Vice President, General Counsel and Secretary	2021	$	231,000	$	—	$	—	$	133,600	$	364,600
	2020	$	211,750	$	100,000	$	—	$	—	$	311,750
	2019	$	250,250	$	—	$	—	$	—	$	250,250
Scot A. Shoup, Senior Vice President of Operations	2021	$	353,400	$	—	$	—	$	65,600	$	419,000
	2020	$	372,000	$	—	$	—	$	—	$	372,000
	2019	$	372,000	$	—	$	—	$	—	$	372,000

(a) On July 21, 2021, the Compensation Committee approved forms of time-based award agreements for phantom units and phantom unit appreciation rights, both of which awards vest in full on the third anniversary of the grant date, or July 21, 2024. The grant date value of a phantom unit under a phantom unit appreciation right award is equal to the average of the closing price for a common unit during the 20 trading days immediately preceding the grant date of the award.

(b) Only the 2021 period is reflected in this table as Sharon L. Taylor became Vice President and Chief Financial Officer and a Named Executive Officer effective January 1, 2021.

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GRANTS OF PLAN-BASED AWARDS

Name and Award Type	Grant Date	All Other Stock Awards: Number of Shares of Stock or Units (#) (a)	All Other Option Awards: Number of Securities Under-lying Options (#)(b)	Exercise or Base Price of Option Awards ($/Unit)		Grant Date Fair Value of Stock and Option Awards ($) (c)
Robert D. Bondurant
Phantom Units	07/21/2021	40,000.00		—		$	121,600
Phantom Unit Appreciation Rights	07/21/2021		150,000	$	2.92	$	18,000
Randall L. Tauscher
Phantom Units	07/21/2021	40,000.00		—		$	121,600
Phantom Unit Appreciation Rights	07/21/2021		125,000	$	2.92	$	15,000
Sharon L. Taylor
Phantom Units	07/21/2021	40,000.00		—		$	121,600
Phantom Unit Appreciation Rights	07/21/2021		80,000	$	2.92	$	9,600
Chris H. Booth
Phantom Units	07/21/2021	40,000.00		—		$	121,600
Phantom Unit Appreciation Rights	07/21/2021		100,000	$	2.92	$	12,000
Scot A. Shoup
Phantom Units	07/21/2021	20,000.00		—		$	60,800
Phantom Unit Appreciation Rights	07/21/2021		40,000	$	2.92	$	4,800

(a) This column includes the number of time-based phantom units granted to our named executive officers in 2021. These awards vest in full on July 21, 2024.

(b) This column includes the number of time-based phantom unit appreciation rights granted to our named executive officers in 2021. These awards vest in full on July 21, 2024.

(c) Amounts in this column reflect the grant date fair value of time-based phantom units and phantom unit appreciation rights granted to our named executive officers in 2021 and are determined in accordance with FASB ASC Topic 718. The grant date fair value of the phantom units is $3.04 and the grant date fair value of the phantom unit appreciation rights is $0.12.

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OUTSTANDING EQUITY AWARDS AT DECEMBER 31, 2021

	Option Awards					Unit Awards
Name and Award Type	Number of Securities Underlying Unexercised Options (#) Exercisable	Number of Securities Underlying Unexercised Options Unexercisable (a)	Option Exercise Price ($)		Option Expiration Date	Number of Shares or Units of Stock That Have Not Vested (#)(a)	Market Value of Shares or Units of Stock That Have Not Vested ($)(b)
Robert D. Bondurant
Phantom Units	—		—		—	40,000	$	106,400
Phantom Unit Appreciation Rights	—	150,000	$	2.92	N/A
Randall L. Tauscher
Phantom Units	—		—		—	40,000	$	106,400
Phantom Unit Appreciation Rights	—	125,000	$	2.92	N/A
Sharon L. Taylor
Phantom Units	—		—		—	40,000	$	106,400
Phantom Unit Appreciation Rights	—	80,000	$	2.92	N/A
Chris H. Booth
Phantom Units	—		—		—	40,000	$	106,400
Phantom Unit Appreciation Rights	—	100,000	$	2.92	N/A
Scot A. Shoup
Phantom Units	—		—		—	20,000	$	53,200
Phantom Unit Appreciation Rights	—	40,000	$	2.92	N/A

(a) Vests in full on July 21, 2024.

(b) The market value of unvested phantom units is calculated by multiplying the number of unvested phantom units held by the NEOs by the closing price of our common stock on December 31, 2021, which was $2.66. Because our closing stock price on December 31, 2021 was less than the strike price of the phantom unit appreciation rights, a $0 market value was included for the unvested phantom unit appreciation rights.

EQUITY VESTED TABLE FOR THE YEAR ENDED DECEMBER 31, 2021

Restricted Unit Plan
	Unit Awards (a)
Name	Number of Common Units Acquired on Vesting	Value Realized on Vesting
Robert D. Bondurant	8,883	$	21,408
Randall L. Tauscher	8,883	$	21,408
Sharon L. Taylor (b)	—	$	—
Chris H. Booth	6,667	$	16,067
Scot A. Shoup	2,667	$	6,427

(a) As of December 31, 2021, there were no outstanding awards under the 2017 LTIP for the Named Executive Officers.

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(b) The 2021 vesting amounts of the awards granted under the 2017 LTIP are not included for Sharon L. Taylor because the grant of the restricted units under the 2017 LTIP occurred prior to Ms. Taylor becoming Vice President and Chief Financial Officer and a Named Executive Officer effective January 1, 2021.

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 $25,000 each, which are paid by the general partner.  Martin Resource Management Corporation 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, 2021 through December 31, 2021.

Name	Fees Earned Paid in Cash		Stock Awards (a)		Total
Ruben S. Martin	$	—	$	—	$	—
Robert D. Bondurant	$	—	$	—	$	—
C. Scott Massey (b)	$	100,000	$	34,859	$	134,859
Byron R. Kelley (b)	$	100,000	$	34,859	$	134,859
James M. Collingsworth (b)	$	100,000	$	34,859	$	134,859

(a) 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 for TBRUs and PBRUs which have not been met as it relates to the 2018 stock award. See Note 17 included in Item 8 herein for the assumptions made in our valuation of such awards.

(b) On February 22, 2021, the Partnership issued 14,056 restricted common units to each of three independent directors, C. Scott Massey, Byron R. Kelley, and James M. Collingsworth under our 2017 LTIP.  These restricted common units vest in equal installments of 3,514 units on January 24, 2022, 2023, 2024 and 2025, 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

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    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 Corporation, 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 March 1, 2022 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	6,114,532	15.7%
Martin Resource Management Corporation 5	6,114,532	15.7%
Martin Resource LLC 5	4,203,823	10.8%
Martin Product Sales LLC 5	1,021,265	2.6%
Cross Oil Refining & Marketing Inc. 5	889,444	2.3%
Invesco Ltd. 2	7,216,779	18.6%
Ruben S. Martin 6	8,899,907	22.9%
Robert D. Bondurant	124,242	—%
Randall L. Tauscher	74,520	—%
Chris H. Booth 7	48,220	—%
Sharon L. Taylor 8	15,253	—%
Scot A. Shoup	25,784	—%
C. Scott Massey 9	97,254	—%
Byron R. Kelley	79,354	—%
James M. Collingsworth 10	77,529	—%
All directors and executive officers as a group (9 persons) 11	9,442,063	24.3%

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 Based solely upon the Schedule 13G/A filed on February 11, 2022 with the SEC by the beneficial owner as of December 31, 2021. Invesco Ltd. has sole voting power and sole dispositive power over 7,216,779 of common units. The address for Invesco Ltd. is 1555 Peachtree Street NE, Suite 1800, Atlanta, Georgia, 30309.

3 The percent of class shown is less than one percent unless otherwise noted.

4 By virtue of its ownership of 89.67% of the outstanding common stock of Martin Resource Management Corporation, the MRMC ESOP Trust (the "MRMC ESOP") is the controlling shareholder of Martin Resource Management Corporation, and may be deemed to beneficially own the 6,114,532 MMLP Common Units held by Martin Resource LLC, Cross Oil Refining & Marketing Inc., and Martin Product Sales LLC. Robert D. Bondurant, Randall L. Tauscher, and Melanie Mathews, Vice President - Human Resources (the "MRMC ESOP Co-Trustees") serve as co-trustees of the MRMC ESOP but all of its voting and investment decisions are directed by the board of directors of Martin Resource Management Corporation. 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 Corporation.

5 Martin Resource Management Corporation 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 Corporation 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 1,021,265 common units beneficially owned by Martin Resource Management Corporation 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 Corporation 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.

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6 Includes: (i) 94,842 common units held of record directly by Mr. Martin and (ii) 2,615,793 Common Units held of record by Senterfitt Holdings Inc., for which Mr. Martin is the sole shareholder and sole director and has sole voting and investment power. By virtue of serving as the Chairman of the Board and President of Martin Resource Management Corporation, Ruben S. Martin may exercise control over the voting and disposition of the securities owned by Martin Resource Management Corporation, and therefore, may be deemed the beneficial owner of the common units owned by Martin Resource Management Corporation, which include 6,114,532 common units beneficially owned through its ownership of Martin Resource LLC, Cross Oil Refining & Marketing Inc. and Martin Product Sales LLC.

7 Mr. Booth is the sole member and sole manager of Mibech Holdings LLC. Mr. Booth may be deemed to be the beneficial owner of 22,375 common units held by Mibech Holdings LLC.

8 Ms. Taylor may be deemed to be the beneficial owner of the 1,450 common units held by her husband.

9 Mr. Massey may be deemed to be the beneficial owner of 1,500 common units held by his wife.

10 Mr. Collingsworth may be deemed to be the beneficial owner of 775 common units held by his wife.

11 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 Corporation as Ruben S. Martin may be deemed to be the beneficial owner thereof.

Martin Resource Management Corporation indirectly owns 100% of the membership interests in the holding company that is the sole member of our general partner and, together with our general partner, owns approximately 15.8% of our outstanding common limited partner units as of December 31, 2021.  The table below sets forth information as of December 31, 2021 concerning (i) each person owning beneficially in excess of 5% of the voting common stock of Martin Resource Management Corporation, and (ii) the beneficial common stock ownership of (a) each director of Martin Resource Management Corporation, (b) each executive officer of Martin Resource Management Corporation, and (c) all such executive officers and directors of Martin Resource Management Corporation 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	138,884.49	89.67	%
Martin ESOP Trust 3	16,003.01	10.33	%
Robert D. Bondurant 3	16,003.01	10.33	%
Randall Tauscher 3	16,003.01	10.33	%

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 138,884.49 shares of common stock of Martin Resource Management Corporation. The MRMC ESOP Co-Trustees serve as trustees 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 Corporation. Of the common stock held by the MRMC ESOP, 131,008.37 shares of common stock are allocated to participant accounts, and 23,879.13 shares of common stock are unallocated.

3 Robert D. Bondurant and Randall Tauscher (the "Martin ESOP 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 Martin ESOP Co-Trustees exercise shared control over the voting and disposition of the securities owned by this trust.  As a result, the Martin ESOP 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 Martin ESOP Co-Trustees includes the 16,003 shares owned by such trust.  The Martin ESOP Co-Trustees disclaim beneficial ownership of these 16,003 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, 2021:

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		2,623,062
Total	—	$	—	2,623,062

Our general partner has adopted and maintains the Martin Midstream Partners L.P. 2021 Phantom Unit Plan and the Martin Midstream Partners L.P. 2017 Restricted Unit Plan. For a description of the material features of these plans, please see "Item 11. Executive Compensation – Employee Benefit Plans – Martin Midstream Partners L.P. Long-Term Incentive Plans".

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Item 13. Certain Relationships and Related Transactions, and Director Independence

Martin Resource Management Corporation owns 6,114,532 of our common limited partnership units representing approximately 15.8% of our outstanding common limited partnership units as of March 1, 2022.  Martin Resource Management Corporation indirectly holds 100% of the membership interests in Martin Midstream GP LLC, our general partner, by virtue of its 100% ownership interest in MMGP Holdings, LLC, the sole member of our general partner. Our general partner owns a 2% general partner interest in us. Our general partner’s ability to manage and operate us and Martin Resource Management Corporation’s ownership of approximately 15.8% of our outstanding common limited partnership units effectively gives Martin Resource Management Corporation 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 Corporation for the transfer of assets to us	4,253,362 subordinated units  (All of the original 4,253,362 subordinated units issued to Martin Resource Management Corporation 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)
	2% general partner interest; and 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 Corporation as holder of all of the subordinated units, and 2% to our general partner.
	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 $0.01 million on its 2% general partner interest.
Payments to our general partner and its affiliates	Martin Resource Management Corporation 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 Corporation 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 Corporation 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 Corporation for indirect general and administrative and corporate overhead expenses.  The board of directors of our general partner 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 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.

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Agreements

Omnibus Agreement

We and our general partner are parties to the Omnibus Agreement with Martin Resource Management Corporation 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 Corporation and our use of certain of Martin Resource Management Corporation’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 Corporation.

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

•terminalling, processing, storage and packaging services for petroleum products and by-products including the refining of naphthenic crude oil;

•land and marine transportation services for petroleum products and by-products, chemicals, and specialty products;

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

•NGL marketing, distribution, and transportation services.

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 Corporation, including the following:

◦distributing asphalt, marine fuel and other liquids;

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

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

◦providing crude oil gathering 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;

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

◦operating, solely for our account, the asphalt facilities in each of Hondo, South Houston and Port Neches, Texas and Omaha, Nebraska.

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

•any business that Martin Resource Management Corporation 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 Corporation 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

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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 Corporation 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 Corporation 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 Corporation 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 Corporation for direct expenses.  In addition to the direct expenses, Martin Resource Management Corporation 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 Corporation for indirect general and administrative and corporate overhead expenses.   For the years ended December 31, 2021, 2020 and 2019, the board of directors of our general partner approved and we reimbursed Martin Resource Management Corporation of $14.4 million, $16.4 million and $16.7 million, respectively, reflecting our allocable share of such expenses. The board of directors of our general partner 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 Corporation 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 Corporation retained businesses. The provisions of the Omnibus Agreement regarding Martin Resource Management Corporation’s services will terminate if Martin Resource Management Corporation ceases to control our general partner.

    Related Party Transactions. The Omnibus Agreement prohibits us from entering into any material agreement with Martin Resource Management Corporation 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 Corporation 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 Corporation 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 Corporation. 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 Corporation. 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 Corporation for general and administrative services performed on our behalf, will terminate if we are no longer an affiliate of Martin Resource Management Corporation.

Master Transportation Services Agreement

    Master Transportation Services Agreement.  MTI, a wholly owned subsidiary of us, is a party to a master transportation services agreement effective January 1, 2019, with certain wholly owned subsidiaries of Martin Resource Management Corporation. Under the agreement, MTI agreed to transport Martin Resource Management Corporation's petroleum products and by-products.

    Term and Pricing. The agreement will continue unless either party terminates the agreement by giving at least 30 days' written notice to the other party.  The rates under the agreement are subject to any adjustments which are mutually agreed upon or in accordance with a price index. Additionally, 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.

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

Terminal Services Agreements

    Diesel Fuel Terminal Services Agreement.  Effective January 1, 2016, we entered into a second amended and restated terminalling services agreement under which we provide terminal services to Martin Resource Management Corporation for marine fuel distribution.  At such time, the per gallon throughput fee we charged under this agreement was increased when compared to the previous agreement and may be adjusted annually based on a price index.  This agreement was further amended on April 1, 2019 and January 1, 2020 to modify its minimum throughput requirements and throughput fees. The term of this agreement is currently evergreen and it will continue on a month to month basis until terminated by either party by giving 60 days’ written notice.  

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

Marine Agreements

Marine Transportation Agreement. We are a party to a marine transportation agreement effective January 1, 2006, as amended, under which we provide marine transportation services to Martin Resource Management Corporation 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 Corporation are based on applicable market rates.

Marine Fuel.  We are a party to an agreement with Martin Resource Management Corporation dated November 1, 2002 as amended, under which Martin Resource Management Corporation provides us with marine fuel from its locations in the Gulf of Mexico at a fixed rate in excess of the Platt’s U.S. Gulf Coast Index for #2 Fuel Oil.  Under this agreement, we agreed to purchase all of its marine fuel requirements that occur in the areas serviced by Martin Resource Management Corporation.

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 20, 2021, under which the Partnership processes crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts for Cross.  The tolling agreement expires November 25, 2031.  Under this tolling agreement, Cross agreed to process a minimum of 6,500 barrels per day of crude oil at the facility at a fixed price per barrel.  Any additional barrels are processed at a modified price per barrel.  In addition, Cross agreed to pay a monthly reservation fee and a periodic fuel surcharge fee based on certain parameters specified in the tolling agreement.   Further, certain capital improvements, to the extent requested by Cross, are reimbursed through a capital recovery fee.  All of these fees (other than the fuel surcharge ) are subject to escalation annually based upon two-thirds of any increase in the Consumer Price Index for a specified annual period.  In no event shall the fees charged under the agreement ever decrease below the amounts which existed as of October 20, 2021.

    Other Miscellaneous Agreements. From time to time we enter into other miscellaneous agreements with Martin Resource Management Corporation for the provision of other services or the purchase of other goods.

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Other Related Party Transactions

    Transfers of Assets Between Entities Under Common Control    

    Acquisition of Martin Transport, Inc. On January 2, 2019, we acquired all of the issued and outstanding equity interests of MTI from Martin Resource Management Corporation for a purchase price of $135.0 million. MTI operates a fleet of trucks providing transportation of petroleum products, liquid petroleum gas, chemicals, sulfur and other products, as well as owns 24 terminals located throughout the U.S. Gulf Coast and Southeastern U.S.. The excess of the purchase price over the carrying value of the assets of $102.4 million was recorded as an adjustment to "Partners' capital." The stock purchase agreement also includes a $10.0 million earn-out based on certain performance thresholds. The performance threshold related to financial results for the years ended December 31, 2020 and 2019 was not achieved, which resulted in a reduction in the potential earn-out by $6.7 million. For the year ended December 31, 2021, the performance threshold related to financial results was exceeded, resulting in an earn-out payment of $1.3 million, which, pursuant to the terms of the stock purchase agreement, will be paid in the second quarter of 2022. The earn-out payment was recorded as additional excess purchase price over the historical carrying value of the assets, resulting in an adjustment to "Partners' capital (deficit)" of $1.3 million.

East Texas Mack Leases. MTI leases equipment, including tractors and trailers, from East Texas Mack Sales. Certain of our directors and officers are owners of East Texas Mack, including entities affiliated with Ruben Martin, who owns approximately 46% of the issued and outstanding stock of East Texas Mack. Amounts paid to East Texas Mack for tractor and trailer lease payments and lease residuals for the fiscal years ended December 31, 2021, 2020 and 2019 were approximately $1.1, $0.7 and $0.9, respectively.

Miscellaneous  

Certain of directors, officers and employees of our general partner and Martin Resource Management Corporation 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 Note 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, 2021 and 2020.  The following fees were paid to KPMG, LLP for services rendered during our last two fiscal years:

	2021			2020
Audit fees	$	1,060,000	(1)	$	1,095,000	(1)
Audit related fees	—			—
Audit and audit related fees	1,060,000			1,095,000
Tax fees	107,000		(2)	169,912		(2)
All other fees	7,000			—
Total fees	$	1,174,000		$	1,264,912

(1)    2021 audit fees include fees for the annual financial statement audit, audit of internal controls over financial reporting, and interim reviews included in our quarterly reports on Form 10-Q. 2020 audit fees include fees for the annual financial statement audit and interim reviews of the financial statements included in our quarterly reports on Form 10-Q. In both periods these amounts also include fees related to services in connection with transactions, regulatory filings, and consents.

(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, 2021 and December 31, 2020 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)    Financial Statements (see Part II, Item 8. of this Annual Report on Form 10-K regarding financial statements)

(2)    Financial Statement Schedules:  The separate filing of financial statement schedules has been omitted because such schedules are either not applicable or the information called for therein appears in the footnotes of our 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	Third Amended and Restated Agreement of Limited Partnership of the Partnership, dated November 23, 2021 (filed as Exhibit 3.1 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed November 29, 2021, and incorporated herein by reference).
3.3	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).
3.4	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).
3.5	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).
3.6	Second Amended and Restated Limited Liability Company Agreement of the General Partner, dated November 23, 2021 (filed as Exhibit 3.1 to the Partnership's Current Report on Form 8-K (Reg. No. 000-50056), filed November 29, 2021, and incorporated herein by reference).
3.7	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).
3.8	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).
3.9	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 incorporated herein by reference).
3.10	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).
3.11	Third Amended and Restated Limited Liability Company Agreement of Redbird Gas Storage LLC (F/K/A Cardinal Gas Storage Partners 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).
4.1	Indenture (including form of 11.50% Senior Secured Second Lien Notes due 2025), dated as of August 12, 2020, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein, U.S. Bank National Association as trustee, and U.S. Bank National Association as collateral trustee (filed as Exhibit 4.2 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed August 12, 2020 and incorporated herein by reference).
4.2	Indenture (including form of 10.00% Senior Secured 1.5 Lien Notes due 2024), dated as of August 12, 2020, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein, U.S. Bank National Association as trustee, and U.S. Bank National Association as collateral trustee (filed as Exhibit 4.3 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed August 12, 2020 and incorporated herein by reference).
4.3*	Description of Securities
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).
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)

136

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	Fifth Amendment to Third Amended and Restated Credit Agreement, dated April 27, 2016, 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 April 27, 2016, and incorporated herein by reference).
10.7	Sixth Amendment to Third Amended and Restated Credit Agreement, dated February 21, 2018, 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 February 22, 2018, and incorporated herein by reference).
10.8	Seventh Amendment to Third Amended and Restated Credit Agreement, dated July 24, 2018, 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 (SEC File No. 000-50056), filed July 25, 2018, and incorporated herein by reference).
10.9	Eighth Amendment to Third Amended and Restated Credit Agreement, dated as of April 16, 2019, 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 April 22, 2019, and incorporated herein by reference).
10.10	Ninth Amendment to Third Amended and Restated Credit Agreement, dated as of July 18, 2019, 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 July 24, 2019, and incorporated herein by reference).
10.11	Tenth Amendment to Third Amended and Restated Credit Agreement, executed as of March 2, 2020, by and among Martin Operating Partnership L.P., a Delaware limited partnership, as borrower, Martin Midstream Partners L.P., a Delaware limited partnership, the other Loan Parties party thereto, the Lenders party thereto, and Royal Bank Of Canada, as administrative agent and collateral agent for the Lenders and as an L/C Issuer and a Lender (filed as Exhibit 10.1 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed March 6, 2020, and incorporated herein by reference).
10.12	Eleventh Amendment to Third Amended and Restated Credit Agreement, executed as of July 8, 2020, by and among Martin Operating Partnership L.P., a Delaware limited partnership, as borrower, Martin Midstream Partners L.P., a Delaware limited partnership, the other Loan Parties party thereto, the Lenders party thereto, and Royal Bank of Canada, as administrative agent and collateral agent for the Lenders and as an L/C Issuer and a Lender (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed July 9, 2020, and incorporated herein by reference).
10.13	Twelfth Amendment to Third Amended and Restated Credit Agreement, dated as of July 16, 2021, by and among Martin Operating Partnership L.P., a Delaware limited partnership, as borrower, Martin Midstream Partners L.P., a Delaware limited partnership, the other Loan Parties party thereto, the Lenders party thereto, and Royal Bank of Canada, as administrative agent and collateral agent for the Lenders and as an L/C Issuer and a Lender (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed July 22, 2021, and incorporated herein by reference).
10.14	Backstop Agreement, dated as of July 9, 2020, among Martin Midstream Partners L.P., Martin Midstream Finance Corp., the other Credit Parties party thereto, and the backstop parties party thereto (filed as Exhibit 10.2 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed July 9, 2020, and incorporated herein by reference).
10.15	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).
10.16	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).
10.17	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).
10.18	Motor Carrier Agreement, dated January 1, 2006, as amended, 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).

137

10.19	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).
10.20*	2021 Amended and Restated Tolling Agreement, dated October 20, 2021, by and between the Operating Partnership and Cross Oil Refining & Marketing, Inc.
10.21	Marine Transportation Agreement, dated January 1, 2006, as amended, 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).
10.22	Marine Fuel Agreement, dated November 1, 2002, by and between Midstream 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).
10.23†	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).
10.24†	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).
10.25	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).
10.28	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).
10.29	Lubricants and Drilling Fluids Terminal Services Agreement by and between the Operating Partnership and MFS LLC, dated December 23, 2003, as amended, (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).
10.30†	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).
10.31	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).
10.32	Amended and Restated Common Unit Purchase Agreement, dated as of November 24, 2009, by and between the Partnership and Martin Resource Management Corporation (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).
10.33	Terminalling Services Agreement (Lubricants), dated January 1, 2015, as amended, 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).
10.34	Fuel Terminalling Services Agreement, dated January 1, 2015, by and between the Operating Partnership and Martin Energy Services LLC (filed as Exhibit 10.27 to the Partnership's Current Report on Form 10-K (SEC File No. 000-50056), filed March 2, 2015, and incorporated herein by reference).
10.35(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).
10.36(1)	First Amendment to the First Amended and Restated Fuel Terminalling Services Agreement, dated January 1, 2017, by and between the Operating Partnership and Martin Energy Services, LLC (filed as Exhibit 10.30 to the Partnership’s Annual Report on Form 10-K (SEC File No. 000-50056), filed February 15, 2017, and incorporated herein by reference).
10.37(1)	Second Amendment to the First Amended and Restated Fuel Terminalling Services Agreement, dated October 1, 2017, by and between the Operating Partnership and Martin Energy Services, LLC (filed as Exhibit 10.31 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056) filed October 25, 2017).
10.38	Martin Midstream Partners L.P. 2017 Restricted Unit Plan (filed as Exhibit A to the Partnership’s Definitive Proxy Statement on Schedule 14A (SEC File No. 000-50056), filed April 21, 2017, and incorporated herein by reference).
10.39	Restricted Unit Agreement under the Martin Midstream Partners L.P. 2017 Restricted Unit Plan (filed as Exhibit 10.34 to the Partnership's Annual Report on Form 10-K (SEC File No. 000-50056), filed February 16, 2018).
10.40	Partnership Interest Purchase Agreement (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed July 25, 2018 and incorporated herein by reference).
10.41	Stock Purchase Agreement between Martin Resource Management Corporation and the Operating Partnership (filed as Exhibit 10.1 on the Partnership’s Current Report Form 8-K (SEC File No. 000-50056), filed October 24, 2018 and incorporated herein by reference).

138

10.42	Master Transportation Services Agreement by and among Martin Resource Management Corporation, Cross Oil Refining & Marketing, Inc., Martin Energy Services LLC, and Martin Product Sales LLC (filed as Exhibit 10.1 on the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed April 26, 2019 and incorporated herein by reference.
10.43	Membership Interest Purchase Agreement by and among Hartree Cardinal Gas, LLC, Cardinal Gas Storage Partners LLC, Hartree Bulk Storage, LLC, and the Partnership (filed as Exhibit 10.1 on the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed June 13, 2019 and incorporated herein by reference.
10.44	Retention Bonus Agreement, dated as of August 28, 2020, among Martin Operating Partnership and certain Named Executive Officers, the material provisions of which were disclosed in item 5.02 on Form 8-K (SEC File No. 000-50056), filed September 3, 2020.
10.45	Restructuring Support Agreement, dated as of June 25, 2020, among Martin Midstream Partners L.P., Martin Midstream GP LLC, Martin Midstream Finance Corp., Martin Operating GP LLC, Martin Operating Partnership L.P., Martin Transport, Inc., Redbird Gas Storage LLC, Talen’s Marine & Fuel, LLC, and certain consenting noteholders of the Partnership’s 7.25% senior unsecured notes due 2021 (filed as Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed June 26, 2020, and incorporated herein by reference).
10.46	Asset Purchase and Sale Agreement, dated as of December 22, 2020, by and between Martin Operating Partnership L.P. and John W. Stone Oil Distributor, LLC (filed as Exhibit 10.1 on the Partnership’s Current Report Form 8-K (SEC File No. 000-50056), filed December 29, 2020 and incorporated herein by reference).
10.47	Vessel Purchase and Sale Agreement, dated December 22, 2020, by and between Martin Operating Partnership L.P. and John W. Stone Oil Distributor, LLC (filed as Exhibit 10.2 on the Partnership’s Current Report Form 8-K (SEC File No. 000-50056), filed December 29, 2020 and incorporated herein by reference).
10.48	Employment Agreement, dated October 20, 2020, between Martin Resource Management Corporation and Robert D. Bondurant (filed as Exhibit 10.1 on the Partnership’s Current Report on Form 8-K (SEC File No. 000-50056), filed October 22, 2020 and incorporated herein by reference).
10.49†	Martin Midstream Partners L.P. 2021 Phantom Unit Plan, effective as of July 21, 2021 (filed as Exhibit 10.1 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed July 26, 2021, and incorporated herein by reference).
10.50†	Form of Phantom Unit Award Agreement for the Martin Midstream Partners L.P. 2021 Phantom Unit Plan (filed as Exhibit 10.2 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed July 26, 2021, and incorporated herein by reference).
10.51†	Form of Phantom Unit Appreciation Right Award Agreement for the Martin Midstream Partners L.P. 2021 Phantom Unit Plan (filed as Exhibit 10.3 to the Partnership’s Quarterly Report on Form 10-Q (SEC File No. 000-50056), filed July 26, 2021, and incorporated herein by reference).
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	Inline 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, 2021, formatted in Extensible Business Reporting Language: (1) the Consolidated Balance Sheets; (2) the Consolidated Statements of Income; (3) Consolidated Statements of Comprehensive Income; (4) the Consolidated Statements of Cash Flows; (5) the Consolidated Statements of Capital; and (6) the Notes to Consolidated Financial Statements.
104	Cover Page Interactive Data File - the cover page XBRL tags are embedded within the Inline XBRL document (contained in Exhibit 101).
*	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 Exchange Act, which has been granted.

