UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
FORM 10-K
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| Mark One | Annual Report Pursuant to Section 13 or 15(d) of the | |
ý☒ | Securities Exchange Act of 1934 | |
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| For the fiscal year ended | December 31, 2018 | 2020 |
OR
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o�� | Transition Report Pursuant to Section 13 or 15(d) of the | |
| Securities Exchange Act of 1934 | |
For the transition period from _____ to _____.
Commission file number 000-50056
MARTIN MIDSTREAM PARTNERS L.P.
(Exact name of registrant as specified in its charter)
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| 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:
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| 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 |
mmlpSecurities Registered Pursuant to Section 12(g) of the Act:
NONE
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes o☐ No ý☒
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes o☐ No ý☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements the past 90 days.
Yes ý☒ No o☐
Indicate by check mark whether the Registrant has submitted electronically, 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 ý☒ No o☐
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of "large accelerated filer," "accelerated filer", "smaller reporting company", and "emerging growth company" in Rule 12b-2 of the Exchange Act.
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Large accelerated filer o | ☐ | Accelerated filerx | ☐ |
Non-accelerated filer o | ☒ | Smaller reporting company | o☐ |
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Emerging growth companyo | ☐ | | |
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 o☐ No ý☒
As of June 30, 2018, 39,052,2372020, 38,852,507 common units were outstanding. The aggregate market value of the common units held by non-affiliates of the registrant as of such date approximated $454,540,329$37,935,739 based on the closing sale price on that date. There were 39,049,181 38,893,342of the registrant’s common units outstanding as of February 19, 2019.March 3, 2021.
DOCUMENTS INCORPORATED BY REFERENCE: None.
TABLE OF CONTENTS
TABLE OF CONTENTS
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| PART I | | |
| Item 1. | Business | |
| Item 1A. | Risk Factors | |
| Item 1B. | Unresolved Staff Comments | |
| Item 2. | Properties | |
| Item 3. | Legal Proceedings | |
| Item 4. | Mine Safety Disclosures | |
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| PART II | |
| Item 5. | Market for Our Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities | |
| Item 6. | Selected Financial Data | |
| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
| Item 7A. | Quantitative and Qualitative Disclosures about Market Risk | |
| Item 8. | Financial Statements and Supplementary Data | |
| Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | |
| Item 9A. | Controls and Procedures | |
| Item 9B. | Other Information | |
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| PART III | |
| Item 10. | Directors, Executive Officers and Corporate Governance | |
| Item 11. | Executive Compensation | |
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | |
| Item 13. | Certain Relationships and Related Transactions, and Director Independence | |
Item 14. | Principal Accounting Fees and Services | |
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| PART IV | | |
| Item 15. | Exhibits, Financial Statement Schedules | |
| Item 16. | Form 10-K Summary | |
PART I
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'sManagement 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"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.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 in the United States ("U.S.") Gulf Coast region. Our four primary business lines include:
Natural gas liquids transportation•Terminalling, processing, storage and distribution services and natural gas storage;
Terminalling and storagepackaging services for petroleum products and by-products, including the refining of naphthenic crude oiloil;
•Land and the blending and packaging of finished lubricants;
Sulfur and sulfur-based products gathering, processing, marketing, manufacturing and distribution; and
Marinemarine transportation services for petroleum products and by-products.by-products, chemicals, and specialty products;
The petroleum•Sulfur and sulfur-based products processing, manufacturing, marketing, and by-products we collect, transport, storedistribution; and market are produced primarily by
•Natural gas liquids ("NGL") marketing, distribution, and transportation services.
Our vertically integrated services have created longstanding relationships with a diversified customer base that includes major and independent oil and gas companies, who often turn to third parties, such as us, for the transportation and disposition of these products. In addition to these major and independent oil and gas companies, our primary customers include independent refiners, large chemical companies, fertilizer manufacturers and other wholesale purchasers of these products. We operate primarily incertain petroleum products and by-products, with significant business concentrated around the U.S. Gulf Coast region. This regionrefinery 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.
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 revenues 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, 2018,2020, Martin Resource Management Corporation owned 15.7% of our total outstanding common limited partner units. Furthermore, Martin Resource Management Corporation controls Martin Midstream GP LLC ("MMGP"), our general partner, by virtue of its 51% voting interest in MMGP Holdings, LLC ("Holdings"), the sole member of MMGP. MMGP owns a 2%2.0% general partner interest in us and all of our incentive distribution rights. Martin Resource Management Corporation directs our business operations through its ownership interests in and control of our general partner.
We entered into an omnibus agreement dated November 1, 2002, with Martin Resource Management 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’sManagement 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 its inception in 2002. Martin Resource Management Corporation began operating our natural gas servicesNGL 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. Over the last 10 years, Martin Resource Management has increased the size of our asset base through expansions and strategic acquisitions.
Primary Business Segments
Our primary business segments can be generally described as follows:
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• | •Terminalling and Storage. We own or operate 17 marine shore-based terminal facilities and 13 specialty terminal facilities located primarily in the U.S. Gulf Coast region 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. We own or operate 19 marine shore-based terminal facilities and 14 specialty terminal facilities located primarily in the U.S. Gulf Coast region that provide storage, refining, blending, packaging, and handling services for producers and suppliers of petroleum products and by-products, including the refining of naphthenic crude oil and the blending and packaging of various grades and quantities of industrial, commercial, and automotive lubricants and greases. Our facilities and resources provide us with the ability to handle various products that require specialized treatment, such as molten sulfur and asphalt. We also provide land rental to oil and gas companies along with storage and handling services for lubricants and fuels. We provide these terminalling and storage services on a fee basis primarily under long-term contracts. A significant portion of the contracts in this segment provide for minimum fee arrangements that are not based on the volumes handled. |
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• | Natural Gas Services. We distribute natural gas liquids ("NGLs"). We purchase NGLs primarily from refineries and natural gas processors. We store and transport NGLs for wholesale deliveries to refineries, industrial NGL users in Texas and the Southeastern U.S, and propane retailers. We own an NGL pipeline, which spans approximately 200 miles from Kilgore, Texas to Beaumont, Texas. We own approximately 2.4 million barrels of underground storage capacity for NGLs. Additionally, we own 100% of the interests in Cardinal Gas Storage Partners LLC ("Cardinal"), which is focused on the operation and management of natural gas storage facilities across northern Louisiana and Mississippi.
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• | Sulfur Services. We have developed an integrated system of transportation assets and facilities relating to sulfur services. We process and distribute sulfur produced by oil refineries primarily located in the U.S. Gulf Coast region. We buy and sell molten sulfur on contracts that are tied to sulfur indices and tend to provide stable margins. We process molten sulfur into prilled or pelletized sulfur at our facilities in Port of Stockton, California and Beaumont, Texas on contracts that often provide guaranteed minimum fees. The sulfur we process and handle is primarily used in the production of fertilizers and industrial chemicals. We own and operate five sulfur-based fertilizer production plants and one emulsified sulfur blending plant that manufactures primarily sulfur-based fertilizer products for wholesale distributors and industrial users. These plants are located in Texas and Illinois. Demand for our sulfur products exist in both the domestic and foreign markets, and our asset base provides additional opportunities to handle increases in U.S. supply and access to foreign demand.
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• | Marine Transportation. We operate a fleet of 31 inland marine tank barges, 17 inland push boats and one offshore tug and barge unit that transport petroleum products and by-products largely in the U.S. Gulf Coast region. We provide these transportation services on a fee basis primarily under annual contracts, and many of our customers have long standing contractual relationships with us. Our modernized asset base is attractive both to our existing customers as well as potential new customers. In addition, our fleet contains several vessels that reflect our focus on specialty products.
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•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 560 trucks and 1,150 tank trailers which are based across 23 terminals strategically located throughout the U.S. Gulf Coast and southeastern United States. Our marine transportation assets include 31 inland marine tank barges, 14 inland push boats and one articulated offshore tug and barge unit that operate coastwise along the Gulf of Mexico and east coast and on the U.S. inland waterway system, primarily between domestic ports along the Gulf of Mexico, 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 liquefied petroleum gas ("LPG"), molten sulfur, sulfuric acid, paper mill liquids, chemicals, dry bulk 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 fleet contains several vessels that reflect our focus on specialty products.
•Sulfur Services. We own 21 railcars and lease 27 railcars equipped to transport molten sulfur and we lease 131 railcars to transport our fertilizer products. We have developed an integrated system of transportation assets and facilities relating to sulfur services. We process and distribute sulfur produced by oil refineries primarily located in the U.S. Gulf Coast region. We 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 Recent Developments
Martin Transport Inc. Stock Purchase Agreement.
Sale of Mega Lubricants
On OctoberDecember 22, 2018,2020, we entered into a stockan asset purchase and sale agreement (the “Stock Purchase Agreement”to sell certain assets used in connection with our Mega Lubricants shore-based terminals business ("Mega Lubricants") with Martin Resource Management to acquire allJohn W. Stone Oil Distributor, LLC ("Stone Oil") for $22.4 million. Mega Lubricants is engaged in the business of the issuedblending, manufacturing and outstanding equity of Martin Transport, Inc. (“MTI”), a wholly-owned subsidiary of Martin Resource Management which operates a fleet of tank trucks providing transportation of petroleum products, liquid petroleum gas, chemicals, sulfurdelivering various marine application lubricants, sub-sea specialty fluids, and other products, as well as owns twenty-three terminals located throughout the Gulf Coastproprietary commercial and Midwest for total consideration of $135.0 million with a $10.0 million earn-out based on certain performance thresholds. Additionally, a post-closing working capital adjustment was finalized on January 28, 2019 which included additional consideration paid to Martin Resource Management of $2.2 million.industrial products. The Stock Purchase Agreement contained customary representations and warranties. Martin Resource Management has owned and operated MTI or its predecessor for over 40 years and MTI is integral to our routine movements of sulfur and NGL’s. Based on operational estimates and current transportation market conditions, this drop-down from our general partner will provide strategic long-term growth for the Partnership. This transaction closed January 2, 2019 and was effective as of January 1, 2019. As of January 1, 2019, Martin Resource Management will no longer provide land transportation services.
Divestiture of WTLPG Partnership Interest. On July 31, 2018, we completed the sale of our 20 percent non-operating interest in West Texas LPG Pipeline L.P. ("WTLPG") to ONEOK, Inc. (“ONEOK”). WTLPG owns an approximate 2,300 mile common-carrier pipeline system that primarily transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. A wholly-owned subsidiary of ONEOK, Inc. is the operator of the assets. In consideration of the sale of these assets, we received cash proceeds of $195.0 million at closing, before transaction fees and expenses.on December 22, 2020. The proceeds from the saletransaction were used to reduce outstanding borrowings under our revolving credit facility.
Credit Facility Amendment.
On February 21, 2018,August 12, 2020, (the "Settlement Date") we amendedsuccessfully completed our revolving credit facilityexchange offer (the "Exchange Offer") and consent solicitation to certain eligible holders of our 7.25% senior unsecured notes due 2021 ("2021 Notes") and separate but related cash tender offer and consent solicitation to certain other holders of our 2021 Notes. Please see Note 15 in orderPart II of this Form 10-K for more information about the Exchange Offer and related transactions.
COVID-19
A novel strain of coronavirus ("COVID-19") surfaced in late 2019 and has spread around the world, including to achieve two primary objectives, the firstUnited States. In March 2020, the World Health Organization declared COVID-19 a pandemic.
The Partnership continues to prioritize the health and safety of our employees, the businesses we serve, and the communities where we live and work. To support the safety of all of our employees and operations, precautionary measures were implemented to prevent the COVID-19 virus from spreading in our workplace or the locations we serve, including suspending non-essential travel, limiting the number of employees attending meetings, reducing the number of people at our locations at any one time, monitoring the health of all employees, and implementing work-from-home initiatives for all eligible employees. Further, we continue to provide awareness training for all of our drivers, vessel crews, blending operators and other affected personnel regarding preventative measures in or around our docks, vessels, and trucks and locations to which was to accommodate growth capital expenditures necessarythey are delivering. Our communication lines are open 24/7 for the previously announced WTLPG expansion project. Startingenvironmental health and safety division, land and marine logistics, and sales and marketing teams.
Due to the economic impacts of the COVID-19 pandemic, 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 2018,2020 and global storage considerations. Travel restrictions and stay-at-home orders implemented by governments in many regions and countries across the amendment provided short-term (5 quarters) covenant reliefglobe, including the United States, have greatly impacted the demand for refined products resulting in a significant reduction in refinery utilization, which has impacted our 2020 performance. This impact started in February of 2020 and
continued through the end of the year, during which time we have seen 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 increasingrefineries has been reduced, demand for our services has decreased.
Looking forward, we expect to continue to experience some adverse impacts of COVID-19 in our transportation segment during the total leverage ratiofirst half of 2021 but we believe that refinery utilization will continue to 5.75 to 1.00 (first and second quarters of 2018) with step downs to 5.50 to 1.00 (third and fourth quarters of 2018 and first quarter of 2019) and to 5.25 to 1.00 beginningincrease in the second quarterhalf of 2019. Additionally,2021 as a result of widespread vaccinations, government stimulus, and a rebounding economy. This should ultimately improve refined product demand as people get back to work and begin traveling again. We expect this will positively impact our transportation segment as demand for our services improves.
The extent to which the facility was amended to establish an inventory financing sublimit tranche for borrowings related to our NGL (butane) marketing business, which is a part ofduration and not in addition to the already existing commitments under the revolving credit facility. This sublimit is not to exceed $75.0 million, with seasonal step downs to $10.0 million for the months of March through June of each fiscal year. The sublimit is subject to a monthly borrowing base not to exceed 90%severity of the valuepandemic impacts our business, results of forward sold/hedged inventory. In conjunction withoperations, and financial condition, will depend on future developments, which are highly uncertain and cannot be predicted at this time. Accordingly, the salefull impact of WTLPGCOVID-19 will not be reflected in our results of operations and overall financial performance until future periods. Management also assessed the extent to which the current macroeconomic events brought about by COVID-19 and significant declines in refined product demand impacted the valuation of expected credit losses on Julyaccounts 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, 2018, we amended our revolving credit facility which included, among other things, further revising our leverage covenants from the February 21, 2018 amendment (discussed in detail above). Total Indebtedness to EBITDA and Senior Secured Indebtedness to EBITDA (each as defined in the credit agreement) was amended to 5.25 times and 3.50 times, respectively. No changes were made to the Consolidated Interest Coverage Ratio (as defined in the credit agreement) of 2.50 times. 2020.
Subsequent Events
Retirement of 2021 Notes. On February 15, 2021, our 2021 Notes matured and we retired the outstanding balance of $28.8 million using our revolving credit facility.
Quarterly Distribution. On January 17, 2019,25, 2021, we declared a quarterly cash distribution of $0.50$0.005 per common unit for the fourth quarter of 2018,2020, or $2.00$0.02 per common unit on an annualized basis, which will bewas paid on February 14, 201912, 2021 to unitholders of record as of February 7, 2019.5, 2021.
Our Growth Strategy
The key components of our growth strategy are:
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• | Pursue Organic Growth Projects. We continually evaluate economically attractive organic expansion opportunities in existing areas of operation that will allow us to leverage our existing market position and increase the distributable cash flow from our existing assets through improved utilization and efficiency.
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• | Pursue Internal Organic Growth by Attracting New Customers and Expanding Services Provided to Existing Customers. Opportunities exist to expand our customer base and provide additional services and products to existing customers. We generally begin a relationship with a customer by transporting, storing or marketing a limited range of products and services. Expanding our customer base and our service and product offerings to existing customers is an efficient and cost effective method of achieving organic growth in revenues and cash flow.
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• | Pursue Strategic Acquisitions. We continually monitor the marketplace to identify and pursue accretive acquisitions that expand the services and products we offer or that expand our geographic presence. After acquiring other businesses, we attempt to utilize our industry knowledge, network of customers and suppliers and strategic asset base to operate the acquired businesses more efficiently and competitively, thereby increasing revenues and cash flow. Our diversified base of operations provides multiple platforms for strategic growth through acquisitions.
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• | Pursue Strategic Commercial Alliances. Many of our larger customers, which include major integrated energy companies, have established strategic alliances with midstream service providers such as us to address logistical and transportation problems or achieve operational synergies. We intend to pursue strategic commercial alliances with such customers in the future.
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Competitive Strengths
•Fee-Based ContractsPursue 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.
•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.
•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.