Item 16. Form 10-K Summary

139

Not applicable.

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
March 1, 2022	By:	/s/ Robert D. Bondurant
		Robert D. Bondurant
		President and Chief Executive Officer

	Martin Midstream Partners L.P
	(Registrant)
	By:	Martin Midstream GP LLC
		It's General Partner
March 1, 2022	By:	/s/ Sharon L. Taylor
		Sharon L. Taylor
		Vice President and Chief Financial 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 March 1, 2022.

140

Signature	Title
/s/ Robert D. Bondurant	President, Director, and Chief Executive Officer of Martin Midstream GP LLC (Principal Executive Officer)
Robert D. Bondurant
/s/Ruben S. Martin	Chairman of the Board of Directors of Martin Midstream GP LLC
Ruben S. Martin
/s/James M. Collingsworth	Director of Martin Midstream GP LLC
James M. Collingsworth
/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

141

EX-4.3

Exhibit 4.3

DESCRIPTION OF THE REGISTRANT’S SECURITIES

REGISTERED PURSUANT TO SECTION 12 OF THE

SECURITIES EXCHANGE ACT OF 1934

    As of March 1, 2022, Martin Midstream Partners L.P. has one class of securities registered under Section 12 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"): (1) our common units.

The following description of our common units is a summary and does not purport to be complete. It is subject to and qualified in its entirety by reference to our Third Amended and Restated Agreement of Limited Partnership, dated November 23, 2021 (our "Partnership Agreement"), which is incorporated by reference as an exhibit to the Annual Report on Form 10-K of which this Exhibit 4.3 is a part. We encourage you to read our Partnership Agreement for additional information.

Description of Our Common Units

    Our common units represent limited partner interests that entitle the holders to participate in our partnership distributions and to exercise the rights and privileges available to limited partners under our Partnership Agreement. References in this "Description of the Common Units" to "we," "us" and "our" mean Martin Midstream Partners L.P.

Number of Units

    As of March 1, 2022, we have 38,836,950 common units outstanding, 32,722,418 of which are held by the public, 4,203,823 are held by Martin Resource LLC, 889,444 are held by Cross Oil Refining & Marketing Inc. and 1,021,265 are held by Martin Product Sales LLC, each a wholly owned subsidiary of Martin Resource Management. The common units represent an aggregate 98.0% limited partner interest. Our general partner owns an aggregate 2.0% general partner interest in us.

Listing

    Our outstanding common units are traded on the Nasdaq National Market under the symbol "MMLP."

Transfer Agent and Registrar

    The transfer agent and registrar for our common units is Computershare.

Transfer of Common Units

    Except as otherwise provided in the Partnership Agreement, the transfer of a common unit will not be recorded by the transfer agent or recognized by us unless the transferee executes and delivers a transfer application. By executing and delivering a transfer application, the transferee of common units:

•becomes the record holder of the common units and is an assignee until admitted into our partnership as a substituted limited partner;

•automatically requests admission as a substituted limited partner in our partnership;

•agrees to be bound by the terms and conditions of, and executes, our Partnership Agreement;

•represents that the transferee has the capacity, power and authority to enter into our Partnership Agreement;

•grants powers of attorney to officers of our general partner and any liquidator of us as specified in our Partnership Agreement; and

•makes the consents and waivers contained in our Partnership Agreement.

    An assignee will become a substituted limited partner of our partnership for the transferred common units upon the consent of our general partner and the recording of the name of the assignee on our books and records. Our general partner may withhold its consent in its sole discretion.

    A transferee’s broker, agent or nominee may complete, execute and deliver a transfer application. We are entitled to treat the record holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the record holder as a result of any agreement between the beneficial owner and the record holder.

    Common units are securities and are transferable according to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to request admission as a substituted limited partner in our partnership for the transferred common units. A purchaser or transferee of common units who does not execute and deliver a transfer application obtains only:

•the right to assign the common unit to a purchaser or other transferee; and

•the right to transfer the right to seek admission as a substituted limited partner in our partnership for the transferred common units.

Thus, a purchaser or transferee of common units who does not execute and deliver a transfer application:

•will not receive cash distributions, unless the common units are held in a nominee or "street name" account and the nominee or broker has executed and delivered a transfer application; and

•may not receive some U.S. federal income tax information or reports furnished to record holders of common units.

    Our Partnership Agreement requires that a transferor of common units provide the transferee with all information that may be necessary to transfer the common units. The transferor is not required to insure the execution of the transfer application by the transferee and has no liability or responsibility if the transferee neglects or chooses not to execute and forward the transfer application to the transfer agent.

    Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or applicable stock exchange regulations.

Cash Distributions

Our Partnership Agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date. Other than the requirement in our Partnership Agreement to distribute all of our available cash each quarter, we have no legal obligation to make quarterly cash distributions and the board of directors of our general partner has considerable discretion to determine the amount of our available cash each quarter. Available cash generally means, for each fiscal quarter, all cash and cash equivalents on hand at the end of each quarter less the amount of cash reserves our general partner determines in its reasonable discretion is necessary or appropriate to: (i) provide for the proper conduct of our business; (ii) comply with applicable law, any debt instruments or other agreements; or (iii) provide funds for distributions to unitholders and our 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. Working capital borrowings are borrowings that are made under our revolving credit facility or other arrangement requiring all borrowings thereunder to be reduced to a relatively small amount each year for an economically meaningful period of time and in all cases are used solely for working capital purposes or to pay distributions to partners.

Liquidation

If we dissolve in accordance with our Partnership Agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the holders of common units and our general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation, all in accordance with the terms of our Partnership Agreement.

Voting Rights

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. The holders of a majority in voting power of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage. For all matters presented to the limited partners at a meeting at which a quorum is present for which no minimum or other vote of the limited partners is specifically required pursuant to our Partnership Agreement, the rules and regulations of any national securities exchange on which the common units are admitted to trading, or applicable law

or pursuant to any regulation applicable to us or our partnership interests, a majority of the votes cast by the limited partners holding outstanding common units will be deemed to constitute the act of all limited partners (with abstentions and broker non-votes being deemed to not have been cast with respect to such matter). The general partner interest does not entitle our general partner to any vote other than its rights as general partner under our Partnership Agreement, will not be entitled to vote on any action required or permitted to be taken by the unitholders and will not count toward or be considered outstanding when calculating required votes, determining the presence of a quorum, or for similar purposes.

Each record holder of a unit has a vote according to its percentage interest in us. However, if at any time any person or group, other than our general partner and its affiliates, a direct transferee of our general partner and its affiliates, a transferee of such direct transferee, who is notified by our general partner that it will not lose its voting rights, or a person or a group who acquired 20% or more of any class of units issued by us with the prior approval of the board of directors of our general partner, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum, or for other similar purposes.

    The following matters require the unitholder vote specified below. Matters requiring the approval of a "unit majority" requires the approval of a majority of the outstanding common units.

Matter	Vote Requirement
Issuance of additional units	No approval rights.
Amendment of the Partnership Agreement	Certain amendments may be made by the general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority.
Merger of our partnership or the sale of all or substantially all of our assets	Unit majority.
Dissolution of our partnership	Unit majority.
Reconstitution of our partnership upon dissolution	Unit majority.
Withdrawal of the general partner	The approval of a majority of the outstanding common units, excluding common units held by the general partner and its affiliates, is required for the withdrawal of the general partner prior to September 30, 2012 in a manner which would cause a dissolution of our partnership.
Removal of the general partner	Not less than 66 2/3% of the outstanding units, including units held by our general partner and its affiliates.
Transfer of ownership interests in the general partner	Our general partner may transfer its general partner interest without a vote of our unitholders in connection with the general partner’s merger or consolidation with or into, or sale of all or substantially all of its assets to, a third person. Our general partner may also transfer all of its general partner interest to an affiliate without a vote of our unitholders. The approval of a majority of the outstanding common units, excluding common units held by the general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to September 30, 2012.
Transfer of ownership interests in the general partner	No approval required at any time.

Amendments of Our Partnership Agreement

Amendments to our Partnership Agreement may be proposed only by or with the consent of our general partner, which consent may be given or withheld in its sole discretion. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner must seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments. No amendment may be made that would:

•enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected;

•enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which may be given or withheld in its sole discretion;

•change the duration of our partnership;

•provide that our partnership is not dissolved upon an election to dissolve our partnership by our general partner that is approved by a unit majority; or;

•give any person the right to dissolve our partnership other than our general partner’s right to dissolve our partnership with the approval of a unit majority.

The provision of our Partnership Agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class.

Additionally, our general partner may generally make amendments to our Partnership Agreement without the approval of any limited partner in certain circumstances.

Limitations on Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that it otherwise acts in conformity with the provisions of our Partnership Agreement, its liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital it is obligated to contribute to us for its common units plus its share of any undistributed profits and assets.

Issuance of Additional Partnership Interests

Subject to certain limitations, our Partnership Agreement authorizes us to issue an unlimited number of additional partnership interests and options, rights, warrants and appreciation rights relating to the partnership interests for any partnership purpose at any time and from time to time to such persons for such consideration and on such terms and conditions as our general partner shall determine in its sole discretion, all without the approval of any partners.

In accordance with Delaware law and the provisions of our Partnership Agreement, we may also issue additional partnership interests that, as determined by our general partner, may have special voting rights to which the common units are not entitled.

Change of Management Provisions

Our Partnership Agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Martin Midstream GP LLC as our general partner or otherwise change our management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group who are notified by our general partner that they will not lose their voting rights or to any person or group who acquires the units with the prior approval of the board of directors of our general partner.

Limited Call Right

If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of such class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10, but not more than 60, days’ written notice.

Books and Reports

Our Partnership Agreement states that we will mail or make available to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also mail or make available summary financial information within 90 days after the close of each quarter. We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year.

Right to Inspect Our Books and Records

In addition to information that a limited partner would otherwise have under Delaware law, our Partnership Agreement provides that a limited partner can, for a purpose reasonably related to its interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at its own expense, have furnished to such limited partner, certain information regarding the status of our business and financial condition, in addition to certain information related to our record holders.

EX-10.20

Exhibit 10.20

2021 AMENDED AND RESTATED TOLLING AGREEMENT

    This 2021 Amended and Restated Tolling Agreement (“Agreement”), effective as of October 20, 2021, is made by and between Martin Operating Partnership L.P., a Delaware limited partnership (“Owner”), and Cross Oil Refining & Marketing, Inc., a Delaware corporation (“Customer”), sometimes referred to individually as a “Party” and collectively as the “Parties.”

RECITALS

WHEREAS, Owner and Customer were previously parties to that certain Tolling Agreement dated November 25, 2009, as amended, followed by that certain Amended and Restated Tolling Agreement dated August 1, 2012, as amended, and currently that certain 2014 Amended and Restated Tolling Agreement dated October 28, 2014, as amended (“Original Agreement”), whereby Owner provides Customer with transportation of Customer’s crude oil from the Magnolia Facility (as defined in that certain Pipeline Transportation and Storage Agreement by and between Owner and Lion Oil Trading & Transportation, Inc. dated October 1, 2011) to Owner’s naphthenic lubricant refinery located in Ouachita County and Union County, Arkansas (“Refinery”) and refining and storage of various quantities of naphthenic lubricants designated by Customer from time to time (all such services referred to herein as the “Refining Services”) at the Refinery; and

    WHEREAS, the Parties wish to enter into this Agreement for the purposes of amending and restating the Original Agreement with respect to the foregoing matters.

    NOW, THEREFORE, in consideration of the mutual promises contained in this Agreement, the Parties agree to the following terms and conditions relating to Owner’s provision of refining and storage services in favor or Customer at the Refinery.

Section 1.    Definitions.In this Agreement, unless the context requires otherwise, the following terms will have the meanings indicated below:

“Affiliate” means, as to any Person, any other Person directly or indirectly controlling, controlled by, or under direct or indirect common control with, such Person. A Person shall be deemed to be controlled by any other Person if such other Person possesses, directly or indirectly, power (a) to vote 10% or more of the securities (on a fully diluted basis) having ordinary voting power for the election of directors, managing members, or managing general partners; or (b) to direct or cause the direction of the management and policies of such Person whether by contract or otherwise.

    “Aggregate Quarterly Tolling Fee” means, for the applicable quarter an amount equal to the sum of (a) the Minimum Quarterly Tolling Fee, (b) the Monthly Reservation Fees paid with respect to such quarter (c) the Gas Surcharge (if any) and (d) the Excess Quarterly Tolling Fee (if any).

“Change of Control” has the meaning set forth in that certain Third Amended and Restated Credit Agreement datedas of June 27, 2014, among Owner, as borrower, Martin Midstream Partners L.P. ("MMLP"), as a guarantor, Royal Bank of Canada, as administrative agent, and the financial institutions party thereto, as lenders, as amended.

“Contribution Agreement” means that certain Amended and Restated Contribution Agreement dated November 4, 2009, among MRMC, Customer, owner and MMLP.

“Customer” has the meaning specified in the preamble paragraph to this Agreement.

“Effective Date” means November 25, 2009.

“Excess Tolling Fee” has the meaning set forth in Exhibit A.

    “Excess Tolling Volume” means the number of barrels of Stock per fiscal quarter in excess of the product of (a) 6,500 multiplied by (b) the number of days in such fiscal quarter.

    “Excess Quarterly Tolling Fee” means the following amounts determined for the applicable fiscal quarter in the aggregate if there is Excess Tolling Volume: an amount equal to the product of (a) the Excess Tolling Volume, multiplied by the Excess Tolling Fee.

“Force Majeure" means (i) acts of nature, landslides, severe lightning, earthquakes, fires, tornadoes, hurricanes, storms, and warnings for any of the foregoing which require the shut-down of wells, plants, pipelines, gathering systems, loading facilities or the Refinery or other related facilities, floods or other water conditions, washouts, severe lightning, freezing of machinery, equipment, wells or lines of pipe, inclement weather that necessitates extraordinary measures and expense to construct facilities or maintain operations, and other adverse weather conditions, (ii) explosions, breakage or accidents to equipment, machinery, plants, facilities or lines of pipe, the making of repairs or alterations to lines of pipe or plants, inability to secure labor or materials to do so, partial or entire failure of wells or gas supply, electric power shortages, accidents of navigation or breakdown or injury of vessels, or (iii) any other causes, whether of the kind enumerated above or otherwise, which were not reasonably foreseeable, and which are not within the control of the Party claiming suspension and which by the exercise of due diligence such Party is unable to prevent or overcome.

“Gas Surcharge” has the meaning set forth in Section 3.4.

“Minimum Daily Tolling Volume” means 6,500 barrels of Stock per day.

    “Minimum Quarterly Tolling Fee” means an amount equal to the product of (a) the Minimum Daily Tolling Volume, multiplied by (b) the Tolling Fee, multiplied by (c) the number of days in the applicable fiscal quarter.

“Monthly Reservation Fee” has the meaning set forth in Exhibit A.

“Person” means any natural person, trustee, corporation, general partnership, limited partnership, limited liability company, joint stock company, trust, unincorporated organization, bank, business association, firm, joint venture, governmental authority, company or other entity

“Product” means naphthenic lubricants, distillates, asphalt flux and other intermediate cuts.

    “Owner” has the meaning specified in the preamble paragraph to this Agreement.

“Refinery” has the meaning specified in the recitals to this Agreement.

“Refining Services” has the meaning specified in the recitals to this Agreement.

“Stock” means crude oil.

“Term” or “term” means twenty-two (22) years commencing on the Effective Date.

“Tolling Fee” has the meaning set forth in Exhibit A.

Section 2.    Refining Services, Statements, Documents and Records.

    2.1    During the term of this Agreement, Owner agrees to provide all neces.sary Refining Services, including services relating to the transportation, receipt, storage and refining, in connection with the refinement of Customer’s inventories of Stock supplied by Customer to Owner from time to time into various grades and quantities of Product designated by Customer from time to time. Owner agrees that the facilities at the Refinery, together with the right to use the Retained Refinery Related Assets (as defined in The Contribution Agreement), are reasonably suited to perform such tasks. Those activities will be performed by Owner in a manner consistent with good operational procedures and safeguards and in compliance with applicable laws, rules, regulations and ordinances. Owner shall be entitled to elect the method of transportation of Stock in order to perform the Refining Services, and may utilize third party providers of freight services, storage facilities, transshipment services, transportation services whether by barge, pipeline, or otherwise, or any other third party arrangement Owner sees fit in the performance of the Refining Services.

    2.2    All inventories of Stock delivered by Customer to Owner hereunder shall be FOB to Owner at its designated internal point of delivery at the Refinery or the Magnolia Facility. All inventories of Product delivered by Owner to Customer hereunder shall be FOB to Customer at Owner’s designated internal point of delivery at the Refinery. Customer agrees to bear all freight and transportation charges relating to all inbound quantities of Stock to the Refinery or the Magnolia Facility and all outbound quantities of Product hereunder.

    2.3    Owner will transmit to Customer a statement of receipts and deliveries of Stock to and Product from the Refinery on a daily basis no later than 10:00 a.m. local time at the Refinery for the immediately preceding business day; provided, however, that if a holiday precedes a business day, the statement with respect to the preceding business day shall not be due until 3:00 p.m. local time on the business day following such holiday. This statement will be transmitted to Customer by facsimile.

    2.4    Owner will provide to Customer copies of individual tank gauging documents, tank truck loading rack bills of lading and scale tickets for receipts or deliveries as requested by Customer to verify the amount of Stock delivered to and Product received from the Refinery.

    2.5    Each Party will maintain a true and correct set of records pertaining to its performance of this Agreement and all transactions related to such performance and will retain copies of all such records for a period of not less than one year following termination or cancellation of this Agreement. Upon reasonable prior" notice, a Party or its authorized representative may, during the Term of this Agreement and for the aforesaid one-year period, audit such records of the other Party during normal business hours at the other Party’s place of business to verify the accuracy of any statement, charge, computation, or demand made under or pursuant to this Agreement. Each Party agrees to keep records and books of account in accordance with generally accepted accounting principles in the industry. Any statement shall be deemed accurate and final as to both Parties unless questioned within one year after payment thereof has been made.

Section 3.    Fees, Charges, Invoices and Taxes.

    3.1    Concurrent with the execution of this Agreement, Customer shall pay to Owner the Monthly Reservation Fee, pro rated for the number of days remaining in the month on which this Agreement is executed. Thereafter, at least 10 days prior to first day of each calendar month, Customer shall pay Owner the Monthly Reservation Fee for such month. Within 30 days following the end of each fiscal quarter during the Term of this Agreement, Owner will submit to Customer statements recording the volume of Customer’s Stock received into and Product delivered from the Refinery during such fiscal quarter and shall submit an invoice to Customer in respect of Refining Services provided by Owner during such quarter reflecting an amount equal to the Aggregate Quarterly Tolling Fee for such Quarter, minus the Monthly Reservation Fees already paid with respect to such quarter (the “Quarterly Payment”). The Minimum Quarterly Tolling Fee for a particular fiscal quarter shall not be subject to any downward adjustment due to the failure of Customer to throughput at the Refinery the aggregate Minimum Daily Tolling Volume for the entirety of such quarter; provided, however, unless such failure is (a) a reasonable result of Customer’s breach of any aspect of the Contribution Agreement, or (b) due to Customer’s failure to provide sufficient Stock, or (c) the result of a Force Majeure event, the effects of which are covered in Section 9 hereof, then the Minimum Quarterly Tolling Fee and the Monthly Reservation Fee for a particular quarter will be subject to a proportional downward adjustment to the extent that, due to Owner’s operational difficulties and/or downtime at, or the closing of any portion of, the Refinery, Owner is not able to refine for the entirety of such quarter a volume equal to the product of the aggregate Minimum Daily Tolling Volume multiplied by the number of days in such quarter. If the Monthly Reservation Fees paid with respect to such quarter have been subject the proportional downward adjustment, such proportionate reduction, to the extent already paid by Customer to Owner with respect to such quarter, shall be refunded to Customer within 30 days following the end of the applicable quarter.

The Tolling Fee and the Monthly Reservation Fee are subject to any applicable adjustment set forth in Section 3.3 below and adjustment set forth in Section 3.6 below.

    3.2    All fees and charges reflected in Owner’s invoices are due and payable within ten days of the date of Owner’s invoice.

    3.3    The Monthly Reservation Fee, Excess Tolling Fee and Tolling Fee, as specified in Exhibit “A” attached hereto and incorporated by reference, payable under this Agreement will each be increased annually on January 1st by an amount equal to the applicable fee in effect on the prior January 1st multiplied by two-thirds (2/3) of the annual percentage change (increase or decrease) in the Consumer Price Index For Urban Wage Earners and Clerical Workers (1967=100) specified for “All Items United States” compiled by the Bureau of Labor Statistics of the United States Department of Labor (“CPI”), by comparing the CPI for the months of October immediately prior to the commencement of the year for which the fee escalation is being calculated with the CPI for the same month in the preceding 12-month period. For example, if the year for which the adjusted fees are being calculated commences on January 1, 2022, the base months for determining the adjustment would be October 2021 and October 2020. In this example, the fees and charges would be adjusted, effective January 1, 2022, based upon the percentage increase in the CPI between that published for October 2020 and that published for October 2021 multiplied by two-thirds (2/3). If the United States Government materially changes the manner of computing the CPI or ceases to publish the CPI at any time during the Term of this Agreement, the Parties will negotiate in good faith to agree upon a substitute index or methods of computing the index for purposes of escalating the fees and charges under this Agreement. Notwithstanding the foregoing, any CPI adjustment hereunder shall not (i) decrease the Monthly Reservation Fee, Excess Tolling Fee or Tolling Fee to an amount less than the amount stated in the Section 1, Definitions as of the date signed hereof or (ii) fail to cover any additional operating costs Owner may incur to provide the Refinery Services hereunder for two (2) consecutive years, which in such event shall trigger the Parties to renegotiate the CPI

adjustment mechanism under this Section 3.3 to more accurately capture such increase in additional operating costs.

    3.4    Owner may add a reasonable surcharge to reflect increased natural gas costs utilized in the refining of the Products (the “Gas Surcharge”), which shall be calculated for each fiscal quarter in accordance with the following formula:

    (a)    The excess of (i) the average of the NYMEX Henry Hub daily closing prices of natural gas during the fiscal quarter (expressed in dollars per MMBTU), over (ii) $4.00 MMBTU; multiplied by

    (b)    the total number of barrels of Stock refined during such fiscal quarter; multiplied by

    (c)    0.57.

Direct natural gas costs will be based upon usage as determined by metering equipment that serves the Refinery.

    3.5    During the term of this Agreement and in consideration of Owner’s agreement to provide Refining Services to Customer hereunder, in addition to the other amounts owed to the Owner hereunder, Customer shall be responsible for all taxes, including ad valorem taxes, assessed against the Stock and the Products, including any sales and use tax.

    3.6    On each anniversary of the Effective Date of this Agreement, a party may request a renegotiation of the Monthly Reservation Fee, if such party reasonably believes that the adjustments in Section 3.3 do not accurately reflect actual increases or decreases in operating costs. In such a case, the parties shall negotiate in good faith to reach mutual agreement on a revised Monthly Reservation Fee which the parties believe will more accurately operating costs for subsequent periods. Any such revised Monthly Reservation Fee that is mutually agreed to shall apply in quarterly periods beginning subsequent to the time of such mutual agreement. For the avoidance of doubt, no adjustments shall be made to the Monthly Reservation Fee to account for any differences between actual and projected operating costs previously incurred, i.e. there is no “true up” contemplated by the Parties.

Section 4.    Operations, Receipts and Deliveries.

    4.1    Customer’s Stock may be delivered and its Product received by Owner at the Refinery via pipeline, rail or truck or on behalf of Customer free of any charge to Owner.

    4.2    Receipts of Product by the Owner will be handled within the normal business hours of the Refinery, as may be established from time to time. Owner will not be responsible for the payment of any demurrage or costs incurred by Customer or its transportation carrier for any delay in receiving Stock or delivering the Product, and all such charges shall be the responsibility of the Customer.

4.3    Owner will notify Customer of changes to the normal business hours of the Refinery, in advance or as soon after implementation as is practicable.

    4.4    Owner and Customer shall perform all activities specified herein in accordance with all applicable federal, state and local laws, rules, regulations, ordinances, decrees, orders, permits, licenses or other requirements having the force of law.

    4.5    Customer must arrange for and pay all third party costs relating to the transportation, receipt, delivery and packaging of all Stock and Products of Customer which are delivered to and from the Refinery.

    4.6    Within 45 days following termination of this Agreement, Customer, at its sole cost and expense, will remove and properly dispose of, or cause to be removed and properly disposed of all Stock, Product, residue, scale, non-merchantable bottoms, and any other accumulation from the Refinery which constitute property of Customer, including the storage tanks and clean the storage tanks’ interior to a condition suitable for the storage of Stock and Product as is typical for the Refinery. If Customer fails to comply with this requirement within the time period referenced, Customer authorizes Owner to either (i) take such action on Customer’s behalf, and Customer will reimburse Owner for all cost and expense reasonably incurred in taking such action, plus a 15% handling fee, and (ii) charge Customer for the cost of storage and handling of said Product at a rate of $0.02 per barrel per day storage in addition to any other fees and rates payable to Owner by Customer under this Agreement, which fees and rates will continue to apply if the Product has not been removed by Customer within the aforesaid 45-day period. Owner's remedies under this Section 4.6 are in addition to any other remedies that Owner may have at law, in equity or otherwise.

    4.7    Owner will not be required to make any improvements, alterations or additions to the Refinery in connection with the provision of the Refining Services. If any federal, state or local governmental body requires installation of any improvement, alteration or addition to the Refinery for purposes of compliance with applicable law or regulation that would materially interfere with or change the nature or cost of providing the Refining Services under this Agreement, Owner will notify Customer of (i) the cost of making any such improvement, alteration or addition, and (ii) when such improvement, alteration or addition must be completed. In the event such costs are $100,000 or less, Owner shall proceed to make such required improvements, alterations or additions. In the event such costs exceed $100,000, Owner and Customer agree to renegotiate the terms of this Agreement in good faith to effect a sharing of such costs. In addition, Owner may, in its discretion, make such improvements, alterations or additions to the Refinery as it may from time to time deem necessary, provided that such discretionary alterations due not interfere with the provision of Refining Services hereunder.

Section 5.    Product Quality Standards and Requirements.

5.1    Customer agree that Owner shall not be required to receive Stock into the Refinery that (i) contains adulterants, which are not normally present in the Product, which pose a risk of damage to Owner’s equipment; (ii) contains any Hazardous Substance (other than petroleum or petroleum by-products); or (iii) does not have properties within the following limits:

Sulfur Content, wt%:    4% Maximum

API Gravity:        20 – 70 deg. API

True Vapor Pressure:    Not greater than 10.9 psia at actual liquid storage                         temperature while in tanks at the Terminal

Viscosity:        Not greater than 420 SUS @100 deg. F and 1500                         SUS @ 60 deg. F

Pour Point:        50 deg. F Max.

    Hydrogen Sulfide:    100 ppm maximum in liquid; 200 ppm maximum in vapor.

    5.2    Owner may sample any Stock delivered to the Refinery for the purpose of conducting an analysis of such Stock. The cost of such analysis will be borne by Owner. The Owner shall use reasonable efforts to keep the results of such analysis confidential.

Section 6.    Title, Custody and Loss of Product.

    Title to Customer’s Stock and Product will remain with Customer at all times, subject to any lien in favor of Owner created pursuant to the terms of this Agreement or under applicable law. Owner will assume custody of the Stock and Product beginning when such Stock or Product passes to the internal point of delivery referred to in the first sentence of Section 2.2 and custody will pass back to Customer at the time such Stock or Product passes to the internal point of delivery referred to in the second sentence of Section 2.2.

Section 7.    Limitation of Liability and Damages.

Notwithstanding any other provision of this Agreement, Owner shall not be responsible for any lost or contaminated Stock or Product, nor liable for any loss, additional cost, lost profit or opportunity, or consequential damage arising therefrom.

Section 8.    Stock and Product Measurement.

8.1    Quantities of Stock received into and Product delivered from the Refinery will be determined for the applicable mode of receipt and delivery by either (i) shore tank or truck tank gauge reading taken before and after each receipt or delivery, (ii) loading rack meter readings, (iii) certified scales, (iv) pipeline meters or (v) other appropriate quantity measuring devices, as determined by Owner. Absent obvious error, the quantities of Stock and Products at the Refinery at any time will be determined from Refinery inventory records of receipts and deliveries. Inventory records of Stock and Product will be verified against the sum of the material at the Refinery as well as line charge. Gauging of Stock received, Product delivered and Stock or Product in storage will be taken jointly by representatives of the Parties; provided, that if Owner does not have representatives present for gauging, Customer’s gauging will be conclusive. Owner may use certified public inspectors at its own expense.

    8.2    Refinery and loading facility meters will be calibrated periodically and upon each completion of repair or replacement of a meter, at Owner’s expense. Current calibration charts, licenses and inspection permits will be available at the Refinery for examination during normal business hours. If a meter is determined by either Party to be defective or inoperative, such Party shall immediately notify the other Party, and it will be the responsibility of the Owner to promptly make repairs or replacements.

    8.3    Unless indicated otherwise, quantity determinations will be based on barrels of Stock or Product.

Section 9.    Force Majeure; Cessation of Operations.

9.1    If either Party is rendered unable to perform or delayed in performing, wholly or in part, its obligations under this Agreement, other than the obligation to pay the Aggregate Quarterly Tolling Fee when due, which shall be payable irrespective of whether a Force Majeure event exists, as a result of a Force Majeure event, that Party may seek to be excused from such performance by giving the other Party prompt written notice of the Force Majeure event with reasonably full particulars of such event. The obligations of the Party giving notice, so far as they are affected by the Force Majeure event, will be suspended during, but not longer than, the

continuance of the Force Majeure event. The affected Party must act with commercially reasonable diligence to resume performance and notify the other Party that the Force Majeure event no longer affects its ability to perform under the Agreement.

9.2    The requirement that any Force Majeure event be remedied with all reasonable dispatch will not require the settlement of strikes, lockouts, or other labor difficulty by the Party claiming excuse due to a Force Majeure event contrary to its wishes.

    9.3    If either Party is rendered unable to perform by reason of Force Majeure for a period in excess of 120 days, and if the party seeking excused performance has not, within such 120 day period, sought to effect a solution to the inability to perform and thereafter diligently continued with such solution until the event has passed and the ability to act and perform is restored, then the other Party may terminate this Agreement upon written notice to the Party claiming excuse due a Force Majeure event.

    9.4    If Owner is excused from providing service pursuant to this Agreement due to an event of Force Majeure that extends beyond a 120 consecutive day period, the fees hereunder that accrue after the expiration of such 120 day period, and the Quarterly Minimum Tolling Fee and the Monthly Reservation Fees with respect to such quarter, if any, that are directly affected by such Force Majeure event will be excused or proportionately reduced to the extent that such event of Force Majeure results in Owner being unable to refine for the entirety of such quarter a volume equal to the product of the aggregate Minimum Daily Tolling Volume multiplied by the number of days in such quarter. With respect to any reduction in the Monthly Reservation Fees, any such amount shall be refunded to Customer upon determination of the adjustments to be made pursuant to this Section 9.4.

    9.5    Notwithstanding anything to the contrary contained in this Agreement, in the event that Owner cannot provide the services under this Agreement as a result of any breech of a representation, warranty or indemnity of Customer contained in the Contribution Agreement, there shall be no reduction in fees under this Agreement and Owner shall be entitled to receive the Aggregate Quarterly Tolling Fee with respect to the period for which services cannot be performed.

Section 10.    Inspection of and Access to Refinery.

10.1    Subject to Customer meeting Owner’s safety requirements and its other reasonable rules and regulations concerning activities in and around the site, Customer’s right and that of its authorized representatives to enter the Refinery in order to observe and verify Owner’s performance hereunder will be exercised in a way that will not interfere with or diminish Owner’s control over or its operation of the Refinery and will be subject to reasonable rules and regulations from time to time promulgated by Owner.

10.2    Customer acknowledges that any grant of the right of access to the Refinery under this Agreement or under any document related to this Agreement is a grant of merely a license and conveys no interest in or to the Refinery or any part of it, and may be withdrawn by Owner at its discretion at any time, subject to the terms of this Agreement.

Section 11.    Assignment.

(a)This Agreement shall be binding upon and shall inure to the benefit of the Parties hereto and their permitted successors and assigns. Neither Party may assign this Agreement, directly or indirectly, without the express prior written consent of the other Party; provided,

however, that either Party may assign this Agreement to a wholly-owned entity or to an entity that wholly-owns the assigning Party; and provided further, that Owner shall be permitted to pledge its rights under this Agreement to any current or future lenders of Owner and Martin Midstream Partners L.P. and Customer acknowledges that such lenders have the right to take an assignment of this Agreement if such pledge is foreclosed upon. For purposes of this Section, “assign” will be considered to include any Change of Control of a Party or an assignment by operation of law in connection with a merger, consolidation, reorganization, receivership, bankruptcy or similar event or by asset sale. In the event the non-assigning Party, upon request by the assigning Party, consents to such assignment, the rights of obligations of the assigning Party shall be binding upon the permitted assignees. The consent by a Party to any assignment, subletting, hypothecation, pledge, encumbrance, mortgage of this Agreement will not constitute a waiver of such Party’s right to withhold its consent to any other or further assignment, subletting, hypothecation, pledge, encumbrance, mortgage of the Agreement. The absolute and unconditional prohibitions contained in this Section are material inducements by the Parties to enter into this Agreement and any breach thereof by a Party will constitute a material default by such Party under this Agreement permitting the non-breaching Party to exercise all remedies provided for in this Agreement or by law.

(b)In the event that this Agreement is terminated as a result of Section 12.1(d), upon the written request of Customer, Owner will seek to cause any successor to negotiate a reasonably acceptable agreement with Customer to provide continued Refining Services to Customer. The obligations under this Section 11(b) shall terminate in the event that Customer’s secured credit facility agented by Regions Bank is terminated.

Section 12.    Termination.

    12.1    This Agreement may be terminated as follows:

    (a)    This Agreement may be terminated at any time by the mutual agreement of the Parties.

    (b)    This Agreement may be terminated by a Party as a result of a breach by the other Party as provided in Section 15.

    (c)    This Agreement may be terminated by a Party as a result of the other Party (including such Party’s assets) (i) filing for bankruptcy (whether voluntary or involuntary, including any petition under insolvency or similar laws), or being adjudicated insolvent or bankrupt, (ii) seeking dissolution or reorganization or the appointment of a receiver, trustee, custodian or liquidator for a substantial portion of its property, assets or business or to effect a plan or other arrangement with its creditors, (iii) making a general assignment for the benefit of its creditors, or consenting or acquiescing in the appointment of a receiver, trustee, custodian or liquidator for a substantial portion of its property, assets or business, or (iv) becoming subject of an involuntary petition for dissolution, reorganization or the appointment of a receiver, trustee, custodian or liquidator or becoming subject to any writ, judgment, warrant of attachment, execution or similar process which is not dismissed within 60 days.

    (d)    This Agreement will automatically terminate in the event that the Owner or its permitted assignees hereunder no longer owns the Refinery.

    (e)    This Agreement will automatically terminate in the event the Omnibus Agreement among Owner, Martin Midstream GP LLC Customer and MMLP, dated November 1, 2002, is terminated.

    (f)    This Agreement is terminated at Owner’s sole and exclusive election in the event that either Customer or Martin Resource Management Corporation materially defaults under the Contribution Agreement and such default is not cured within the applicable cure period of such Contribution Agreement and the cure period provided in Section 15 of this Agreement; provided, however, that any Party that has claimed a dispute pursuant to the applicable provisions of this Contribution Agreement shall not be deemed to be in default until such dispute is resolved against such Party in accordance with the provisions of the Contribution Agreement.

    (g)    The Agreement will terminate upon expiration of the Term.

Section 13.    Notice.

    Any notice required under this Agreement must be in writing and will be deemed received when actually received and delivered by (i) United States mail, certified or registered, return receipt requested, (ii) confirmed overnight courier service, or (iii) confirmed facsimile transmission properly addressed or transmitted to the address of the Party indicated below or to such other address or facsimile number as a Party will provide to the other Party in accordance with this provision:

If to Customer:    Cross Oil Refining & Marketing, Inc.

            Attn: Chris Booth

            4200 Stone Road

            Kilgore, Texas 75662

            Telephone: (903) 988-6443

            Telecopy: (903) 988-7915

If to Owner:        Martin Operating Partnership L.P.

            Attn: Chris Booth

            4200 Stone Road

            Kilgore, Texas 75662

            Telephone: (903) 988-6443

            Telecopy: (903) 988-7915

            with a copy to:

                Mr. Byron Kelley    

                14 Holley Ridge Drive

            Kingwood, Texas 77339-3517

            Telephone: (281) 360-7125

Section 14.    Compliance with Law and Safety.

    14.1.    Customer warrants that the Stock delivered by it to the Refinery is produced, transported, and handled are in full compliance with all statutes, ordinances, rules, regulations, orders and directives of federal, state, or local authority (“laws”), including those applicable to environmental pollution, and all presidential proclamations that apply to either Party. Customer also warrants that the Product tendered to it by Owner at the Refinery is transported and handled in full compliance with all laws, including those applicable to environmental pollution, and all presidential proclamations that apply to either Party.

    14.2.    Customer certifies, on behalf of itself, its employees, agents, and contractors that all vehicles and vessels used in connection with this Agreement will comply with all applicable federal, state, and local laws and that they will comply with Owner’s safety rules. Customer will furnish Owner with information (including Material Safety Data Sheet) concerning the safety

and health aspects of each of the Products produced under this Agreement. Customer will communicate such information to all persons who may be exposed to or may handle such Products, including without limitation, Owner’s employees, agents and contractors.

    14.3    Unless the Stock provided by Customer contained adulterants or Customer has breached its Pre-Closing Liabilities under the Contribution Agreement, Owner warrants that the Products produced are in full compliance with all statutes, ordinances, rules, regulations, orders and directives of federal, state, or local authority (“Laws”), including those applicable to environmental pollution, and all presidential proclamations that apply to either Party.

Section 15.    Default, Waiver and Remedies

    A material breach of any of the terms and conditions of this Agreement by either Party will constitute a default. Upon default, the non-defaulting Party shall, within 30 calendar days of knowledge of such default, notify the defaulting Party of the particulars of such default and the defaulting Party has 30 calendar days thereafter to cure such default. Upon the defaulting Party’s failure to cure the default within the 30-day grace period, any and all obligations, including payments of fees due under this Agreement, will, at the option of the non-defaulting Party, become immediately due and payable and the non-defaulting Party may terminate this Agreement upon written notice to the defaulting Party. The waiver by the non-defaulting Party of any right under this Agreement will not operate to waive any other such right nor operate as waiver of that right at any future date upon another default by either Party under this Agreement and a single or partial exercise of any right, power or privilege will not be presumed to preclude any subsequent or further exercise of that right, power, or privilege or the exercise of any other right, power, or privilege. Nothing in this Section is intended in any way to limit or prejudice any other rights or remedies the non-defaulting Party may have under this Agreement or the law. The remedies of Owner provided in this Agreement are not exclusive and, except as otherwise expressly limited by this Agreement, are in addition to all other remedies of Owner at law or in equity. Acceptance by Owner of any payment from Customer for any charge or service after termination of this Agreement shall not be deemed a renewal of this Agreement under any circumstances, nor a waiver of any rights Owner may have under this Agreement or otherwise.

Section 16.    Insurance.

16.1.    Coverage by Owner.

    (A) During the term of this Agreement Owner will procure and maintain, at its sole expense, with solvent underwriters, policies of insurance in the minimum amounts outlined below:

(1) Commercial General Liability (Occurrence Form) for bodily injury and property damage, including the following coverage: premises/operations, independent contractors, blanket contractual liability, explosion, broad form property damage, products/completed operations, sudden and accidental pollution liability and, where appropriate, stop-gap coverage with total limits to all insureds for not less than $1 million for each occurrence and $2 million aggregate for each annual period;

        (2) Excess Liability of $5 million in excess of the limits for all of the above insurance policy types to include a “drop down” provision in the event the underlying limits are exhausted;

    (3) Workers’ Compensation complying with the laws and statutory minimum coverage of the state or states where performance under this Agreement takes place, whether or

not such coverage its required by law, including, coverage for voluntary compensation and alternate employer and an “other states coverage” endorsement;

        (4) Employer’s Liability with limits of $1 million (combined single limit) for each accident, including occupational disease coverage with a limit of $100,000 for each employee and a $1 million policy limit, including coverage under the Federal Longshoremen and Harbor Workers’ Act, the Jones Act, the Federal Death on the High Seas Act and general maritime remedies of seamen including transportation, wages, maintenance and cure whether the action is in rem or in personam;

        (5) Pollution Legal Liability applicable to bodily injury, property damage, including loss of use of damaged property or loss of property that has not been physically injured or destroyed, cleanup costs and defense, including costs and expenses incurred in the investigation, defense or settlement of claims, and all such coverage to apply to sudden and non-sudden pollution conditions resulting from the escape or release of smoke, vapors, fumes, acids, alkalis, toxic chemicals, liquids, or gases, waste materials, or other irritants, contaminants or pollutants, in an amount of $1 million per loss, with an annual aggregate of $2 million;

        (6) Business Interruption applicable to the Refinery and its operations of $20,000,000 million; and

        (7) Such other insurance, including Business Income and Extra Expense, Off Premise Services and Business Income for Dependent Properties, as reasonably determined to be necessary by Owner and Customer

16.2.    Certificates of Insurance. Prior to Customer commencing any performance under this Agreement and as a condition of exercising any rights under this Agreement, Owner will furnish to Customer, certificates of insurance, evidencing that proper insurance has been secured in accordance with the specific terms of this Agreement. Failure of Customer to require such certificate or to object to any such certificate it receives or to commence performance without first providing a conforming certificate or request copies of any policy will not be a waiver of Owner’s obligation to meet its insurance obligations under this Section, including, without limitation, its obligation to provide conforming certificates.

16.3.    Reports of Accidents. Owner and Customer will immediately provide written notice to each other of all accidents or occurrences resulting in injuries to employees or third parties, or damage to property arising out of or during the course of the performance under this Agreement and, as soon as practical, will furnish each other with a copy of all reports made by any insurance underwriter or reports to others of such accidents or occurrences.

Section 17.    Indemnity.

        17.1.    To the extent permitted by law and except as otherwise specifically provided in this Agreement, Customer will defend and indemnify Owner from and against any liability, loss, damage, claim, suit, penalty, fine, judgment, cost or expense (including reasonable attorney fees and other costs of litigation) resulting from, associated with or arising out of (i) Customer’s failure to comply with applicable governmental or quasi-governmental laws, regulations or rules, (ii) bodily injury or death of any person, including, without limitation, Customer’s and Owner’s employees, agents and representatives, (iii) damage to natural resources or to property of any nature, including, without limitation, that involving the Stock and the Products and other property of Customer and the Refinery and other property of Owner, to the extent caused by the negligent or willful acts or omissions of Customer, its employees, agents, representatives or contractors, (iv) discharges, spills, or leaks of Stock or Products or any other substances, to the extent caused by the negligent or willful acts or omissions of Customer, its employees, agents,

representatives or contractors in the exercise of any of the rights granted under this Agreement or in the operation, loading, or unloading of any motor vehicle, or any vessel owned or hired by Customer, its agents or contractors, (v) all product liability or similar claims relating to the Stock and the Products, or (vi) governmental proceedings relating to the operations at the Refinery, except to the extent any such loss, damage, claim, suit, liability, penalty, fine, judgment or expense is (a) finally determined to have resulted from the negligent or willful misconduct of Owner, or (b) covered by the following indemnity.

    17.2.    To the extent permitted by law and as otherwise specifically provided in this Agreement, Owner will defend and indemnify Customer from and against any loss, damage, claim, suit, liability, penalty, fine, judgment or expense (including reasonable attorney fees and other costs of litigation) resulting from, associated with or arising out of (i) Owner’s failure to comply with applicable governmental or quasi-governmental laws, regulations or rules unless such failure is reasonably resulting from Customer’s failure to comply with its obligations, liabilities or indemnities in the Contribution Agreement, (ii) bodily injury or death of any person, including, without limitation, Customer’s and Owner’s employees, agents or representatives, (iii) damage to natural resources or to property of any nature, including, without limitation, that involving the Stock and the Products and other property of Customer and the Refinery and other property of Owner to the extent caused by the negligent or willful acts or omissions of Owner, its employees, agents, representatives or contractors, (iv) discharges, spills, or leaks of Stock or Products or any other substances, to the extent caused by the negligent or willful acts or omissions of Owner, its employees, agents, representatives or contractors in the exercise of any of the rights granted under this Agreement or in the operation, loading, or unloading of any motor vehicle, or any vessel owned or hired by Owner, its agents or contractors, and (v) governmental proceedings relating to the operations at the Refinery, except to the extent any such loss, damage, claim, suit liability, penalty, fine, judgment or expense is (a) finally determined to have resulted from negligent or willful misconduct of Customer, or (b) covered by the preceding indemnity.

17.3    Under the foregoing indemnities, where the personal injury to or death of any person, or loss of or damage to property is the result of the joint or concurrent negligence or willful acts or omissions of Owner and Customer, each Party’s duty of indemnification will be in proportion to its share of such joint or concurrent negligence, or willful misconduct.

17.4    To receive the foregoing indemnities, the Party seeking indemnification must notify the other in writing of a claim or suit promptly and provide reasonable cooperation (at the indemnifying Party’s expense) and full authority to defend or settle the claim or suit. Neither Party shall have any obligation to indemnify the other under any settlement made without its written consent.

17.5    In addition to and separate and apart from other insurance obligations that Customer may assume under the terms of this Agreement, insurance covering this indemnity agreement must be provided by Customer to the extent permitted by law. Further, by requiring insurance in this Agreement, Owner does not represent that the required insurance coverage and minimum limits will necessarily be adequate to protect Owner, and such insurance coverage and limits will not be deemed as a limitation on Customer’s liability under the indemnities granted to Owner in this Agreement.

Section 18.    Construction of Agreement.

18.1    Headings. The headings of the sections and subsections of this Agreement are for convenience only and will not be used in the interpretation of this Agreement.

18.2     Amendment or Waiver. This Agreement may not be amended, modified or waived except by written instrument executed by officers or duly authorized representatives of the respective Parties. In addition, as long as Owner is a party to this Agreement, the Conflicts Committee of MMLP shall be required to approve any amendment to this Agreement in accordance with its required procedures.

18.3     Severability of Provisions. If any provision of this Agreement is held to be unenforceable, this Agreement shall be considered divisible and such provision shall be deemed inoperative to the extent it is deemed unenforceable, and in all other respects this Agreement shall remain in full force and effect; provided, however, that if any such provision may be made enforceable by limitation or modification thereof, then such provision shall be deemed to be so limited or modified and shall be enforceable to the maximum extent provided by applicable law.

    18.4     Entire Agreement. This Agreement (including the attachments) contains the entire and exclusive agreement between the Parties with respect to the subject matter hereof and supersedes and renders void all previous agreements, negotiations and representations between the Parties, whether written or oral. The terms of this Agreement may not be amended, contradicted, explained or supplanted by any usage of trade, course of dealing or course of performance.

Section 19.    Law.

    This Agreement will be construed and governed by the laws of the State of Texas without regard to principles of conflict of laws.

Section 20.    Alternative Dispute Resolution.

    20.1. Covered Disputes. Any dispute, controversy or claim (whether sounding in contract, tort or otherwise) arising out of or relating to this Agreement, including without limitation the meaning of its provisions, or the proper performance of any of its terms by either Party, its breach, termination or invalidity (“Dispute”) will be resolved in accordance with the procedures specified in this Section, which will be the sole and exclusive procedure for the resolution of any such Dispute, except that a Party, without prejudice to the following procedures, may file a complaint to seek preliminary injunctive or other provisional judicial relief, if in its sole judgment, that action is necessary to avoid irreparable damage or to preserve the status quo. Despite that action the Parties will continue, subject to Section 20.6, to participate in good faith in the procedures specified in this Section.

    20.2 Initiation of Procedures. Either Party wishing to initiate the dispute resolution procedures set forth in this Section with respect to a Dispute not resolved in the ordinary course of business must give written notice of the Dispute to the other Party (“Dispute Notice”). The Dispute Notice will include (i) a statement of that Party’s position and a summary of arguments supporting that position, and (ii) the name and title of the executive who will represent that Party, and of any other person who will accompany the executive, in the negotiations under next subsection.

    20.3 Negotiation Between Executives. If one Party has given a Dispute Notice under the preceding subsection, the Parties will attempt in good faith to resolve the Dispute within 45 calendar days of the notice by negotiation between executives who have authority to settle the Dispute and who are at a higher level of management than the persons with direct responsibility for administration of this Agreement or the matter in Dispute. Within 15 calendar days after delivery of the Dispute Notice, the receiving Party will submit to the other a written response. The response will include (i) a statement of that Party’s position and a summary of arguments supporting that position, and (ii) the name and title of the executive who will represent that Party

and of any other person who will accompany the executive. Within 45 calendar days after delivery of the Dispute Notice, the executives of both Parties will meet at a mutually acceptable time and place, and thereafter, as often as they reasonably deem necessary, to attempt to resolve the Dispute. The Conflicts Committee of MMLP shall have the right to have a representative present at any such meeting.

    20.4 Mediation. If the Dispute has not been resolved by negotiation under the preceding subsection within 45 calendar days of the Dispute Notice, and only in such event, either Party may initiate the mediation procedure of this subsection by giving written notice to the other Party (“Mediation Notice”). The Parties will endeavor to settle the Dispute by mediation within 90 calendar days of the Mediation Notice.

    20.5 Arbitration. If the Dispute has not been resolved by mediation under the preceding subparagraph within 90 calendar days of the Mediation Notice, and only in such event, either Party may initiate the arbitration procedure of this subsection by giving written notice to the other Party (“Arbitration Notice”). The Dispute will be finally resolved by binding arbitration in accordance with the then current Arbitration Rules of the American Arbitration Association (“AAA”) by a single arbitrator, chosen by mutual agreement of both Parties. If the Parties cannot select an arbitrator within 30 calendar days of the Arbitration Notice, the AAA will select the arbitrator. The United States Arbitration Act, 9 U.S.C. Sec. 1-16 as amended (“the Act”), will govern the arbitration. Judgment upon the award rendered by the arbitrator may be entered by any court of any state having jurisdiction. The statute of limitations of the State of Texas for the commencement of a lawsuit will apply to the commencement of an arbitration under this Agreement, except that no defenses will be available based upon the passage of time during any negotiation or mediation called for by this Section. Each Party will assume its own costs of legal representation and expert witnesses and the Parties will share equally the other costs of the arbitration. The arbitrator will award pre-judgment interest in accordance with the law of Texas; however, the arbitrator may not award punitive damages. The arbitration will take place in Houston, Texas

    20.6 Tolling and Performance. Except as indicated in the preceding subsection with regard to the commencement of arbitration, all applicable statutes of limitation and defenses based upon the passage of time will be tolled while the procedures specified in this Section are pending. The Parties will take any action required to effectuate that tolling. Each Party is required to continue to perform its obligations under this Agreement pending final resolution of any Dispute, unless to do so would be impossible or impracticable under the circumstances. Furthermore, notwithstanding the pendency of the mediation or arbitration, the Parties shall continue to perform under this Agreement to the extent that such performance does not exacerbate (other than with respect to monetary matters) the specific matter giving rise to the dispute, controversy or claim.

    This Agreement has been executed by the authorized representatives of each Party as indicated below effective as of the date set forth above.

CROSS OIL REFINING & MARKETING, INC.

By: /s/ Randall L. Tauscher

Randall L. Tauscher, President and

Chief Executive Officer

MARTIN OPERATING PARTNERSHIP L.P.

By: Martin Operating GP LLC, Its General Partner

By: Martin Midstream Partners L.P., Its Sole Member

By: Martin Midstream GP LLC, Its General Partner

By: /s/ Robert D. Bondurant

Robert D. Bondurant, President and

Chief Executive Officer

EX-21.1

Exhibit 21.1

SUBSIDIARIES OF

MARTIN MIDSTREAM PARTNERS L.P.

Subsidiary	Jurisdiction of Organization
Martin Operating GP LLC	Delaware
Martin Operating Partnership L.P.	Delaware
Martin Midstream Finance Corp	Delaware
Redbird Gas Storage LLC	Delaware
Martin Transport, Inc.	Texas
Talen's Marine & Fuel LLC	Louisiana

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the registration statement (No. 333-231927) on Form S-3 and in the registration statements (Nos. 333-218693, 333-203857, and 333-140152) on Form S-8 of our reports dated March 1, 2022, with respect to the consolidated financial statements of Martin Midstream Partners L.P. and the effectiveness of internal control over financial reporting.

/s/ KPMG LLP

Dallas, Texas

March 1, 2022

EX-31.1

Exhibit 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

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

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

I, Robert D. Bondurant, certify that:

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

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

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

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

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

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

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

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

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

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

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

March 1, 2022

/s/ Robert D. Bondurant

Robert D. Bondurant, President and

Chief Executive Officer of

Martin Midstream GP LLC,

the General Partner of Martin Midstream Partners L.P.

EX-31.2

Exhibit 31.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

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

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

I, Sharon L. Taylor, certify that:

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

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

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

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

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

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

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

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

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

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

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

March 1, 2022

/s/ Sharon L. Taylor

Sharon L. Taylor, Vice President and

Chief Financial Officer of

Martin Midstream GP LLC,

the General Partner of Martin Midstream Partners L.P.

EX-32.1

Exhibit 32.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER PURSUANT TO 18 U.S.C.  SECTION 1350,

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

    In connection with the Annual Report of Martin Midstream Partners L.P., a Delaware limited partnership (the “Partnership”), on Form 10-K for the year ended December 31, 2021, as filed with the Securities and Exchange Commission (the “Report”), I, Robert D. Bondurant, Chief Executive Officer of Martin Midstream GP LLC, the general partner of the Partnership, certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), that to my knowledge:

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

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

/s/ Robert D. Bondurant

Robert D. Bondurant,

Chief Executive Officer of Martin Midstream GP LLC,

General Partner of Martin Midstream Partners L.P.

March 1, 2022

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

EX-32.2

Exhibit 32.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER PURSUANT TO 18 U.S.C.  SECTION 1350,

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

    In connection with the Annual Report of Martin Midstream Partners L.P., a Delaware limited partnership (the “Partnership”), on Form 10-K for the year ended December 31, 2021, as filed with the Securities and Exchange Commission (the “Report”), I, Sharon L. Taylor, Chief Financial Officer of Martin Midstream GP LLC, the general partner of the Partnership, certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), that to my knowledge:

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

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

/s/ Sharon L. Taylor

Sharon L. Taylor,

Chief Financial Officer

of Martin Midstream GP LLC,

General Partner of Martin Midstream Partners L.P.

March 1, 2022

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

XML

Cover Page - USD ($)	12 Months Ended
	Dec. 31, 2021	Mar. 01, 2022	Jun. 30, 2021
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Current Fiscal Year End Date	--12-31
Document Period End Date	Dec. 31, 2021
Document Transition Report	false
Entity File Number	000-50056
Entity Registrant Name	MARTIN MIDSTREAM PARTNERS L.P.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	05-0527861
Entity Address, Address Line One	4200 Stone Road
Entity Address, City or Town	Kilgore
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	75662
City Area Code	903
Local Phone Number	983-6200
Title of each class	Common Units representing limited partnership interests
Trading Symbol(s)	MMLP
Name of each exchange on which registered	NASDAQ
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Public Float			$ 95,996,227
Entity Common Stock, Shares Outstanding (in shares)		38,836,950
Documents Incorporated by Reference	None.
Entity Central Index Key	0001176334
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	FY
Amendment Flag	false

XML

Audit Information	12 Months Ended
	Dec. 31, 2021
Audit Information [Abstract]
Auditor Name	KPMG LLP
Auditor Firm ID	185
Auditor Location	Dallas, Texas

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Assets
Cash	$ 52	$ 4,958
Trade and accrued accounts receivable, less allowance for doubtful accounts of $311 and $261, respectively	84,199	52,748
Inventories	62,120	54,122
Due from affiliates	14,409	14,807
Other current assets	12,908	8,991
Total current assets	173,688	135,626
Property, plant and equipment, at cost	898,770	889,108
Accumulated depreciation	(553,300)	(509,237)
Property, plant and equipment, net	345,470	379,871
Goodwill	16,823	16,823
Right-of-use assets	21,861	22,260
Deferred income taxes, net	19,821	22,253
Intangibles and other assets, net	2,198	2,805
Total assets	579,861	579,638
Liabilities and Partners’ Capital (Deficit)
Current portion of long term debt and finance lease obligations	280	31,497
Trade and other accounts payable	70,342	51,900
Product exchange payables	1,406	373
Due to affiliates	1,824	435
Income taxes payable	385	556
Fair value of derivatives	0	207
Other accrued liabilities	29,850	34,407
Total current liabilities	104,087	119,375
Long-term debt, net	498,871	484,597
Finance lease obligations	9	289
Operating lease liabilities	15,704	15,181
Other long-term obligations	9,227	7,067
Total liabilities	627,898	626,509
Commitments and contingencies
Partners’ capital (deficit)	(48,853)	(46,871)
Accumulated other comprehensive income	816	0
Partners’ capital (deficit)	(48,037)	(46,871)
Total liabilities and partners' capital	$ 579,861	$ 579,638

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Assets
Allowance for doubtful accounts	$ 311	$ 261

XML

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Revenues:
Total revenues		$ 882,431	$ 672,142	$ 847,118
Cost of products sold: (excluding depreciation and amortization)
Total cost of products sold (excluding depreciation and amortization)		533,098	356,926	492,795
Expenses:
Operating expenses	[1]	193,952	183,747	209,313
Selling, General and Administrative Expense	[1]	41,012	40,900	41,433
Depreciation and amortization		56,751	61,462	60,060
Total costs and expenses		824,813	643,035	803,601
Other operating income (loss), net		(534)	12,488	14,587
Gain on involuntary conversion of property, plant and equipment		196	4,907	0
Operating income		57,280	46,502	58,104
Other income (expense):
Interest expense, net		(54,107)	(46,210)	(51,690)
Gain on retirement of senior unsecured notes		0	3,484	0
Loss on exchange of senior unsecured notes		0	(8,817)	0
Other, net		(4)	6	6
Total other income (expense)		(54,111)	(51,537)	(51,684)
Net income (loss) before taxes		3,169	(5,035)	6,420
Income tax expense		(3,380)	(1,736)	(1,900)
Income (loss) from continuing operations		(211)	(6,771)	4,520
Loss from discontinued operations, net of income taxes		0	0	(179,466)
Net loss		(211)	(6,771)	(174,946)
Less general partner's interest in net loss		4	135	3,499
Less (income) loss allocable to unvested restricted units		0	21	(41)
Limited partners' interest in net loss		(207)	(6,615)	(171,488)
Terminalling and storage
Revenues:
Total revenues	[1]	75,223	80,864	87,397
Transportation
Revenues:
Total revenues	[1]	144,314	132,492	159,622
Sulfur services
Revenues:
Total revenues		11,799	11,659	11,434
Product sales
Revenues:
Total revenues	[1]	651,095	447,127	588,665
Natural gas liquids
Revenues:
Total revenues	[1]	414,043	247,479	366,502
Cost of products sold: (excluding depreciation and amortization)
Total cost of products sold (excluding depreciation and amortization)	[1]	362,706	215,895	325,376
Sulfur services
Revenues:
Total revenues	[1]	133,243	96,348	99,906
Cost of products sold: (excluding depreciation and amortization)
Total cost of products sold (excluding depreciation and amortization)	[1]	89,134	58,515	65,893
Terminalling and storage
Revenues:
Total revenues	[1]	103,809	103,300	122,257
Cost of products sold: (excluding depreciation and amortization)
Total cost of products sold (excluding depreciation and amortization)	[1]	$ 81,258	$ 82,516	$ 101,526