Competitive Strengths
We believe we are well positioned to execute our business strategy because of the following competitive strengths:
Fee-Based Contracts. We generate a majoritysignificant amount of our cash flow from fee-based contracts with our customers.customers, many of which are major and independent oil and gas companies with whom we have longstanding customer relationships. A significant portion
majority of theour 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 Base and Integrated Distribution Network.Operational Footprint. We own and operate a diversified asset base that enables us to offer our customers an integrated distribution network consisting of transportation, terminalling, storage, packaging and storage andother midstream logistical services for petroleum products and by-products.by-products in one of the world’s most active refining and petrochemical regions.
Strategically Located AssetsAssets. .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, weour land transportation assets are onebased out of the largest operators of marine service shore-based terminals inlocated to serve refineries and chemical companies across the U.S. Gulf Coast region providing broad geographic coverage and distribution capability of our products and services to our customers. Our natural gas storage and NGL distribution and storage assets are located in areas highly desirable for our customers. Finally, manyCoast. Many of our sulfur services assets are strategically located to source sulfur from the largest refinery sources in the United States. 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.Facilities. We have the assets and expertise to handle and transport certainan 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 ranging between(between approximately -30 to +400 degrees FahrenheitFahrenheit) to remain in liquid form, which our facilities are designed to accommodate. These capabilities help us enhance relationships with our customers by offering them services to handle their unique product requirements.
Strong Industry Reputation and Established Relationships with Suppliers and Customers.Customers. We have established a reputation in our industry as a reliable and cost-effective supplier of services to our customers and have a track record of safe, efficient operation of our facilities. Our management has also established long-term relationships with many of our suppliers and customers. We benefit from our management'smanagement’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.
Experienced Management Team and Operational Expertise. Members of our executive management team and the heads of our principal business lines have a significant amount of experience in the industries in which we operate. Our management team has a successful track record of creating internal growth and completing acquisitions. Our management team's experience and familiarity with our industry and businesses are important assets that assist us in implementing our business strategies. 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, 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 U.S. Gulf Coast region is a major hub for petroleum refining. Approximately 50% of U.S. refining capacity exists in this region. Growth in the refining and natural gas processing industries has increased the volume of petroleum products and by-products that are transported within the U.S. Gulf Coast region, which consequently has increased the need for terminalling and storage services.
The marine and offshore oil and gas exploration and production industries use terminal facilities in the U.S. Gulf Coast region as shore bases that provide them logistical support services as well as provide a broad range of products, including fuel oil,
lubricants, chemicals and supplies. The demand for these types of terminals, services and products is driven primarily by offshore exploration, development and production in the Gulf of Mexico. Offshore activity is greatly influenced by current and projected prices of oil and natural gas.gas and regulatory requirements.
Specialty Petroleum Terminals. We own or operate 1213 terminalling facilities providing storage, handling and transportation of various petroleum products and by-products.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 both acquisition andprimarily organic growth.
At the Neches, Stanolind, and StanolindTampa terminals, our customers are primarily energy orand petrochemical companies. In addition, Martin Resource Management Corporation pays us for terminalling and storage of asphalt at our Tampa facility 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 and terminal where we process crude oil into finished products that include naphthenic lubricants, distillates, asphalt and other intermediates. This process is dedicated to an affiliatea 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 processingproduction, packaging and packagingdistribution of automotive, commercial and industrial greases.
In Houston, Texas, we own and operate a plant that specializes in the processingproduction and packagingdistribution of post tensioncommercial and industrial greases. In Phoenix, Arizona, we lease and operate a plant that specializes in the production and distribution of commercial and industrial greases.
InWe own asphalt terminals in each of Hondo, South Houston, and Port Neches, Texas we own an asphalt terminal whose use isand Omaha, Nebraska, each dedicated to an affiliatea subsidiary of Martin Resource Management Corporation through a terminalling service agreement based on throughput rates.
In South Houston, Texas, we own an asphalt terminal whose use is dedicated to an affiliate of Martin Resource Management through a terminalling service agreement based on throughput rates.
In Port Neches, Texas, we own an asphalt terminal whose use is dedicated to an affiliate of Martin Resource Management through a terminalling service agreement based upon throughput rates.
In Omaha, Nebraska, we own an asphalt terminal whose use is dedicated to an affiliate of Martin Resource Management through a terminalling service agreement based on throughput rates.
In Beaumont, Texas, we own a terminal where we receive natural gasoline via pipeline and then ship the product to our customers via other pipelines to which the facility is connected, referred to as the "Spindletop Terminal." Our fees for the use of this facility are based on the volume of barrels shipped from the terminal.
The following is a summary description of our shore-based specialty terminals:
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| Terminal | | Location | | Aggregate Capacity (in barrels) | | Products | | Description |
| Tampa (1) | | Tampa, Florida | | 719,000662,000 | | Asphalt, crude oil, and fuel oildiesel | | Marine terminal, loading/unloading for vessels, barges, railcars and trucks |
| Stanolind | | Beaumont, Texas | | 593,000619,000 | | 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 | | 548,000551,000 | | Molten sulfur, formed sulfur, ammonia, asphalt, fuel oil, crude oil and sulfur-based fertilizer | | Marine terminal, loading/unloading for vessels, barges, railcars and trucks |
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(1) | This terminal is located on land owned by the Tampa Port Authority that was leased to us under a 10-year lease that expires in December 2021. This lease may be extended at the option of the tenant for one option period of five years. |
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(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. |
(1)This terminal is located on land owned by the Tampa Port Authority that was leased to us under a 10-year lease that expires in December 2021. This lease may be extended at the option of the tenant for one option period of five years.
(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.
The following is a summary description of our non shore-based specialty terminals:
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| 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 | | Crude refining facility |
| Martin Lubricants | | Smackover, Arkansas | | 3.94.0 million gallons bulk storage | | Agricultural, automotive, and industrial lubricants and grease | | Lubricants packaging facility |
Martin LubricantsSpecialty Products (1) | | Kansas City, Missouri | | 0.2 million gallons of bulk storage | | Automotive, commercial and industrial greases | | Grease manufacturing and packaging facility |
Martin LubricantsSpecialty Products | | Houston, Texas | | 0.2 million gallons of bulk storage | | Post tensionCommercial and industrial greases | | Grease manufacturing and packaging facility |
| Martin Specialty Products (2) | | Phoenix, Arizona | | 0.1 million gallons of bulk storage | | 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 | | 24,00017,500 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 |
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(1) | This terminal contains a warehouse owned by third parties and leased under a lease that expires in December 2020 and can be extended by us for two successive five-year periods. |
(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 1917 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 U.S. Gulf Coast region. These terminals are used to distribute and market fuel and lubricants. Additionally, full service terminals also provide shore bases for companies that are operating in the offshore exploration and production industry. Customers are primarily oil and gas exploration and production companies and oilfield service companies, such as drilling fluid companies, marine transportation companies and offshore construction companies. Shore bases typically provide logistical support, including the storing and handling of tubular goods, loading and unloading bulk materials, providing facilities from which major and independent oil companies can communicate with and control offshore operations and leasing dockside facilities to companies which provide complementary products and services such as drilling fluids and cementing services. We generate revenues from our terminals that have shore bases by fees that we charge our customers under land rental contracts for the use of our terminal facility for these shore bases. These contracts generally provide us a fixed land rental fee and additional rental fees that are determined based on a percentage of the sales value of the products and services delivered from the shore base. In addition, Martin Resource Management 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 6four full service terminals. These facilities provide logistical support services and storage and handling services for fuel and lubricants. The significant difference between our full service terminals and our fuel and lubricant terminals is that our full service terminals generate additional revenues by providing shore bases to support our customer’s operating activities related to the offshore exploration and production industry. One typical use for our shore bases is for drilling fluids manufacturers to manufacture and sell drilling fluids to the offshore drilling industry. Offshore drilling companies may also set up service facilities at these terminals to support their offshore operations. Customers of our full service terminals are primarily oil and gas exploration and production companies, oilfield service companies such as drilling fluids companies, marine transportation companies and offshore construction companies.
The following is a summary description of our full service terminals:
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| Terminal | | Location | | Aggregate Capacity (barrels) | | End of Lease (Including Options) |
AmeliaFourchon 15 | | Amelia,Fourchon, Louisiana | | 13,0007,600 | | August 2023February 2047 |
Fourchon 15 | | Fourchon, Louisiana | | 7,600 | | February 2047 |
| Harbor Island (1) | | Harbor Island,Port Aransas, Texas | | 6,800 | | December 2039 |
Intracoastal City 2 (2)Pelican Island | | Intracoastal City, LouisianaGalveston, Texas | | 17,70087,600 | | December 2025Own |
Pelican IslandTheodore | | Galveston, Texas | | 87,600 | | Own |
Theodore | | Theodore, Alabama | | 19,900 | | Own |
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(1) | A portion of this terminal is owned. |
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(2) | This terminal is currently in caretaker status. |
(1)A portion of this terminal is owned.
Fuel and Lubricant Terminals. We own or operate 13 lubricantfuel and fuellubricant terminals located in the U.S. Gulf Coast region that provide storage and handling services for lubricants and fuel oil.
The following is a summary description of our fuel and lubricant terminals at: |
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| Terminal | | Location | | Aggregate Capacity (barrels) | | End of Lease (Including Options) |
Dulac (1)Amelia | | Dulac,Amelia, Louisiana | | 15,40013,000 | | December 2041August 2023 |
| Dulac (1) | | Dulac, Louisiana | | — | | December 2041 |
| Dock 193 (3) | | Gueydan, Louisiana | | 11,000 | | May 20202022 |
| Fourchon | | Fourchon, Louisiana | | 80,900 | | May 2027 |
| Fourchon 16 | | Fourchon, Louisiana | | 16,400 | | July 2048 |
| Galveston T (2) | | Galveston, Texas | | 1,400 | | Own |
| Intracoastal City (2) | | Intracoastal City, Louisiana | | — | | Own |
| Jennings Bulk Plant | | Jennings, Louisiana | | 9,100 | | Own |
Channelview | | Houston, Texas | | 39,800 | | 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)(3) | | Sabine Pass, Texas | | 16,700 | | September 2036 |
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(1) | This terminal is currently in caretaker status and the lease will not be renewed at the end of the current option. |
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(2) | These terminals are currently in caretaker status. |
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(3) | A portion of this terminal is owned. |
(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 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.
Natural Gas ServicesTransportation 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 560 trucks and 1,150 tank trailers that transport petroleum products and by-products, petrochemicals, and chemicals. Our land transportation assets operate out of 23 strategically located terminals throughout the U.S. Gulf Coast and Southeastern United States.
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 MTI’s land transportation fleet or by contracting with common carriers, owner-operators and railroad tank cars. We typically enter into annual contracts with independent retail propane distributors to deliver their estimated annual volume requirements based on prevailing market prices. Dependable delivery is very important to these customers and in some cases may be more important than price. We ensure adequate supply of NGLs through:
storage of NGLs ;
efficient use of railroad tank cars
the transportation fleet of vehicles owned by MTI; and
product management expertise to obtain supplies when needed.
The following is a summary descriptionlisting of our owned NGL facilities:terminals utilized in our land transportation business: |
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NGL Facility | | Location | | Capacity | | Description |
Wholesale terminals | | Arcadia, Louisiana | | 2,400,000 barrels | | Underground storage |
Retail terminals | | Kilgore, Texas | | 90,000 gallons | | Retail propane distribution |
| | Longview, Texas | | 30,000 gallons | | Retail propane distribution |
| | Henderson, Texas | | 12,000 gallons | | Retail propane distribution |
Rail terminal | | Arcadia, Louisiana | | 24 railcars per day | | NGL railcar loading and unloading capabilities |
In addition to the owned NGL facilities above, we lease underground storage capacity at four locations under short-term lease agreements.
Our NGL customers consist of refiners, industrial processors and retail propane distributors. The majority of our NGL volumes are sold to refiners and industrial processors.
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. The primary components of competition related to our natural gas storage operations are location, rates, terms and flexibility of service and supply. Our natural gas storage facilities compete with other storage providers and increased competition could result from newly developed storage facilities or expanded capacity from existing competitors.
Natural Gas Storage
Natural gas storage facilities provide a staging and warehousing function for seasonal swings in demand relative to supply, as well as an essential reliability cushion against disruptions in natural gas supply, demand and transportation by allowing natural gas to be injected into, withdrawn from or warehoused in such storage facilities as dictated by market conditions. The long term demand for storage services in the U.S. is driven primarily by the long-term demand for natural gas and the overall lack of balance between the supply of and demand for natural gas on a seasonal, monthly, daily or other basis. In general and on a long-term basis, to the extent the overall demand for natural gas increases and such growth includes higher demand from seasonal or weather-sensitive end-users (such as gas-fired power generators and residential and commercial consumers), demand for natural gas storage services should also grow. In addition, any factors that contribute to more frequent and severe imbalances between the supply of and demand for natural gas, whether caused by supply or demand fluctuations, should increase the need for and the value of storage services. On a short term basis, storage demand and values are also significantly influenced by operational imbalances, near term seasonal spreads, shorter term spreads and basis differentials.
We own 100% of the interests in Cardinal, which is focused on the operation and management of natural gas storage facilities across northern Louisiana and Mississippi.
Cardinal facilities are summarized below:
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Facility Name / Location | | Facility Type | | Working Storage Capacity | | Percent of Capacity Contracted (1) | | Weighted Average Life of Remaining Contract TermTerminal Locations |
Arcadia Gas Storage, LLC Bienville Parish, LouisianaTexas | Louisiana | Salt domeArkansas | | 15.25 billion cubic feet (bcf) | | 100% | | 2.2 yearsOther |
Cadeville Gas Storage, LLC Ouachita Parish, LouisianaBaytown | Arcadia | Depleted reservoirMarion | | 17.0 bcf | | 100% | | 4.4 yearsTheodore, Alabama |
Perryville Gas Storage, LLC Franklin Parish, LouisianaBeaumont | Baton Rouge | Salt domeSmackover | | 11.85 bcf | | 74% | | 2.2 yearsTampa, Florida |
Monroe Gas Storage Company, LLC Monroe County, Beaumont Lube | Bossier City | Stephens | Hattiesburg, Mississippi |
| Channelview | Jennings | Depleted reservoir | Kenova, West Virginia |
| Corpus Christi | 6.7 bcfLake Charles | Tennessee | 100% |
| Kilgore | Reserve | 3.0 yearsChattanooga | |
| Longview | | Kingsport | |
| Plainview | | | |
(1) Contracted capacity refers specificallyOur 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 firm contracteda 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. These rates 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.
These facilities were developed to provide producers, end users, local distribution companies, pipelines and energy marketers with high-deliverability storage services and hub services.
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 U.S. Gulf Coast region is a major hub for petroleum refining. The petroleum refining process generates products and by-products that require transportation in large quantities from the refinery or processor. Convenient access to and use of this waterway system by the petroleum and petrochemical industry is a major reason for the current location of U.S. refineries and petrochemical facilities. The marine transportation industry uses push boats and tugboats as power sources and tank barges for freight capacity. The combination of the power source and tank barge freight capacity is called a tow.
Marine Fleet. We utilize a fleet of inland and offshore tows that provide marine transportation of petroleum products and by-products produced in oil refining. Our marine transportation business operates coastwise along the Gulf of Mexico and east coast of the United States, 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 | | 26 | | 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. InSulfur demand in the U.S., approximately 9 generally averages 8.5 million to 9.5 million tons annually, and is concentrated around large phosphate fertilizer operations primarily located in the southeastern parts of sulfur are consumed annually with the Tampa, Florida area being the largest single market.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.United States.
Sulfur is an importanthas long been recognized as essential for plant nutrient and is primarily used in the manufacture of phosphate fertilizersanimal 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 make phosphoric acid, the base material for most high-grademanufacture 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 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 the Port of Stockton, California and Beaumont, Texas, which are used to convert molten sulfur into solid form (prills/granules). The Stockton facility is equipped with one wet prill unit capable of processing 1,000 metric tons of molten sulfur per day. The Beaumont facility is equipped with two wet prill units and one granulation unit capable of processing a combined 5,500 metric tons of molten sulfur per day. Formed sulfur at both facilities is stored in bulk until sold into local or international agricultural markets. Our forming services contracts are fee based and typically include minimum fee guarantees.
Our sulfuric acid production facility at our Plainview, Texas location processes molten sulfur to produce a dedicated supply of raw material sulfuric acid to our ammonium sulfate production plant. The ammonium sulfate plant produces approximately 400 tons per day of quality ammonium sulfate and is marketed to our customers throughout the U.S. The sulfuric acid produced and not consumed by the captive ammonium sulfate production is sold to third parties.
Fertilizer and related sulfur products are a natural extension of our molten sulfur business because of our access to sulfur and our distribution capabilities.