[1] Related Party Transactions Included Above Year Ended December 31, 202120202019Revenues:   Terminalling and storage$62,677 $63,823 $71,733 Transportation20,046 21,997 24,243 Product sales479 317 931 Costs and expenses:   Cost of products sold: (excluding depreciation and amortization)   Sulfur services9,980 10,519 10,765           Terminalling and storage27,866 18,429 23,859 Expenses:   Operating expenses78,607 80,075 88,194 Selling, general and administrative32,924 32,886 32,622 

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CONSOLIDATED STATEMENTS OF OPERATIONS - (Related Party Transactions) (Parenthetical) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Revenues:
Total revenues		$ 882,431	$ 672,142	$ 847,118
Cost of products sold: (excluding depreciation and amortization)
Total cost of products sold (excluding depreciation and amortization)		533,098	356,926	492,795
Expenses:
Operating expenses		78,607	80,075	88,194
Selling, general and administrative		32,924	32,886	32,622
Terminalling and storage
Revenues:
Total revenues	[1]	75,223	80,864	87,397
Transportation
Revenues:
Total revenues	[1]	144,314	132,492	159,622
Product sales
Revenues:
Total revenues	[1]	651,095	447,127	588,665
Sulfur services
Revenues:
Total revenues	[1]	133,243	96,348	99,906
Cost of products sold: (excluding depreciation and amortization)
Total cost of products sold (excluding depreciation and amortization)	[1]	89,134	58,515	65,893
Terminalling and storage
Revenues:
Total revenues	[1]	103,809	103,300	122,257
Cost of products sold: (excluding depreciation and amortization)
Total cost of products sold (excluding depreciation and amortization)	[1]	81,258	82,516	101,526
Related Party
Expenses:
Operating expenses		78,607	80,075	88,194
Related Party | Terminalling and storage
Revenues:
Total revenues		62,677	63,823	71,733
Related Party | Transportation
Revenues:
Total revenues		20,046	21,997	24,243
Expenses:
Operating expenses		55,382	55,786	61,376
Related Party | Product sales
Revenues:
Total revenues		479	317	931
Related Party | Sulfur services
Cost of products sold: (excluding depreciation and amortization)
Total cost of products sold (excluding depreciation and amortization)		9,980	10,519	10,765
Expenses:
Operating expenses		4,411	4,489	4,810
Related Party | Terminalling and storage
Cost of products sold: (excluding depreciation and amortization)
Total cost of products sold (excluding depreciation and amortization)		27,866	18,429	23,859
Expenses:
Operating expenses		$ 16,776	$ 17,797	$ 18,562

[1] Related Party Transactions Included Above Year Ended December 31, 202120202019Revenues:   Terminalling and storage$62,677 $63,823 $71,733 Transportation20,046 21,997 24,243 Product sales479 317 931 Costs and expenses:   Cost of products sold: (excluding depreciation and amortization)   Sulfur services9,980 10,519 10,765           Terminalling and storage27,866 18,429 23,859 Expenses:   Operating expenses78,607 80,075 88,194 Selling, general and administrative32,924 32,886 32,622 

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CONSOLIDATED STATEMENTS OF OPERATIONS - (Allocation of Net Income) (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Limited partner interest:
Continuing operations	$ (207)	$ (6,615)	$ 4,430
Discontinued operations	0	0	(175,918)
Limited partner's interest in net income	(207)	(6,615)	(171,488)
General partner interest:
Continuing operations	(4)	(135)	91
Discontinued operations	0	0	(3,590)
Net income allocated to general partners	$ (4)	$ (135)	$ (3,499)
Basic:
Continuing operations (in dollars per share)	$ (0.01)	$ (0.17)	$ 0.11
Discontinued operations (in dollars per share)	0	0	(4.55)
Net Income, Basic (in dollars per share)	$ (0.01)	$ (0.17)	$ (4.44)
Weighted average limited partner units - basic (in shares)	38,689,041	38,656,559	38,658,881
Diluted:
Continuing operations (in dollars per share)	$ (0.01)	$ (0.17)	$ 0.11
Discontinued operations (in dollars per share)	0	0	(4.55)
Net Income, Diluted (in dollars per share)	$ (0.01)	$ (0.17)	$ (4.44)
Weighted average limited partner units - diluted (in shares)	38,689,041	38,656,559	38,658,881

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CONSOLIDATED AND CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of Comprehensive Income [Abstract]
Net Income (loss)	$ (211)	$ (6,771)	$ (174,946)
Changes in fair values of commodity cash flow hedges	816	0	0
Comprehensive income (loss)	$ 605	$ (6,771)	$ (174,946)

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CONSOLIDATED STATEMENTS OF CHANGES IN CAPITAL (DEFICIT) - USD ($) $ in Thousands	Total	Common Common	General Partner Amount	Accumulated Other Comprehensive Income	Time Based Restricted Units Common Common	Parent Net Investment
Beginning balance at Dec. 31, 2018	$ 288,432	$ 258,085	$ 6,627			$ 23,720
Beginning balance (in shares) at Dec. 31, 2018		39,032,237
Increase (Decrease) in Partners' Capital
Net Income (loss)	(174,946)	$ (171,447)	(3,499)			0
Issuance of common units, net	(289)	$ (289)
Issuance of time-based restricted units (in shares)					16,944
Forfeiture of restricted units (in shares)		(154,288)
Cash distributions	(49,093)	$ (48,111)	(982)
Excess purchase price over carrying value of acquired assets	(102,393)	(102,393)
Changes in fair values of commodity cash flow hedges	0
Deferred taxes on acquired assets and liabilities	24,781	24,781
Unit-based compensation	1,424	1,424
Purchase of treasury units	(392)	$ (392)
Purchase of treasury units (in shares)		(31,504)
Contribution to parent	(23,720)					(23,720)
Ending balance at Dec. 31, 2019	(36,196)	$ (38,342)	2,146			0
Ending balance (in shares) at Dec. 31, 2019		38,863,389
Increase (Decrease) in Partners' Capital
Net Income (loss)	(6,771)	$ (6,636)	(135)			0
Issuance of time-based restricted units (in shares)					81,000
Forfeiture of restricted units (in shares)		(85,467)
Cash distributions	(5,317)	$ (5,211)	(106)
Changes in fair values of commodity cash flow hedges	0
Unit-based compensation	1,422	1,422
Purchase of treasury units	(9)	$ (9)
Purchase of treasury units (in shares)		(7,748)
Ending balance at Dec. 31, 2020	(46,871)	$ (48,776)	1,905			0
Ending balance (in shares) at Dec. 31, 2020		38,851,174
Increase (Decrease) in Partners' Capital
Net Income (loss)	(211)	$ (207)	(4)
Issuance of time-based restricted units (in shares)					42,168
Forfeiture of restricted units (in shares)		(83,436)
General partner contribution	3		3
Cash distributions	(791)	$ (775)	(16)
Excess purchase price over carrying value of acquired assets	(1,350)	(1,350)
Changes in fair values of commodity cash flow hedges	816			$ 816
Unit-based compensation	384	384
Purchase of treasury units	(17)	$ (17)
Purchase of treasury units (in shares)		(7,156)
Ending balance at Dec. 31, 2021	$ (48,037)	$ (50,741)	$ 1,888	$ 816		$ 0
Ending balance (in shares) at Dec. 31, 2021		38,802,750

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash flows from operating activities:
Net loss	$ (211)	$ (6,771)	$ (174,946)
Less: Loss from discontinued operations	0	0	179,466
Income (loss) from continuing operations	(211)	(6,771)	4,520
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	56,751	61,462	60,060
Amortization and write-off of deferred debt issue costs	3,367	3,422	4,041
Amortization of premium on notes payable	0	(191)	(306)
Deferred income tax expense	2,432	1,169	1,360
(Gain) loss on disposition or sale of property, plant, and equipment	534	(9,788)	(13,332)
Gain on involuntary conversion of property, plant and equipment	(196)	(4,907)	0
Gain on retirement of senior unsecured notes	0	(3,484)	0
Non-cash impact related to exchange of senior unsecured notes	0	(749)	0
Derivative income	5,593	8,209	5,137
Net cash paid for commodity derivatives	(4,984)	(8,669)	(4,466)
Unit-based compensation	384	1,422	1,424
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
Accounts and other receivables	(31,448)	30,741	62
Product exchange receivables	0	0	166
Inventories	(8,334)	5,264	21,493
Due from affiliates	398	2,932	1,822
Other current assets	(3,552)	(5,733)	(254)
Trade and other accounts payable	14,331	(7,318)	(898)
Product exchange payables	1,033	(3,949)	(7,781)
Due to affiliates	1,389	(1,035)	(1,469)
Income taxes payable	(171)	84	27
Other accrued liabilities	(2,236)	4,144	(3,017)
Change in other non-current assets and liabilities	649	(1,470)	(543)
Net cash provided by continuing operating activities	35,729	64,785	68,046
Net cash provided by discontinued operating activities	0	0	7,769
Net cash provided by operating activities	35,729	64,785	75,815
Cash flows from investing activities:
Payments for property, plant, and equipment	(16,059)	(28,622)	(30,621)
Acquisitions, net of cash acquired	0	0	(23,720)
Payments for plant turnaround costs	(4,109)	(1,478)	(5,677)
Proceeds from sale of property, plant, and equipment	643	25,154	20,660
Proceeds from involuntary conversion of property, plant and equipment	284	7,550	5,031
Net cash provided by (used in) continuing investing activities	(19,241)	2,604	(34,327)
Net cash provided by discontinued investing activities	0	0	209,155
Net cash provided by (used in) investing activities	(19,241)	2,604	174,828
Cash flows from financing activities:
Payments of long-term debt	(333,790)	(333,637)	(724,000)
Payments under finance lease obligations	(2,707)	(4,562)	(5,514)
Proceeds from long-term debt	316,500	282,019	638,000
Proceeds from issuance of common units, net of issuance related costs	0	0	(289)
General partner contributions	3	0	0
Excess purchase price over carrying value of acquired assets	0	0	(102,393)
Purchase of treasury units	(17)	(9)	(392)
Payments of debt issuance costs	(592)	(3,781)	(4,406)
Cash distributions paid	(791)	(5,317)	(49,093)
Net cash used in financing activities	(21,394)	(65,287)	(248,087)
Net increase (decrease) in cash	(4,906)	2,102	2,556
Cash at beginning of year	4,958	2,856	300
Cash at end of year	$ 52	$ 4,958	$ 2,856

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Organization and Description of Business

12 Months Ended

Dec. 31, 2021

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Description of Business

ORGANIZATION AND DESCRIPTION OF BUSINESS

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

    The Partnership provides specialty services to major and independent oil and gas companies, independent refiners, large chemical companies, and other wholesale purchasers of certain petroleum products and by-products, with significant business concentrated around the U.S. Gulf Coast refinery complex, which is a major hub for petroleum refining, natural gas gathering and processing, and support services for the exploration and production industry. The petroleum products and by-products the Partnership gathers, transports, stores and markets are produced primarily by major and independent oil and gas companies who often rely on third parties, such as the Partnership, for the transportation and disposition of these products.

    On December 28, 2021, Martin Resource Management Corporation indirectly acquired, through its wholly owned subsidiary, Martin Resource LLC, the remaining 49% voting interest (50% economic interest) in MMGP Holdings, LLC ("Holdings"), which is the sole member of Martin Midstream GP LLC ("MMGP"), the general partner of the Partnership. As a result, Martin Resource Management Corporation indirectly owns 100% of MMGP. On November 23, 2021, MMGP contributed to the Partnership all of the outstanding incentive distribution rights for no consideration, whereupon the incentive distribution rights were cancelled and cease to exist.

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Significant Accounting Policies and Practices

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

Significant Accounting Policies and Practices

SIGNIFICANT ACCOUNTING POLICIES AND PRACTICES

(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 existed as of December 31, 2021 or 2020.

Divestiture of Natural Gas Storage Assets. On June 28, 2019, the Partnership completed the sale of its membership interests in Arcadia Gas Storage, LLC, Cadeville Gas Storage LLC, Monroe Gas Storage Company, LLC and Perryville Gas Storage LLC (the "Natural Gas Storage Assets") to Hartree Cardinal Gas, LLC ("Hartree"), a subsidiary of Hartree Bulk Storage, LLC. The Natural Gas Storage Assets consist of approximately 50 billion cubic feet of working capacity located in northern Louisiana and Mississippi. In consideration of the sale of the Natural Gas Storage Assets, the Partnership received cash proceeds of $210,067 after transaction fees and expenses. The net proceeds were used to reduce outstanding borrowings under the Partnership's credit facility. The Partnership concluded the disposition represents a strategic shift and will have a major effect on its financial results going forward. As a result, the Partnership has presented the results of operations and cash flows relating to the Natural Gas Storage Assets as discontinued operations for the year ended December 31, 2019. See Note 5 for more information.

    (b)       Product Exchanges

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

(c)       Inventories

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

(d)      Revenue Recognition

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

Natural Gas Liquids – Revenue is recognized when product is delivered by truck, rail, or pipeline to the Partnership's NGL customers. Revenue is recognized on title transfer of the product to the customer. Delivery of product is invoiced as the transaction occurs and is generally paid within a month.

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

Transportation – Revenue related to land transportation is recognized for line hauls based on a mileage rate. For contracted trips, revenue is recognized upon completion of the particular trip. The performance of the service is invoiced as the transaction occurs and is generally paid within a month. Revenue related to marine transportation is recognized for time charters based on a per day rate. For contracted trips, revenue is recognized upon completion of the particular trip. The performance of the service is invoiced as the transaction occurs and is generally paid within a month.

(e)       Equity Method Investments

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

    (f)      Property, Plant, and Equipment

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

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

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

(g)      Goodwill and Other Intangible Assets

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

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

Of the Partnership's four reporting units, the terminalling and storage, transportation, and sulfur services reporting units contain goodwill.

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

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

Applying this impairment review methodology, the Partnership considered the impact that COVID-19 had on our cash flows and the value our unit price during both 2021 and 2020 and elected to bypass the qualitative assessment and perform a quantitative assessment. Based upon the most recent annual review as of August 31, 2021, no goodwill impairment exists within the Partnership's reporting units for the year ended December 31, 2021. No goodwill impairment was recorded for the years ended December 31, 2020 or 2019.

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 for the years ended December 31, 2021, 2020 or 2019.

(h)      Debt Issuance Costs

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

In connection with the issuance, amendment, expansion and restatement of debt arrangements, the Partnership incurred debt issuance costs of $592, $3,781 and $4,406 in the years ended December 31, 2021, 2020 and 2019, respectively.

Amortization and write-off of debt issuance costs, which is included in interest expense, totaled $3,367, $3,422 and $4,041 for the years ended December 31, 2021, 2020 and 2019, respectively.  Accumulated amortization amounted to $26,022 and $22,655 at December 31, 2021 and 2020, 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.  

The Partnership identified triggering events related to a certain asset group in its transportation segment in 2021. The Partnership performed a recoverability test and concluded the estimated undiscounted cash flows expected to be generated by the asset group exceeded the carrying value of the asset group and no impairment was recorded.

(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 at present value based upon estimated costs to retire the asset 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)      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.

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

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

(o)      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.

(p)      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.

(q)      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.

MTI is a wholly owned subsidiary of the Partnership. Prior to the acquisition of MTI on January 2, 2019, MTI was a Qualified Subchapter S subsidiary (“QSub”) of Martin Resource Management Corporation, a qualifying S Corporation. A QSub is disregarded and not treated as a corporation separate from its S Corporation parent for federal income tax purposes. S Corporations are generally not subject to income taxes because income and losses flow through to shareholders and are reported on their individual returns. Three states in which MTI was subject to taxation prior to the acquisition - Louisiana, New Jersey and Tennessee - do not recognize the federal S Corporation status and, therefore, taxed MTI on a C Corporation basis. Subsequent to the acquisition, the QSub election terminated resulting in MTI being taxed as a stand-alone C Corporation.

The Partnership's financial statements recognize the current and deferred income tax consequences that result from MTI’s activities during the current period pursuant to the provisions of the FASB ASC 740 related to income taxes. As a result of the common control transaction with the Partnership, the deferred tax consequences of the changes in the tax bases of MTI’s assets and liabilities were included in equity under the provisions of ASC 740-20-45-11.

With respect to the Partnership’s taxable subsidiary (MTI), income taxes are accounted for under the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to

apply to taxable income in the years those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

In the ordinary course of business, there may be many transactions and calculations where the ultimate tax outcome is uncertain. The calculation of tax liabilities involves dealing with uncertainties in the application of complex tax laws. In accordance with the provisions of ASC 740, we use a two-step approach for recognizing and measuring tax benefits taken or expected to be taken in a tax return. In the first step, “recognition”, the Partnership determines whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the Partnership presumes that the position will be examined by the appropriate taxing authority that has full knowledge of all relevant information. In the second step, “measurement”, a tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement based upon management’s intent regarding negotiation and litigation. In evaluating all income tax positions for all open years, management has determined all positions are more likely than not to be sustained at full benefit based upon their technical merit under applicable tax laws.

(r)      Comprehensive Income

Comprehensive income includes net income and other comprehensive income. Other comprehensive income for the Partnership includes unrealized gains and losses on derivative instruments. In accordance with ASC 815-10, the Partnership records deferred hedge gains and losses on its derivative instruments that qualify as cash flow hedges as other comprehensive income.

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Recent Accounting Pronouncements

12 Months Ended

Dec. 31, 2021

Accounting Changes and Error Corrections [Abstract]

Recent Accounting Pronouncements

RECENT ACCOUNTING PRONOUNCEMENTS

On January 1, 2021, the Partnership adopted FASB Accounting Standards Update (“ASU”) 2019-12, Income Taxes (Accounting Standards Codification (“ASC”) Topic 740): Simplifying the Accounting for Income Taxes, which removes certain exceptions to general principles in ASC 740 and clarifies and amends existing guidance within U.S. GAAP. Adoption of the new standard did not have a material impact on the Partnership’s consolidated financial statements.    

On January 1, 2020, the Partnership adopted ASU 2016-13, "Financial Instruments - Credit Losses," which required the Partnership to measure all expected credit losses for financial instruments held at the reporting date based on historical experience, current conditions, and reasonable supportable forecasts. This replaced the existing incurred loss model and is applicable to the measurement of credit losses on financial assets, including trade receivables. Adoption of the new standard did not have a material impact on the Partnership’s consolidated financial statements.

In June 2018, the FASB issued ASU 2018-07, Compensation - Stock Compensation: Improvements to Non-employee Share-Based Payment Accounting, which will expand the scope of FASB ASC 718 to include share-based payment transactions for acquiring goods and services from non-employees. The standard is effective for the Partnership's financial statements issued for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. The Partnership adopted this standard effective January 1, 2019. The result of this adoption did not have a material impact on the Partnership's consolidated financial statements.

    In February 2016, the FASB issued ASU 2016-02, Leases, which introduces the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous guidance. Lessor accounting under the new standard is substantially unchanged and substantially all of our leases will continue to be classified as operating leases under the new standard. Additional qualitative and quantitative disclosures, including significant judgments made by management are required.  The update is effective for annual reporting periods beginning after December 15, 2018, including interim periods within those reporting periods, with early adoption permitted. The original guidance required application on a modified retrospective basis with the earliest period presented. In August 2018, the FASB issued ASU 2018-11, Targeted Improvements to FASB ASC 842, which includes an option to not restate comparative periods in transition and elect to use the effective date of ASC 842, Leases, as the date of initial application of transition. The Partnership adopted this ASU on January 1, 2019, electing the transition option provided under ASU 2018-11.

    The new standard provides a number of optional practical expedients in transition. The Partnership elected the "package of practical expedients", which permits the Partnership not to reassess under the new standard our prior conclusions about lease identification, lease classification and initial direct costs. The new standard also provides practical expedients for an entity’s ongoing accounting. The Partnership elected the short-term lease recognition exemption for all leases that qualify. This means, for those assets that qualify, the Partnership did not recognize Right-of-Use ("ROU") assets or lease liabilities, and this includes not recognizing ROU assets or lease liabilities for existing short-term leases of those assets in transition. See Note 10 for more information.

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Acquisitions

12 Months Ended

Dec. 31, 2021

Business Combination and Asset Acquisition [Abstract]

Acquisitions

ACQUISITIONS

    Martin Transport, Inc. Stock Purchase Agreement. On January 2, 2019, the Partnership acquired all of the issued and outstanding equity interests of MTI, a wholly-owned subsidiary of Martin Resource Management Corporation, which operates a fleet of trucks providing transportation of petroleum products, liquid petroleum gas, chemicals, sulfur and other products, as well as owns 24 terminals located throughout the U.S. Gulf Coast and Southeastern U.S. for total consideration as follows:

Purchase price 1	$	135,000
Plus: Working Capital Adjustment	2,795
Less: Finance lease obligations assumed	(11,682)
Cash consideration paid	$	126,113

    1 The stock purchase agreement also includes a $10,000 earn-out based on certain performance thresholds. The performance threshold related to financial results for the years ended December 31, 2020 and 2019 was not achieved, which resulted in a reduction in the potential earn-out by $6,666. For the year ended December 31, 2021, the performance threshold related to financial results was exceeded, resulting in an earn-out payment of $1,350, which, pursuant to the terms of the stock purchase agreement, will be paid in the second quarter of 2022.

    The transaction closed on January 2, 2019 and was effective as of January 1, 2019 and was funded with borrowings under the Partnership's credit facility.

    This acquisition is considered a transfer of net assets between entities under common control. The acquisition of MTI was recorded at the historical carrying value of the assets at the acquisition date, which were as follows:

Accounts receivable, net	$	11,724
Inventories	1,138
Due from affiliates	1,042
Other current assets	897
Property, plant and equipment, net	25,383
Goodwill	489
Other noncurrent assets	362
Current installments of finance lease obligations	(5,409)
Accounts payable	(2,564)
Due to affiliates	(482)
Other accrued liabilities	(2,588)
Finance lease obligations, net of current installments	(6,272)
Historical carrying value of assets acquired	$	23,720

    The excess purchase price over the historical carrying value of the assets at the acquisition date was $102,393 and was recorded as an adjustment to "Partners' capital (deficit)". The earn out-payment discussed above was recorded as additional excess purchase price over the historical carrying value of the assets, resulting in an adjustment to "Partners' capital (deficit)" of $1,350.

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Discontinued Operations And Divestitures

12 Months Ended

Dec. 31, 2021

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations And Divestitures

DISCONTINUED OPERATIONS AND DIVESTITURES

    Divestitures

Divestiture of Mega Lubricants. On December 22, 2020, the Partnership completed the sale of its Mega Lubricants shored-based terminals business (“Mega Lubricants”) for $22,400. Mega Lubricants is engaged in the business of blending, manufacturing and delivering various marine application lubricants, sub-sea specialty fluids, and proprietary developed commercial and industrial products. The Partnership recorded a gain on the disposition of $10,101, which was included in "Other operating income, net" on the Partnership's Consolidated Statements of Operations. The proceeds from the transaction were used to reduce outstanding borrowings under the Partnership’s credit facility. The divestiture of Mega Lubricants did not qualify for discontinued operations presentation under the guidance of ASC 205-20.

Divestiture of East Texas Pipeline. On August 12, 2019, the Partnership completed the sale of its East Texas Pipeline for $17,500. The Partnership recorded a gain on the disposition of $16,154, which was included in "Other operating income, net" on the Partnership's Consolidated Statements of Operations. The net proceeds were used to reduce outstanding borrowings under the Partnership's credit facility. The divestiture of the East Texas Pipeline assets did not qualify for discontinued operations presentation under the guidance of ASC 205-20.

Divestiture of Natural Gas Storage Assets. On June 28, 2019, the Partnership completed the sale of the Natural Gas Storage Assets to Hartree, a subsidiary of Hartree Bulk Storage, LLC. The Natural Gas Storage Assets consist of approximately 50 billion cubic feet of working capacity located in northern Louisiana and Mississippi. In consideration of the sale of these assets, the Partnership received cash proceeds of $210,067 after transaction fees and expenses. The net proceeds were used to reduce outstanding borrowings under the Partnership's credit facility. The Partnership concluded the disposition represents a strategic shift and will have a major effect on its financial results going forward. As a result, the Partnership has presented the results of operations and cash flows relating to the Natural Gas Storage Assets as discontinued operations for the year ended December 31, 2019.

    The operating results, which are included in income (loss) from discontinued operations, were as follows:

	For the Year Ended December 31,
	2019
Total revenues	$	22,836
Total costs and expenses and other, net, excluding depreciation and amortization	(15,360)
Depreciation and amortization	(8,161)
Other operating loss, net 1	(178,781)
Other, net	—
Income (loss) from discontinued operations before income taxes	(179,466)
Income tax expense	—
Income (loss) from discontinued operations, net of income taxes	$	(179,466)

    1 The year ended December 31, 2019 includes a loss on the disposition of the Natural Gas Storage Assets of $178,781.

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Revenue

12 Months Ended

Dec. 31, 2021

Revenue from Contract with Customer [Abstract]

Revenue

REVENUE

    The following table disaggregates our revenue by major source:

	2021		2020		2019
Terminalling and storage segment
Lubricant product sales	$	103,809	$	103,300	$	122,257
Throughput and storage	75,223		80,864		87,397
	$	179,032	$	184,164	$	209,654
Transportation segment
Land transportation	$	111,611	$	88,652	$	98,895
Inland transportation	29,536		40,507		54,834
Offshore transportation	3,167		3,333		5,893
	$	144,314	$	132,492	$	159,622
Sulfur service segment
Sulfur product sales	$	32,416	$	24,176	$	30,135
Fertilizer product sales	100,827		72,172		69,771
Sulfur services	11,799		11,659		11,434
	$	145,042	$	108,007	$	111,340
Natural gas liquids segment
Natural gas liquids product sales	$	414,043	$	247,479	$	366,502
	$	414,043	$	247,479	$	366,502

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

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

Terminalling and Storage Segment

    Revenue is recognized for storage contracts based on the contracted monthly tank fixed fee.  For throughput contracts, revenue is recognized based on the volume moved through the Partnership’s terminals at the contracted rate.  For the Partnership’s tolling agreement, revenue is recognized based on the contracted monthly reservation fee and throughput volumes moved through the facility.  When lubricants and drilling fluids are sold by truck or rail, revenue is recognized when title is transferred, which is either upon delivering product to the customer or when the product leaves the Partnership's facility, depending on the specific terms of the contract. Delivery of product is invoiced as the transaction occurs and is generally paid within a month. Throughput and storage revenue in the table above includes non-cancelable revenue arrangements that are under the scope of ASC 842, whereby the Partnership has committed certain Terminalling and Storage assets in exchange for a minimum fee.

Natural Gas Liquids Segment

    NGL revenue is recognized when product is delivered by truck, rail, or pipeline to the Partnership's NGL customers. Revenue is recognized on title transfer of the product to the customer. Delivery of product is invoiced as the transaction occurs and is generally paid within a month.

Sulfur Services Segment

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

Transportation Segment

    Revenue related to land transportation is recognized for line hauls based on a mileage rate. For contracted trips, revenue is recognized upon completion of the particular trip. The performance of the service is invoiced as the transaction occurs and is generally paid within a month.

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

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

	2022		2023		2024		2025		2026		Thereafter		Total
Terminalling and storage
Throughput and storage	$	43,527	$	42,041	$	43,360	$	44,661	$	45,940	$	251,349	$	470,878
Natural Gas Services
Natural Gas Liquids	$	6,047	$	5,391	$	5,406	$	5,391	$	3,131	$	—	$	25,366
Sulfur services
Sulfur product sales	17,703		16,953		14,493		2,156		1,182		295		52,782
Total	$	67,277	$	64,385	$	63,259	$	52,208	$	50,253	$	251,644	$	549,026

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Inventories

12 Months Ended

Dec. 31, 2021

Inventory Disclosure [Abstract]

Inventories

INVENTORIES

Components of inventories at December 31, 2021 and 2020 were as follows: 

	2021		2020
Natural gas liquids	$	20,034	$	27,878
Sulfur	612		24
Fertilizer	13,005		10,854
Lubricants	23,876		11,002
Other	4,593		4,364
	$	62,120	$	54,122

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2021

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

PROPERTY, PLANT, AND EQUIPMENT

At December 31, 2021 and 2020, property, plant and equipment consisted of the following:

	Depreciable Lives	2021		2020
Land	—	$	21,422	$	21,459
Improvements to land and buildings	10-25 years	132,064		135,227
Storage equipment	5-50 years	122,300		121,437
Marine vessels	4-25 years	183,414		179,666
Operating plant and equipment	3-50 years	360,122		356,293
Furniture, fixtures and other equipment	3-20 years	13,727		14,209
Transportation equipment	3-7 years	50,961		49,836
Construction in progress		14,760		10,981
		$	898,770	$	889,108

Depreciation expense for the years ended December 31, 2021, 2020 and 2019 was $52,289, $55,817 and $53,856, respectively, which includes amortization of fixed assets acquired under capital lease obligations of $164, $1,755, and $2,686. Gross assets under capital leases were $1,071 and $10,352 at December 31, 2021 and 2020, respectively. Accumulated amortization associated with capital leases was $364 and $3,703 at December 31, 2021 and 2020, respectively.

Additions to property, plant and equipment included in accounts payable at December 31, 2021, 2020 and 2019 were $3,229, $468, and $3,791, respectively. Equipment purchased under capital lease obligations was $0, $83, and $1,308 for the years ended December 31, 2021, 2020, and 2019, respectively.

In the first quarter of 2020, the Partnership identified a triggering event related to a decline in the fair value related to the assets classified as held for sale at December 31, 2019. As a result, an impairment charge of $3,052 and $1,300 was recorded in the Terminalling and Storage and Transportation segments, respectively, during the year ended December 31, 2020 and was recorded in "Other operating income (loss)" in the Partnership's Consolidated Statements of Operations. At December 31, 2020, the remaining assets previously classified as held for sale in the amount of $700 no longer met the criteria to be classified as held for sale in accordance with ASC 360-10.

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Goodwill

12 Months Ended

Dec. 31, 2021

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill

GOODWILL

    The following table represents the goodwill balance by reporting unit at December 31, 2021 and 2020 as follows:

	2021		2020
Carrying amount of goodwill:
Terminalling and storage	$	10,985	$	10,985
Sulfur services	5,349		5,349
Transportation	489		489
Total goodwill	$	16,823	$	16,823

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Leases

12 Months Ended

Dec. 31, 2021

Leases [Abstract]

Leases

LEASES

    The Partnership has numerous 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.

    Operating lease ROU assets and operating lease liabilities are recognized based on the present value of lease payments over the lease term at commencement date. Because most of the Partnership's leases do not provide an implicit rate of return, the Partnership uses its imputed collateralized rate based on the information available at commencement date in determining the present value of lease payments. The estimated rate is based on a risk-free rate plus a risk-adjusted margin.

The Partnership's leases have remaining lease terms of 1 year to 15 years, some of which include options to extend the leases for up to 5 years, and some of which include options to terminate the leases within 1 year. The Partnership includes extension periods and excludes termination periods from its lease term if, at commencement, it is reasonably likely that the Partnership will exercise the option.

    The components of lease expense for the years ended December 31, 2021, 2020, and 2019 were as follows:

	2021		2020		2019
Operating lease cost	$	9,266	$	10,672	$	10,805
Finance lease cost:
Amortization of right-of-use assets	164		1,755		2,686
Interest on lease liabilities	26		294		671
Short-term lease cost	10,290		13,187		13,756
Variable lease cost	115		109		92
Total lease cost	$	19,861	$	26,017	$	28,010

    Supplemental cash flow information for the years ended December 31, 2021, 2020, and 2019 related to leases were as follows:

	2021		2020		2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	19,678	$	23,996	$	24,526
Operating cash flows from finance leases	26		294		671
Financing cash flows from finance leases	2,707		4,562		5,514
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	7,668	$	7,779	$	9,122
Finance leases	0		83		1,309

    

Supplemental balance sheet information related to leases was as follows at December 31, 2021 and 2020:

	2021			2020
Operating Leases
Operating lease right-of-use assets	$	21,861		$	22,260
Current portion of operating lease liabilities included in "Other accrued liabilities"	$	6,600		$	7,529
Operating lease liabilities	15,704			15,181
Total operating lease liabilities	$	22,304		$	22,710
Finance Leases
Property, plant and equipment, at cost	$	1,071		$	10,352
Accumulated depreciation	(364)			(3,703)
Property, plant and equipment, net	$	707		$	6,649
Current installments of finance lease obligations	$	280		$	2,707
Finance lease obligations	9			289
Total finance lease obligations	$	289		$	2,996
Weighted Average Remaining Lease Term (years)
Operating leases	6.46			5.87
Finance leases	0.97			1.39
Weighted Average Discount Rate
Operating leases	4.96		%	5.04		%
Finance leases	5.74		%	6.04		%

    The Partnership’s future minimum lease obligations as of December 31, 2021 consist of the following:

	Operating Leases		Finance Leases
Year 1	$	7,501	$	289
Year 2	4,672		9
Year 3	3,137		—
Year 4	2,460		—
Year 5	1,602		—
Thereafter	6,820		—
Total	26,192		298
Less amounts representing interest costs	(3,888)		(9)
Total lease liability	$	22,304	$	289

    As of December 31, 2021, we have additional operating leases for land, buildings and equipment that have not yet commenced of $1,184. These operating leases will commence during the first quarter of 2022 with lease terms of 3 to 5 years.

The Partnership has non-cancelable revenue arrangements that are under the scope of ASC 842 whereby we have committed certain terminalling and storage assets in exchange for a minimum fee. Future minimum revenues the Partnership expects to receive under these non-cancelable arrangements as of December 31, 2021 are as follows: 2022 - $17,093; 2023 - $14,425; 2024 - $14,425; 2025 - $13,858; 2026 - $8,173; subsequent years - $30,670.

Leases

LEASES

    The Partnership has numerous 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.

    Operating lease ROU assets and operating lease liabilities are recognized based on the present value of lease payments over the lease term at commencement date. Because most of the Partnership's leases do not provide an implicit rate of return, the Partnership uses its imputed collateralized rate based on the information available at commencement date in determining the present value of lease payments. The estimated rate is based on a risk-free rate plus a risk-adjusted margin.

The Partnership's leases have remaining lease terms of 1 year to 15 years, some of which include options to extend the leases for up to 5 years, and some of which include options to terminate the leases within 1 year. The Partnership includes extension periods and excludes termination periods from its lease term if, at commencement, it is reasonably likely that the Partnership will exercise the option.

    The components of lease expense for the years ended December 31, 2021, 2020, and 2019 were as follows:

	2021		2020		2019
Operating lease cost	$	9,266	$	10,672	$	10,805
Finance lease cost:
Amortization of right-of-use assets	164		1,755		2,686
Interest on lease liabilities	26		294		671
Short-term lease cost	10,290		13,187		13,756
Variable lease cost	115		109		92
Total lease cost	$	19,861	$	26,017	$	28,010

    Supplemental cash flow information for the years ended December 31, 2021, 2020, and 2019 related to leases were as follows:

	2021		2020		2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	19,678	$	23,996	$	24,526
Operating cash flows from finance leases	26		294		671
Financing cash flows from finance leases	2,707		4,562		5,514
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	7,668	$	7,779	$	9,122
Finance leases	0		83		1,309

    

Supplemental balance sheet information related to leases was as follows at December 31, 2021 and 2020:

	2021			2020
Operating Leases
Operating lease right-of-use assets	$	21,861		$	22,260
Current portion of operating lease liabilities included in "Other accrued liabilities"	$	6,600		$	7,529
Operating lease liabilities	15,704			15,181
Total operating lease liabilities	$	22,304		$	22,710
Finance Leases
Property, plant and equipment, at cost	$	1,071		$	10,352
Accumulated depreciation	(364)			(3,703)
Property, plant and equipment, net	$	707		$	6,649
Current installments of finance lease obligations	$	280		$	2,707
Finance lease obligations	9			289
Total finance lease obligations	$	289		$	2,996
Weighted Average Remaining Lease Term (years)
Operating leases	6.46			5.87
Finance leases	0.97			1.39
Weighted Average Discount Rate
Operating leases	4.96		%	5.04		%
Finance leases	5.74		%	6.04		%

    The Partnership’s future minimum lease obligations as of December 31, 2021 consist of the following:

	Operating Leases		Finance Leases
Year 1	$	7,501	$	289
Year 2	4,672		9
Year 3	3,137		—
Year 4	2,460		—
Year 5	1,602		—
Thereafter	6,820		—
Total	26,192		298
Less amounts representing interest costs	(3,888)		(9)
Total lease liability	$	22,304	$	289

    As of December 31, 2021, we have additional operating leases for land, buildings and equipment that have not yet commenced of $1,184. These operating leases will commence during the first quarter of 2022 with lease terms of 3 to 5 years.

The Partnership has non-cancelable revenue arrangements that are under the scope of ASC 842 whereby we have committed certain terminalling and storage assets in exchange for a minimum fee. Future minimum revenues the Partnership expects to receive under these non-cancelable arrangements as of December 31, 2021 are as follows: 2022 - $17,093; 2023 - $14,425; 2024 - $14,425; 2025 - $13,858; 2026 - $8,173; subsequent years - $30,670.

Leases

LEASES

    The Partnership has numerous 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.

    Operating lease ROU assets and operating lease liabilities are recognized based on the present value of lease payments over the lease term at commencement date. Because most of the Partnership's leases do not provide an implicit rate of return, the Partnership uses its imputed collateralized rate based on the information available at commencement date in determining the present value of lease payments. The estimated rate is based on a risk-free rate plus a risk-adjusted margin.

The Partnership's leases have remaining lease terms of 1 year to 15 years, some of which include options to extend the leases for up to 5 years, and some of which include options to terminate the leases within 1 year. The Partnership includes extension periods and excludes termination periods from its lease term if, at commencement, it is reasonably likely that the Partnership will exercise the option.

    The components of lease expense for the years ended December 31, 2021, 2020, and 2019 were as follows:

	2021		2020		2019
Operating lease cost	$	9,266	$	10,672	$	10,805
Finance lease cost:
Amortization of right-of-use assets	164		1,755		2,686
Interest on lease liabilities	26		294		671
Short-term lease cost	10,290		13,187		13,756
Variable lease cost	115		109		92
Total lease cost	$	19,861	$	26,017	$	28,010

    Supplemental cash flow information for the years ended December 31, 2021, 2020, and 2019 related to leases were as follows:

	2021		2020		2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	19,678	$	23,996	$	24,526
Operating cash flows from finance leases	26		294		671
Financing cash flows from finance leases	2,707		4,562		5,514
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	7,668	$	7,779	$	9,122
Finance leases	0		83		1,309

    

Supplemental balance sheet information related to leases was as follows at December 31, 2021 and 2020:

	2021			2020
Operating Leases
Operating lease right-of-use assets	$	21,861		$	22,260
Current portion of operating lease liabilities included in "Other accrued liabilities"	$	6,600		$	7,529
Operating lease liabilities	15,704			15,181
Total operating lease liabilities	$	22,304		$	22,710
Finance Leases
Property, plant and equipment, at cost	$	1,071		$	10,352
Accumulated depreciation	(364)			(3,703)
Property, plant and equipment, net	$	707		$	6,649
Current installments of finance lease obligations	$	280		$	2,707
Finance lease obligations	9			289
Total finance lease obligations	$	289		$	2,996
Weighted Average Remaining Lease Term (years)
Operating leases	6.46			5.87
Finance leases	0.97			1.39
Weighted Average Discount Rate
Operating leases	4.96		%	5.04		%
Finance leases	5.74		%	6.04		%

    The Partnership’s future minimum lease obligations as of December 31, 2021 consist of the following:

	Operating Leases		Finance Leases
Year 1	$	7,501	$	289
Year 2	4,672		9
Year 3	3,137		—
Year 4	2,460		—
Year 5	1,602		—
Thereafter	6,820		—
Total	26,192		298
Less amounts representing interest costs	(3,888)		(9)
Total lease liability	$	22,304	$	289

    As of December 31, 2021, we have additional operating leases for land, buildings and equipment that have not yet commenced of $1,184. These operating leases will commence during the first quarter of 2022 with lease terms of 3 to 5 years.

The Partnership has non-cancelable revenue arrangements that are under the scope of ASC 842 whereby we have committed certain terminalling and storage assets in exchange for a minimum fee. Future minimum revenues the Partnership expects to receive under these non-cancelable arrangements as of December 31, 2021 are as follows: 2022 - $17,093; 2023 - $14,425; 2024 - $14,425; 2025 - $13,858; 2026 - $8,173; subsequent years - $30,670.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2021

Fair Value Disclosures [Abstract]

Fair Value Measurements

FAIR VALUE MEASUREMENTS

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

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

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

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

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

	Level 2
	December 31,
	2021		2020
Commodity derivative contracts, net	$	—	$	(207)

    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.

•Current and non-current portion of long-term debt: The carrying amount of the credit facility approximates fair value due to the debt having a variable interest rate and is in Level 2. The estimated fair value of the 2021 Notes, 2024 Notes, and 2025 Notes (collectively, the "senior notes") is considered Level 2, as the fair value is based upon quoted prices for identical liabilities in markets that are not active.

	December 31, 2021				December 31, 2020
	Carrying Value		Fair Value		Carrying Value		Fair Value
2021 Notes	$	—	$	—	$	28,790	$	28,581
2024 Notes	$	51,317	$	55,220	$	50,173	$	55,214
2025 Notes	$	290,667	$	307,146	$	290,250	$	288,692
Total	$	341,984	$	362,366	$	369,213	$	372,487

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Derivative Instruments and Hedging Activities

12 Months Ended

Dec. 31, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

The Partnership’s results of operations could be materially impacted by changes in commodity prices and 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. At the time derivative contracts are entered into, the Partnership assesses whether the nature of the instrument qualifies for hedge accounting treatment according to the requirements of ASC 815 – Derivatives and Hedging. For those transactions designated as hedging instruments for accounting purposes, the Partnership documents all relationships between hedging instruments and hedged items, as well as our risk-management objective and strategy for undertaking the various hedge transactions. The Partnership also assesses, both at the hedge’s inception and on an ongoing basis, whether the derivatives used in hedging transactions are highly effective in offsetting changes in cash flows or fair value of hedged items. All derivatives and hedging instruments are included on the balance sheet as an asset or a liability measured at fair value. Changes in fair value for hedging instruments are recognized on the balance sheet through Accumulated Other Comprehensive Income ("AOCI"). Settlements related to effective hedging relationships will be reclassified from AOCI to earnings during the period in which the hedged transactions are reflected on the income statement.

From time to time, derivatives designated for hedge accounting may be closed prior to contract expiration. The accounting treatment of closed positions depends on whether the closure occurred due to the hedged transaction occurring early or if the hedged transaction is still expected to occur as originally forecasted. For hedged transactions that occur early, the closure results in the realized gain or loss from closure being recognized in the same period the accelerated hedged transaction affects earnings. For hedged transactions that are still expected to occur as originally forecasted, the closure results in the realized gain or loss being deferred until the hedged transaction affects earnings.

If it is determined that hedged transactions associated with cash flow hedges are no longer probable to occur, the gain or loss associated with the instrument is recognized immediately into earnings.

From time to time, we may have derivative financial instruments for which we do not elect hedge accounting. Changes in fair value for derivatives not designated as hedges 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 enters into hedging transactions to protect a portion of its commodity price risk exposure. These hedging arrangements are in the form of swaps for NGLs. At December 31, 2021, the Partnership has instruments totaling a gross notional quantity of 0 barrels. At December 31, 2020, the Partnership had instruments totaling a gross notional quantity of 137,000 barrels settling during the period from January 31, 2021 through February 28, 2021. These instruments settle against the applicable pricing source for each grade and location.

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

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

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

	Derivative Assets					Derivative Liabilities
		Fair Values					Fair Values
	Balance Sheet Location	December 31, 2021		December 31, 2020		Balance Sheet Location	December 31, 2021		December 31, 2020
Derivatives designated as hedging instruments:	Current:
Commodity contracts	Fair value of derivatives	$	—	$	—	Fair value of derivatives	$	—	$	—
Derivatives not designated as hedging instruments:	Current:
Commodity contracts	Fair value of derivatives	$	—	$	—	Fair value of derivatives	$	—	$	207

The following table summarizes the loss recognized in AOCI at December 31, 2021 and the gain (loss) reclassified from accumulated other comprehensive loss into earnings during the year ended December 31, 2021 for derivative financial instruments designated as cash flow hedges:

	Amount of Gain (Loss) Recognized in AOCI				Location of Gain (Loss) Reclassified from AOCI into Income	Amount of Gain (Loss) Reclassified from AOCI into Income
	2021		2020			2021		2020
Commodity contracts	$	816	$	—	Cost of products sold	$	(3,768)	$	—
Total	$	816	$	—		$	(3,768)	$	—

The following tables summarize the loss recognized in earnings for derivative instruments not designated as hedging instruments during the year ended December 31, 2021:

	Location of Gain (Loss) Recognized in Income on  Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives
		2021		2020
Derivatives not designated as hedging instruments:
Commodity contracts	Cost of products sold	$	(1,825)	$	(8,209)
Total effect of derivatives not designated as hedging instruments		$	(1,825)	$	(8,209)

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Related Party Transactions

12 Months Ended

Dec. 31, 2021

Related Party Transactions [Abstract]

Related Party Transactions

RELATED PARTY TRANSACTIONSAs of December 31, 2021, Martin Resource Management Corporation owned 6,114,532 of the Partnership’s common units representing approximately 15.8% of the Partnership’s outstanding limited partnership units.  Martin Resource Management Corporation controls the Partnership's general partner by virtue of owning 100% of the membership interests 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.  The Partnership’s general partner’s ability, as general partner, to manage and operate the Partnership, and Martin Resource Management Corporation’s ownership as of December 31, 2021 of approximately 15.8% of the Partnership’s outstanding limited partnership units, effectively gives Martin Resource Management Corporation 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 Corporation 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 Corporation and the Partnership’s use of certain Martin Resource Management Corporation 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 Corporation.

    Non-Competition Provisions. Martin Resource Management Corporation 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 land and marine transportation of petroleum products, by-products, and chemicals;

•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 Corporation, including the following:

◦distributing asphalt, marine fuel and other liquids;

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

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

◦providing crude oil gathering 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;

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

◦operating, solely for our account, the asphalt facilities in each of Hondo, South Houston and Port Neches, Texas and Omaha, Nebraska.

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

•any business that Martin Resource Management Corporation 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 Corporation 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 Corporation 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 Corporation 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 Corporation for direct expenses.  In addition to the direct expenses, under the Omnibus Agreement, the Partnership is required to reimburse Martin Resource Management Corporation for indirect general and administrative and corporate overhead expenses.

    Effective January 1, 2021, through December 31, 2021, the board of directors of our general partner approved an annual reimbursement amount for indirect expenses of $14,386.  The Partnership reimbursed Martin Resource Management Corporation for $14,386, $16,410 and $16,657 of indirect expenses for the years ended December 31, 2021, 2020 and 2019, respectively.  The board of directors of our general partner 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 Corporation provides to 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 Corporation retained businesses. The provisions of the Omnibus Agreement regarding Martin Resource Management Corporation’s services will terminate if Martin Resource Management Corporation 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 Corporation 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 Corporation that requires aggregate annual payments in excess of the then-applicable agreed upon reimbursable amount of indirect general and administrative expenses. Please read "Services" above.

    License Provisions. Under the Omnibus Agreement, Martin Resource Management Corporation 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 Corporation.  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 Corporation.  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 Corporation for general and administrative services performed on its behalf, will terminate if the Partnership is no longer an affiliate of Martin Resource Management Corporation.

Master Transportation Services Agreement

    Master Transportation Services Agreement.  MTI, a wholly owned subsidiary of the Partnership, is a party to a master transportation services agreement effective January 1, 2019, with certain wholly owned subsidiaries of Martin Resource Management Corporation. Under the agreement, MTI agreed to transport Martin Resource Management Corporation's petroleum products and by-products.

    Term and Pricing.  The agreement will continue unless either party terminates the agreement by giving at least 30 days' written notice to the other party.  The rates under the agreement are subject to any adjustments which are mutually agreed upon or in accordance with a price index. Additionally, 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.  MTI has agreed to indemnify Martin Resource Management Corporation against all claims arising out of the negligence or willful misconduct of MTI and its officers, employees, agents, representatives and subcontractors. Martin Resource Management Corporation has agreed to indemnify MTI against all claims arising out of the negligence or willful misconduct of Martin Resource Management Corporation and its officers, employees, agents, representatives and subcontractors. In the event a claim is the result of the joint negligence or misconduct of MTI and Martin Resource Management Corporation, 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, the Partnership entered into a second amended and restated terminalling services agreement under which the Partnership provides terminal services to Martin Resource Management Corporation for marine fuel distribution.  At such time, the per-gallon throughput fee the Partnership charged under this agreement was increased when compared to the previous agreement and may be adjusted annually based on a price index.  This agreement was further amended on April 1, 2019 and January 1, 2020 to modify its minimum throughput requirements and throughput fees. The term of this agreement is currently evergreen and it will continue on a month to month basis until terminated by either party by giving 60 days’ written notice.  

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

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 Corporation 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 Corporation are based on applicable market rates.

    Marine Fuel.  The Partnership is a party to an agreement with Martin Resource Management Corporation dated November 1, 2002, under which Martin Resource Management Corporation provides the Partnership with marine fuel from its locations in the Gulf of Mexico at a fixed rate in excess of the Platt's U.S. Gulf Coast Index for #2 Fuel Oil.  Under this agreement, the Partnership agreed to purchase all of its marine fuel requirements that occur in the areas serviced by Martin Resource Management Corporation.

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 20, 2021, under which the Partnership processes crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts for Cross.  The tolling agreement

expires November 25, 2031.  Under this tolling agreement, Cross agreed to process a minimum of 6,500 barrels per day of crude oil at the facility at a fixed price per barrel.  Any additional barrels are processed at a modified price per barrel.  In addition, Cross agreed to pay a monthly reservation fee and a periodic fuel surcharge fee based on certain parameters specified in the tolling agreement.   Further, certain capital improvements, to the extent requested by Cross, are reimbursed through a capital recovery fee.  As of December 31, 2019, the annual capital recovery fee reimbursement of $2,088 expired. An additional $2,586 of capital recovery fee reimbursement expired on December 31, 2020.  All of these fees (other than the fuel surcharge) are subject to escalation annually based upon two-thirds of any increase in the Consumer Price Index for a specified annual period.  In no event shall the fees charged under the agreement ever decrease below the amounts which existed as of October 20, 2021. Also, the Partnership renegotiated a crude transportation contract set to expire in the first half of 2022 resulting in a reduction in revenue of $2,145 annually beginning January 1, 2020.

East Texas Mack Leases. MTI leases equipment, including tractors and trailers, from East Texas Mack Sales ("East Texas Mack"). Certain of our directors or officers are owners of East Texas Mack, including entities affiliated with Ruben Martin, who owns approximately 46% of the issued and outstanding stock of East Texas Mack. Amounts paid to East Texas Mack for tractor and trailer lease payments and lease residuals for the fiscal years ended December 31, 2021, 2020 and 2019 were approximately $1,089, $650, and $875, respectively.

    Other Miscellaneous Agreements. From time to time the Partnership enters into other miscellaneous agreements with Martin Resource Management Corporation 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:	2021		2020		2019
Terminalling and storage	$	62,677	$	63,823	$	71,733
Transportation	20,046		21,997		24,243
Product sales:
Sulfur services	109		60		54
Terminalling and storage	370		257		877
	479		317		931
	$	83,202	$	86,137	$	96,907

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

Cost of products sold:
Sulfur services	$	9,980	$	10,519	$	10,765
Terminalling and storage	27,866		18,429		23,859
	$	37,846	$	28,948	$	34,624

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

Operating expenses:
Transportation	$	55,382	$	55,786	$	61,376
Natural gas liquids	2,038		2,003		3,446
Sulfur services	4,411		4,489		4,810
Terminalling and storage	16,776		17,797		18,562
	$	78,607	$	80,075	$	88,194

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

Selling, general and administrative:
Transportation	$	6,996	$	7,358	$	7,107
Natural gas liquids	4,590		2,397		2,804
Sulfur services	3,276		3,080		2,850
Terminalling and storage	3,370		3,403		3,083
Indirect overhead allocation, net of reimbursement	14,692		16,648		16,778
	$	32,924	$	32,886	$	32,622

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Supplemental Balance Sheet Information

12 Months Ended

Dec. 31, 2021

Balance Sheet Related Disclosures [Abstract]

Supplemental Balance Sheet Information

SUPPLEMENTAL BALANCE SHEET INFORMATION

    Components of "Intangibles and other assets, net" at December 31, 2021 and 2020 were as follows:

	2021		2020
Catalyst and turnaround costs	$	687	$	803
Other intangible assets	358		586
Other	1,153		1,416
	$	2,198	$	2,805

Other intangible assets consist of technology-based assets.

Amortization expense, included in "Depreciation and amortization" on the Partnership's Consolidated Statements of Operations includes amortization of intangible assets, turnaround expenses, and deferred charges. Aggregate amortization expense included in continuing operations was $4,085, $5,235, and $5,797, for the years ended December 31, 2021, 2020 and 2019, respectively.

Estimated amortization expense for the years subsequent to December 31, 2021 are as follows: 2022 - $4,403; 2023 - $661; 2024 - $266; 2025 - $84; 2026 - $1; subsequent years - $0.

Components of "Other accrued liabilities" at December 31, 2021 and 2020 were as follows:

	2021		2020
Accrued interest	$	15,135	$	16,104
Asset retirement obligations	261		1,692
Property and other taxes payable	4,631		4,869
Accrued payroll	2,973		3,244
Operating lease liabilities	6,600		7,529
Other	250		969
	$	29,850	$	34,407

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

	Year Ended December 31,
	2021		2020
	(In thousands)
Beginning asset retirement obligations	$	8,759	$	8,936
Revisions to existing liabilities 1	—		918
Accretion expense	375		410
Liabilities settled	(62)		(1,505)
Ending asset retirement obligations	9,072		8,759
Current portion of asset retirement obligations 2	(261)		(1,692)
Long-term portion of asset retirement obligations 3	$	8,811	$	7,067

1 Several 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.

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

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

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Long-Term Debt

12 Months Ended

Dec. 31, 2021

Debt Disclosure [Abstract]

Long-Term Debt

LONG-TERM DEBT

    At December 31, 2021 and 2020, long-term debt consisted of the following:

	2021		2020
$275,000 1 Credit facility at variable interest rate (5.00% 1 weighted average at December 31, 2021), due August 2023 4 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, net of unamortized debt issuance costs of $2,613 and $3,826, respectively 2	$	156,887	$	144,174
$400,000 Senior notes, 7.25% interest, net of unamortized debt issuance costs of $0 and $— respectively, including unamortized premium of $0 and $344, respectively, issued $250,000 February 2013 and $150,000 April 2014, $26,200 repurchased during 2015, $9,344 repurchased during 2020, and $335,666 refinanced as part of the August 2020 Exchange offer, $28,790 repaid at maturity in February 2021, unsecured 2,3,4,5	—		28,790
$53,750 Senior notes, due February 2024, 10.0% interest, net of unamortized debt issuance costs of $2,433 and $3,577, respectively 2,3	$	51,317	$	50,173
$291,970 Senior notes, due February 2025, 11.5% interest, net of unamortized debt issuance costs of $1,303 and $1,720, respectively 2,3	$	290,667	$	290,250
Total	498,871		513,387
Less: current portion	—		(28,790)
Total long-term debt, net of current portion	$	498,871	$	484,597
Current installments of finance lease obligations	$	280	$	2,707
Finance lease obligations	9		289
Total finance lease obligations	$	289	$	2,996

    1 Interest rate fluctuates based on LIBOR plus an applicable margin set on the date of each advance. The margin above LIBOR is set every three months. All amounts outstanding at December 31, 2021 were at LIBOR plus an applicable margin of 4.00%, with LIBOR having a floor of 1.00%. The applicable margin for revolving loans that are LIBOR loans currently ranges from 2.75% to 4.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 1.75% to 3.00%. The credit facility contains various covenants which limit the Partnership’s ability to make distributions; make certain investments and acquisitions; enter into certain agreements; incur indebtedness; sell assets; and make certain amendments to the Partnership's omnibus agreement with Martin Resource Management Corporation (the "Omnibus Agreement"). The credit facility was amended July 16, 2021 to, among other things, reduce the commitments thereunder from $300,000 to $275,000.

    2 The Partnership was in compliance with all debt covenants as of December 31, 2021.

3 The indentures for each of the outstanding senior notes 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.

4 On February 15, 2021, our 2021 Notes matured and we retired the outstanding balance of $28,790 using proceeds from our credit facility.

5 In March 2020, the Partnership repurchased on the open market an aggregate $9,344 of the 2021 Notes, resulting in a gain on retirement of $3,484.

The Partnership paid cash interest, net of capitalized interest, in the amount of $51,708, $37,678, and $48,025 for the years ended December 31, 2021, 2020 and 2019, respectively. Capitalized interest was $0, $43, and $5 for the years ended December 31, 2021, 2020 and 2019, respectively.

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Partners' Capital (Deficit)

12 Months Ended

Dec. 31, 2021

Equity [Abstract]

Partners' Capital (Deficit)

PARTNERS' CAPITAL (DEFICIT)

    As of December 31, 2021, partners’ capital consisted of 38,802,750 common limited partner units, representing a 98% partnership interest, and a 2% general partner interest. Martin Resource Management Corporation, through subsidiaries, owned 6,114,532 of the Partnership's common limited partnership units representing approximately 15.8% of the Partnership's outstanding common limited partnership units. MMGP, the Partnership's general partner, owns the 2% general partnership interest.

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.

Impact on Partners' Capital (Deficit) Related to Transactions Between Entities Under Common Control

Under ASC 805, assets and liabilities transferred between entities under common control are accounted for at the historical cost of those entities' ultimate parent, in a manner similar to a pooling of interests. Any difference in the amount paid by the transferee versus the historical cost of the assets transferred is recorded as an adjustment to equity (contribution or distribution) by the transferee. This is in contrast with a business combination between unrelated parties, where assets and liabilities are recorded at their fair values at the acquisition date, with any excess of amounts paid over the fair value representing goodwill. From time to time, the most recent being in 2019, the Partnership has entered into common control acquisitions from Martin Resource Management Corporation. The consideration transferred totaling $552,123 exceeds the historical cost of the net assets received. This excess of the purchase price over the historical cost of the net assets received has resulted in cumulative distributions of $289,084 reflected as reductions to Partners' capital.

    Incentive Distribution Rights

MMGP holds a 2% general partner interest and, until November 23, 2021, MMGP held 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. On November 23, 2021, MMGP contributed to the Partnership all of the outstanding IDRs for no consideration, whereupon the IDRs were cancelled and cease to exist (the “IDR Elimination”). Until the IDR Elimination, the Partnership was required to distribute all of its available cash from operating surplus, as previously defined in the Partnership Agreement.

    For the years ended December 31, 2021, 2020 and 2019, the general partner was allocated no incentive distributions.

Distributions of Available Cash

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

Net Income per Unit

The Partnership follows the provisions of the FASB ASC 260-10 related to earnings per share, which addresses the application of the two-class method in determining income per unit for master limited partnerships having multiple classes of securities that may participate in partnership distributions accounted for as equity distributions. Undistributed earnings are allocated to the general partner and limited partners utilizing the contractual terms of the Partnership Agreement. Distributions to the general partner pursuant to the IDRs are limited to available cash that will be distributed as defined in the Partnership Agreement. Accordingly, the Partnership does not allocate undistributed earnings to the general partner for the IDRs because the general partner's share of available cash is the maximum amount that the general partner would be contractually entitled to receive if all earnings for the period were distributed. When current period distributions are in excess of earnings, the excess

distributions for the period are to be allocated to the general partner and limited partners based on their respective sharing of losses specified in the Partnership Agreement. Additionally, as required under FASB ASC 260-10-45-61A, unvested share-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities, as defined in FASB ASC 260-10-20, for earnings per unit calculations.