In the U.S., fertilizer is generally sold to farmers through local dealers. These dealers are typically owned and supplied by much larger wholesale distributors. We sell to these wholesale distributors. Our industrial sulfur products are marketed primarily in the southern U.S., where many paper manufacturers and power plants are located. Our products are sold in accordance with price lists that vary from state to state. These price lists are updated periodically to reflect changes in seasonal or competitive prices. We transport our fertilizer and industrial sulfur products to our customers using third-party common carriers. We utilize 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:
•Plant nutrient sulfur products. We produce plant nutrient and agricultural ground sulfur products at our facilities in Odessa, Texas, Seneca, Illinois and Cactus, Texas. Our plant nutrient sulfur product is a 90% degradable sulfur product marketed under the Disper-Sul® trade name and sold throughout the U.S. to direct application agricultural markets.
•Ammonium sulfate products. We produce various grades of ammonium sulfate including granular, coarse, standard, and 40% ammonium sulfate solution. These products primarily serve direct application agricultural markets. We package these custom grade products under both proprietary and private labels and sell them to major retail distributors and other retail customers.
•Sulfuric acid. Our sulfuric acid production facility at our Plainview, Texas location processes molten sulfur to produce a dedicated supply of raw material sulfuric acid to our ammonium sulfate production plant. The ammonium sulfate plant produces approximately 400 tons per day of quality ammonium sulfate and is marketed to our customers throughout the U.S. The sulfuric acid produced and not consumed by the captive ammonium sulfate production is sold to third parties.
•Industrial sulfur products. We produce industrial sulfur products such as elemental pastille sulfur, industrial ground sulfur products, and emulsified sulfur. We produce elemental pastille sulfur at our Odessa, Texas and Seneca, Illinois facilities. Elemental pastille sulfur is used to increase the efficiency of the coal-fired precipitators in the power industry. These industrial ground sulfur products are also used in a variety of dusting and wettable
sulfur applications such as rubber manufacturing, fungicides, sugar and animal feeds. We produce emulsified sulfur at our Nash, Texas facility. Emulsified sulfur is primarily used to control the sulfur content in the pulp and paper manufacturing processes.
•Liquid sulfur products. We produce ammonium thiosulfate at our Neches terminal facility in Beaumont, Texas. This agricultural sulfur product is a clear liquid containing 12% nitrogen and 26% sulfur. This product serves as a liquid plant nutrient used directly through spray rigs or irrigation systems. It is also blended with other nitrogen phosphorus potassium liquids or suspensions as well. Our market is predominantly the Mid-South U.S. and Coastal Bend area of Texas.
Our Sulfur Services Facilities. We own 2621 railcars and lease 4227 railcars equipped to transport molten sulfur. We own the following marine assets and use them to transport molten sulfur between U.S. Gulf Coast storage terminals (including our terminal in Beaumont, Texas) under third-party marine transportation agreements:
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Asset | | Class of Equipment | Number in Class | Capacity/Horsepower | | Products Transported |
Margaret Sue | | Offshore tank barge | 1 | 10,500 long tons | | Molten sulfur |
M/V Martin Explorer | | Offshore tugboat | 1 | 7,130 horsepower | | N/A |
M/V Martin Express | | Inland push boat | 1 | 1,200 horsepower | | N/A |
MGM 101 | | Inland tank barge | 2 | 2,500 long tons | | Molten sulfur |
MGM 102 | | Inland tank barge | | 2,500 long tons | | Molten sulfur |
We operate the following sulfur forming facilities as part of our sulfur services business:
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| Terminal | Location | Location | | Daily Production Capacity | | Products Stored |
| Neches | | Beaumont, Texas | | 5,500 metric tons per day | | Molten, prilled and granulated sulfur |
| Stockton | | Stockton, California | | 1,000 metric tons per day | | Molten and prilled sulfur |
We lease 132131 railcars to transport our fertilizer products. We own the following manufacturing plants as part of our sulfur services business:
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| Facility | Location | Location | | Annual Capacity | | Description |
| Fertilizer plant | | Plainview, Texas | | 150,000 tons | | Fertilizer production |
| Fertilizer plant | | Beaumont, Texas | | 110,000 tons | | Liquid sulfur fertilizer production |
| Fertilizer plants | | Odessa, Texas | | 35,000 tons | | Dry sulfur fertilizer production |
| Fertilizer plant | | Seneca, Illinois | | 36,000 tons | | Dry sulfur fertilizer production |
| Fertilizer plant | | Cactus, Texas | | 20,000 tons | | Dry sulfur fertilizer production |
| Industrial sulfur plant | | Nash, Texas | | 18,000 tons | | Emulsified sulfur production |
| Sulfuric acid plant | | Plainview, Texas | | 150,000 tons | | Sulfuric acid production |
Competition. The Martin Explorer/Margaret Sue articulated barge unit is one of four vessels currently used to transport molten sulfur between U.S. ports on the Gulf of Mexico and Tampa, Florida. Phosphate fertilizer manufacturers consume a majority of the sulfur produced in the U.S., which they purchase directly from both producers and resellers. As a reseller, we compete against producers and other resellers capable of accessing the required transportation and storage assets. Our sulfur-based fertilizer products compete with several large fertilizer and sulfur product manufacturers. However, the close proximity of our manufacturing plants to our customer base is a competitive advantage for us in the markets we serve and allows us to minimize freight costs and respond quickly to customer requests. Our sulfuric acid products compete with regional producers and importers in the South and Southwest portion of the U.S. from Louisiana to California.
Seasonality. Sales of our agricultural fertilizer products are partly seasonal as a result of increased demand during the growing season.
Marine TransportationNatural Gas Liquids Segment
Industry Overview.The inland waterway system 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 composedalmost entirely used as a petrochemical feedstock in the production of a network of interconnected riversethylene and canals that serve as water highways andpropylene. Propane is used to transport vast quantitiesas a petrochemical feedstock in the production of products annually. This waterway system extends approximately 26,000 miles,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 which 12,000 miles are generally considered significant formotor 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 commerce.
The Gulf Coast region is a major hub for petroleum refining. The petroleum refining process generates products and by-products that require transportation in large quantities from the refinery or processor. Convenient access to and use of this waterway system by the petroleum and petrochemical industry is a major reason for the current location of U.S. refineries and petrochemical facilities. The marine transportation industry uses push boats and tugboats as power sources and tank barges for freight capacity. The combination of the power source and tank barge freight capacity is called a tow.
Marine Fleet. We utilize a fleet of inland and offshore tows that provide marine transportation of petroleum products and by-products produced in oil refiningrefiners and natural gas processing. Our marine transportation business operates coastwise along the Gulf of Mexico and East Coast and on the U.S. inland waterway system, primarily between domestic ports along the Gulf of Mexico, Intracoastal Waterway, the Mississippi River system and the Tennessee-Tombigbee Waterway system. 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.processors. We transport asphalt, fuel oil, gasoline, sulfurNGLs using Martin Transport Inc.'s ("MTI") land transportation fleet or by contracting with common carriers, owner-operators and other bulk liquids.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;
•efficient use of railroad tank cars;
•the transportation fleet owned by MTI; and
•product management expertise to obtain supplies when needed.
The following is a summary description of the marine vessels we use in our marine transportation business (excluding equipment classified as Assets Held for Sale):owned NGL facilities: |
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Class of Equipment NGL Facility | Location | Number in Class Capacity | | Capacity/Horsepower | | Description of Products Carried |
Inland tank bargesWholesale terminals | Arcadia, Louisiana | 72,100,000 barrels | | Under 20,000 barrels | | Asphalt, crude oil, fuel oil, gasoline and sulfurUnderground storage |
Inland tank bargesRail terminal | Arcadia, Louisiana | 24 railcars per day | | 20,000 - 31,000 barrels | | Asphalt, crude oil, fuel oilNGL railcar loading and gasoline |
Inland push boats | | 17 | | 800 - 2,650 horsepower | | N/A |
Offshore tank barge | | 1 | | 59,000 barrels | | Diesel fuel |
Offshore tugboat | | 1 | | 5,100 horsepower | | N/Aunloading capabilities |
In addition to the owned NGL facilities above, we lease underground storage capacity at four locations under short-term lease agreements.
Our largest marine transportationNGL customers include majorconsist of refiners, industrial processors and independent oilretail propane distributors. The majority of our NGL volumes are sold to refiners and gas refining companies, petroleum marketing companiesindustrial processors.
Seasonality. The level of NGL supply and Martin Resource Management. We conduct our marine transportation servicesdemand 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 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 Managementprices. Abnormally cold weather can put extra upward pressure 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 terminatespropane prices during the agreement by giving written notice to the other party at least 60 days prior to the expiration of the then-applicable term.
winter.
Competition.We compete with large integrated NGL producers and marketers, as well as small local independent marketers, 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, qualityrespect to location, rates, terms and flexibility of service and the availability of a single source of supply of services.supply.
In addition to competitors that provide marine transportation services, we also compete with providers of other modes of transportation, such as rail, trucks and, to a lesser extent, pipelines. For example, a typical two inland barge unit carries a volume of product equal to approximately 80 railcars or 250 tanker trucks. Pipelines generally provide a less expensive form of transportation than marine transportation. However, pipelines are not able to transport most of the products we transport and are generally a less flexible form of transportation because they are limited to the fixed point-to-point distribution of commodities in high volumes over extended periods of time.
Our Relationship with Martin Resource Management Corporation
Martin Resource Management Corporation is engaged in the following principal business activities:
providing land transportation of various liquids using a fleet of trucks and road vehicles and road trailers (the Partnership acquired MTI effective January 1, 2019);
•distributing fuel oil, asphalt, marine fuel and other liquids;
•providing marine bunkering and other shore-based marine services in Texas, Louisiana, Mississippi, Alabama, and Florida;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;
operating an engineering services company;
•supplying employees and services for the operation of our business; and
•operating, solely for our account, the asphalt facilities in Omaha, Nebraska,each of Hondo, South Houston and Port Neches, Texas Hondo, Texas, and South Houston, Texas.Omaha, Nebraska.
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 15.7% of the outstanding limited partner units. In addition, Martin Resource Management Corporation controls MMGP, our general partner, by virtue of its 51% voting interest in Holdings, the sole member of MMGP. MMGP owns a 2% general partner interest in us and all of our incentive distribution rights.
Management
Martin Resource Management 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 $127.9$125.3 million, $129.5$138.7 million and $135.8$136.1 million of direct costs and expenses for the years ended December 31, 2018, 20172020, 2019 and 2016,2018, 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, 2020, 2019, and 2018, 2017, and 2016, the conflicts committeeboard of directors of our general partner ("Conflicts Committee") approved reimbursement amounts of $16.4 million, $16.4$16.7 million and $13.0$16.4 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committeeboard 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’sManagement 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 motor carriermaster transportation services agreement, marine transportation agreements, terminal services agreements, a tolling agreement, and a sulfuric acid sales agency agreement. Pursuant to the terms of the Omnibus Agreement, we are prohibited from entering into certain material agreements with Martin Resource Management Corporation without the approval of the conflicts committee of our general partner ("Conflicts Committee.Committee").
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. Our motor carrier agreement with Martin Resource Management provides us with access to Martin Resource Management’s fleet of road vehicles and road trailers to provide land transportation in the areas served by Martin Resource Management (the Partnership acquired MTI effective January 1, 2019). Our ability to utilize MTI’s land transportation operations is currently a key component of our integrated distribution network.
Corporation. In the aggregate, our purchases from Martin Resource Management Corporation accounted for approximately 9%19%, 8%17%, and 11%14% of our total cost of products soldcosts and expenses during for the years ended December 31, 2020, 2019 and 2018, 2017 and 2016, respectively. We also purchase marine fuel from Martin Resource Management, which we account for as an operating expense.
Correspondingly, Martin Resource Management Corporation is one of our significant customers. Our sales to Martin Resource Management Corporation accounted for approximately 10%13%, 11%, and 13%11% of our total revenues for each of the years ended December 31, 2020, 2019 and 2018, 2017 and 2016, respectively. We have entered into certain agreements with Martin Resource Management pursuant to which we provide terminalling and storage and marine transportation services to its subsidiary, Martin Energy Services LLC ("MES"), and MES provides terminal services to us to handle lubricants, greases and drilling fluids. Additionally, we have entered into a long-term, fee for services-based tolling agreement with Martin Resource Management where Martin Resource Management agrees to pay us for the processing of its crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts.
For a more comprehensive discussion concerning the Omnibus Agreement and the other agreements that we have entered into with Martin Resource Management 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.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 located at an individual location subject to anof affected properties. Excluding Neches Industrial Park, which has no minimum deductible, the overall minimum deductible ofranges from $1.0 million to $5.0 million for damage caused by the named windstorm at all locations excluding Neches Industrial Park.windstorm. Our onshore program currently provides $40.0 million per occurrence for named windstorm events. events, including business interruption coverage in connection with a named windstorm event and has a waiting period of 45 days.
For non-windstormnon-named windstorms or events, our deductible applicable to onshore physical damage deductible is $0.5 million per occurrence.occurrence for all properties. Business interruption coverage in connection with a non-named windstorm or event is subject to the same $40.0a $200.0 million per occurrence and aggregate limit as the property damage coverage and has a waiting period of 45 days. For non-windstorm events, our30 days, excluding the Smackover Refinery which has a waiting period applicable to business interruption is 30of 45 days.
We have various pollution liability policies which provide coverages ranging from remediation of our property to third party liability. The limits of these policies vary based on our assessments of exposure at each location.
Loss of, or damage to, our vessels and cargo is insured through hull and cargo insurance policies. Vessel operating liabilities such as collision, cargo, environmental and personal injury are insured primarily through our participation in mutual insurance associations and other reinsurance arrangements, pursuant to which we are potentially exposed to assessments in the event claims by us or other members exceed available funds and reinsurance. Protection and indemnity ("P&I") insurance coverage is provided by P&I associations and other insurance underwriters. Our vessels are entered in P&I associations that are parties to a pooling agreement, known as the International Group Pooling Agreement ("Pooling Agreement") through which approximately 90% of the world's ocean-going tonnage is reinsured through a group reinsurance policy. With regard to collision coverage, the first $1.0 million of coverage is insured by our hull policy and any excess is insured by a P&I association. We insure our owned cargo through a domestic insurance company. We insure cargo owned by third parties through our P&I coverage. As a member of P&I associations that are parties to the Pooling Agreement, we are subject to supplemental calls payable to the associations of which we are a member, based on our claims record and the other members of the other P&I associations that are parties to the Pooling Agreement. Except for our marine operations, we self-insure against liability exposure up to a predetermined amount, beyond which we are covered by catastrophe insurance coverage.
For marine claims, our insurance covers up to $1.0 billion of liability per accident or occurrence. We believe our current insurance coverage is adequate to protect us against most accident related risks involved in the conduct of our business. However, there can be no assurance that all risks are adequately insured against, that any particular claim will be paid by the insurer, or that we will be able to procure adequate insurance coverage at commercially reasonable rates in the future.
Environmental and Regulatory Matters
Our activities are subject to various federal, state and local laws and regulations, as well as orders of regulatory bodies, governing a wide variety of matters, including marketing, production, pricing, community right-to-know, protection of the environment, safety and other matters.
Environmental
We are subject to complex federal, state, and local environmental laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of human health, natural resources and the environment. These laws and regulations can impair our operations that affect the environment in many ways, such as requiring the acquisition of permits to conduct regulated activities; restricting the manner in which we can release materials into the environment; requiring remedial activities or capital expenditures to mitigate pollution from former or current operations; and imposing substantial liabilities on us for pollution resulting from our operations. Many environmental laws and regulations can impose joint and several, strict liability, and any failure to comply with environmental laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial obligations, and, in some circumstances, the issuance of injunctions that can limit or prohibit our operations.
The clearcontinuing 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 regulations. Nevertheless, a possibility exists that petroleum and other solid wastes may have been disposed of on or under various properties owned or leased by us during the operating history of those facilities. In addition, a number of these properties have been operated by third parties over whom we had no control as to such entities’ handling of petroleum, petroleum by-products or other wastes and the manner in which such substances may have been disposed of or released. State and federal laws and regulations applicable to oil and natural gas wastes and properties have gradually become more strict and, under such laws and regulations, we could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination, even under circumstances where such contamination resulted from past operations of third parties.
Clean Air Act
Our operations are subject to the federal Clean Air Act ("CAA"), as amended, and comparable state statutes. Amendments to theThe CAA adopted in 1990 containcontains provisions that may result in the imposition of increasingly stringent pollution control requirements with respect to air emissions from the operations of our terminal facilities, processing and storage facilities and fertilizer and related products manufacturing and processing facilities. Such air pollution control requirements may include specific equipment or technologies to control emissions, permits with emissions and operational limitations, pre-approval of new or modified projects or facilities producing air emissions, and similar measures. Failure to comply with applicable air statutes or regulations may lead to the assessment of administrative, civil or criminal penalties, and/or result in the limitation or cessation of construction or operation of certain air emission sources. We believe our operations, including our manufacturing, processing and storage facilities and terminals, are in substantial compliance with applicable requirements of the CAA and analogous state laws.
Global Warming and Climate Change. Recent scientificScientific studies have suggestedsuggest that emissions of certain gases, commonly referred to as "greenhouse gases"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 greenhouse gasGHG emissions. Many states have already taken legal measures to reduce emissions of greenhouse gases,GHGs, primarily through the planned development of greenhouse gasGHG emission inventories and/or regional greenhouse gasGHG cap and trade programs. Also,Additionally, as a result of the April 2007 U.S. Supreme Court’s decision on April 2, 2007,Court ruling in Massachusetts, et al. v. EPA, that the EPA eventually concluded that it is requiredhas authority to regulate greenhouse gascarbon dioxide emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court's holding in Massachusetts that greenhouse gases fall under the federal CAA's definitionCAA, the EPA has taken several steps towards implementing regulations regarding the emission of air pollutant has
also ledGHGs. 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 determine that regulationregulate GHG emissions under existing provisions of greenhouse gas emissions from stationary sources under various Clean Air Act programs is required. To that end, EPA promulgated regulations, referred to as the Tailoring Rule, 75 Fed. Red. 31514, to begin gradually subjecting stationary greenhouse gas emission sources to various Clean Air Act programs, including permitting programs applicable to new and existing major sources of greenhouse gas emissions. In reviewing the regulations at issue, the Supreme Court struck down EPA’s permitting requirements as applicable only to greenhouse gas emissions, although it upheld the EPA’s authority to control greenhouse gas emissions when a permit is required due to emissions of other pollutants.federal CAA.
On an international level, almost 200 nations agreed
Further, in December 2015, over 190 countries, including the United States, reached an agreement to an international climate change agreementreduce global GHG emissions ("Paris Agreement"). The Paris Agreement entered into force in Paris, France that calls forNovember 2016, after over 70 countries, including the United States, ratified or otherwise consented to set their own greenhouse gas emissions targets and be transparent aboutbound by the measures each country will use to achieve its emissions targets. Althoughagreement. In November 2020, the present administration has announced its intention to withdrawUnited States formally withdrew from the Paris accord, such withdrawal has not yet been finalized. It is not possible at this time to predict how or whenAgreement. However, on January 20, 2021, President Biden signed an “Acceptance on Behalf of the United States might impose restrictionsof America” that will allow the U.S. to rejoin the Paris Agreement. The newly signed acceptance, deposited with the United Nations on GHGs asJanuary 20, 2021, reverses the prior withdrawal. The United States will officially rejoin the Paris Agreement on February 19, 2021. In addition, shortly after taking office in January 2021, President Biden issued a series of executive orders designed to address climate change. Reentry into the Paris Agreement and President Biden’s executive orders
may result in the development of the international climate change agreement. Further, severaladditional 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 itsthe 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 greenhouse gasesGHGs in areas in which we conduct business could adversely affect our operations and demand for our services.
Moreover, in interpretative guidance on climate change disclosures, the U.S. Securities and Exchange Commission ("SEC") indicates that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, our operations have the potential to be adversely affected. Potential adverse effects could include disruption of our business activities, including, for example, damages to our facilities from powerful winds or floods, or increases in our costs of operation or reductions in the efficiency of our operations, as well as potentially increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process related services provided by companies or suppliers with whom we have a business relationship. In addition, the demand for and consumption of our products and services (due to change in both costs and weather patterns), and the economic health of the regions in which we operate, could have a material adverse effect on our business, financial condition, results of operations and 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 asthe 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.United States. 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 United States, the definition of which was expanded by the EPA and Corps of Engineers in aStates. In June 2015, rulemaking. The 2015 rule, if it were to become effective, could significantly expand federal control of land and water resources across the U.S., triggering substantial additional permitting and regulatory requirements to which our operations may be subject from time to time. The EPA and the Corps subsequently proposed a rulemaking in June 2017 to repeal the 2015 rule and also announced their intent to issue a new rule defining the CWA’s jurisdiction. The EPA and the Corps issued a final rule in January 2018 staying implementation of the 2015 rule for two years. On December 11, 2018, the EPA and the U.S. Army Corps proposedof Engineers finalized a new rule definingintended to clarify the CWA’s jurisdiction. A nationwide patchworkmeaning of litigationthe term "waters of the United States," which established the scope of regulated waters under the Clean Water Act. However, in October 2019, the subject rule was repealed and court rulings developed regarding the rules. At this time, duepre-2015 regulatory text was re-codified. In April 2020, the EPA and the Army Corps of Engineers issued the final Navigable Waters Protection Rule amending the definition of "water of the United States" and replacing the EPA's October 2019 final rule. Judicial challenges to varied court rulings,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. " If the rules are vacated and the expanded scope of jurisdiction in the 2015 rule is effective in some states, while the agencies’ decisionultimately implemented, or to delay implementation of the 2015 rule is effective in other states. If finalized, the 2018 proposed rule would apply nationwide, replacing the national patchwork of CWA jurisdictional applicability. Additionally, if finalized, it is possible that the 2018 proposed rule could be challenged. The scope of the CWA’s jurisdiction will likely remain fluid until a final regulatory determination is made and subsequent litigation, if any, is finalized. To the extent a rule ultimately promulgated expandsthat any future rules expand the scope of the CWA’sClean 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. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages including natural resource damages. Under the OPA, vessels and shore facilities handling, storing, or transporting oil are required to develop and implement oil spill response plans, and vessels greater than 300 tons in weight must provide to the U.S. Coast Guard evidence of financial responsibility to cover the costs of cleaning up oil spills from such vessels. The OPA also requires that all newly constructed tank barges engaged in oil transportation in the U.S. be double hulled effective January 1, 2016. We believe we are in substantial compliance with all of the oil spill-related and financial responsibility requirements. Nonetheless, in the aftermath of the Deepwater Horizon incident in 2010, Congress has from time to time considered oil spill related legislation that could have the effect of substantially increasing financial responsibility requirements and potential fines and damages for violations and discharges subject to the OPA, and similar legislation. Any such changes in law affecting areas where we conduct business could materially affect our operations.
Safety Regulation
The Company’sPartnership’s marine transportation operations are subject to regulation by the U.S. Coast Guard, federal laws, state laws and certain international treaties. Tank ships, push boats, tugboats and barges are required to meet construction and repair standards established by the American Bureau of Shipping, a private organization,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
The workplaces associated with our manufacturing, processing, terminal and storage facilities are subject to the requirements of the federal Occupational Safety and Health Act ("OSHA"OSH Act") and comparable state statutes. We believe we have conducted our operations in substantial compliance with OSHAOSH 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 the mosta stringent regimen of vessel inspection in the world,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 Employees
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 employsCorporation has approximately 7351,500 employees of which 1,130 individuals, including 57 employees59 individuals represented by labor unions, who provide direct support to our operations as of December 31, 2018.2020. 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 1920 to our consolidated financial statements included in this annual report on Form 10-K.
Access to Public Filings
We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to these reports filed with the SEC under theU.S. Securities and Exchange Act of 1934.Commission (the "SEC") under the Exchange Act. These documents may be accessed free of charge on our website at the following address: www.martinmidstream.com.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.
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.
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:
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| 1 | 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. |
| 2 | 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. |
| 3 | 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. |
| 4 | 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. |
| 5 | 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. |
| 6 | 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. |
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| 7 | Fluctuations in interest rates could materially affect our financial results, and the phase-out of LIBOR may adversely affect interest expense related to our floating rate debt. |
| 8 | 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. |
| 9 | 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. |
| 10 | Our future acquisitions may not be successful, may substantially increase our indebtedness and contingent liabilities and may create integration difficulties. |
| 11 | 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. |
| 12 | 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. |
| 13 | Adverse weather conditions, including droughts, hurricanes, tropical storms and other severe weather, could reduce our results of operations and ability to make distributions to our unitholders. |
| 14 | 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. |
| 15 | 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. |
| 16 | Increasing energy prices could adversely affect our results of operations. |
| 17 | Decreasing energy prices could adversely affect our results of operations. |
| 18 | Our NGL and sulfur-based fertilizer products are subject to seasonal demand and could cause our revenues to vary. |
| 19 | The highly competitive nature of our industry could adversely affect our results of operations and ability to make distributions to our unitholders. |
| 20 | 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. |
| 21 | The loss or insufficient attention of key personnel could negatively impact our results of operations and ability to make distributions to our unitholders. |
| 22 | 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. |
| 23 | 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. |
| 24 | 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. |
| 25 | 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. |
| 26 | 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. |
| 27 | Changes in transportation regulations may increase our costs and negatively impact our results of operations. |
| 28 | Our interest rate swap activities could have a material adverse effect on our earnings, profitability, liquidity, cash flows and financial condition. |
| 29 | The industry in which we operate is highly competitive, and increased competitive pressure could adversely affect our business and operating results. |
| 30 | Information technology systems present potential targets for cyber security attacks, which could adversely affect our business. |
| 31 | 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. |
| 32 | 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. |
| 33 | 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. |
| 34 | 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. |
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| 35 | 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. |
| 36 | We may issue additional common units without unitholder approval, which would dilute unitholder ownership interests. |
| 37 | 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. |
| 38 | Our general partner has a limited call right that may require unitholders to sell their common units at an undesirable time or price. |
| 39 | Our common units have a limited trading volume compared to other publicly traded securities. |
| 40 | 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. |
| 41 | Cash reimbursements due to Martin Resource Management Corporation may be substantial and will reduce our cash available for distribution to our unitholders. |
| 42 | 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. |
| 43 | Martin Resource Management Corporation and its affiliates may engage in limited competition with us. |
| 44 | 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. |
| 45 | 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. |
| 46 | 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. |
| 47 | 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. |
| 48 | 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. |
| 49 | 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. |
| 50 | Tax gain or loss on the disposition of our common units could be different than expected. |
| 51 | Unitholders may be subject to limitations on their ability to deduct interest expenses incurred by us. |
| 52 | 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. |
| 53 | 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. |
| 54 | 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. |
| 55 | Unitholders may be subject to state, local and foreign taxes and return filing requirements as a result of investing in our common units. |
| 56 | There are limits on the deductibility of our losses that may adversely affect our unitholders. |
| 57 | 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. |
| 58 | 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. |
| 59 | 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. |
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-lookingforward-
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 have 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 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, 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 the minimum quarterlya distribution each quarter.
We may not have sufficient available cash each quarter in the future to pay the minimum quarterly distributions on all our units. Under the terms of our partnership agreement,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 credit facilitydebt instruments could prevent us from making distributions to our unitholders or limit our ability to pursue opportunities that would increase our distributions to unitholders.
The payment of principal and interest on our indebtedness reduces the cash available for distribution to our unitholders. In addition, we are prohibited byour 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 credit facilitydebt 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;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.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 levels of offshore oil and gas exploration, development and productionsuch 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, and to pursue other business opportunities.
As of December 31, 2020, we had approximately $525.5 million in principal amount of debt outstanding (including $148.0 million outstanding under our revolving 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;
•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 revolving 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 revolving credit facility has $300.0 million in lender commitments, the amount we are able to borrow is limited by the financial covenants contained therein. As of December 31, 2020, we had the ability to borrow approximately $20.5 million under our revolving credit facility due to such financial covenants.
Fluctuations in interest rates could materially affect our financial results.results, and the phase-out of LIBOR may adversely affect interest expense related to our floating rate debt.
Borrowings under our revolving 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, 2018,2020, if LIBOR exceeds the 1.00% floor the impact of a 100 basis point increase in interest rates were to increase by 100 basis points, the correspondingon this amount of debt would result in an increase in interest expense on our variable rate debt wouldand a corresponding decrease future earnings and cash flows byin net income of approximately $2.9$1.5 million per year.annually.
Further, LIBORthe U.S. Dollar London Interbank Offered Rate ("LIBOR") and certain other interest rate “benchmarks”"benchmarks" are the subject of recent national, international, and other regulatory guidance and proposals for reform. These reforms may cause such benchmarks to perform differently than in the past or have other consequences which cannot be predicted. On July 27, 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, publicly announced that it intends to stop persuading or compelling banks to submit LIBOR rates after 2021. On November 30, 2020, ICE Benchmark Administration, the current administrator of LIBOR, announced that it intends to cease publication of 1-week and 2-month LIBOR at the end of 2021 and, subject to compliance with applicable regulations, including as to representativeness, it does not intend to cease publication of the remaining LIBOR tenors until June 30, 2023. It is expected thatuncertain whether LIBOR will be available as a transition away frombenchmark for pricing our floating rate indebtedness until, or after, June 30, 2023. Our revolving credit facility includes a mechanism to amend the widespread usefacility 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, to alternativeinterest under our revolving credit facility will bear interest at higher rates will occur overbased on the courseprime 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 the next several years. Asmanaging our interest rate exposure, our hedging strategies may not be effective as a result of this transition,the replacement or phasing out of LIBOR, and our earnings may disappear entirelybe subject to volatility. In addition, the overall financial markets may be disrupted as a result of the phase-out or perform differently thanreplacement 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 past, and interest ratesfinancial market could have an adverse effect on our variable rate indebtedness may be adversely affected.
If we do not have sufficient capital resources for acquisitions or opportunities for expansion, our growth will be limited.
We intend to explore acquisition opportunities in order to expand ourfinancial condition, results of operations and increase our profitability. We may finance acquisitions through public and private financing, or we may use our limited partner interests for all or a portion of the consideration to be paid in acquisitions. Distributions of cash with respect to these equity securities or limited partner interests may reduce the amount of cash available for distribution to the common units. In addition, in the event our limited partner interests do not maintain a sufficient valuation, or potential acquisition candidates are unwilling to accept our limited partner interests as all or part of the consideration, we may be required to use our cash resources, if available, or rely on other financing arrangements to pursue acquisitions. If we use funds from operations, other cash resources or increased borrowings for an acquisition, the acquisition could adversely impact our ability to make our minimum quarterly distributions to our unitholders. Additionally, if we do not have sufficient capital resources or are not able to obtain financing on terms acceptable to us for acquisitions, our ability to implement our growth strategies may be adversely impacted.flows.
A higher cost of capital relative to our peers could limit our ability to grow through acquisitions.
In order to expand our operations and increase profitability, we explore acquisition opportunities. When competing for acquisition targets, firms with a lower cost of capital will be in a stronger position to secure the acquisition. A higher cost of capital relative to our peers could put us in a weaker position to grow through acquisitions.
We are exposed to counterparty risk in our credit facility and related interest rate protection agreements.
We rely on our credit facility to assist in financing a significant portion of our working capital, acquisitions and capital expenditures. Our ability to borrow under our credit facility may be impaired because:
•one or more of our lenders may be unable or otherwise fail to meet its funding obligations;
◦the lenders do not have to provide funding if there is a default under the credit facility or if any of the representations or warranties included in the credit facility are false in any material respect; and
◦if any lender refuses to fund its commitment for any reason, whether or not valid, the other lenders are not required to provide additional funding to make up for the unfunded portion.
If we are unable to access funds under our credit facility, we will need to meet our capital requirements, including some of our short-term capital requirements, using other sources. Alternative sources of liquidity may not be available on acceptable terms, if at all. If the cash generated from our operations or the funds we are able to obtain under our credit facility or other sources of liquidity are not sufficient to meet our capital requirements, then we may need to delay or abandon capital projects or other business opportunities, which could have a material adverse effect on our business, financial condition and results of operations.
In addition, we have from time to time entered into interest rate protection agreements to manage our interest rate risk exposure by fixing a portion of the interest expense we pay on our long-term debt under our credit facility. Uncertainty in the global economy and banking markets exists, which could affect whether the counterparties to such interest rate protection agreements are able to honor their agreements. If the counterparties fail to honor their commitments, we could experience higher interest rates, which could have a material adverse effect on our business, financial condition and results of operations. In addition, if the counterparties fail to honor their commitments, we also may be required to replace such interest rate protection agreements with new interest rate protection agreements, and such replacement interest rate protection agreements may be at higher rates than our current interest rate protection agreements, which could have a material adverse effect on our business, financial condition and results of operations.
The impacts of climate-related initiatives at the international, federalWe are exposed to counterparty credit risk. Nonpayment and state levels remain uncertain at this time.