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

	Years Ended December 31,
	2021		2020		2019
Continuing operations:
Income (loss) from continuing operations	$	(211)	$	(6,771)	$	4,520
Less general partner’s interest in net income (loss):
Distributions payable on behalf of IDRs	—		—		—
Distributions payable on behalf of general partner interest	16		61		(20)
General partner interest in undistributed income (loss)	(20)		(196)		111
Less income (loss) allocable to unvested restricted units	—		(21)		(1)
Limited partners’ interest in net income (loss)	$	(207)	$	(6,615)	$	4,430

	Years Ended December 31,
	2021		2020		2019
Discontinued operations:
Loss from discontinued operations	$	—	$	—	$	(179,466)
Less general partner’s interest in net income (loss):
Distributions payable on behalf of IDRs	—		—		—
Distributions payable on behalf of general partner interest	—		—		806
General partner interest in undistributed loss	—		—		(4,396)
Less income allocable to unvested restricted units	—		—		42
Limited partners’ interest in net loss	$	—	$	—	$	(175,918)

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

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

	Years Ended December 31,
	2021	2020	2019
Basic weighted average limited partner units outstanding	38,689,041	38,656,559	38,658,881
Dilutive effect of restricted units issued	—	—	—
Total weighted average limited partner diluted units outstanding	38,689,041	38,656,559	38,658,881

    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. All common unit equivalents were antidilutive for the years ended December 31, 2021, 2020 and 2019 because the limited partners were allocated a net loss in this period.

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Unit Based Awards - Long-Term Incentive Plans

12 Months Ended

Dec. 31, 2021

Share-based Payment Arrangement [Abstract]

Unit Based Awards - Long-Term Incentive Plans

UNIT BASED AWARDS - LONG-TERM INCENTIVE PLANS

    The Partnership recognizes compensation cost related to unit-based awards to both employees and non-employees in its consolidated financial statements in accordance with certain provisions of ASC 718. Amounts recognized in operating expense and selling, general, and administrative expense in the consolidated financial statements with respect to these plans are as follows:

	For the Year Ended December 31,
	2021		2020		2019
Restricted unit awards
Employees	$	194	$	1,204	$	1,226
Non-employee directors	190		—		—
Phantom unit Awards
Employees	415		—		—
Non-employee directors	—		218		198
Total unit-based compensation expense	$	799	$	1,422	$	1,424

    Long-Term Incentive Plans

      The Partnership's general partner has long-term incentive plans for employees and directors of the general partner and its affiliates who perform services for the Partnership.

Phantom Unit Plan

On July 21, 2021, the board of directors of the general partner of the Partnership and the compensation committee of the general partner’s board of directors (the "Compensation Committee") approved the Martin Midstream Partners L.P. 2021 Phantom Unit Plan (the “Plan”), effective as of the same date. The Plan permits the awards of phantom units and phantom unit appreciation rights (collectively, "phantom unit awards") to any employee or non-employee director of the Partnership, including its executive officers. The awards may be time-based or performance-based and will be paid, if at all, in cash.

The award of a phantom unit entitles the participant to a cash payment equal to the value of the phantom unit on the vesting date or dates, which value is the fair market value of a common unit of the Partnership (a “Unit”) on such vesting date or dates. The award of a phantom unit appreciation right entitles the recipient to a cash payment equal to the difference between the value of a phantom unit on the vesting date or dates in excess of the value assigned by the Compensation Committee to the phantom unit as of the grant date. Phantom units and phantom unit appreciation rights granted to participants do not confer upon participants any right to a Unit.

On July 21, 2021, the Compensation Committee approved forms of time-based award agreements for phantom units and phantom unit appreciation rights, both of which awards vest in full on the third anniversary of the grant date. The grant date value of a phantom unit under a phantom unit appreciation right award is equal to the average of the closing price for a Unit during the 20 trading days immediately preceding the grant date of the award.

Generally, vesting of an award is subject to a participant remaining continuously employed with the Partnership through the vesting date. However, if prior to the vesting date (i) a participant is terminated without cause (as defined in the award agreement) or terminates employment after the participant has attained both the age of 65 and ten years of employment (“retirement-eligible”), a prorated portion of the award will vest and be paid in cash no later than the 30th day following such termination date (subject to a six-month delay in payment for certain retirement-eligible participants) or (ii) there is a change in control of the Partnership (as defined in the Plan), the award will vest in full and be paid in cash no later than the 30th day following the date of the change of control; provided, that the participant has been in continuous employment through the termination or change in control date, as applicable.

On July 21, 2021, 620,000 phantom units and 1,245,000 phantom unit appreciation rights were granted to employees of the general partner and its affiliates who perform services for the Partnership.

Phantom unit awards are recorded in operating expense and selling, general and administrative expense based on the fair value of the vested portion of the awards on the balance sheet date. The fair value of these awards is updated at each balance sheet date and changes in the fair value of the vested portions of the awards are recorded as increases or decreases to compensation expense within operating expense and selling, general and administrative expense in the Consolidated Statements of Operations. All of the Partnership's outstanding phantom unit awards at December 31, 2021 met the criteria to be treated under liability classification in accordance with ASC 718, given that these awards will settle in cash on the vesting date.

Compensation expense for the phantom awards is based on the fair value of the units as of the balance sheet date as further discussed below, and such costs are recognized ratably over the service period of the awards. As the fair value of liability awards is required to be re-measured each period end, stock compensation expense amounts recognized in future periods for these awards will vary. The estimated future cash payments of these awards are presented as liabilities within "Other current liabilities" and "Other long-term obligations" in the Consolidated Balance Sheets. As of December 31, 2021, there was a total of $1,233 of unrecognized compensation costs related to non-vested phantom unit awards. These costs are expected to be recognized over a remaining life of 2.56 years.

The fair value of the phantom unit awards was estimated using a Monte Carlo valuation model as of the balance sheet date. The Monte Carlo valuation model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility was calculated based on the historical volatility of the Partnership’s common units as well as set of peer companies.

Restricted Unit Plan

    On May 26, 2017, the unitholders of the Partnership approved the Martin Midstream Partners L.P. 2017 Restricted Unit Plan (the “2017 LTIP”). The 2017 LTIP currently permits the grant of awards covering an aggregate of 3,000,000 common units, all of which can be awarded in the form of restricted units. The 2017 LTIP is administered by the Compensation Committee.

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

The restricted units issued to directors generally vest in equal annual installments over a four-year period.

On February 22, 2021, the Partnership issued 14,056 TBRUs to each of the Partnership's three independent directors under the 2017 LTIP.  These restricted common units vest in equal installments of 3,514 units on January 24, 2022, 2023, 2024, and 2025.

On March 1, 2018, the Partnership issued 301,550 TBRUs and 317,925 PBRUs to certain employees of Martin Resource Management Corporation. The TBRUs vested in equal installments over a three-year service period. The PBRUs would have vested at the conclusion of a three-year performance period based on certain performance targets. In addition, the PBRUs awarded on March 1, 2018 would have only vested if the grantee was employed by Martin Resource Management Corporation on March 31, 2021. However, the performance conditions related to the PBRUs awarded on March 1, 2018 were

not achieved and the Partnership treated these units as forfeited at expiration on March 31, 2021. As such, the Partnership did not recognize compensation expense related to these units.

     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, 2021 is provided below:

	Number of Units		Weighted Average Grant-Date Fair Value Per Unit
Non-vested, beginning of year	273,424		$	10.52
Granted (TBRU)	42,168		$	2.49
Vested	(117,280)		$	11.96
Forfeited	(83,436)		$	13.90
Non-Vested, end of year	114,876		$	3.65
Aggregate intrinsic value, end of year	$	306

    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, 2021, 2020 and 2019 is provided below:

	For the Year Ended December 31,
	2021		2020		2019
Aggregate intrinsic value of units vested	$	257	$	151	$	1,351
Fair value of units vested	$	1,418	$	1,427	$	1,551

    As of December 31, 2021, there was $248 of unrecognized compensation cost related to non-vested time-based restricted units. That cost is expected to be recognized over a weighted-average period of 2.12 years.

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Income Taxes

12 Months Ended

Dec. 31, 2021

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

    The components of income tax expense (benefit) from operations for the years ended December 31, 2021, 2020 and 2019 are as follows:

	2021		2020		2019
Current:
Federal	$	455	$	(174)	$	174
State	493		741		366
	948		567		540
Deferred:
Federal	2,142		1,027		882
State	290		142		478
	2,432		1,169		1,360
Total income tax expense	$	3,380	$	1,736	$	1,900

    The operations of a partnership are generally not subject to income taxes, except for Texas margin tax, because its income is taxed directly to its partners. The Texas margin tax 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 income tax, and therefore, the recognition of deferred taxes applies to the margin tax. The impact on deferred taxes as a result of this provision is immaterial. State income taxes attributable to the Texas margin tax relating to the operation of the Partnership of $300, $468 and $458 were recorded in income tax expense for the years ended December 31, 2021, 2020 and 2019, respectively.

MTI, a wholly owned subsidiary of the Partnership, is subject to income taxes due to its corporate structure (“Taxable Subsidiary”). Prior to the acquisition of MTI on January 2, 2019, MTI was a QSub of Martin Resource Management Corporation, a qualifying S Corporation. A QSub is not treated as a separate corporation for federal income tax purposes as it is deemed liquidated into its S Corporation parent. S Corporations are generally not subject to income taxes because income and losses flow through to shareholders and are reported on their individual returns. The principal component of the difference between the expected state tax expense and actual state tax expense relates to taxes incurred in states that do not recognize S corporation status.

Subsequent to the acquisition, the QSub election terminated resulting in MTI being taxed as a stand-alone C Corporation. Total income tax expense relating to the operation of the Taxable Subsidiary of $3,080 and $1,268 was recorded in income tax expense for the years ended December 31, 2021 and 2020, respectively.

The income tax expense from the Taxable Subsidiary operations for the years ended December 31, 2021 and 2020 differs from the "expected" tax expense (computed by applying the federal corporate rate of 21% to income before income taxes of the Taxable Subsidiary) as follows:

	2021		2020
"Expected" tax expense	$	2,223	$	361
Increase in income taxes resulting from:
State income taxes, net of federal income tax expense	382		327
Other non-deductible items	384		472
Other, net	91		108
Actual tax expense	$	3,080	$	1,268

Cash paid for income taxes was $1,232, $416 and $515 for the years ended December 31, 2021, 2020 and 2019, respectively.

Deferred taxes are the result of differences between the bases of assets and liabilities for financial reporting and income tax purposes. Significant components of deferred tax assets and liabilities at December 31, 2021 and 2020 are as follows:

	2021		2020
Deferred tax assets:
Bad debt reserves	$	26	$	59
Goodwill and intangibles	12,523		13,893
Employee benefits	57		244
Interest expense	—		—
Tax loss carryforwards	10,676		12,671
Other	129		251
Subtotal	23,411		27,118
Less: Valuation allowance	—		—
Total net deferred tax assets	23,411		27,118
Deferred tax liabilities:
Property and equipment	(3,590)		(4,861)
Operating leases	—		(4)
Other	—		—
Total deferred tax liabilities	(3,590)		(4,865)
Net deferred tax assets	$	19,821	$	22,253

Deferred tax assets are regularly reviewed for recoverability and a valuation allowance is provided when it is more likely than not that some portion or all of a deferred tax asset will not be realized. The ultimate realization of deferred tax assets

is dependent upon future taxable income during the periods in which those temporary differences become deductible. In assessing the need for a valuation allowance, management considers all available positive and negative evidence, including the ability to carryback operating losses to prior periods and the expected future utilization of net operating loss carryforwards, the reversal of deferred tax liabilities, projected taxable income, and tax-planning strategies. On the basis of these considerations, as of December 31, 2021, management believes it is more likely than not that the Taxable Subsidiary will realize the benefit of the existing deferred tax assets.

    Federal income taxes refundable related to the operation of the Taxable Subsidiary of $70 and $0 for the years ended December 31, 2021 and 2020, respectively, are included in “Other current assets”."Income taxes payable" includes a state income tax liability related to the operation of the Partnership of $304 and $455 for the years ended December 31, 2021 and 2020, respectively. Also included in "Income taxes payable" are state income tax liabilities related to the operation of the Taxable Subsidiary of $81 and $101 for the years ended December 31, 2021 and 2020, respectively.

    At December 31, 2021, MTI had net operating loss carryforwards for income tax purposes of approximately $67,681 related to federal and state taxes. Of these net operating loss carryforwards, approximately $19,379 will expire between 2024 and 2041 and approximately $48,302 may be carried forward indefinitely.

    The operations of the Partnership are generally not subject to income taxes, except as discussed above, because its income is taxed directly to its partners. The net tax basis in the Partnership's assets and liabilities is greater (less) than the reported amounts on the financial statements by approximately $91,893 and $88,526 as of December 31, 2021 and 2020, respectively.

    As of December 31, 2021, the tax years that remain open to assessment are 2018-2020.

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Business Segments

12 Months Ended

Dec. 31, 2021

Segment Reporting [Abstract]

Business Segments

BUSINESS SEGMENTS

    The Partnership has four reportable segments: terminalling and storage, natural gas liquids, 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 interest expense.

	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, 2021:
Terminalling and storage	$	185,629	$	(6,597)	$	179,032	$	28,210	$	10,785	$	9,582
Natural gas liquids	414,043		—		414,043		2,390		38,098		537
Sulfur services	145,042		—		145,042		10,432		32,972		7,813
Transportation	161,180		(16,866)		144,314		15,719		(8,446)		4,997
Indirect selling, general, and administrative	—		—		—		—		(16,129)		—
Total	$	905,894	$	(23,463)	$	882,431	$	56,751	$	57,280	$	22,929
Year Ended December 31, 2020:
Terminalling and storage	$	191,041	$	(6,877)	$	184,164	$	29,489	$	22,153	$	11,619
Natural gas liquids	247,484		(5)		247,479		2,456		22,104		395
Sulfur services	108,020		(13)		108,007		12,012		36,256		7,415
Transportation	150,285		(17,793)		132,492		17,505		(16,102)		7,348
Indirect selling, general, and administrative	—		—		—		—		(17,909)		—
Total	$	696,830	$	(24,688)	$	672,142	$	61,462	$	46,502	$	26,777
Year Ended December 31, 2019:
Terminalling and storage	$	216,313	$	(6,659)	$	209,654	$	30,952	$	16,732	$	12,987
Natural gas liquids	366,502		—		366,502		2,469		44,020		1,870
Sulfur services	111,340		—		111,340		11,332		22,721		14,853
Transportation	183,740		(24,118)		159,622		15,307		(7,388)		8,213
Indirect selling, general, and administrative	—		—		—		—		(17,981)		—
Total	$	877,895	$	(30,777)	$	847,118	$	60,060	$	58,104	$	37,923

Revenues from one customer in the Natural Gas Liquids segment was $140,324, $74,722 and $112,280 for the years ended December 31, 2021, 2020 and 2019, respectively.

The Partnership's assets by reportable segment as of December 31, 2021 and 2020 are as follows:

	2021		2020
Total assets:
Terminalling and storage	$	248,194	$	252,794
Natural gas liquids	78,483		80,737
Sulfur services	108,007		94,154
Transportation	145,177		151,953
Total assets	$	579,861	$	579,638

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2021

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES

Contingencies

From time to time, the Partnership is subject to various claims and legal actions arising in the ordinary course of business.  In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Partnership.

On December 31, 2015, the Partnership received a demand from a customer in its lubricants packaging business for defense and indemnity in connection with various lawsuits filed against it, which generally alleged that the customer engaged in unlawful and deceptive business practices in connection with its marketing and advertising of its private label motor oil (the “Marketing Lawsuits”). The Partnership disputed and continues to dispute that it has any obligation to defend or indemnify the customer for the customer’s conduct. Accordingly, on January 7, 2016, the Partnership filed a Complaint for Declaratory Judgment in the Chancery Court of Davidson County, Tennessee (the “Tennessee Court”), under Case No. 16-0018-BC, requesting a judicial determination that the Partnership did not owe the customer the demanded defense and indemnity obligations (the “Declaratory Judgment Action”). The Marketing Lawsuits pending in federal court against the customer were transferred to the U.S. District Court for the Western District of Missouri under the consolidated case MDL No. 2709 for pretrial proceedings (the “Consolidated Lawsuits”). On March 1, 2017, at the joint request of the customer and the Partnership, the Tennessee Court administratively closed the Declaratory Judgment Action. Recently, the customer settled the Consolidated Lawsuits. On December 17, 2021, at the request of the customer, the Tennessee Court reopened the Declaratory Judgment Action and the customer asserted various counterclaims against the Partnership seeking, among other things, to recover its costs of defending and settling the Consolidated Lawsuits. At this time, we are unable to determine what ultimate exposure we may have in this matter, if any. The Partnership intends to vigorously defend the counterclaims asserted by the customer in the Declaratory Judgment Action.

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Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2021
Consolidating Financial Statements [Abstract]
Condensed Consolidating Financial Information	CONDENSED CONSOLIDATING FINANCIAL INFORMATION    The Partnership's operations are conducted by its operating subsidiaries as it has no independent assets or operations. Martin Operating Partnership L.P. (the "Operating Partnership"), the Partnership’s wholly-owned subsidiary, and the Partnership's other operating subsidiaries have issued in the past, and may issue in the future, unconditional guarantees of senior or subordinated debt securities of the Partnership. The guarantees that have been issued are full, irrevocable and unconditional and joint and several. In addition, the Operating Partnership may also issue senior or subordinated debt securities which, if issued, will be fully, irrevocably and unconditionally guaranteed by the Partnership. Substantially all of the Partnership's operating subsidiaries are subsidiary guarantors of its outstanding senior notes and any subsidiaries other than the subsidiary guarantors are minor.

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Subsequent Events	12 Months Ended
	Dec. 31, 2021
Subsequent Events [Abstract]
Subsequent Events	SUBSEQUENT EVENTSQuarterly Distribution.  On January 25, 2022, the Partnership declared a quarterly cash distribution of $0.005 per common unit for the fourth quarter of 2021, or $0.02 per common unit on an annualized basis, which was paid on February 14, 2022 to unitholders of record as of February 7, 2022.

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Significant Accounting Policies and Practices (Policies)

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

Principles of Presentation and Consolidation

Principles of Presentation and Consolidation    The consolidated financial statements include the financial statements of the Partnership and its wholly-owned subsidiaries and equity method investees.  In the opinion of the management of the Partnership’s general partner, all adjustments and elimination of significant intercompany balances necessary for a fair presentation of the Partnership’s results of operations, financial position and cash flows for the periods shown have been made.  All such adjustments are of a normal recurring nature.  In addition, the Partnership evaluates its relationships with other entities to identify whether they are variable interest entities under certain provisions of the Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC"), 810-10 and to assess whether it is the primary beneficiary of such entities.  If the determination is made that the Partnership is the primary beneficiary, then that entity is included in the consolidated financial statements in accordance with ASC 810-10.  No such variable interest entities existed as of December 31, 2021 or 2020.

Product Exchanges

Product Exchanges

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

Inventories

Inventories

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

Revenue Recognition

Revenue Recognition

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

Natural Gas Liquids – Revenue is recognized when product is delivered by truck, rail, or pipeline to the Partnership's NGL customers. Revenue is recognized on title transfer of the product to the customer. Delivery of product is invoiced as the transaction occurs and is generally paid within a month.

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

Transportation – Revenue related to land transportation is recognized for line hauls based on a mileage rate. For contracted trips, revenue is recognized upon completion of the particular trip. The performance of the service is invoiced as the transaction occurs and is generally paid within a month. Revenue related to marine transportation is recognized for time charters based on a per day rate. For contracted trips, revenue is recognized upon completion of the particular trip. The performance of the service is invoiced as the transaction occurs and is generally paid within a month.

Equity Method Investments

Equity Method Investments

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

Property, Plant and Equipment

Property, Plant, and Equipment

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

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

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

Goodwill and Other Intangible Assets

Goodwill and Other Intangible Assets

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

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

Of the Partnership's four reporting units, the terminalling and storage, transportation, and sulfur services reporting units contain goodwill.

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

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

Applying this impairment review methodology, the Partnership considered the impact that COVID-19 had on our cash flows and the value our unit price during both 2021 and 2020 and elected to bypass the qualitative assessment and perform a quantitative assessment. Based upon the most recent annual review as of August 31, 2021, no goodwill impairment exists within the Partnership's reporting units for the year ended December 31, 2021. No goodwill impairment was recorded for the years ended December 31, 2020 or 2019.

Other intangible assets that have finite lives are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable. An impairment is indicated if the carrying amount of a long-lived intangible asset exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If impairment is indicated, the Partnership would record an impairment loss equal to the difference between the carrying value and the fair value of the asset.

Debt Issuance Costs

Debt Issuance CostsDebt issuance costs relating to the Partnership’s credit facility and senior 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.

Impairment of Long-Lived Assets

Impairment of Long-Lived Assets

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

The Partnership identified triggering events related to a certain asset group in its transportation segment in 2021. The Partnership performed a recoverability test and concluded the estimated undiscounted cash flows expected to be generated by the asset group exceeded the carrying value of the asset group and no impairment was recorded.

Asset Retirement Obligations

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

Derivative Instruments and Hedging Activities

Derivative Instruments and Hedging Activities

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

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

Use of Estimates

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

Environmental Liabilities and Litigation

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.

Trade and Accrued Accounts Receivable and Allowance for Doubtful Accounts

Trade and Accrued Accounts Receivable and Allowance for Doubtful Accounts.

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

Deferred Catalyst Costs

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

Deferred Turnaround Costs

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

Income Taxes

Income Taxes

Comprehensive Income

Comprehensive Income Comprehensive income includes net income and other comprehensive income. Other comprehensive income for the Partnership includes unrealized gains and losses on derivative instruments. In accordance with ASC 815-10, the Partnership records deferred hedge gains and losses on its derivative instruments that qualify as cash flow hedges as other comprehensive income.

Recent Accounting Pronouncements

RECENT ACCOUNTING PRONOUNCEMENTS

On January 1, 2021, the Partnership adopted FASB Accounting Standards Update (“ASU”) 2019-12, Income Taxes (Accounting Standards Codification (“ASC”) Topic 740): Simplifying the Accounting for Income Taxes, which removes certain exceptions to general principles in ASC 740 and clarifies and amends existing guidance within U.S. GAAP. Adoption of the new standard did not have a material impact on the Partnership’s consolidated financial statements.    

On January 1, 2020, the Partnership adopted ASU 2016-13, "Financial Instruments - Credit Losses," which required the Partnership to measure all expected credit losses for financial instruments held at the reporting date based on historical experience, current conditions, and reasonable supportable forecasts. This replaced the existing incurred loss model and is applicable to the measurement of credit losses on financial assets, including trade receivables. Adoption of the new standard did not have a material impact on the Partnership’s consolidated financial statements.

In June 2018, the FASB issued ASU 2018-07, Compensation - Stock Compensation: Improvements to Non-employee Share-Based Payment Accounting, which will expand the scope of FASB ASC 718 to include share-based payment transactions for acquiring goods and services from non-employees. The standard is effective for the Partnership's financial statements issued for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. The Partnership adopted this standard effective January 1, 2019. The result of this adoption did not have a material impact on the Partnership's consolidated financial statements.

    In February 2016, the FASB issued ASU 2016-02, Leases, which introduces the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous guidance. Lessor accounting under the new standard is substantially unchanged and substantially all of our leases will continue to be classified as operating leases under the new standard. Additional qualitative and quantitative disclosures, including significant judgments made by management are required.  The update is effective for annual reporting periods beginning after December 15, 2018, including interim periods within those reporting periods, with early adoption permitted. The original guidance required application on a modified retrospective basis with the earliest period presented. In August 2018, the FASB issued ASU 2018-11, Targeted Improvements to FASB ASC 842, which includes an option to not restate comparative periods in transition and elect to use the effective date of ASC 842, Leases, as the date of initial application of transition. The Partnership adopted this ASU on January 1, 2019, electing the transition option provided under ASU 2018-11.

    The new standard provides a number of optional practical expedients in transition. The Partnership elected the "package of practical expedients", which permits the Partnership not to reassess under the new standard our prior conclusions about lease identification, lease classification and initial direct costs. The new standard also provides practical expedients for an entity’s ongoing accounting. The Partnership elected the short-term lease recognition exemption for all leases that qualify. This means, for those assets that qualify, the Partnership did not recognize Right-of-Use ("ROU") assets or lease liabilities, and this includes not recognizing ROU assets or lease liabilities for existing short-term leases of those assets in transition. See Note 10 for more information.

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.

Fair Value of Financial Instruments

The Partnership is required to disclose estimated fair values for its financial instruments. Fair value estimates are set forth below for these financial instruments. The following methods and assumptions were used to estimate the fair value of each class of financial instrument:•Accounts and other receivables, trade and other accounts payable, accrued interest payable, other accrued liabilities, income taxes payable and due from/to affiliates: The carrying amounts approximate fair value due to the short maturity and highly liquid nature of these instruments, and as such these have been excluded from the table below. There is negligible credit risk associated with these instruments. •Current and non-current portion of long-term debt: The carrying amount of the credit facility approximates fair value due to the debt having a variable interest rate and is in Level 2. The estimated fair value of the 2021 Notes, 2024 Notes, and 2025 Notes (collectively, the "senior notes") is considered Level 2, as the fair value is based upon quoted prices for identical liabilities in markets that are not active.