Currently, there are numerous international, federalnonperformance by our customers, suppliers or vendors could reduce our revenues, increase our expenses and state-level initiatives and proposals addressing domestic and global climate issues. Within the U.S., most of these proposals would regulate and/or tax, in one fashion or another, the production of carbon dioxide and other "greenhouse gases" to facilitate the reduction of carbon compound emissions to the atmosphere and provide tax and other incentives to produce and use more "clean energy." Costs to comply with future climate-related initiatives couldotherwise have a materialnegative 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 conditiondistress 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 resultswe may be forced to cancel all or a portion of operations.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 recent and future acquisitions may not be successful, may substantially increase our indebtedness and contingent liabilities and may create integration difficulties.
As part of our business strategy, we intend to acquire businesses or assets we believe complement our existing operations. We may not be able to successfully integrate recent or any future acquisitions into our existing operations or achieve the desired profitability from such acquisitions. These acquisitions may require substantial capital expenditures and the incurrence of additional indebtedness. If we make acquisitions, our capitalization and results of operations may change significantly. Further, any acquisition could result in:
◦post-closing discovery of material undisclosed liabilities of the acquired business or assets;
◦the unexpected loss of key employees or customers from the acquired businesses;
◦difficulties resulting from our integration of the operations, systems and management of the acquired business; and
◦an unexpected diversion of our management's attention from other operations.
If recent or any future acquisitions are unsuccessful or result in unanticipated events or if we are unable to successfully integrate acquisitions into our existing operations, such acquisitions could adversely affect our results of operations, cash flow and ability to make distributions to our unitholders.
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 United States 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 United States, 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 United States, 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 United States 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 United States will officially rejoin the Paris Agreement on February 19, 2021. 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.
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 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 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 U.S. Gulf Coast region and along the Mississippi River inland waterway. Weather in these regions is sometimes severe (including tropical storms and hurricanes) and can be a major factor in our day-to-day operations. Our marine transportation operations can be significantly delayed, impaired or postponed by adverse weather conditions, such as fog in the winter and spring months and certain river conditions. Additionally, our marine transportation operations and our assets in the Gulf of Mexico, including our barges, push boats, tugboats and terminals, can be adversely impacted or damaged by hurricanes, tropical storms, tidal waves or other related events. Demand for our lubricants and the diesel fuel we throughput in our Terminalling and Storage segment can be affected if offshore drilling operations are disrupted by weather in the Gulf of Mexico.
National weather conditions have a substantial impact on the demand for our products. Unusually warm weather during the winter months can cause a significant decrease in the demand for NGL products. Likewise, extremeExtreme weather conditions (either wet or dry) can decreasehas 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 natural gas, and other petroleum products and by-products;
◦fires and explosions;
◦damage to transportation, terminalling and storage facilities and surrounding properties caused by natural disasters; and
◦terrorist attacks or sabotage.
Our insurance coverage may not be adequate to protect us from all material expenses related to potential future claims for personal-injury and property damage, including various legal proceedings and litigation resulting from these hazards and risks. If we incur material liabilities that are not covered by insurance, our operating results, cash flow and ability to make distributions to our unitholders could be adversely affected.
Changes in the insurance markets attributable to the effects of hurricanes and their aftermath may make some types of insurance more difficult or expensive for us to obtain. As a result, we may be unable to secure the levels and types of insurance
we would otherwise have secured prior to such events. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage.
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.
Increasing energy prices could adversely affect our results of operations.
Increasing energy prices could adversely affect our results of operations. Diesel fuel, natural gas, chemicals and other supplies are recorded in operating expenses. An increase in price of these products would increase our operating expenses, which could adversely affect our results of operations including net income and cash flows. We cannot assure unitholders that we will be able to pass along increased operating expenses to our customers.
Decreasing energy prices could adversely affect our results of operations.
Decreasing energy prices could adversely affect our results of operations. If commodity prices remain weak for a sustained period, our pipeline, terminalling throughput and NGL volumes may be negatively impacted, particularly as producers are curtailing or redirecting drilling, adversely affecting our results of operations. A sustained decline in commodity prices could result in a decrease in activity in the areas served by certain of our terminalling and storage and marine transportation assets resulting in reduced utilization of these assets.
Increased competition from alternative natural gas transportationFor 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 OPEC and other non-OPEC producer nations during the first quarter of 2020 and global storage optionsconsiderations. Travel restrictions and alternative fuel sources couldstay-at-home orders implemented by governments in many regions and countries across the globe, including the United States, have a significant financial impact on us.
Our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows could be adversely affected by activities of other interstate and intrastate pipelines and storage facilities that may expand or construct competing transportation and storage systems. In addition, future pipeline transportation and storage capacity could be constructed in excess of actual demand and with lower fuel requirements, operating and maintenance costs than our facilities, which could reducegreatly impacted the demand for refined products resulting in a significant reduction in refinery utilization, which has impacted our 2020 performance. This impact started in February of 2020 and continued through the rates thatend of the year, during which time we receivehave seen 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 has been reduced, demand for our services in particular areas. Further, natural gas also competes with alternative energy sources available to our customers that are used to generate electricity, such as hydroelectric power, solar, wind, nuclear, coal and fuel oil.has decreased.
Our NGL and sulfur-based fertilizer products are subject to seasonal demand and could cause our revenues to vary.
The demand for NGLs and natural gas is highest in the winter. Therefore, revenue from our natural gas servicesNGL business is higher in the winter than in other seasons. Our sulfur-based fertilizer products experience an increase in demand during the spring, which increases the revenue generated by this business line in this period compared to other periods. The seasonality of the revenue from these products may cause our results of operations to vary on a quarter-to-quarter basis and thus could cause our cash available for quarterly distributions to fluctuate from period to period.
The highly competitive nature of our industry could adversely affect our results of operations and ability to make distributions to our unitholders.
We operate in a highly competitive marketplace in each of our primary business segments. Most of our competitors in each segment are larger companies with greater financial and other resources than we possess. We may lose customers and future business opportunities to our competitors and any such losses could adversely affect our results of operations and ability to make distributions to our unitholders.
Our business is subject to compliance with environmental laws and regulations that could expose us to significant costs and liabilities and adversely affect our results of operations and ability to make distributions to our unitholders.
Our business is subject to federal, state and local environmental laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of human health, natural resources and the environment. These laws and regulations may impose numerous obligations that are applicable to our operations, such as: requiring the acquisition of permits to conduct regulated activities; restricting the manner in which we can release materials into the environment; requiring remedial activities or capital expenditures to mitigate pollution from former or current operations; and imposing substantial liabilities on us for pollution resulting from our operations. Numerous governmental authorities, such as the U.S. Environmental Protection AgencyEPA 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 clearcontinuing trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and, thus, any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial position.
The loss or insufficient attention of key personnel could negatively impact our results of operations and ability to make distributions to our unitholders.
Our success is largely dependent upon the continued services of members of the senior management team of Martin Resource Management.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.
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.
NASDAQ does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements, and therefore, unitholders do not have the same protections afforded to shareholders of corporations subject to all NASDAQ requirements.
Because we are a publicly traded partnership, the Nasdaq Global Select Market ("NASDAQ") does not require our general partner to have a majority of independent directors on its board of directors or to establish a compensation committee or nominating and corporate governance committee. Accordingly, unitholders do not have the same protections afforded to certain corporations that are subject to all of NASDAQ corporate governance requirements.
Our marine transportation business could be adversely affected if we do not satisfy the requirements of the Jones Act or if the Jones Act were modified or eliminated.
The Jones Act is a federal law that restricts domestic marine transportation in the U.S. to vessels built and registered in the U.S. Furthermore, the Jones Act requires that the vessels be manned and owned by U.S. citizens. If we fail to comply with these requirements, our vessels lose their eligibility to engage in coastwise trade within U.S. domestic waters.
The requirements that our vessels be U.S. built and manned by U.S. citizens, the crewing requirements and material requirements of the Coast Guard and the application of U.S. labor and tax laws significantly increase the costs of U.S. flagged vessels when compared with foreign-flagged vessels. During the past several years, certain interest groups have lobbied Congress to repeal the Jones Act to facilitate foreign flag competition for trades and cargoes reserved for U.S. flagged vessels under the Jones Act and cargo preference laws. If the Jones Act were to be modified to permit foreign competition that would not be subject to the same U.S. government imposed costs, we may need to lower the prices we charge for our services in order to compete with foreign competitors, which would adversely affect our cash flow and ability to make distributions to our unitholders.
Our marine transportation business could be adversely affected if the U.S. Government purchases or requisitions any of our vessels under the Merchant Marine Act.
We are subject to the Merchant Marine Act of 1936, which provides that, upon proclamation by the U.S. President of the U.S. of a national emergency or a threat to the national security, the U.S. Secretary of Transportation may requisition or purchase any vessel or other watercraft owned by U.S. citizens (including us, provided that we are considered a U.S. citizen for this purpose). If one of our push boats, tugboats or tank barges were purchased or requisitioned by the U.S. government under this law, we would be entitled to be paid the fair market value of the vessel in the case of a purchase or, in the case of a requisition, the fair market value of charter hire. However, if one of our push boats or tugboats is requisitioned or purchased and its associated tank barge is left idle, we would not be entitled to receive any compensation for the lost revenues resulting from the idled barge. We also would not be entitled to be compensated for any consequential damages we suffer as a result of the requisition or purchase of any of our push boats, tugboats or tank barges. If any of our vessels are purchased or requisitioned for an extended period of time by the U.S. government, such transactions could have a material adverse effect on our results of operations, cash flow and ability to make distributions to our unitholders.
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.
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. These systems could be a potential target for a cyber security attack as they are used to store and process sensitive information regarding our operations, financial position, and information pertaining to our customers and vendors. While we take the utmost precautions, we cannot guarantee safety from all threats and attacks. Any successful breach of security could result in the spread of inaccurate or confidential information, disruption of operations, environmental harm, endangerment of employees, damage to our assets, and increased costs to respond. Any of these instances could have a negative impact on cash flows, litigation status and/or our reputation, which could have a material adverse affecteffect on our business, financial conditions and operations. 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.
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 agreementPartnership Agreement provides that we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders. Our general partner may also cause us to issue an unlimited number of additional common units or other equity securities of equal rank with the common units, without unitholder approval, in a number of circumstances such as:
•the issuance of common units in additional public offerings or in connection with acquisitions that increase cash flow from operations on a pro forma, per unit basis;
•the conversion of subordinated units into common units;
•the conversion of units of equal rank with the common units into common units under some circumstances; or
•the conversion of our general partner's general partner interest in us and its incentive distribution rights into common units as a result of the withdrawal of our general partner.
Our partnership agreementPartnership 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,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,Partnership Agreement, these registration rights allow the general partner and its affiliates or their assignees holding any units to require registration of any of these units and to include any of these units in a registration by us of other units, including units offered by us or by any unitholder. Our general partner will continue to have these registration rights for two years following its withdrawal or removal as a general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. Except as described below, the general partner and its affiliates may sell their units in private transactions at any time, subject to compliance with applicable laws. Our general partner and its affiliates, with our concurrence, have granted comparable registration rights to their bank group to which their partnership units have been pledged.
The sale of any common or subordinated units could have an adverse impact on the price of the common units or on any trading market that may develop.
Unitholders have less power to elect or remove management of our general partner than holders of common stock in a corporation. It is unlikely that our common unitholders will have sufficient voting power to elect or remove our general partner without the consent of Martin Resource Management 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, 2018,2020, Martin Resource Management Corporation owned 15.7% of our total outstanding common limited partner units.
Unitholders' voting rights are further restricted by our partnership agreementPartnership 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 agreementPartnership 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 agreementPartnership 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 agreementPartnership 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,Partnership Agreement, or to take other action under our partnership agreementPartnership 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 agreementPartnership Agreement contains provisions that reduce the remedies available to unitholders for actions that might otherwise constitute a breach of fiduciary duty by our general partner.
Our partnership agreementPartnership Agreement limits the liability and reduces the fiduciary duties of our general partner to the unitholders. Our partnership agreementPartnership 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: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 agreementPartnership Agreement and conflicts of interest that might otherwise be considered a breach of fiduciary duties under applicable state law.
We may issue additional common units without unitholder approval, which would dilute unitholder ownership interests.
Our general partner may also cause us to issue an unlimited number of additional common units or other equity securities of equal rank with the common units, without unitholder approval, in a number of circumstances such as:
◦the issuance of common units in additional public offerings or in connection with acquisitions that increase cash flow from operations on a pro forma, per unit basis;
◦the conversion of subordinated units into common units;
◦the conversion of units of equal rank with the common units into common units under some circumstances; or
◦the conversion of our general partner's general partner interest in us and its incentive distribution rights into common units as a result of the withdrawal of our general partner.
We may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Our partnership agreementPartnership Agreement does not give our unitholders the right to approve our issuance of equity securities ranking junior to the common units at any time.
The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:
◦our unitholders' proportionate ownership interest in us will decrease;
◦the amount of cash available for distribution on a per unit basis may decrease;
◦because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
◦the relative voting strength of each previously outstanding unit will diminish;
◦the market price of the common units may decline; and
◦the ratio of taxable income to distributions may increase.
The control of our general partner may be transferred to a third party and that party could replace our current management team, without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in our partnership agreementPartnership 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,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 - TaxFactors-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'sManagement 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, 2018,2020, Martin Resource Management Corporation owned 15.7% of our total outstanding common limited partner units and a 51% voting interest in Holdings, the sole member of MMGP. MMGP owns a 2% general partnership interest in us and all of our incentive distribution rights. 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 agreementPartnership 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'sManagement 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,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 agreementPartnership 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;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.
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”("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.
Our partnership agreementPartnership Agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amount will be adjusted to reflect the impact of that law on us.
The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative or judicial interpretation at any time.
At the federal level, members of Congress and the President of the United States have periodically considered substantive changes to the existing U.S. tax laws that would have affected certain publicly traded partnerships, including the elimination of partnership tax treatment for publicly traded partnerships. At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay a Texas margin tax at a maximum effective rate of 0.525% of our gross income apportioned to Texas in the prior year. Imposition of any such tax on us by any other state will reduce the cash available for distribution to 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”"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”"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”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”"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.
The effects of the budget reconciliation act commonly referred to as the Tax Cuts and Jobs Act (hereinafter, “Tax Cuts and Jobs Act”) could have an adverse effect on the timing and amount of income allocations to our unitholders.
On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”) that makes significant changes to the U.S. Internal Revenue Code. Among other changes, the Tax Act includes a reduction in the corporate and individual tax rates, a new deduction on certain pass-through income, a repeal of the partnership technical termination rule, and new limitations on certain deductions and credits, including interest expense deductions. The Tax Act had no material impact on our unitholder allocations for 2018.
A successful IRS contest of the federal income tax positions we take could adversely affect the market for our common units and the costs of any contest will be borne by our unitholders, debt security holders and our general partner.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take and our counsel's conclusions. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel's conclusions or the positions we take. A court may not agree with some or all our counsel's conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the prices at which they trade. In addition, the costs of any contest with the IRS will be borne directly or indirectly by all of our unitholders, debt security holders and our general partner.
If the IRS makes audit adjustments to our income tax returns, for tax years beginning after December 31, 2017, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.
Pursuant to the Bipartisan Budget Act of 2015 and recently issued proposed Treasury Regulations (the “Proposed Partnership Audit Regulations”), for taxable years beginning after December 31, 2017, if 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. These rules are not applicable to us for tax years beginning on or prior to December 31, 2017.
Additionally, pursuant to the Bipartisan Budget Act of 2015 and the Proposed Partnership Audit Regulations, we are no longer required to designate a “tax matters partner.” Instead, for taxable years beginning after December 31, 2017, we are required to designate a partner, or other person, with a substantial presence in the United States as the partnership representative (“("Partnership Representative”Representative"). The Partnership Representative will have the sole authority to act on our behalf for purposes of, among other things, U.S. federal income tax audits and judicial review of administrative adjustments by the IRS. If we do not make such a designation, the IRS can select any personWe have designated our general partner as theour Partnership Representative. AnyFurther, any actions taken by us or by the Partnership Representative on our behalf with respect to, among other things, U.S. federal income tax audits and judicial review of administrative adjustments by the IRS, will be binding on us and all of theour unitholders. We anticipate that our current tax matters partner will be designated the Partnership Representative.
Unitholders may be required to pay taxes on income from us, including their share of income from the cancellation of debt, even if they do not receive any cash distributions from us.
Unitholders may be required to pay federal income taxes and, in some cases, state, local and foreign income taxes on their share of our taxable income even if they receive no cash distributions from us. Unitholders may not receive cash 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.
WeA 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"cancellation of indebtedness income”income" (also referred to as “COD income”"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 taxable year, the Coronavirus Aid, Relief, and Economic Security Act increases the 30% adjusted taxable income limitation to 50%, unless we elect not to apply such increase, and for purposes of determining our 50% adjusted taxable income limitation, we may elect to substitute our 2020 adjusted taxable income with our 2019 adjusted taxable income. 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.
Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.Snon-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. Tax-exempt entities, non-U.S. personsIn addition,. under the Tax Cuts and other unique investorsJobs Act, 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 consult their tax advisor regarding their investment inhave 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.units, that occur before January 1, 2022. Under recently finalized Treasury Regulations, in the case of transfers of our common units occurring on or after January 1, 2022, 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 Martin Transport Inc.(“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, 2020, 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, Nevada, New Mexico, Oklahoma, Pennsylvania, Tennessee, Texas, Utah, and West Virginia. We may do business or own property in other states or foreign countries in the future. It is the unitholder's responsibility to file all federal, state, local and foreign tax returns. Our counsel has not rendered an opinion on the state, local or foreign tax consequences of an investment in our common units.
There are limits on the deductibility of our losses that may adversely affect our unitholders.
There are a number of limitations that may prevent unitholders from using their allocable share of our losses as a deduction against unrelated income. In cases when our unitholders are subject to the passive loss rules (generally, individuals and closely-held corporations), any losses generated by us will only be available to offset our future income and cannot be used to offset income from other activities, including other passive activities or investments. Unused losses may be deducted when the unitholder disposes of its entire investment in us in a fully taxable transaction with an unrelated party. A unitholder's share of our net passive income may be offset by unused losses from us carried over from prior years but not by losses from other passive activities, including losses from other publicly traded partnerships. Other limitations that may further restrict the
deductibility of our losses by a unitholder include the at-risk rules, 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.
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.
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.
From time to time, we are subject to certain legal proceedings, claims and disputes that arise in the ordinary course of our business. Although we cannot predict the outcomes of these legal proceedings, we do not believe these actions, in the aggregate, will have a material adverse impact on our financial position, results of operations or liquidity. A description of our legal proceedings is included in "Item 8. Financial Statements and Supplementary Data, Note 22. Commitments and Contingencies", and is incorporated herein by reference.
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| Item 4. | Mine Safety Disclosures |
Not applicable.
PART II
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| Item 5. | Market for Our Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities |
Market Information and Holders
Our common units are traded on the NASDAQ under the symbol "MMLP." As of January 25, 2019,March 3, 2021, there were approximately 279233 holders of record and approximately 20,32913,757 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,Partnership Agreement, to unitholders of record on the applicable record date. Our general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct our business. These can include cash reserves for future capital and maintenance expenditures, reserves to stabilize distributions of cash to the unitholders and our general partner, reserves to reduce debt, or, as necessary, reserves to comply with the terms of any of our agreements or obligations. Our distributions are effectively made 98% to unitholders and 2% to our general partner, subject to the payment of incentive distributions to our general partner if certain target cash distribution levels to common unitholders are achieved. Distributions to our general partner increase to 15%, 25% and 50% based on incremental distribution thresholds as set forth in our partnership agreement.Partnership Agreement.
Our ability to distribute available cash is contractually restricted by the terms of our credit facility. Our credit facility contains covenants requiring us to maintain certain financial ratios. We are prohibited from making any distributions to unitholders if the distribution would cause a default or an event of default, or a default or an event of default exists, under our credit facility. Please read "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Description of Our Credit Facility."
Quarterly Distribution. On January 17, 2019,25, 2021, we declared a quarterly cash distribution of $0.50$0.005 per common unit for the fourth quarter of 2018,2020, or $2.00$0.02 per common unit on an annualized basis, which will bewas paid on February 14, 201912, 2021 to unitholders of record as of February 7, 2019.5, 2021.
|
| | | | |
| Item 6. | Selected Financial Data |
The following table sets forth selected financial data and other operating data of the Partnership for the years ended December 31, 2020, 2019, 2018, 2017 2016, 2015 and 20142016 and is derived from the audited consolidated financial statements of the Partnership.
The following selected financial data are qualified by reference to and should be read in conjunction with the Partnership's Consolidated Financial Statements and Notes thereto and "Management’s Discussion and Analysis of Financial Condition and Results of Operations" included elsewhere in this document.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | 2018 | | 2017 | | 2016 |
| (Dollars in thousands, except per unit amounts) |
| | | | | |
| Revenues | $ | 672,142 | | | $ | 847,118 | | | $ | 1,020,104 | | | $ | 973,386 | | | $ | 857,522 | |
| | | | | | | | | |
| Income (loss) from continuing operations | (6,771) | | | 4,520 | | | (7,831) | | | (1,183) | | | 10,157 | |
| Income (loss) from discontinued operations, net of tax | — | | | (179,466) | | | 63,486 | | | 21,099 | | | 20,806 | |
| Net income (loss) | $ | (6,771) | | | $ | (174,946) | | | $ | 55,655 | | | $ | 19,916 | | | $ | 30,963 | |
| Net income (loss) attributable to limited partners | $ | (6,615) | | | $ | (171,488) | | | $ | 43,195 | | | $ | 16,750 | | | $ | 23,143 | |
| | | | | | | | | |
| Net income (loss) per limited partner unit – continuing operations | (0.17) | | | 0.11 | | | (0.49) | | | (0.1) | | | 0.22 | |
| Net income (loss) per limited partner unit – discontinued operations | — | | | (4.55) | | | 1.60 | | | 0.54 | | | 0.43 | |
| Net income (loss) per limited partner unit | $ | (0.17) | | | $ | (4.44) | | | $ | 1.11 | | | $ | 0.44 | | | $ | 0.65 | |
| | | | | | | | | |
| Total assets | $ | 579,638 | | | $ | 667,156 | | | $ | 1,073,628 | | | $ | 1,285,621 | | | $ | 1,269,354 | |
| Long-term debt | 484,886 | | | 570,505 | | | 662,731 | | | 814,874 | | | 808,150 | |
| | | | | | | | | |
| Cash dividends per common unit (in dollars) | 0.14 | | | 1.25 | | | 2.00 | | | 2.00 | | | 2.94 | |
|
| | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
| | (Dollars in thousands, except per unit amounts) |
| | | | | | |
| Revenues | $ | 972,655 |
| | $ | 946,116 |
| | $ | 827,391 |
| | $ | 1,036,844 |
| | $ | 1,642,141 |
|
| | | | | | | | | | |
| Income (loss) from continuing operations | (7,595 | ) | | 13,007 |
| | 27,003 |
| | 32,088 |
| | (11,590 | ) |
| Income (loss) from discontinued operations, net of tax | 51,700 |
| | 4,128 |
| | 4,649 |
| | 10,169 |
| | (115 | ) |
| Net income (loss) | $ | 44,105 |
| | $ | 17,135 |
| | $ | 31,652 |
| | $ | 42,257 |
| | $ | (11,705 | ) |
| Net income (loss) attributable to limited partners | $ | 43,195 |
| | $ | 16,750 |
| | $ | 23,143 |
| | $ | 21,902 |
| | $ | (15,176 | ) |
| | | | | | | | | | |
| Net income (loss) per limited partner unit – continuing operations | (0.19 | ) | | 0.33 |
| | 0.55 |
| | 0.47 |
| | (0.48 | ) |
| Net income (loss) per limited partner unit – discontinued operations | 1.30 |
| | 0.11 |
| | 0.10 |
| | 0.15 |
| | (0.01 | ) |
| Net income (loss) per limited partner unit | $ | 1.11 |
| | $ | 0.44 |
| | $ | 0.65 |
| | $ | 0.62 |
| | $ | (0.49 | ) |
| | | | | | | | | | |
| Total assets | $ | 1,033,398 |
| | $ | 1,253,498 |
| | $ | 1,246,363 |
| | $ | 1,380,473 |
| | $ | 1,553,919 |
|
| Long-term debt | 656,459 |
| | 812,632 |
| | 808,107 |
| | 865,003 |
| | 902,005 |
|
| | | | | | | | | | |
| Cash dividends per common unit (in dollars) | 2.00 |
| | 2.00 |
| | 2.94 |
| | 3.25 |
| | 3.18 |
|
|
| | | | |
| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
Overview
We are a publicly traded limited partnership with a diverse set of operations focused primarily in the United States ("U.S.") Gulf Coast region. Our four primary business lines include:
•Terminalling, processing, storage and storagepackaging services for petroleum products and by-products including the refining of naphthenic crude oiloil;
•Land and the blending and packaging of finished lubricants;
Natural gas liquids transportation and distribution services and natural gas storage;
Sulfur and sulfur-based products gathering, processing, marketing, manufacturing and distribution; and
Marinemarine transportation services for petroleum products and by-products.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, fertilizer manufacturers and other wholesale purchasers of these products. We operate primarily in the U.S. Gulf Coast region. This region is a major hub for petroleum refining, natural gas gathering and processing, and support services for the exploration and production industry.
WeSignificant Recent Developments
Sale of Mega Lubricants.
On December 22, 2020, we entered into an asset purchase and sale agreement to sell Mega Lubricants to Stone Oil for $22.4 million. 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 transaction closed on December 22, 2020. The proceeds from the transaction were formedused to reduce outstanding borrowings under our revolving credit facility.
Exchange Offer and Cash Tender Offer
On August 12, 2020, we successfully completed our exchange offer and consent solicitation to certain eligible holders of our 2021 Notes and separate but related cash tender offer and consent solicitation to certain other holders of our 2021 Notes. Please see Note 15 in 2002Part II of this Form 10-K for more information about the exchange offer and related transactions.
COVID-19
COVID-19 surfaced in late 2019 and has spread around the world, including to the United States. In March 2020, the World Health Organization declared COVID-19 a pandemic. The Partnership continues to prioritize the health and safety of our employees, the businesses we serve, and the communities where we live and work. To support the safety of all of our employees and operations, precautionary measures were implemented to prevent the COVID-19 virus from spreading in our workplace or the locations we serve, including suspending non-essential travel, limiting the number of employees attending meetings, reducing the number of people at our locations at any one time, monitoring the health of all employees, and implementing work-from-home initiatives for all eligible employees. Further, we continue to provide awareness training for all of our drivers, vessel crews, blending operators and other affected personnel regarding preventative measures in or around our docks, vessels, and trucks and locations to which they are delivering. Our communication lines are open 24/7 for the environmental health and safety division, land and marine logistics, and sales and marketing teams.
Due to the economic impacts of the COVID-19 pandemic, the markets experienced a decline in oil prices in response to oil demand concerns. These concerns were further exacerbated by Martin Resource Management,the price war among members of 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 United States, have greatly impacted the demand for refined products resulting in a privately-held company whose initial predecessor was incorporatedsignificant reduction in 1951refinery utilization, which has impacted our 2020 performance. This impact started in February of 2020 and continued through the end of the year, during which time we have seen unfavorable trends in certain key metrics across several of our business lines compared to historical periods. The
significant reduction in refinery utilization as a supplierresult of reduced refined products demand significantly impacted our Transportation and NGL segments. As the volume of products produced or purchased by refineries has been reduced, demand for our services has decreased.
Looking forward, we expect to continue to experience some adverse impacts of COVID-19 in our transportation segment during the first half of 2021 but we believe that refinery utilization will continue to increase in the second half of 2021 as a result of widespread vaccinations, government stimulus, and a rebounding economy. This should ultimately improve refined product demand as people get back to work and begin traveling again. We expect this will positively impact our transportation segment as demand for our services improves.
The extent to drilling rig contractors. Since then, Martin Resourcewhich 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, the full impact of COVID-19 will not be reflected in our results of operations and overall financial performance until future periods. Management has expanded its operations through acquisitionsalso assessed the extent to which the current macroeconomic events brought about by COVID-19 and internal expansion initiativessignificant 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 its management identified and capitalized on the needs of producers and purchasers of petroleum products and by-products and other bulk liquids. Martin Resource Management is an important supplier and customer of ours. As of December 31, 2018, Martin Resource Management owned 15.7%2020.
Subsequent Events
Retirement of 2021 Notes. On February 15, 2021, our total2021 Notes matured and we retired the outstanding balance of $28.8 million using our revolving credit facility.
Quarterly Distribution. On January 25, 2021, we declared a quarterly cash distribution of $0.005 per common limited partner units. Furthermore, Martin Resource Management controls Martin Midstream GP LLC ("MMGP"), our general partner, by virtueunit for the fourth quarter of its 51% voting interest in MMGP Holdings, LLC ("Holdings"), the sole member2020, or $0.02 per common unit on an annualized basis, which was paid on February 12, 2021 to unitholders of MMGP. MMGP owns a 2% general partner interest in us and allrecord as of our incentive distribution rights. Martin Resource Management directs our business operations through its ownership interests in and control of our general partner.February 5, 2021.
We entered into an omnibus agreement dated November 1, 2002, with Martin Resource Management (the "Omnibus Agreement") that governs, among other things, potential competition and indemnification obligations among the parties to the agreement, related party transactions, the provision of general administration and support services by Martin Resource Management and our use of certain of Martin Resource Management’s trade names and trademarks. Under the terms of the Omnibus Agreement, the employees of Martin Resource Management are responsible for conducting our business and operating our assets. The Omnibus Agreement was amended on November 25, 2009, to include processing crude oil into finished products including naphthenic lubricants, distillates, asphalt and other intermediate cuts. The Omnibus Agreement was amended further on October 1, 2012, to permit the Partnership to provide certain lubricant packaging products and services to Martin Resource Management.
Martin Resource Management has operated our business since 2002. Martin Resource Management began operating our natural gas services business in the 1950s and our sulfur business in the 1960s. It began our marine transportation business in the late 1980s. It entered into our fertilizer and terminalling and storage businesses in the early 1990s. In recent years, Martin Resource Management has increased the size of our asset base through expansions and strategic acquisitions.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations are based on the historical consolidated financial statements included elsewhere herein. We prepared these financial statements in conformity with United States generally accepted accounting principles ("U.S. GAAP" or "GAAP"). The preparation of these financial statements required us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. We based our estimates on historical experience and on various other assumptions we believe to be reasonable under the circumstances. We routinely evaluate these estimates, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Our results may differ from these estimates, and any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Changes in these estimates could materially affect our financial position, results of operations or cash flows. You should also read Note 2, "Significant Accounting Policies" in Notes to Consolidated Financial Statements. The following table evaluates the potential impact of estimates utilized during the periods ended December 31, 20182020 and 2017:
2019:
|
| | | | | | | | | | | | | |
| 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, nowe 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 years ended December 31, 2019 or 2018. |
| 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 2020 and elected to bypass the qualitative assessment and perform a quantitative assessment. Based upon the most recent annual review as of August 31, 2020, no goodwill impairment exists within our reporting units for the year ended December 31, 2018. In 2017, we2020. No goodwill impairment was recorded an impairment charge of $1.6 million in our Marine Transportation segment and $0.6 million in our Terminalling and Storage segment. |
Asset Retirement Obligations |
Asset retirement obligations ("AROs") associated with a contractualduring the years ended December 31, 2019 or regulatory remediation requirement are recorded at fair value in the period in which the obligation can be reasonably estimated and the related asset is depreciated over its useful life or contractual term. The liability is determined using a credit-adjusted risk-free interest rate and is accreted over time until the obligation is settled. | | Determining the fair value of AROs requires management judgment to evaluate required remediation activities, estimate the cost of those activities and determine the appropriate interest rate. | | If actual results differ from judgments and assumptions used in valuing an ARO, we may experience significant changes in ARO balances. The establishment of an ARO has no initial impact on earnings.2018. |
Our Relationship with Martin Resource Management Corporation
Martin Resource Management Corporation directs our business operations through its ownership and control 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, 2020, 2019 and 2018, 2017 and 2016, the conflicts committeeboard of directors of our general partner ("Conflicts Committee") approved reimbursement amounts of $16.4 million, $16.4$16.7 million and $13.0$16.4 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committeeboard 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. Among other things, we provide marine transportation and terminalling and storage services to Martin Resource Management. We purchase land transportation services and marine fuel from Martin Resource Management (the Partnership acquired MTI effective January 1, 2019).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.
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."
How We Evaluate Our Operations
Our management uses a variety of financial and operational measurements other than our financial statements prepared in accordance with U.S. GAAP to analyze our performance. These include: (1) net income before interest expense, income tax expense, and depreciation and amortization ("EBITDA"), (2) adjusted EBITDA and (3) distributable cash flow. Our management views these measures as important performance measures of core profitability for our operations and the
ability to generate and distribute cash flow, and as key components of our internal financial reporting. We believe investors benefit from having access to the same financial measures that our management uses.