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Acquisitions (Tables)

12 Months Ended

Dec. 31, 2021

Business Combination and Asset Acquisition [Abstract]

Schedule of Business Acquisitions

On January 2, 2019, the Partnership acquired all of the issued and outstanding equity interests of MTI, a wholly-owned subsidiary of Martin Resource Management Corporation, which operates a fleet of trucks providing transportation of petroleum products, liquid petroleum gas, chemicals, sulfur and other products, as well as owns 24 terminals located throughout the U.S. Gulf Coast and Southeastern U.S. for total consideration as follows:

Purchase price 1	$	135,000
Plus: Working Capital Adjustment	2,795
Less: Finance lease obligations assumed	(11,682)
Cash consideration paid	$	126,113

    1 The stock purchase agreement also includes a $10,000 earn-out based on certain performance thresholds. The performance threshold related to financial results for the years ended December 31, 2020 and 2019 was not achieved, which resulted in a reduction in the potential earn-out by $6,666. For the year ended December 31, 2021, the performance threshold related to financial results was exceeded, resulting in an earn-out payment of $1,350, which, pursuant to the terms of the stock purchase agreement, will be paid in the second quarter of 2022.This acquisition is considered a transfer of net assets between entities under common control. The acquisition of MTI was recorded at the historical carrying value of the assets at the acquisition date, which were as follows:

Accounts receivable, net	$	11,724
Inventories	1,138
Due from affiliates	1,042
Other current assets	897
Property, plant and equipment, net	25,383
Goodwill	489
Other noncurrent assets	362
Current installments of finance lease obligations	(5,409)
Accounts payable	(2,564)
Due to affiliates	(482)
Other accrued liabilities	(2,588)
Finance lease obligations, net of current installments	(6,272)
Historical carrying value of assets acquired	$	23,720

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DISCONTINUED OPERATIONS AND DIVESTITURES (Tables)

12 Months Ended

Dec. 31, 2021

Discontinued Operations and Disposal Groups [Abstract]

Disposal Groups, Including Discontinued Operations

The operating results, which are included in income (loss) from discontinued operations, were as follows:

	For the Year Ended December 31,
	2019
Total revenues	$	22,836
Total costs and expenses and other, net, excluding depreciation and amortization	(15,360)
Depreciation and amortization	(8,161)
Other operating loss, net 1	(178,781)
Other, net	—
Income (loss) from discontinued operations before income taxes	(179,466)
Income tax expense	—
Income (loss) from discontinued operations, net of income taxes	$	(179,466)

    1 The year ended December 31, 2019 includes a loss on the disposition of the Natural Gas Storage Assets of $178,781.

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Revenue (Tables)

12 Months Ended

Dec. 31, 2021

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

The following table disaggregates our revenue by major source:

	2021		2020		2019
Terminalling and storage segment
Lubricant product sales	$	103,809	$	103,300	$	122,257
Throughput and storage	75,223		80,864		87,397
	$	179,032	$	184,164	$	209,654
Transportation segment
Land transportation	$	111,611	$	88,652	$	98,895
Inland transportation	29,536		40,507		54,834
Offshore transportation	3,167		3,333		5,893
	$	144,314	$	132,492	$	159,622
Sulfur service segment
Sulfur product sales	$	32,416	$	24,176	$	30,135
Fertilizer product sales	100,827		72,172		69,771
Sulfur services	11,799		11,659		11,434
	$	145,042	$	108,007	$	111,340
Natural gas liquids segment
Natural gas liquids product sales	$	414,043	$	247,479	$	366,502
	$	414,043	$	247,479	$	366,502

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction

	2022		2023		2024		2025		2026		Thereafter		Total
Terminalling and storage
Throughput and storage	$	43,527	$	42,041	$	43,360	$	44,661	$	45,940	$	251,349	$	470,878
Natural Gas Services
Natural Gas Liquids	$	6,047	$	5,391	$	5,406	$	5,391	$	3,131	$	—	$	25,366
Sulfur services
Sulfur product sales	17,703		16,953		14,493		2,156		1,182		295		52,782
Total	$	67,277	$	64,385	$	63,259	$	52,208	$	50,253	$	251,644	$	549,026

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Inventories (Tables)

12 Months Ended

Dec. 31, 2021

Inventory Disclosure [Abstract]

Components of Inventory

Components of inventories at December 31, 2021 and 2020 were as follows: 

	2021		2020
Natural gas liquids	$	20,034	$	27,878
Sulfur	612		24
Fertilizer	13,005		10,854
Lubricants	23,876		11,002
Other	4,593		4,364
	$	62,120	$	54,122

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2021

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

At December 31, 2021 and 2020, property, plant and equipment consisted of the following:

	Depreciable Lives	2021		2020
Land	—	$	21,422	$	21,459
Improvements to land and buildings	10-25 years	132,064		135,227
Storage equipment	5-50 years	122,300		121,437
Marine vessels	4-25 years	183,414		179,666
Operating plant and equipment	3-50 years	360,122		356,293
Furniture, fixtures and other equipment	3-20 years	13,727		14,209
Transportation equipment	3-7 years	50,961		49,836
Construction in progress		14,760		10,981
		$	898,770	$	889,108

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Goodwill (Tables)

12 Months Ended

Dec. 31, 2021

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill

The following table represents the goodwill balance by reporting unit at December 31, 2021 and 2020 as follows:

	2021		2020
Carrying amount of goodwill:
Terminalling and storage	$	10,985	$	10,985
Sulfur services	5,349		5,349
Transportation	489		489
Total goodwill	$	16,823	$	16,823

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Leases (Tables)

12 Months Ended

Dec. 31, 2021

Leases [Abstract]

Components of Lease Expense

The components of lease expense for the years ended December 31, 2021, 2020, and 2019 were as follows:

	2021		2020		2019
Operating lease cost	$	9,266	$	10,672	$	10,805
Finance lease cost:
Amortization of right-of-use assets	164		1,755		2,686
Interest on lease liabilities	26		294		671
Short-term lease cost	10,290		13,187		13,756
Variable lease cost	115		109		92
Total lease cost	$	19,861	$	26,017	$	28,010

    Supplemental cash flow information for the years ended December 31, 2021, 2020, and 2019 related to leases were as follows:

	2021		2020		2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	19,678	$	23,996	$	24,526
Operating cash flows from finance leases	26		294		671
Financing cash flows from finance leases	2,707		4,562		5,514
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	7,668	$	7,779	$	9,122
Finance leases	0		83		1,309

Schedule of Supplemental Balance Sheet Information

Supplemental balance sheet information related to leases was as follows at December 31, 2021 and 2020:

	2021			2020
Operating Leases
Operating lease right-of-use assets	$	21,861		$	22,260
Current portion of operating lease liabilities included in "Other accrued liabilities"	$	6,600		$	7,529
Operating lease liabilities	15,704			15,181
Total operating lease liabilities	$	22,304		$	22,710
Finance Leases
Property, plant and equipment, at cost	$	1,071		$	10,352
Accumulated depreciation	(364)			(3,703)
Property, plant and equipment, net	$	707		$	6,649
Current installments of finance lease obligations	$	280		$	2,707
Finance lease obligations	9			289
Total finance lease obligations	$	289		$	2,996
Weighted Average Remaining Lease Term (years)
Operating leases	6.46			5.87
Finance leases	0.97			1.39
Weighted Average Discount Rate
Operating leases	4.96		%	5.04		%
Finance leases	5.74		%	6.04		%

Schedule of Future Minimum Lease Obligations, Finance Lease

The Partnership’s future minimum lease obligations as of December 31, 2021 consist of the following:

	Operating Leases		Finance Leases
Year 1	$	7,501	$	289
Year 2	4,672		9
Year 3	3,137		—
Year 4	2,460		—
Year 5	1,602		—
Thereafter	6,820		—
Total	26,192		298
Less amounts representing interest costs	(3,888)		(9)
Total lease liability	$	22,304	$	289

Schedule of Future Minimum Obligations, Operating Leases

The Partnership’s future minimum lease obligations as of December 31, 2021 consist of the following:

	Operating Leases		Finance Leases
Year 1	$	7,501	$	289
Year 2	4,672		9
Year 3	3,137		—
Year 4	2,460		—
Year 5	1,602		—
Thereafter	6,820		—
Total	26,192		298
Less amounts representing interest costs	(3,888)		(9)
Total lease liability	$	22,304	$	289

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2021

Fair Value Disclosures [Abstract]

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

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

	Level 2
	December 31,
	2021		2020
Commodity derivative contracts, net	$	—	$	(207)

	December 31, 2021				December 31, 2020
	Carrying Value		Fair Value		Carrying Value		Fair Value
2021 Notes	$	—	$	—	$	28,790	$	28,581
2024 Notes	$	51,317	$	55,220	$	50,173	$	55,214
2025 Notes	$	290,667	$	307,146	$	290,250	$	288,692
Total	$	341,984	$	362,366	$	369,213	$	372,487

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Derivative Instruments and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Effect of Derivative Instruments on the Consolidated Balance Sheets

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

	Derivative Assets					Derivative Liabilities
		Fair Values					Fair Values
	Balance Sheet Location	December 31, 2021		December 31, 2020		Balance Sheet Location	December 31, 2021		December 31, 2020
Derivatives designated as hedging instruments:	Current:
Commodity contracts	Fair value of derivatives	$	—	$	—	Fair value of derivatives	$	—	$	—
Derivatives not designated as hedging instruments:	Current:
Commodity contracts	Fair value of derivatives	$	—	$	—	Fair value of derivatives	$	—	$	207

Summary of Losses Recognized in AOCI and Reclassification From AOCI

The following table summarizes the loss recognized in AOCI at December 31, 2021 and the gain (loss) reclassified from accumulated other comprehensive loss into earnings during the year ended December 31, 2021 for derivative financial instruments designated as cash flow hedges:

	Amount of Gain (Loss) Recognized in AOCI				Location of Gain (Loss) Reclassified from AOCI into Income	Amount of Gain (Loss) Reclassified from AOCI into Income
	2021		2020			2021		2020
Commodity contracts	$	816	$	—	Cost of products sold	$	(3,768)	$	—
Total	$	816	$	—		$	(3,768)	$	—

Effect of Derivative Instruments on the Consolidated Statement of Operations

The following tables summarize the loss recognized in earnings for derivative instruments not designated as hedging instruments during the year ended December 31, 2021:

	Location of Gain (Loss) Recognized in Income on  Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives
		2021		2020
Derivatives not designated as hedging instruments:
Commodity contracts	Cost of products sold	$	(1,825)	$	(8,209)
Total effect of derivatives not designated as hedging instruments		$	(1,825)	$	(8,209)

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2021

Related Party Transactions [Abstract]

The Impact of Related Party Transactions

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

Revenues:	2021		2020		2019
Terminalling and storage	$	62,677	$	63,823	$	71,733
Transportation	20,046		21,997		24,243
Product sales:
Sulfur services	109		60		54
Terminalling and storage	370		257		877
	479		317		931
	$	83,202	$	86,137	$	96,907

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

Cost of products sold:
Sulfur services	$	9,980	$	10,519	$	10,765
Terminalling and storage	27,866		18,429		23,859
	$	37,846	$	28,948	$	34,624

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

Operating expenses:
Transportation	$	55,382	$	55,786	$	61,376
Natural gas liquids	2,038		2,003		3,446
Sulfur services	4,411		4,489		4,810
Terminalling and storage	16,776		17,797		18,562
	$	78,607	$	80,075	$	88,194

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

Selling, general and administrative:
Transportation	$	6,996	$	7,358	$	7,107
Natural gas liquids	4,590		2,397		2,804
Sulfur services	3,276		3,080		2,850
Terminalling and storage	3,370		3,403		3,083
Indirect overhead allocation, net of reimbursement	14,692		16,648		16,778
	$	32,924	$	32,886	$	32,622

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Supplemental Balance Sheet Information (Tables)

12 Months Ended

Dec. 31, 2021

Balance Sheet Related Disclosures [Abstract]

Schedule of Intangible and Other Assets, Net

Components of "Intangibles and other assets, net" at December 31, 2021 and 2020 were as follows:

	2021		2020
Catalyst and turnaround costs	$	687	$	803
Other intangible assets	358		586
Other	1,153		1,416
	$	2,198	$	2,805

Schedule of Other Accrued Liabilities

Components of "Other accrued liabilities" at December 31, 2021 and 2020 were as follows:

	2021		2020
Accrued interest	$	15,135	$	16,104
Asset retirement obligations	261		1,692
Property and other taxes payable	4,631		4,869
Accrued payroll	2,973		3,244
Operating lease liabilities	6,600		7,529
Other	250		969
	$	29,850	$	34,407

Schedule of Asset Retirement Obligations

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

	Year Ended December 31,
	2021		2020
	(In thousands)
Beginning asset retirement obligations	$	8,759	$	8,936
Revisions to existing liabilities 1	—		918
Accretion expense	375		410
Liabilities settled	(62)		(1,505)
Ending asset retirement obligations	9,072		8,759
Current portion of asset retirement obligations 2	(261)		(1,692)
Long-term portion of asset retirement obligations 3	$	8,811	$	7,067

1 Several 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.

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

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

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2021

Debt Disclosure [Abstract]

Schedule of Long-Term Debt

At December 31, 2021 and 2020, long-term debt consisted of the following:

	2021		2020
$275,000 1 Credit facility at variable interest rate (5.00% 1 weighted average at December 31, 2021), due August 2023 4 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, net of unamortized debt issuance costs of $2,613 and $3,826, respectively 2	$	156,887	$	144,174
$400,000 Senior notes, 7.25% interest, net of unamortized debt issuance costs of $0 and $— respectively, including unamortized premium of $0 and $344, respectively, issued $250,000 February 2013 and $150,000 April 2014, $26,200 repurchased during 2015, $9,344 repurchased during 2020, and $335,666 refinanced as part of the August 2020 Exchange offer, $28,790 repaid at maturity in February 2021, unsecured 2,3,4,5	—		28,790
$53,750 Senior notes, due February 2024, 10.0% interest, net of unamortized debt issuance costs of $2,433 and $3,577, respectively 2,3	$	51,317	$	50,173
$291,970 Senior notes, due February 2025, 11.5% interest, net of unamortized debt issuance costs of $1,303 and $1,720, respectively 2,3	$	290,667	$	290,250
Total	498,871		513,387
Less: current portion	—		(28,790)
Total long-term debt, net of current portion	$	498,871	$	484,597
Current installments of finance lease obligations	$	280	$	2,707
Finance lease obligations	9		289
Total finance lease obligations	$	289	$	2,996

    1 Interest rate fluctuates based on LIBOR plus an applicable margin set on the date of each advance. The margin above LIBOR is set every three months. All amounts outstanding at December 31, 2021 were at LIBOR plus an applicable margin of 4.00%, with LIBOR having a floor of 1.00%. The applicable margin for revolving loans that are LIBOR loans currently ranges from 2.75% to 4.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 1.75% to 3.00%. The credit facility contains various covenants which limit the Partnership’s ability to make distributions; make certain investments and acquisitions; enter into certain agreements; incur indebtedness; sell assets; and make certain amendments to the Partnership's omnibus agreement with Martin Resource Management Corporation (the "Omnibus Agreement"). The credit facility was amended July 16, 2021 to, among other things, reduce the commitments thereunder from $300,000 to $275,000.

    2 The Partnership was in compliance with all debt covenants as of December 31, 2021.

3 The indentures for each of the outstanding senior notes 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.

4 On February 15, 2021, our 2021 Notes matured and we retired the outstanding balance of $28,790 using proceeds from our credit facility.

5 In March 2020, the Partnership repurchased on the open market an aggregate $9,344 of the 2021 Notes, resulting in a gain on retirement of $3,484.

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Partners' Capital (Deficit) (Tables)

12 Months Ended

Dec. 31, 2021

Equity [Abstract]

Reconciliation of Net Income to Partners Interest in Net Income

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

	Years Ended December 31,
	2021		2020		2019
Continuing operations:
Income (loss) from continuing operations	$	(211)	$	(6,771)	$	4,520
Less general partner’s interest in net income (loss):
Distributions payable on behalf of IDRs	—		—		—
Distributions payable on behalf of general partner interest	16		61		(20)
General partner interest in undistributed income (loss)	(20)		(196)		111
Less income (loss) allocable to unvested restricted units	—		(21)		(1)
Limited partners’ interest in net income (loss)	$	(207)	$	(6,615)	$	4,430

	Years Ended December 31,
	2021		2020		2019
Discontinued operations:
Loss from discontinued operations	$	—	$	—	$	(179,466)
Less general partner’s interest in net income (loss):
Distributions payable on behalf of IDRs	—		—		—
Distributions payable on behalf of general partner interest	—		—		806
General partner interest in undistributed loss	—		—		(4,396)
Less income allocable to unvested restricted units	—		—		42
Limited partners’ interest in net loss	$	—	$	—	$	(175,918)

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

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

	Years Ended December 31,
	2021	2020	2019
Basic weighted average limited partner units outstanding	38,689,041	38,656,559	38,658,881
Dilutive effect of restricted units issued	—	—	—
Total weighted average limited partner diluted units outstanding	38,689,041	38,656,559	38,658,881

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Unit Based Awards - Long-Term Incentive Plans (Tables)

12 Months Ended

Dec. 31, 2021

Share-based Payment Arrangement [Abstract]

Schedule of Compensation Costs Related to Unit Based Plan

Amounts recognized in operating expense and selling, general, and administrative expense in the consolidated financial statements with respect to these plans are as follows:

	For the Year Ended December 31,
	2021		2020		2019
Restricted unit awards
Employees	$	194	$	1,204	$	1,226
Non-employee directors	190		—		—
Phantom unit Awards
Employees	415		—		—
Non-employee directors	—		218		198
Total unit-based compensation expense	$	799	$	1,422	$	1,424

Summary of Restricted Unit Activity

A summary of the restricted unit activity for the year ended December 31, 2021 is provided below:

	Number of Units		Weighted Average Grant-Date Fair Value Per Unit
Non-vested, beginning of year	273,424		$	10.52
Granted (TBRU)	42,168		$	2.49
Vested	(117,280)		$	11.96
Forfeited	(83,436)		$	13.90
Non-Vested, end of year	114,876		$	3.65
Aggregate intrinsic value, end of year	$	306

Summary of Aggregate Intrinsic Value and Fair Value of Units Vested

A summary of the restricted units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) during the years ended December 31, 2021, 2020 and 2019 is provided below:

	For the Year Ended December 31,
	2021		2020		2019
Aggregate intrinsic value of units vested	$	257	$	151	$	1,351
Fair value of units vested	$	1,418	$	1,427	$	1,551

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2021

Income Tax Disclosure [Abstract]

Components of Income Tax Expense (Benefit)

The components of income tax expense (benefit) from operations for the years ended December 31, 2021, 2020 and 2019 are as follows:

	2021		2020		2019
Current:
Federal	$	455	$	(174)	$	174
State	493		741		366
	948		567		540
Deferred:
Federal	2,142		1,027		882
State	290		142		478
	2,432		1,169		1,360
Total income tax expense	$	3,380	$	1,736	$	1,900

Income Tax Reconciliation

The income tax expense from the Taxable Subsidiary operations for the years ended December 31, 2021 and 2020 differs from the "expected" tax expense (computed by applying the federal corporate rate of 21% to income before income taxes of the Taxable Subsidiary) as follows:

	2021		2020
"Expected" tax expense	$	2,223	$	361
Increase in income taxes resulting from:
State income taxes, net of federal income tax expense	382		327
Other non-deductible items	384		472
Other, net	91		108
Actual tax expense	$	3,080	$	1,268

Deferred Tax Assets and Liabilities

Significant components of deferred tax assets and liabilities at December 31, 2021 and 2020 are as follows:

	2021		2020
Deferred tax assets:
Bad debt reserves	$	26	$	59
Goodwill and intangibles	12,523		13,893
Employee benefits	57		244
Interest expense	—		—
Tax loss carryforwards	10,676		12,671
Other	129		251
Subtotal	23,411		27,118
Less: Valuation allowance	—		—
Total net deferred tax assets	23,411		27,118
Deferred tax liabilities:
Property and equipment	(3,590)		(4,861)
Operating leases	—		(4)
Other	—		—
Total deferred tax liabilities	(3,590)		(4,865)
Net deferred tax assets	$	19,821	$	22,253

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Business Segments (Tables)

12 Months Ended

Dec. 31, 2021

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

	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, 2021:
Terminalling and storage	$	185,629	$	(6,597)	$	179,032	$	28,210	$	10,785	$	9,582
Natural gas liquids	414,043		—		414,043		2,390		38,098		537
Sulfur services	145,042		—		145,042		10,432		32,972		7,813
Transportation	161,180		(16,866)		144,314		15,719		(8,446)		4,997
Indirect selling, general, and administrative	—		—		—		—		(16,129)		—
Total	$	905,894	$	(23,463)	$	882,431	$	56,751	$	57,280	$	22,929
Year Ended December 31, 2020:
Terminalling and storage	$	191,041	$	(6,877)	$	184,164	$	29,489	$	22,153	$	11,619
Natural gas liquids	247,484		(5)		247,479		2,456		22,104		395
Sulfur services	108,020		(13)		108,007		12,012		36,256		7,415
Transportation	150,285		(17,793)		132,492		17,505		(16,102)		7,348
Indirect selling, general, and administrative	—		—		—		—		(17,909)		—
Total	$	696,830	$	(24,688)	$	672,142	$	61,462	$	46,502	$	26,777
Year Ended December 31, 2019:
Terminalling and storage	$	216,313	$	(6,659)	$	209,654	$	30,952	$	16,732	$	12,987
Natural gas liquids	366,502		—		366,502		2,469		44,020		1,870
Sulfur services	111,340		—		111,340		11,332		22,721		14,853
Transportation	183,740		(24,118)		159,622		15,307		(7,388)		8,213
Indirect selling, general, and administrative	—		—		—		—		(17,981)		—
Total	$	877,895	$	(30,777)	$	847,118	$	60,060	$	58,104	$	37,923

Assets by Segment

The Partnership's assets by reportable segment as of December 31, 2021 and 2020 are as follows:

	2021		2020
Total assets:
Terminalling and storage	$	248,194	$	252,794
Natural gas liquids	78,483		80,737
Sulfur services	108,007		94,154
Transportation	145,177		151,953
Total assets	$	579,861	$	579,638

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Organization and Description of Business (Details) - segment		12 Months Ended
	Dec. 28, 2021	Dec. 31, 2021
Schedule of Equity Method Investments
Number of primary business lines		4
Martin Resource Management Corporation | Holdings
Schedule of Equity Method Investments
Interest acquired, percent	49.00%
Economic ownership percentage by parent	50.00%
Holdings | Martin Resource Management Corporation
Schedule of Equity Method Investments
Ownership percentage	100.00%	100.00%

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Significant Accounting Policies and Practices (Details) ft³ in Billions	12 Months Ended
	Dec. 31, 2021 USD ($) segment	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Jun. 28, 2019 USD ($) ft³
Goodwill and Other Intangibles
Number of reporting units | segment	4
Impairment of goodwill	$ 0	$ 0	$ 0
Impairment of intangible assets	0	0	0
Debt Issuance Costs
Debt issuance cost	592,000	3,781,000	4,406,000
Amortization of debt issuance costs	3,367,000	3,422,000	$ 4,041,000
Accumulated amortization of debt issuance costs	$ 26,022,000	$ 22,655,000
Minimum
Deferred Catalyst Costs
Catalyst, useful life (in months)	12 months
Deferred Turnaround Costs
Turnarounds, useful life (in months)	12 months
Maximum
Deferred Catalyst Costs
Catalyst, useful life (in months)	36 months
Deferred Turnaround Costs
Turnarounds, useful life (in months)	36 months
Natural Gas Storage Assets | Discontinued Operations, Disposed of by Sale
Accounting Policies
Natural gas storage (in cubic feet) | ft³				50
Proceeds from sale of assets				$ 210,067,000

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Acquisitions - Narrative (Details) $ in Thousands		12 Months Ended
	Jan. 02, 2019 USD ($) terminal	Dec. 31, 2021 USD ($)	Dec. 31, 2019 USD ($)
Business Acquisition
Excess purchase price over carrying value of acquired assets		$ 1,350	$ 102,393
Martin Transport Inc.
Business Acquisition
Number of terminals | terminal	24
MEH South Texas Terminals LLC
Business Acquisition
Excess purchase price over carrying value of acquired assets	$ 102,393

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Acquisitions - Purchase Price (Details) - Martin Transport Inc. - USD ($) $ in Thousands		3 Months Ended
	Jan. 02, 2019	Dec. 31, 2022
Consideration Transferred
Purchase price	$ 135,000
Plus: Working Capital Adjustment	2,795
Less: Finance lease obligations assumed	(11,682)
Cash consideration paid	126,113
Earn - out based on performance threshold	10,000
Decrease in earn-out	$ 6,666
Scenario, Forecast | Subsequent Event
Consideration Transferred
Proceeds from contingent consideration		$ 1,350

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Acquisitions - Martin Transport, Inc. Assets Acquired (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020	Jan. 02, 2019
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net
Goodwill	$ 16,823	$ 16,823
Martin Transport Inc.
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net
Accounts receivable, net			$ 11,724
Inventories			1,138
Due from affiliates			1,042
Other current assets			897
Property, plant and equipment, net			25,383
Goodwill			489
Other noncurrent assets			362
Current installments of finance lease obligations			(5,409)
Accounts payable			(2,564)
Due to affiliates			(482)
Other accrued liabilities			(2,588)
Finance lease obligations, net of current installments			(6,272)
Historical carrying value of assets acquired			$ 23,720

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DISCONTINUED OPERATIONS AND DIVESTITURES - Narrative (Details) - Discontinued Operations, Disposed of by Sale $ in Thousands, ft³ in Billions			12 Months Ended
	Dec. 22, 2020 USD ($)	Aug. 12, 2019 USD ($)	Dec. 31, 2019 USD ($)	Jun. 28, 2019 USD ($) ft³
Mega Lubricants
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Proceeds from sale of assets	$ 22,400
Gain on disposition	$ 10,101
East Texas Pipeline
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Proceeds from sale of assets		$ 17,500
Gain on disposition		$ 16,154
Natural Gas Storage Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Proceeds from sale of assets				$ 210,067
Gain on disposition			$ 178,781
Natural gas storage (in cubic feet) | ft³				50

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DISCONTINUED OPERATIONS AND DIVESTITURES - Discontinued Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disposal Group, Including Discontinued Operation, Income Statement Disclosures
Income (loss) from discontinued operations, net of income taxes	$ 0	$ 0	$ (179,466)
Natural Gas Storage Assets | Discontinued Operations, Disposed of by Sale
Disposal Group, Including Discontinued Operation, Income Statement Disclosures
Total revenues			22,836
Total costs and expenses and other, net, excluding depreciation and amortization			(15,360)
Depreciation and amortization			(8,161)
Other operating loss, net			(178,781)
Other, net			0
Income (loss) from discontinued operations before income taxes			(179,466)
Income tax expense			0
Income (loss) from discontinued operations, net of income taxes			(179,466)
Gain on disposition			$ 178,781

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Revenue - Disaggregation of Revenue (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disaggregation of Revenue
Total revenues		$ 882,431	$ 672,142	$ 847,118
Lubricant product sales
Disaggregation of Revenue
Total revenues	[1]	103,809	103,300	122,257
Throughput and storage
Disaggregation of Revenue
Total revenues	[1]	75,223	80,864	87,397
Sulfur services
Disaggregation of Revenue
Total revenues		11,799	11,659	11,434
Natural gas liquids product sales
Disaggregation of Revenue
Total revenues	[1]	414,043	247,479	366,502
Terminalling and storage segment
Disaggregation of Revenue
Total revenues		179,032	184,164	209,654
Terminalling and storage segment | Lubricant product sales
Disaggregation of Revenue
Total revenues		103,809	103,300	122,257
Terminalling and storage segment | Throughput and storage
Disaggregation of Revenue
Total revenues		75,223	80,864	87,397
Transportation segment
Disaggregation of Revenue
Total revenues		144,314	132,492	159,622
Transportation segment | Land transportation
Disaggregation of Revenue
Total revenues		111,611	88,652	98,895
Transportation segment | Inland transportation
Disaggregation of Revenue
Total revenues		29,536	40,507	54,834
Transportation segment | Offshore transportation
Disaggregation of Revenue
Total revenues		3,167	3,333	5,893
Sulfur service segment
Disaggregation of Revenue
Total revenues		145,042	108,007	111,340
Sulfur service segment | Sulfur product sales
Disaggregation of Revenue
Total revenues		32,416	24,176	30,135
Sulfur service segment | Fertilizer product sales
Disaggregation of Revenue
Total revenues		100,827	72,172	69,771
Sulfur service segment | Sulfur services
Disaggregation of Revenue
Total revenues		11,799	11,659	11,434
Natural gas liquids
Disaggregation of Revenue
Total revenues		414,043	247,479	366,502
Natural gas liquids | Natural gas liquids product sales
Disaggregation of Revenue
Total revenues		$ 414,043	$ 247,479	$ 366,502

[1] Related Party Transactions Included Above Year Ended December 31, 202120202019Revenues:   Terminalling and storage$62,677 $63,823 $71,733 Transportation20,046 21,997 24,243 Product sales479 317 931 Costs and expenses:   Cost of products sold: (excluding depreciation and amortization)   Sulfur services9,980 10,519 10,765           Terminalling and storage27,866 18,429 23,859 Expenses:   Operating expenses78,607 80,075 88,194 Selling, general and administrative32,924 32,886 32,622 

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Revenue - Estimated Revenue Expected to be Recognized in Future (Details) $ in Thousands	Dec. 31, 2021 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Revenue, remaining performance obligation	$ 549,026
Throughput and storage | Terminalling and storage
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Revenue, remaining performance obligation	470,878
Natural gas liquids | Natural gas liquids
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Revenue, remaining performance obligation	25,366
Sulfur product sales | Sulfur services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Revenue, remaining performance obligation	52,782
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Revenue, remaining performance obligation	$ 67,277
Revenue, remaining performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Throughput and storage | Terminalling and storage
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Revenue, remaining performance obligation	$ 43,527
Revenue, remaining performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Natural gas liquids | Natural gas liquids
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Revenue, remaining performance obligation	$ 6,047
Revenue, remaining performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Sulfur product sales | Sulfur services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Revenue, remaining performance obligation	$ 17,703
Revenue, remaining performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Revenue, remaining performance obligation	$ 64,385
Revenue, remaining performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Throughput and storage | Terminalling and storage
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Revenue, remaining performance obligation	$ 42,041
Revenue, remaining performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Natural gas liquids | Natural gas liquids
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Revenue, remaining performance obligation	$ 5,391
Revenue, remaining performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Sulfur product sales | Sulfur services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Revenue, remaining performance obligation	$ 16,953
Revenue, remaining performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Revenue, remaining performance obligation	$ 63,259
Revenue, remaining performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Throughput and storage | Terminalling and storage
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Revenue, remaining performance obligation	$ 43,360
Revenue, remaining performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Natural gas liquids | Natural gas liquids
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Revenue, remaining performance obligation	$ 5,406
Revenue, remaining performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Sulfur product sales | Sulfur services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Revenue, remaining performance obligation	$ 14,493
Revenue, remaining performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Revenue, remaining performance obligation	$ 52,208
Revenue, remaining performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Throughput and storage | Terminalling and storage
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Revenue, remaining performance obligation	$ 44,661
Revenue, remaining performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Natural gas liquids | Natural gas liquids
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Revenue, remaining performance obligation	$ 5,391
Revenue, remaining performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Sulfur product sales | Sulfur services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Revenue, remaining performance obligation	$ 2,156
Revenue, remaining performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Revenue, remaining performance obligation	$ 50,253
Revenue, remaining performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Throughput and storage | Terminalling and storage
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Revenue, remaining performance obligation	$ 45,940
Revenue, remaining performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Natural gas liquids | Natural gas liquids
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Revenue, remaining performance obligation	$ 3,131
Revenue, remaining performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Sulfur product sales | Sulfur services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Revenue, remaining performance obligation	$ 1,182
Revenue, remaining performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Revenue, remaining performance obligation	$ 251,644
Revenue, remaining performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Throughput and storage | Terminalling and storage
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Revenue, remaining performance obligation	$ 251,349
Revenue, remaining performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Natural gas liquids | Natural gas liquids
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Revenue, remaining performance obligation	$ 0
Revenue, remaining performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Sulfur product sales | Sulfur services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction
Revenue, remaining performance obligation	$ 295
Revenue, remaining performance obligation, expected timing of satisfaction	1 year

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Inventories (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Inventory Disclosure [Abstract]
Natural gas liquids	$ 20,034	$ 27,878
Sulfur	612	24
Fertilizer	13,005	10,854
Lubricants	23,876	11,002
Other	4,593	4,364
Inventories	$ 62,120	$ 54,122

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Property, Plant, and Equipment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment
Property, plant and equipment, at cost	$ 898,770	$ 889,108
Land
Property, Plant and Equipment
Property, plant and equipment, at cost	21,422	21,459
Improvements to land and buildings
Property, Plant and Equipment
Property, plant and equipment, at cost	$ 132,064	135,227
Improvements to land and buildings | Minimum
Property, Plant and Equipment
Depreciable lives (in years)	10 years
Improvements to land and buildings | Maximum
Property, Plant and Equipment
Depreciable lives (in years)	25 years
Storage equipment
Property, Plant and Equipment
Property, plant and equipment, at cost	$ 122,300	121,437
Storage equipment | Minimum
Property, Plant and Equipment
Depreciable lives (in years)	5 years
Storage equipment | Maximum
Property, Plant and Equipment
Depreciable lives (in years)	50 years
Marine vessels
Property, Plant and Equipment
Property, plant and equipment, at cost	$ 183,414	179,666
Marine vessels | Minimum
Property, Plant and Equipment
Depreciable lives (in years)	4 years
Marine vessels | Maximum
Property, Plant and Equipment
Depreciable lives (in years)	25 years
Operating plant and equipment
Property, Plant and Equipment
Property, plant and equipment, at cost	$ 360,122	356,293
Operating plant and equipment | Minimum
Property, Plant and Equipment
Depreciable lives (in years)	3 years
Operating plant and equipment | Maximum
Property, Plant and Equipment
Depreciable lives (in years)	50 years
Furniture, fixtures and other equipment
Property, Plant and Equipment
Property, plant and equipment, at cost	$ 13,727	14,209
Furniture, fixtures and other equipment | Minimum
Property, Plant and Equipment
Depreciable lives (in years)	3 years
Furniture, fixtures and other equipment | Maximum
Property, Plant and Equipment
Depreciable lives (in years)	20 years
Transportation equipment
Property, Plant and Equipment
Property, plant and equipment, at cost	$ 50,961	49,836
Transportation equipment | Minimum
Property, Plant and Equipment
Depreciable lives (in years)	3 years
Transportation equipment | Maximum
Property, Plant and Equipment
Depreciable lives (in years)	7 years
Construction in progress
Property, Plant and Equipment
Property, plant and equipment, at cost	$ 14,760	$ 10,981