EBITDA and Adjusted EBITDA. Certain items excluded from EBITDA and adjusted EBITDA are significant components in understanding and assessing an entity's financial performance, such as cost of capital and historic costs of depreciable assets. We have included information concerning EBITDA and adjusted EBITDA because they provide investors and management with additional information to better understand the following: financial performance of our assets without regard to financing methods, capital structure or historical cost basis; our operating performance and return on capital as compared to those of other similarly situated entities; and the viability of acquisitions and capital expenditure projects. Our method of computing adjusted EBITDA may not be the same method used to compute similar measures reported by other entities. The economic substance behind our use of adjusted EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make distributions to our unit holders.
Distributable Cash Flow. Distributable cash flow is a significant performance measure used by our management and by external users of our financial statements, such as investors, commercial banks and research analysts, to compare basic cash flows generated by us to the cash distributions we expect to pay our unitholders. Distributable cash flow is also an important financial measure for our unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships because the value of a unit of such an entity is generally determined by the unit's yield, which in turn is based on the amount of cash distributions the entity pays to a unitholder.
EBITDA, adjusted EBITDA and distributable cash flow should not be considered alternatives to, or more meaningful than, net income, cash flows from operating activities, or any other measure presented in accordance with U.S. GAAP. Our method of computing these measures may not be the same method used to compute similar measures reported by other entities.
Non-GAAP Financial Measures
The following table reconciles the non-GAAP financial measurements used by management to our most directly comparable GAAP measures for the years ended December 31, 2018, 2017,2020, 2019, and 2016,2018, which represents EBITDA, Adjusted EBITDA and Distributable Cash Flow from continuing operations.
Reconciliation of EBITDA, Adjusted EBITDA, and Distributable Cash Flow
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| (in thousands) |
| Net income (loss) | $ | (6,771) | | | $ | (174,946) | | | $ | 55,655 | |
| Less: (Income) loss from discontinued operations, net of income taxes | — | | | 179,466 | | | (63,486) | |
| Income (loss) from continuing operations | (6,771) | | | 4,520 | | | (7,831) | |
| Adjustments: | | | | | |
| Interest expense | 46,210 | | | 51,690 | | | 52,349 | |
| Income tax expense | 1,736 | | | 1,900 | | | 577 | |
| Depreciation and amortization | 61,462 | | | 60,060 | | | 61,484 | |
| EBITDA from Continuing Operations | 102,637 | | | 118,170 | | | 106,579 | |
| Adjustments: | | | | | |
| Gain on sale of property, plant and equipment | (9,788) | | | (13,332) | | | (1,041) | |
| | | | | |
| Gain on involuntary conversion of property, plant and equipment | (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 | (460) | | | 671 | | | (76) | |
| Non-cash insurance related accruals | 250 | | | 500 | | | — | |
| Lower of cost or market adjustments | 370 | | | 633 | | | — | |
| | | | | |
| | | | | |
| Unit-based compensation | 1,422 | | | 1,424 | | | 1,224 | |
| Transaction costs associated with acquisitions | — | | | 224 | | | 465 | |
| Adjusted EBITDA from Continuing Operations | 94,857 | | | 108,290 | | | 107,151 | |
| Adjustments: | | | | | |
| Interest expense | (46,210) | | | (51,690) | | | (52,349) | |
| Income tax expense | (1,736) | | | (1,900) | | | (577) | |
| Amortization of deferred debt issuance costs | 3,422 | | | 4,041 | | | 3,445 | |
| | | | | |
| Amortization of debt premium | (191) | | | (306) | | | (306) | |
| Deferred income taxes | 1,169 | | | 1,360 | | | 208 | |
| Payments for plant turnaround costs | (1,478) | | | (5,677) | | | (1,893) | |
| Maintenance capital expenditures | (10,138) | | | (12,368) | | | (19,553) | |
| Distributable Cash Flow from Continuing Operations | $ | 39,695 | | | $ | 41,750 | | | $ | 36,126 | |
| | | | | |
| Income (loss) from discontinued operations, net of income taxes | $ | — | | | $ | (179,466) | | | $ | 63,486 | |
| Adjustments: | | | | | |
| Depreciation and amortization | $ | — | | | $ | 8,161 | | | $ | 18,795 | |
| EBITDA from Discontinued Operations | $ | — | | | $ | (171,305) | | | $ | 82,281 | |
| Equity in earnings of unconsolidated entities | $ | — | | | $ | — | | | $ | (3,382) | |
| Distributions from unconsolidated entities | $ | — | | | $ | — | | | $ | 3,500 | |
| Gain on disposition of Investment in WTLPG | $ | — | | | $ | — | | | $ | (48,564) | |
| Loss on sale of property, plant and equipment, net | $ | — | | | $ | 178,781 | | | $ | 824 | |
| Non-cash insurance related accruals | $ | — | | | $ | 3,213 | | | $ | — | |
| Adjusted EBITDA from Discontinued Operations | $ | — | | | $ | 10,689 | | | $ | 34,659 | |
| Maintenance capital expenditures | $ | — | | | $ | (912) | | | $ | (1,952) | |
| Distributable Cash Flow from Discontinued Operations | $ | — | | | $ | 9,777 | | | $ | 32,707 | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | | | | | |
| Net income | $ | 44,105 |
| | $ | 17,135 |
| | $ | 31,652 |
|
| Less: Income from discontinued operations, net of income taxes | (51,700 | ) | | (4,128 | ) | | (4,649 | ) |
| Income (loss) from continuing operations | (7,595 | ) | | 13,007 |
| | 27,003 |
|
| Adjustments: | | | | | |
| Interest expense | 52,037 |
| | 47,743 |
| | 46,100 |
|
| Income tax expense | 369 |
| | 352 |
| | 726 |
|
| Depreciation and amortization | 76,866 |
| | 85,195 |
| | 92,132 |
|
| EBITDA | 121,677 |
| | 146,297 |
| | 165,961 |
|
| Adjustments: | | | | | |
| (Gain) loss on sale of property, plant and equipment | 379 |
| | (523 | ) | | (33,400 | ) |
| Impairment of long-lived assets | — |
| | 2,225 |
| | 26,953 |
|
| Impairment of goodwill | — |
| | — |
| | 4,145 |
|
| Unrealized mark-to-market on commodity derivatives | (76 | ) | | (3,832 | ) | | 4,579 |
|
| Hurricane damage repair accrual | — |
| | 657 |
| | — |
|
| Asset retirement obligation revision | — |
| | 5,547 |
| | — |
|
| Unit-based compensation | 1,224 |
| | 650 |
| | 904 |
|
| Transaction costs associated with acquisitions | 465 |
| | — |
| | — |
|
| Adjusted EBITDA | 123,669 |
| | 151,021 |
| | 169,142 |
|
| Adjustments: | | | | | |
| Interest expense | (52,037 | ) | | (47,743 | ) | | (46,100 | ) |
| Income tax expense | (369 | ) | | (352 | ) | | (726 | ) |
| Amortization of deferred debt issuance costs | 3,445 |
| | 2,897 |
| | 3,684 |
|
| Amortization of debt premium | (306 | ) | | (306 | ) | | (306 | ) |
| Non-cash mark-to-market on interest rate derivatives | — |
| | — |
| | (206 | ) |
| Payments for plant turnaround costs | (1,893 | ) | | (1,583 | ) | | (2,061 | ) |
| Maintenance capital expenditures | (21,505 | ) | | (18,080 | ) | | (17,163 | ) |
Distributable Cash Flow1 | $ | 51,004 |
| | $ | 85,854 |
| | $ | 106,264 |
|
1
Excludes distributable cash flow from discontinued
The results of operations were $3,253, $5,214 and $7,435 for the years ended December 31, 2018, 20172020, 2019, and 2016, respectively.
Results of Operations
The results of operations for the years ended December 31,2018, 2017, and 2016 have been derived from our consolidated financial statements. Discussions of the year ended December 31, 2018 that are not included in this Annual Report on Form 10-K and year-to-year comparisons of the year ended December 31, 2019 and the year ended December 31, 2018 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, 2019.
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 equity in earnings (loss) of unconsolidated entities, interest expense, and indirect selling, general and administrative expenses, are discussed after the comparative discussion of our results within each segment.
The Natural Gas ServicesLiquids segment information below excludes the discontinued operations of the Natural Gas Storage Assets and WTLPG partnership interests disposed of on June 28, 2019 and July 31, 2018, respectively, for the years ended December 31, 2018, 20172019 and 2016.2018. See Item 8, Note 5.
The following table sets forth our operating revenues and operating income by segment for the years ended December 31, 2018, 2017,2020, 2019, and 2016.2018.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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, 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 | |
| | | | | | | | | | | |
| Year Ended December 31, 2018: | | | | | | | | | | | |
| Terminalling and storage | $ | 247,840 | | | $ | (6,400) | | | $ | 241,440 | | | $ | 17,820 | | | $ | (280) | | | $ | 17,540 | |
| Natural gas liquids | 496,026 | | | (19) | | | 496,007 | | | 13,152 | | | 18,429 | | | 31,581 | |
| Sulfur services | 132,536 | | | — | | | 132,536 | | | 17,216 | | | 10,181 | | | 27,397 | |
| Transportation | 178,163 | | | (28,042) | | | 150,121 | | | 14,770 | | | (28,330) | | | (13,560) | |
| Indirect selling, general and administrative | — | | | — | | | — | | | (17,901) | | | — | | | (17,901) | |
| Total | $ | 1,054,565 | | | $ | (34,461) | | | $ | 1,020,104 | | | $ | 45,057 | | | $ | — | | | $ | 45,057 | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | 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, 2018: | |
| | |
| | |
| | |
| | |
| | |
|
| Terminalling and storage | $ | 247,840 |
| | $ | (6,226 | ) | | $ | 241,614 |
| | $ | 17,820 |
| | $ | (4,095 | ) | | $ | 13,725 |
|
| Natural gas services | 548,135 |
| | — |
| | 548,135 |
| | 24,938 |
| | 3,632 |
| | 28,570 |
|
| Sulfur services | 132,536 |
| | — |
| | 132,536 |
| | 17,216 |
| | (2,940 | ) | | 14,276 |
|
| Marine transportation | 52,830 |
| | (2,460 | ) | | 50,370 |
| | 2,713 |
| | 3,403 |
| | 6,116 |
|
| Indirect selling, general and administrative | — |
| | — |
| | — |
| | (17,901 | ) | | — |
| | (17,901 | ) |
| Total | $ | 981,341 |
| | $ | (8,686 | ) | | $ | 972,655 |
| | $ | 44,786 |
| | $ | — |
| | $ | 44,786 |
|
| | | | | | | | | | | | |
| Year Ended December 31, 2017: | |
| | |
| | |
| | |
| | |
| | |
|
| Terminalling and storage | $ | 236,169 |
| | $ | (5,998 | ) | | $ | 230,171 |
| | $ | 3,305 |
| | $ | (2,676 | ) | | $ | 629 |
|
| Natural gas services | 532,908 |
| | (226 | ) | | 532,682 |
| | 49,377 |
| | 2,472 |
| | 51,849 |
|
| Sulfur services | 134,684 |
| | — |
| | 134,684 |
| | 25,862 |
| | (2,657 | ) | | 23,205 |
|
| Marine transportation | 51,915 |
| | (3,336 | ) | | 48,579 |
| | (1,211 | ) | | 2,861 |
| | 1,650 |
|
| Indirect selling, general and administrative | — |
| | — |
| | — |
| | (17,332 | ) | | — |
| | (17,332 | ) |
| Total | $ | 955,676 |
| | $ | (9,560 | ) | | $ | 946,116 |
| | $ | 60,001 |
| | $ | — |
| | $ | 60,001 |
|
| | | | | | | | | | | | |
| Year Ended December 31, 2016: | |
| | |
| | |
| | |
| | |
| | |
|
| Terminalling and storage | $ | 242,363 |
| | $ | (5,653 | ) | | $ | 236,710 |
| | $ | 44,143 |
| | $ | (3,483 | ) | | $ | 40,660 |
|
| Natural gas services | 391,333 |
| | — |
| | 391,333 |
| | 38,447 |
| | 3,056 |
| | 41,503 |
|
| Sulfur services | 141,058 |
| | — |
| | 141,058 |
| | 26,815 |
| | (3,422 | ) | | 23,393 |
|
| Marine transportation | 61,233 |
| | (2,943 | ) | | 58,290 |
| | (19,888 | ) | | 3,849 |
| | (16,039 | ) |
| Indirect selling, general and administrative | — |
| | — |
| | — |
| | (16,794 | ) | | — |
| | (16,794 | ) |
| Total | $ | 835,987 |
| | $ | (8,596 | ) | | $ | 827,391 |
| | $ | 72,723 |
| | $ | — |
| | $ | 72,723 |
|
Terminalling and Storage Segment
Comparative Results of Operations for the Twelve MonthsYears Ended December 31, 20182020 and 20172019
| | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | Variance | | Percent Change |
| | 2020 | | 2019 | | |
| | (In thousands) | | |
| Revenues: | | | | | | | |
| Services | $ | 87,661 | | | $ | 93,980 | | | $ | (6,319) | | | (7)% |
| Products | 103,380 | | | 122,333 | | | (18,953) | | | (15)% |
| Total revenues | 191,041 | | | 216,313 | | | (25,272) | | | (12)% |
| | | | | | | |
| Cost of products sold | 87,495 | | | 107,081 | | | (19,586) | | | (18)% |
| Operating expenses | 50,421 | | | 53,279 | | | (2,858) | | | (5)% |
| Selling, general and administrative expenses | 6,159 | | | 5,997 | | | 162 | | | 3% |
| | | | | | | |
| Depreciation and amortization | 29,489 | | | 30,952 | | | (1,463) | | | (5)% |
| | 17,477 | | | 19,004 | | | (1,527) | | | (8)% |
| Other operating income (loss), net | 6,429 | | | (1,334) | | | 7,763 | | | 582% |
| Gain on involuntary conversion of property, plant and equipment | 63 | | | — | | | 63 | | | |
| Operating income | $ | 23,969 | | | $ | 17,670 | | | $ | 6,299 | | | 36% |
| | | | | | | |
| Shore-based throughput volumes (guaranteed minimum) (gallons) | 80,000 | | | 80,000 | | | — | | | —% |
| Smackover refinery throughput volumes (guaranteed minimum BBL per day) | 6,500 | | | 6,500 | | | — | | | —% |
|
| | | | | | | | | | | | | |
| | Year Ended December 31, | | Variance | | Percent Change |
| | 2018 | | 2017 | | |
| | (In thousands) | | |
| Revenues: | | | | | | | |
| Services | $ | 102,514 |
| | $ | 105,703 |
| | $ | (3,189 | ) | | (3)% |
| Products | 145,326 |
| | 130,466 |
| | 14,860 |
| | 11% |
| Total revenues | 247,840 |
| | 236,169 |
| | 11,671 |
| | 5% |
| | | | | | | | |
| Cost of products sold | 132,384 |
| | 118,832 |
| | 13,552 |
| | 11% |
| Operating expenses | 54,129 |
| | 63,191 |
| | (9,062 | ) | | (14)% |
| Selling, general and administrative expenses | 5,327 |
| | 5,832 |
| | (505 | ) | | (9)% |
| Impairment of long-lived assets | — |
| | 600 |
| | (600 | ) | | (100)% |
| Depreciation and amortization | 39,508 |
| | 45,160 |
| | (5,652 | ) | | (13)% |
| | 16,492 |
| | 2,554 |
| | 13,938 |
| | 546% |
| Other operating income, net | 1,328 |
| | 751 |
| | 577 |
| | 77% |
| Operating income | $ | 17,820 |
| | $ | 3,305 |
| | $ | 14,515 |
| | 439% |
| | | | | | | | |
| Lubricant sales volumes (gallons) | 24,016 |
| | 21,897 |
| | 2,119 |
| | 10% |
| Shore-based throughput volumes (guaranteed minimum) (gallons) | 80,000 |
| | 144,998 |
| | (64,998 | ) | | (45)% |
| Smackover refinery throughput volumes (guaranteed minimum BBL per day) | 6,500 |
| | 6,500 |
| | — |
| | —% |
Services revenues. Services revenue decreased $3.2$6.3 million, of which $7.6$3.8 million was primarily a result of expiring capital recovery fees at our Smackover refinery and decreased fees related to a crude pipeline gathering rate adjustment. In addition, revenue from shore-based terminals decreased $2.1 million primarily due to decreased throughput of $3.2 million and consigned lube revenue of $0.6 million, offset by $1.0 million related to contract termination fees, and $0.8 million in space rental income. Revenue from specialty terminals decreased $0.3 million due to $1.2 million in decreased throughput rates, offset by $0.8 million related to a new contract.