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Property, Plant and Equipment - Narratives (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment
Depreciation expense	$ 52,289	$ 55,817	$ 53,856
Amortization of right-of-use assets	164	1,755	2,686
Property, plant and equipment, at cost	1,071	10,352
Finance Lease, Right-of-Use Asset, Accumulated Amortization	364	3,703
Additions to property, plant and equipment included in accounts payable	3,229	468	3,791
Capital leased assets, additions	$ 0	83	$ 1,308
Assets held for sale		700
Terminalling and storage
Property, Plant and Equipment
Impairment charge		3,052
Transportation
Property, Plant and Equipment
Impairment charge		$ 1,300

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Goodwill (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Goodwill
Carrying amount of goodwill	$ 16,823	$ 16,823
Terminalling and storage
Goodwill
Carrying amount of goodwill	10,985	10,985
Sulfur services
Goodwill
Carrying amount of goodwill	5,349	5,349
Transportation
Goodwill
Carrying amount of goodwill	$ 489	$ 489

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Leases - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Lessee, Lease, Description
Termination period ( in years)	1 year
Right-of-use assets	$ 21,861	$ 22,260
Non-cancelable revenue arrangements, future minimum revenues, 2022	17,093
Non-cancelable revenue arrangements, future minimum revenues, 2023	14,425
Non-cancelable revenue arrangements, future minimum revenues, 2024	14,425
Non-cancelable revenue arrangements, future minimum revenues, 2025	13,858
Non-cancelable revenue arrangements, future minimum revenues, 2026	8,173
Non-cancelable revenue arrangements, future minimum revenues, subsequent years	30,670
Land, Building and Equipment
Lessee, Lease, Description
Right-of-use assets	$ 1,184
Minimum
Lessee, Lease, Description
Remaining lease term (in years)	1 year
Minimum | Land, Building and Equipment
Lessee, Lease, Description
Operating lease term (years)	3 years
Maximum
Lessee, Lease, Description
Remaining lease term (in years)	15 years
Renewal term (in years)	5 years
Maximum | Land, Building and Equipment
Lessee, Lease, Description
Operating lease term (years)	5 years

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Leases - Lease Cost (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Operating lease cost	$ 9,266	$ 10,672	$ 10,805
Finance lease cost:
Amortization of right-of-use assets	164	1,755	2,686
Interest on lease liabilities	26	294	671
Short-term lease cost	10,290	13,187	13,756
Variable lease cost	115	109	92
Total lease cost	$ 19,861	$ 26,017	$ 28,010

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Leases - Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$ 19,678	$ 23,996	$ 24,526
Operating cash flows from finance leases	26	294	671
Financing cash flows from finance leases	2,707	4,562	5,514
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	7,668	7,779	9,122
Finance leases	$ 0	$ 83	$ 1,309

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Leases - Balance Sheet Information (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Operating Leases
Operating lease right-of-use assets	$ 21,861	$ 22,260
Current portion of operating lease liabilities included in "Other accrued liabilities"	6,600	7,529
Operating lease liabilities	15,704	15,181
Total operating lease liabilities	$ 22,304	$ 22,710
Operating Lease, Liability, Current, Statement of Financial Position	Other accrued liabilities	Other accrued liabilities
Finance Leases
Property, plant and equipment, at cost	$ 1,071	$ 10,352
Accumulated depreciation	(364)	(3,703)
Property, plant and equipment, net	707	6,649
Current installments of finance lease obligations	$ 280	$ 2,707
Finance Lease, Liability, Current, Statement of Financial Position	Current portion of long term debt and finance lease obligations	Current portion of long term debt and finance lease obligations
Finance lease obligations	$ 9	$ 289
Total finance lease obligations	$ 289	$ 2,996
Weighted Average Remaining Lease Term (years)
Operating leases	6 years 5 months 15 days	5 years 10 months 13 days
Finance leases	11 months 19 days	1 year 4 months 20 days
Weighted Average Discount Rate
Operating leases	4.96%	5.04%
Finance leases	5.74%	6.04%

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Leases - Future Minimum Lease Obligations (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Operating Leases
Year 1	$ 7,501
Year 2	4,672
Year 3	3,137
Year 4	2,460
Year 5	1,602
Thereafter	6,820
Total	26,192
Less amounts representing interest costs	(3,888)
Total lease liability	22,304	$ 22,710
Finance Leases
Year 1	289
Year 2	9
Year 3	0
Year 4	0
Year 5	0
Thereafter	0
Total	298
Less amounts representing interest costs	(9)
Total lease liability	$ 289	$ 2,996

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Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Recurring | Level 2 | Commodity derivative contracts, net
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Commodity derivative contracts, net	$ 0	$ (207)
Nonrecurring | Carrying Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Senior notes	341,984	369,213
Nonrecurring | Carrying Value | 2021 Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Senior notes	0	28,790
Nonrecurring | Carrying Value | 2024 Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Senior notes	51,317	50,173
Nonrecurring | Carrying Value | 2025 Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Senior notes	290,667	290,250
Nonrecurring | Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Senior notes	362,366	372,487
Nonrecurring | Fair Value | 2021 Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Senior notes	0	28,581
Nonrecurring | Fair Value | 2024 Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Senior notes	55,220	55,214
Nonrecurring | Fair Value | 2025 Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Senior notes	$ 307,146	$ 288,692

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Derivative Instruments and Hedging Activities - Narrative (Details) - bbl	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Commodity derivative contracts, net
Derivative [Line Items]
Notional quantity (in bbl)	0	137,000

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Derivative Instruments and Hedging Activities - Balance Sheet Derivatives (Details) - Commodity derivative contracts, net - Fair Value of Derivatives, Current - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Designated as Hedging Instrument
Derivatives, Fair Value
Derivative asset, fair value	$ 0	$ 0
Derivative liability, fair value	0	0
Not Designated as Hedging Instrument
Derivatives, Fair Value
Derivative asset, fair value	0	0
Derivative liability, fair value	$ 0	$ 207

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Derivative Instruments and Hedging Activities - Derivative Financial Instruments Designated as Cash Flow Hedges (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Amount recognized in AOCI after reclassification	$ 816	$ 0	$ 0
Designated as Hedging Instrument
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Amount of Gain (Loss) Reclassified from AOCI into Income	(3,768)	0
Amount recognized in AOCI after reclassification	816	0
Commodity derivative contracts, net | Designated as Hedging Instrument
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Amount of Gain (Loss) Recognized in AOCI	816	0
Commodity derivative contracts, net | Cost of products sold | Designated as Hedging Instrument
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Amount of Gain (Loss) Reclassified from AOCI into Income	$ (3,768)	$ 0

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Derivative Instruments and Hedging Activities - Effect of derivative instruments on the Consolidated Statement of Operations (Details) - Not Designated as Hedging Instrument - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Derivative Instruments, Gain (Loss)
Amount of Gain (Loss) Recognized in Income on Derivatives	$ (1,825)	$ (8,209)
Commodity contracts | Cost of products sold
Derivative Instruments, Gain (Loss)
Amount of Gain (Loss) Recognized in Income on Derivatives	$ (1,825)	$ (8,209)

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Related Party Transactions - Narrative (Details) - shares		12 Months Ended
	Dec. 28, 2021	Dec. 31, 2021
Martin Resource Management
Related Party Transaction
Number of shares owned (in shares)		6,114,532
Equity investment ownership percentage		15.80%
MMGP
Related Party Transaction
General partner interest percentage		2.00%
MMGP | Martin Resource Management
Related Party Transaction
General partner interest percentage		2.00%
Ownership percentage		15.80%
Holdings | Martin Resource Management Corporation
Related Party Transaction
Ownership percentage	100.00%	100.00%

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Related Party Transactions - Omnibus Agreement Narrative (Details) - Omnibus Agreement - Martin Resource Management - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Related Party Transaction
Noncompete restriction threshold	$ 5,000,000
Noncompete restriction ownership option opportunity threshold minimum	5,000,000
Noncompete restriction ownership option opportunity threshold minimum with equity limitation	$ 5,000,000
Equity limitation on ownership restriction percentage	20.00%
Approved Annual Reimbursements For Indirect Expenses	$ 14,386,000
Indirect expenses reimbursed	$ 14,386,000	$ 16,410,000	$ 16,657,000

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Related Party Transactions - Master Transportation Services Agreement (Details)	12 Months Ended
	Dec. 31, 2021
Master Transportation Services Agreement | Martin Resource Management
Related Party Transaction
Minimum term of written notice (in days)	30 days

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Related Party Transactions - Terminal Services Agreements (Details)	12 Months Ended
	Dec. 31, 2021
Terminal Services Agreements | Martin Resource Management
Related Party Transaction
Minimum term of written notice (in days)	60 days

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Related Party Transactions - Marine Agreements (Details) - Marine Transportation Agreement - Martin Resource Management	12 Months Ended
	Dec. 31, 2021
Related Party Transaction
Automatic consecutive term renewal (in years)	1 year
Minimum term of written notice (in days)	60 days

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Related Party Transactions - Other Agreements (Details) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2022 USD ($)	Dec. 31, 2021 USD ($) bbl_per_day	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Related Party Transaction
Operating cash flows from operating leases		$ 19,678	$ 23,996	$ 24,526
East Texas Mack | Ruben Martin
Related Party Transaction
Ownership interest		46.00%
Operating cash flows from operating leases		$ 1,089	650	875
Cross Tolling Agreement | Martin Resource Management
Related Party Transaction
Production minimum per day (in bbl) | bbl_per_day		6,500
Capital recovery fee reimbursement, expired			$ 2,586	$ 2,088
Scenario, Forecast | Cross Tolling Agreement | Martin Resource Management
Related Party Transaction
Annual revenue decrease from contract expiration	$ 2,145

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Related Party Transactions - Schedule of the impact of Related Party Transactions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating expenses:
Operating expenses	$ 78,607	$ 80,075	$ 88,194
Related Party
Revenues:
Revenue from related parties	83,202	86,137	96,907
Cost of products sold:
Costs of products sold	37,846	28,948	34,624
Operating expenses:
Operating expenses	78,607	80,075	88,194
Selling, general and administrative:
Selling, general and administrative	32,924	32,886	32,622
Throughput and storage | Related Party
Revenues:
Revenue from related parties	62,677	63,823	71,733
Transportation | Related Party
Revenues:
Revenue from related parties	20,046	21,997	24,243
Operating expenses:
Operating expenses	55,382	55,786	61,376
Selling, general and administrative:
Selling, general and administrative	6,996	7,358	7,107
Natural gas liquids | Related Party
Operating expenses:
Operating expenses	2,038	2,003	3,446
Selling, general and administrative:
Selling, general and administrative	4,590	2,397	2,804
Product sales | Related Party
Revenues:
Revenue from related parties	479	317	931
Sulfur services | Related Party
Revenues:
Revenue from related parties	109	60	54
Cost of products sold:
Costs of products sold	9,980	10,519	10,765
Operating expenses:
Operating expenses	4,411	4,489	4,810
Selling, general and administrative:
Selling, general and administrative	3,276	3,080	2,850
Terminalling and storage | Related Party
Revenues:
Revenue from related parties	370	257	877
Cost of products sold:
Costs of products sold	27,866	18,429	23,859
Operating expenses:
Operating expenses	16,776	17,797	18,562
Selling, general and administrative:
Selling, general and administrative	3,370	3,403	3,083
Indirect overhead allocation, net of reimbursement | Related Party
Selling, general and administrative:
Selling, general and administrative	$ 14,692	$ 16,648	$ 16,778

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Supplemental Balance Sheet Information - Other Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Balance Sheet Related Disclosures [Abstract]
Catalyst and turnaround costs	$ 687	$ 803
Other intangible assets	358	586
Other	1,153	1,416
Intangible and other assets, net	$ 2,198	$ 2,805

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Supplemental Balance Sheet Information - Other Intangible Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Balance Sheet Related Disclosures [Abstract]
Amortization of intangible assets	$ 4,085	$ 5,235	$ 5,797
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity
2022	4,403
2023	661
2024	266
2025	84
2026	1
Subsequent years	$ 0

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Supplemental Balance Sheet Information - Other Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Balance Sheet Related Disclosures [Abstract]
Accrued interest	$ 15,135	$ 16,104
Asset retirement obligations	261	1,692
Property and other taxes payable	4,631	4,869
Accrued payroll	2,973	3,244
Operating lease liabilities	6,600	7,529
Other	250	969
Total other accrued liabilities	$ 29,850	$ 34,407

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Supplemental Balance Sheet Information - Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligation, Roll Forward Analysis
Beginning asset retirement obligations	$ 8,759	$ 8,936
Revisions to existing liabilities	0	918
Accretion expense	375	410
Liabilities settled	(62)	(1,505)
Ending asset retirement obligations	9,072	8,759
Current portion of asset retirement obligations	(261)	(1,692)
Long-term portion of asset retirement obligations	$ 8,811	$ 7,067

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Long-Term Debt (Details) - USD ($)	1 Months Ended			12 Months Ended
	Feb. 28, 2021	Aug. 31, 2020	Mar. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Jul. 16, 2021	Jul. 15, 2021	Dec. 31, 2016	Apr. 30, 2014	Feb. 28, 2013
Debt Instrument
Repayments of long-term debt				$ 333,790,000	$ 333,637,000	$ 724,000,000
Total long-term debt				498,871,000	513,387,000
Less: current portion				0	(28,790,000)
Total long-term debt, net of current portion				498,871,000	484,597,000
Current installments of finance lease obligations				280,000	2,707,000
Finance lease obligations				9,000	289,000
Total finance lease obligations				$ 289,000	2,996,000
Applicable margins (percent)				4.00%
Gain on retirement of senior unsecured notes				$ 0	3,484,000	$ 0
Revolving Loan Facility
Debt Instrument
Maximum borrowing capacity				$ 275,000,000			$ 275,000,000	$ 300,000,000
Weighted average interest rate				5.00%
Unamortized debt issuance costs				$ 2,613,000	3,826,000
Total long-term debt				$ 156,887,000	144,174,000
Revolving Loan Facility | LIBOR
Debt Instrument
Interest rate floor (percent)				1.00%
Revolving Loan Facility | Minimum | LIBOR
Debt Instrument
Applicable margins (percent)				2.75%
Revolving Loan Facility | Minimum | Prime Rate
Debt Instrument
Applicable margins (percent)				1.75%
Revolving Loan Facility | Maximum | LIBOR
Debt Instrument
Applicable margins (percent)				4.00%
Revolving Loan Facility | Maximum | Prime Rate
Debt Instrument
Applicable margins (percent)				3.00%
Senior Notes | Senior Notes 7.250%
Debt Instrument
Unamortized debt issuance costs				$ 0	0
Face amount				$ 400,000,000						$ 150,000,000	$ 250,000,000
Fixed rate cost				7.25%
Unamortized premium				$ 0	344,000
Amount of debt repurchased			$ 9,344,000	9,344,000					$ 26,200,000
Debt refinanced		$ 335,666,000
Repayments of long-term debt	$ 28,790,000
Total long-term debt				0	28,790,000
Gain on retirement of senior unsecured notes			$ 3,484,000
Senior Notes | 2024 Notes
Debt Instrument
Unamortized debt issuance costs				2,433,000	3,577,000
Face amount				$ 53,750,000
Fixed rate cost				10.00%
Total long-term debt				$ 51,317,000	50,173,000
Senior Notes | 2025 Notes
Debt Instrument
Unamortized debt issuance costs				1,303,000	1,720,000
Face amount				$ 291,970,000
Fixed rate cost				11.50%
Total long-term debt				$ 290,667,000	$ 290,250,000

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Long-Term Debt - Narratives (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Debt Disclosure [Abstract]
Cash paid for interest	$ 51,708	$ 37,678	$ 48,025
Capitalized interest	$ 0	$ 43	$ 5

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Partners' Capital (Deficit) - Narrative (Details)	12 Months Ended
	Dec. 31, 2021 shares
Limited Partners' Capital Account
Common limited partner units (in shares)	38,802,750
Martin Resource Management
Limited Partners' Capital Account
Common limited partner units (in shares)	6,114,532
MMGP
Limited Partners' Capital Account
General partner interest percentage	2.00%
MMGP | Martin Resource Management
Limited Partners' Capital Account
Ownership percentage	15.80%
General partner interest percentage	2.00%
Martin Resource Management Corporation
Limited Partners' Capital Account
Ownership percentage	98.00%

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Partners' Capital (Deficit) - Impact on Partners' Capital (Deficit) Related to Transactions Between Entities Under Common Control (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Limited Partners' Capital Account
Cash distributions	$ 791	$ 5,317	$ 49,093
Martin Resource Management Corporation | Martin Resource Management Corporation
Limited Partners' Capital Account
Purchase price	552,123
Cash distributions	$ 289,084

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Partners' Capital (Deficit) - Incentive Distribution Rights (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Martin Midstream GP LLC
Limited Partners' Capital Account
Distributions payable on behalf of IDRs	$ 0	$ 0	$ 0
MMGP
Limited Partners' Capital Account
General partner interest percentage	2.00%
MMGP | Martin Midstream GP LLC
Limited Partners' Capital Account
General partner interest percentage	2.00%

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Partners' Capital (Deficit) - Distributions of Available Cash (Details)	12 Months Ended
	Dec. 31, 2021
Equity [Abstract]
Distribution period (in days)	45 days

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Partners' Capital (Deficit) - Reconciliation of net income to partners interest in net income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Reconciliation of Net Income from Continuing and Discontinued Operations
Income (loss) from continuing operations	$ (211)	$ (6,771)	$ 4,520
Loss from discontinued operations	0	0	(179,466)
Less general partner’s interest in net income (loss):
Less income (loss) allocable to unvested restricted units	0	21	(41)
Limited partners' interest in net loss	$ (207)	$ (6,615)	$ (171,488)
Basic weighted average limited partner units outstanding (in shares)	38,689,041	38,656,559	38,658,881
Dilutive effect of restricted units issued (in shares)	0	0	0
Total weighted average limited partner diluted units outstanding (in shares)	38,689,041	38,656,559	38,658,881
Continuing operations:
Reconciliation of Net Income from Continuing and Discontinued Operations
Income (loss) from continuing operations	$ (211)	$ (6,771)	$ 4,520
Less general partner’s interest in net income (loss):
Distributions payable on behalf of IDRs	0	0	0
Distributions payable on behalf of general partner interest	16	61	(20)
General partner interest in undistributed income (loss)	(20)	(196)	111
Less income (loss) allocable to unvested restricted units	0	(21)	(1)
Limited partners' interest in net loss	(207)	(6,615)	4,430
Discontinued operations:
Reconciliation of Net Income from Continuing and Discontinued Operations
Loss from discontinued operations	0	0	(179,466)
Less general partner’s interest in net income (loss):
Distributions payable on behalf of IDRs	0	0	0
Distributions payable on behalf of general partner interest	0	0	806
General partner interest in undistributed income (loss)	0	0	(4,396)
Less income (loss) allocable to unvested restricted units	0	0	42
Limited partners' interest in net loss	$ 0	$ 0	$ (175,918)

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Unit Based Awards - Long-Term Incentive Plans - Schedule of compensation costs relate to unit based plan (Details) - Selling, General and Administrative Expense - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award
Total unit-based compensation expense	$ 799	$ 1,422	$ 1,424
Employees | Restricted unit awards
Share-based Compensation Arrangement by Share-based Payment Award
Total unit-based compensation expense	194	1,204	1,226
Employees | Phantom unit Awards
Share-based Compensation Arrangement by Share-based Payment Award
Total unit-based compensation expense	415	0	0
Non-employee directors | Restricted unit awards
Share-based Compensation Arrangement by Share-based Payment Award
Total unit-based compensation expense	190	0	0
Non-employee directors | Phantom unit Awards
Share-based Compensation Arrangement by Share-based Payment Award
Total unit-based compensation expense	$ 0	$ 218	$ 198

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Unit Based Awards - Long-Term Incentive Plans - Narrative (Details) $ in Thousands								12 Months Ended
	Jan. 24, 2025 shares	Jan. 24, 2024 shares	Jan. 24, 2023 shares	Jan. 24, 2022 shares	Jul. 21, 2021 shares	Feb. 22, 2021 director shares	Mar. 01, 2018 shares	Dec. 31, 2021 USD ($) shares	May 26, 2017 shares
Share-based Compensation Arrangement by Share-based Payment Award
Number of shares authorized (in shares)									3,000,000
Phantom unit Awards
Share-based Compensation Arrangement by Share-based Payment Award
Trading days					20 days
Compensation costs not yet recognized | $								$ 1,233
Weighted average period for recognition (in years)								2 years 6 months 21 days
Phantom unit Awards | Employees
Share-based Compensation Arrangement by Share-based Payment Award
Issuance of performance-based restricted units (in shares)					620,000
Phantom Units Appreciation Rights | Employees
Share-based Compensation Arrangement by Share-based Payment Award
Issuance of performance-based restricted units (in shares)					1,245,000
Restricted unit awards
Share-based Compensation Arrangement by Share-based Payment Award
Number of units vested (in shares)								117,280
Restricted unit awards | Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award
Vesting period (in years)								4 years
Time Based Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award
Issuance of performance-based restricted units (in shares)								42,168
Compensation costs not yet recognized | $								$ 248
Weighted average period for recognition (in years)								2 years 1 month 13 days
Vesting period (in years)								3 years
Number of directors receiving grants | director						3
Time Based Restricted Units | Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award
Issuance of performance-based restricted units (in shares)						14,056
Time Based Restricted Units | Employees
Share-based Compensation Arrangement by Share-based Payment Award
Issuance of performance-based restricted units (in shares)							301,550
Performance Based Restricted Units
Share-based Compensation Arrangement by Share-based Payment Award
Vesting period (in years)								3 years
Performance Based Restricted Units | Employees
Share-based Compensation Arrangement by Share-based Payment Award
Issuance of performance-based restricted units (in shares)							317,925
Scenario, Forecast | Time Based Restricted Units | Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award
Number of units vested (in shares)	3,514	3,514	3,514	3,514

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Unit Based Awards - Long-Term Incentive Plans - Summary of restricted unit activity (Details) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2021 USD ($) $ / shares shares
Restricted unit awards
Number of Units
Non-vested, beginning of period, numbers of units (in shares) | shares	273,424
Vested, number of units (in shares) | shares	(117,280)
Forfeited, number of units (in shares) | shares	(83,436)
Non-vested, end of period, number of units (in shares) | shares	114,876
Weighted Average Grant-Date Fair Value Per Unit
Non-vested, beginning of period, weighted average grant-date fair value per unit (in dollars per share) | $ / shares	$ 10.52
Vested, weighted average grant-date fair value per unit (in dollars per share) | $ / shares	11.96
Forfeited, weighted average grant-date fair value per unit (in dollars per share) | $ / shares	13.90
Non-vested, end of period, weighted average grant-date fair value per unit (in dollars per share) | $ / shares	$ 3.65
Aggregate intrinsic value, end of year | $	$ 306
Time Based Restricted Units
Number of Units
Issuance of performance-based restricted units (in shares) | shares	42,168
Weighted Average Grant-Date Fair Value Per Unit
Granted, weighted average grant-date fair value per unit (in dollars per share) | $ / shares	$ 2.49

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Unit Based Awards - Long-Term Incentive Plans - Summary of aggregate intrinsic value and fair value of units vested (Details) - Restricted unit awards - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award
Aggregate intrinsic value of units vested	$ 257	$ 151	$ 1,351
Fair value of units vested	$ 1,418	$ 1,427	$ 1,551

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Income Taxes - Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Current:
Federal	$ 455	$ (174)	$ 174
State	493	741	366
Total current income tax expense	948	567	540
Deferred:
Federal	2,142	1,027	882
State	290	142	478
Total deferred income tax expense (benefit)	2,432	1,169	1,360
Total income tax expense	$ 3,380	$ 1,736	$ 1,900

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Income Taxes - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating Loss Carryforwards
Income Tax Expense (Benefit)	$ 3,380	$ 1,736	$ 1,900
Cash paid for income taxes	1,232	416	515
Income taxes payable	385	556
Difference between partnership's tax basis and reported amounts	91,893	88,526
State
Operating Loss Carryforwards
Income taxes payable	304	455
MTI
Operating Loss Carryforwards
Income Tax Expense (Benefit)	3,080	1,268
Net operating loss carryforwards	67,681
Net operating loss carryforwards, subject to expiration	19,379
Net operating loss carryforwards, not subject to expiration	48,302
MTI | State
Operating Loss Carryforwards
Income taxes refundable	81	101
MTI | Federal
Operating Loss Carryforwards
Income taxes refundable	70	0
Texas
Operating Loss Carryforwards
State income taxes	$ 300	$ 468	$ 458

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Income Taxes - Income Tax Reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Increase in income taxes resulting from:
Total income tax expense	$ 3,380	$ 1,736	$ 1,900
MTI
Operating Loss Carryforwards
"Expected" tax expense	2,223	361
Increase in income taxes resulting from:
State income taxes, net of federal income tax expense	382	327
Other non-deductible items	384	472
Other, net	91	108
Total income tax expense	$ 3,080	$ 1,268

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Income Taxes - Deferred Income Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Deferred tax assets:
Bad debt reserves	$ 26	$ 59
Goodwill and intangibles	12,523	13,893
Employee benefits	57	244
Interest expense	0	0
Tax loss carryforwards	10,676	12,671
Other	129	251
Subtotal	23,411	27,118
Less: Valuation allowance	0	0
Total net deferred tax assets	23,411	27,118
Deferred tax liabilities:
Property and equipment	(3,590)	(4,861)
Operating leases	0	(4)
Other	0	0
Total deferred tax liabilities	(3,590)	(4,865)
Net deferred tax assets	$ 19,821	$ 22,253

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Business Segments - Narratives (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2021 USD ($) segment	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Business Acquisition
Number of reporting units | segment	4
Total revenues	$ 882,431	$ 672,142	$ 847,118
Natural gas liquids
Business Acquisition
Total revenues	414,043	247,479	366,502
One customers | Revenue | Customer concentration risk | Natural gas liquids
Business Acquisition
Total revenues	$ 140,324	$ 74,722	$ 112,280

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Business Segments - Income Statement (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information
Total revenues	$ 882,431	$ 672,142	$ 847,118
Depreciation and Amortization	56,751	61,462	60,060
Operating Income (Loss) after Eliminations	57,280	46,502	58,104
Capital Expenditures and Plant Turnaround Costs	22,929	26,777	37,923
Operating Revenues
Segment Reporting Information
Total revenues	905,894	696,830	877,895
Intersegment Eliminations
Segment Reporting Information
Total revenues	(23,463)	(24,688)	(30,777)
Indirect selling, general, and administrative
Segment Reporting Information
Depreciation and Amortization	0	0	0
Operating Income (Loss) after Eliminations	(16,129)	(17,909)	(17,981)
Capital Expenditures and Plant Turnaround Costs	0	0	0
Terminalling and storage
Segment Reporting Information
Total revenues	179,032	184,164	209,654
Depreciation and Amortization	28,210	29,489	30,952
Operating Income (Loss) after Eliminations	10,785	22,153	16,732
Capital Expenditures and Plant Turnaround Costs	9,582	11,619	12,987
Terminalling and storage | Operating Revenues
Segment Reporting Information
Total revenues	185,629	191,041	216,313
Terminalling and storage | Intersegment Eliminations
Segment Reporting Information
Total revenues	(6,597)	(6,877)	(6,659)
Natural gas liquids
Segment Reporting Information
Total revenues	414,043	247,479	366,502
Depreciation and Amortization	2,390	2,456	2,469
Operating Income (Loss) after Eliminations	38,098	22,104	44,020
Capital Expenditures and Plant Turnaround Costs	537	395	1,870
Natural gas liquids | Operating Revenues
Segment Reporting Information
Total revenues	414,043	247,484	366,502
Natural gas liquids | Intersegment Eliminations
Segment Reporting Information
Total revenues	0	(5)	0
Sulfur services
Segment Reporting Information
Total revenues	145,042	108,007	111,340
Depreciation and Amortization	10,432	12,012	11,332
Operating Income (Loss) after Eliminations	32,972	36,256	22,721
Capital Expenditures and Plant Turnaround Costs	7,813	7,415	14,853
Sulfur services | Operating Revenues
Segment Reporting Information
Total revenues	145,042	108,020	111,340
Sulfur services | Intersegment Eliminations
Segment Reporting Information
Total revenues	0	(13)	0
Transportation
Segment Reporting Information
Total revenues	144,314	132,492	159,622
Depreciation and Amortization	15,719	17,505	15,307
Operating Income (Loss) after Eliminations	(8,446)	(16,102)	(7,388)
Capital Expenditures and Plant Turnaround Costs	4,997	7,348	8,213
Transportation | Operating Revenues
Segment Reporting Information
Total revenues	161,180	150,285	183,740
Transportation | Intersegment Eliminations
Segment Reporting Information
Total revenues	$ (16,866)	$ (17,793)	$ (24,118)

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Business Segments - Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Total assets:
Total assets	$ 579,861	$ 579,638
Terminalling and storage
Total assets:
Total assets	248,194	252,794
Natural gas liquids
Total assets:
Total assets	78,483	80,737
Sulfur services
Total assets:
Total assets	108,007	94,154
Transportation
Total assets:
Total assets	$ 145,177	$ 151,953

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Subsequent Events (Details) - Subsequent Event	Jan. 25, 2022 $ / shares
Subsequent Event
Dividends declared (in dollars per share)	$ 0.005
Annualized dividends declared (in dollars per share)	$ 0.02