Products revenues. A 22% decrease in lubricant sales volumes combined with a 13% decrease in average sales price at our shore-based terminals offset byresulted in a $4.1$10.3 million increasedecrease to products revenues. In addition, a 7% decrease in average sales price combined with a 2% decrease in sales volumes at our specialty terminals primarily as a resultblending and packaging facilities resulted in an $8.8 million decrease in products revenues.
Cost of the Hondo asphalt plant being put into service on July 1, 2017.
Products revenues.products sold. A 28% increase22% decrease in sales volumes combined with a 4% increase14% decrease in average cost per gallon at our shore-based terminals resulted in a $9.8 million decrease in cost of products sold. In addition, an 11% decrease in average cost per gallon combined with a 2% decrease in sales pricevolume at our blending and packaging facilities resulted in a $20.3 million increase to products revenues. Offsetting this increase was a 9% decrease in sales volumes offset by a 1% increase in average sales price at our shore based terminals resulting in a $5.4 million decrease in products revenues.
Cost of products sold. A 28% increase in sales volumes combined with a 10% increase in average cost per gallon at our blending and packaging facilities resulted in a $19.0 million increase in cost of products sold. Offsetting this increase was a 9% decrease in sales volume offset by a 2% increase in average cost per gallon at our shore based terminals resulting in a $5.5$9.7 million decrease in cost of products sold.
Operating expenses. Operating expenses at our shore-based terminals decreased by $8.0$2.9 million, primarily due to the 2017 period including an increase in the accrual related to asset retirement obligations of $6.3 million. Additionally, lease expense decreased $0.7 million as a result of closing several facilities. Operating expenses at our specialty terminals decreased $1.8 million, primarily due to the 2017 period including $2.5 million in hurricane expenses offset by an increase of $1.0 million in expenses at our Hondo facility which was placed in service in July of 2017. Offsetting this decrease was a $0.8 million increase at our Smackover refinery due to an increase in utilities of $0.4 million, $0.2 milliondecreases in repairs and maintenance of $1.0 million, miscellaneous operating expenses of $0.8, compensation expense of $0.7 million, and $0.2professional fees of $0.3 million in professional fees.across our terminals.
Selling, general and administrative expenses. Selling, general and administrative expenses decreasedincreased primarily as a result of decreasedan increase in legal expenses.
Impairment of long-lived assets. This represents the loss on impairment of non-core operating assets in 2017.
Depreciation and amortization. The decrease in depreciation and amortization is due to the disposition of assets at several closed shore-based facilities, offset by recent capital expenditures.
Other operating income, net. Other operating income, net represents gains from the disposition of property, plant and equipment.
Comparative Results of Operations for the Twelve Months Ended December 31, 2017 and 2016
|
| | | | | | | | | | | | | |
| | Year Ended December 31, | | Variance | | Percent Change |
| | 2017 | | 2016 | | |
| | (In thousands) | | |
| Revenues: | | | | | | | |
| Services | $ | 105,703 |
| | $ | 128,783 |
| | $ | (23,080 | ) | | (18)% |
| Products | 130,466 |
| | 113,580 |
| | 16,886 |
| | 15% |
| Total revenues | 236,169 |
| | 242,363 |
| | (6,194 | ) | | (3)% |
| | | | | | | | |
| Cost of products sold | 118,832 |
| | 102,883 |
| | 15,949 |
| | 16% |
| Operating expenses | 63,191 |
| | 65,292 |
| | (2,101 | ) | | (3)% |
| Selling, general and administrative expenses | 5,832 |
| | 4,677 |
| | 1,155 |
| | 25% |
| Impairment of long-lived assets | 600 |
| | 15,252 |
| | (14,652 | ) | | (96)% |
| Depreciation and amortization | 45,160 |
| | 45,484 |
| | (324 | ) | | (1)% |
| | 2,554 |
| | 8,775 |
| | (6,221 | ) | | (71)% |
| Other operating income, net | 751 |
| | 35,368 |
| | (34,617 | ) | | (98)% |
| Operating income | $ | 3,305 |
| | $ | 44,143 |
| | $ | (40,838 | ) | | (93)% |
| | | | | | | | |
| Lubricant sales volumes (gallons) | 21,897 |
| | 17,995 |
| | 3,902 |
| | 22% |
| Shore-based throughput volumes (guaranteed minimum) (gallons) | 144,998 |
| | 200,000 |
| | (55,002 | ) | | (28)% |
| Smackover refinery throughput volumes (guaranteed minimum BBL per day) | 6,500 |
| | 6,500 |
| | — |
| | —% |
| Corpus Christi crude terminal (barrels per day) | — |
| | 66,167 |
| | (66,167 | ) | | (100)% |
Services revenues.Services revenue decreased primarily as a result of decreased throughput volumes and pass-through revenues at our Corpus Christi crude terminal, which was sold on December 21, 2016.
Products revenues. An 11% increase in sales volumes offset by a 1% decrease in average sales price at our blending and packaging facilities resulted in a $5.9 million increase to products revenues. Products revenues at our shore-based terminals increased $11.0 million resulting from an 18% increase in average sales price and a 1% increase in sales volume.
Cost of products sold. An 11% increase in sales volumes at our blending and packaging facilities resulted in a $4.9 million increase in cost of products sold. Average cost per gallon increased 2%, resulting in a $0.8 million increase in cost of products sold. Cost of products sold at our shore-based terminals increased $10.1 million resulting from an 19% increase in average cost per gallon and a 1% increase in sales volumes.
Operating expenses. Operating expenses at our specialty terminals decreased $4.8 million, primarily as a result of the disposition of the Corpus Christi crude terminalling assets in the fourth quarter 2016 of $7.6 million, offset by hurricane expenses of $2.5 million. Operating expenses at our shore-based terminals increased by $3.2 million, primarily due to a $5.5 million increase in the accrual related to asset retirement obligations at leased terminal facilities and hurricane expenses of $0.3 million, offset by $2.7 million decrease associated with closed facilities.
Selling, general and administrative expenses. Selling, general and administrative expenses increased primarily due to increased legal fees of $0.6 million and compensation expense of $0.5 million.
Impairment of long-lived assets. This represents the loss on impairment of non-core operating assets.
Depreciation and amortization. The decrease in depreciation and amortization is due to the impact of the disposition of assets and assets being fully depreciated, offset by capital expenditures.
Other operating income (loss), net. Other operating income (loss), net represents gains and losses from the disposition of property, plant and equipment.
Gain on involuntary conversion of property, plant and equipment. The 2016 period includes the$0.1 million gain on the dispositioninvoluntary conversion of the Corpus Christi crudeproperty, plant and equipment is due to insurance proceeds received related to structural damage of terminalling assets during a weather incident at our Neches Terminal in May of $37.3 million.2019.
Natural Gas ServicesTransportation Segment
Comparative Results of Operations for the Twelve MonthsYears Ended December 31, 20182020 and 2019
| | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | Variance | | Percent Change |
| | 2020 | | 2019 | | |
| | (In thousands) | | |
| Revenues | $ | 150,285 | | | $ | 183,740 | | | $ | (33,455) | | | (18)% |
| Operating expenses | 122,064 | | | 141,713 | | | (19,649) | | | (14)% |
| Selling, general and administrative expenses | 8,245 | | | 8,199 | | | 46 | | | 1% |
| | | | | | | |
| | | | | | | |
| Depreciation and amortization | 17,505 | | | 15,307 | | | 2,198 | | | 14% |
| | 2,471 | | | 18,521 | | | (16,050) | | | (87)% |
| Other operating loss, net | (690) | | | (1,691) | | | 1,001 | | | 59% |
| Operating income | $ | 1,781 | | | $ | 16,830 | | | $ | (15,049) | | | (89)% |
2017
|
| | | | | | | | | | | | | |
| | Year Ended December 31, | | Variance | | Percent Change |
| | 2018 | | 2017 | | |
| | (In thousands) | | |
| Revenues: | | | | | | | |
| Services | $ | 52,109 |
| | $ | 58,817 |
| | $ | (6,708 | ) | | (11)% |
| Products | 496,026 |
| | 474,091 |
| | 21,935 |
| | 5% |
| Total revenues | 548,135 |
| | 532,908 |
| | 15,227 |
| | 3% |
| | | | | | | |
|
| Cost of products sold | 467,571 |
| | 425,073 |
| | 42,498 |
| | 10% |
| Operating expenses | 24,065 |
| | 22,347 |
| | 1,718 |
| | 8% |
| Selling, general and administrative expenses | 9,063 |
| | 11,106 |
| | (2,043 | ) | | (18)% |
| Depreciation and amortization | 21,283 |
| | 24,916 |
| | (3,633 | ) | | (15)% |
| | 26,153 |
| | 49,466 |
| | (23,313 | ) | | (47)% |
| Other operating loss, net | (1,215 | ) | | (89 | ) | | (1,126 | ) | | (1,265)% |
| Operating income | $ | 24,938 |
| | $ | 49,377 |
| | $ | (24,439 | ) | | (49)% |
| | | | | | | | |
| NGLs Volumes (barrels) | 10,223 |
| | 10,487 |
| | (264 | ) | | (3)% |
Services Revenues. The decrease in services revenue is primarily a result of lower firm storage re-contracting rates at our natural gas storage facilities.
Products Revenues. Our NGL average sales price per barrel increased $3.31, or 7%, resulting in an increase to products revenues of $34.7 million. The increase in average sales price per barrel was a result of an increase in market prices. Product sales volumes decreased 3%, decreasing revenues $12.8 million.
Cost of products soldMarine Transportation Revenues. Our average cost per barrel increased $5.20, or 13%, increasing cost of products sold by $54.6 million. The increase in average cost per barrel was a result of an increase in market prices. The decrease in sales volume of 3% resulted in a $12.1 million decrease to cost of products sold. Our margins decreased $1.89 per barrel, or 40% during the period.
Operating expenses. Operating expenses increased $1.4 million at our natural gas storage facilities, primarily as a result of $0.6 million in increased utility expense, $0.5 million in insurance premiums, and $0.3 million in park and loan expense. Additionally, repairs and maintenance expense at our underground NGL storage facility increased $0.3 million.
Selling, general and administrative expenses. Selling, general and administrative expenses decreased primarily as a result of decreased compensation expense.
Depreciation and amortization. Depreciation and amortization decreased primarily due to a $3.9 million decrease in amortization related to contracts acquired during the purchase of Cardinal Gas Storage Partners, LLC (“Cardinal”), offset by a $0.3 million increase in depreciation expense related to recent capital expenditures.
Other operating loss, net. Other operating loss, net represents losses from the disposition of property, plant and equipment.
Comparative Results of Operations for the Twelve Months Ended December 31, 2017 and 2016
|
| | | | | | | | | | | | | |
| | Year Ended December 31, | | Variance | | Percent Change |
| | 2017 | | 2016 | | |
| | (In thousands) | | |
| Revenues: | | | | | | | |
| Services | $ | 58,817 |
| | $ | 61,133 |
| | $ | (2,316 | ) | | (4)% |
| Products | 474,091 |
| | 330,200 |
| | 143,891 |
| | 44% |
| Total revenues | 532,908 |
| | 391,333 |
| | 141,575 |
| | 36% |
| | | | | | | | |
| Cost of products sold | 425,073 |
| | 292,573 |
| | 132,500 |
| | 45% |
| Operating expenses | 22,347 |
| | 23,152 |
| | (805 | ) | | (3)% |
| Selling, general and administrative expenses | 11,106 |
| | 8,970 |
| | 2,136 |
| | 24% |
| Depreciation and amortization | 24,916 |
| | 28,081 |
| | (3,165 | ) | | (11)% |
| | 49,466 |
| | 38,557 |
| | 10,909 |
| | 28% |
| Other operating loss, net | (89 | ) | | (110 | ) | | 21 |
| | 19% |
| Operating income | $ | 49,377 |
| | $ | 38,447 |
| | $ | 10,930 |
| | 28% |
| | | | | | | | |
| NGLs Volumes (barrels) | 10,487 |
| | 9,532 |
| | 955 |
| | 10% |
Services Revenues. The decrease in services revenue is primarily a result of decreased storage rates at our Arcadia gas storage facility.
Products Revenues. Our NGL average sales price per barrel increased $10.57, or 31%, resulting in an increase to products revenues of $100.7 million. The increase in average sales price per barrel was a result of an increase in market prices. Product sales volumes increased 10%, increasing revenues $43.2 million.
Cost of products sold. Our average cost per barrel increased $9.84, or 32%, increasing cost of products sold by $93.8 million. The increase in average cost per barrel was a result of an increase in market prices. The increase in sales volume of 10% resulted in a $38.7 million increase to cost of products sold. Our margins increased $0.73 per barrel, or 18% during the period.
Operating expenses. Operating expenses decreased $0.8 million due to $0.3 million of decreased maintenance expense at our NGL East Texas pipeline, decreased compensation expense of $0.3 million, and decreased repairs and maintenance at our underground NGL storage facility of $0.2 million.
Selling, general and administrative expenses. Selling, general and administrative expenses increased primarily as a result of increased compensation expense.
Depreciation and amortization. Depreciation and amortization decreased primarily due to a $3.7 million decrease in amortization related to contracts acquired during the purchase of Cardinal Gas Storage Partners, LLC (“Cardinal”), offset by a $0.6 million increase in depreciation expense related to recent capital expenditures.
Other operating loss, net. Other operating loss, net represents losses from the disposition of property, plant and equipment.
Sulfur Services Segment
Comparative Results of Operations for the Twelve Months Ended December 31, 2018 and 2017
|
| | | | | | | | | | | | | |
| | Year Ended December 31, | | Variance | | Percent Change |
| | 2018 | | 2017 | | |
| | (In thousands) | | |
| Revenues: | | | | | | | |
| Services | $ | 11,148 |
| | $ | 10,952 |
| | $ | 196 |
| | 2% |
| Products | 121,388 |
| | 123,732 |
| | (2,344 | ) | | (2)% |
| Total revenues | 132,536 |
| | 134,684 |
| | (2,148 | ) | | (2)% |
| | | | | | | | |
| Cost of products sold | 90,780 |
| | 82,760 |
| | 8,020 |
| | 10% |
| Operating expenses | 11,618 |
| | 13,783 |
| | (2,165 | ) | | (16)% |
| Selling, general and administrative expenses | 4,326 |
| | 4,136 |
| | 190 |
| | 5% |
| Depreciation and amortization | 8,485 |
| | 8,117 |
| | 368 |
| | 5% |
| | 17,327 |
| | 25,888 |
| | (8,561 | ) | | (33)% |
| Other operating loss, net | (111 | ) | | (26 | ) | | (85 | ) | | (327)% |
| Operating income | $ | 17,216 |
| | $ | 25,862 |
| | $ | (8,646 | ) | | (33)% |
| | | | | | | | |
| Sulfur (long tons) | 688.0 |
| | 807.0 |
| | (119.0 | ) | | (15)% |
| Fertilizer (long tons) | 277.0 |
| | 276.0 |
| | 1.0 |
| | —% |
| Sulfur services volumes (long tons) | 965.0 |
| | 1,083.0 |
| | (118.0 | ) | | (11)% |
Services Revenues. Services revenues increased as a result of a contractually prescribed index based fee adjustment.
Products Revenues. ProductsInland revenues decreased $14.8$11.2 million, due to an 11% decrease in sales volumes, primarily related to a 15% decrease in sulfur volumes. Offsetting, products revenues increased $12.5 million as a result of a 10% rise in average sulfur services sales prices.
Cost of products sold. A 23% increase in prices impacted cost of products sold by $19.1 million, resulting from an increase in commodity prices. An 11% decrease in sales volumes resulted in an offsetting decrease in cost of products sold of $11.1 million. Margin per tontows, transportation rates and utilization. In addition, offshore revenue decreased $6.11, or 16%.
Operating expenses. Our operating expenses decreased primarily as a result of a $1.5 million reduction in compensation expense and $0.4 million in lower property taxes. Additionally, outside towing decreased $0.3 million, railcar leases decreased $0.3 million, and repairs and maintenance on marine vessels decreased $0.2 million. An offsetting increase of $0.5 million resulted from an increase in marine fuel and lube.
Selling, general and administrative expenses. Increased primarily as a result of increased compensation expense.
Depreciation and amortization. Depreciation expense increased $0.4 million due to capital projects being completed and placed in service in the fourth quarter of 2017 and throughout 2018.
Other operating loss, net. Other operating loss, net represents losses from the disposition of property, plant and equipment.
Comparative Results of Operations for the Twelve Months Ended December 31, 2017 and 2016
|
| | | | | | | | | | | | | |
| | Year Ended December 31, | | Variance | | Percent Change |
| | 2017 | | 2016 | | |
| | (In thousands) | | |
| Revenues: | | | | | | | |
| Services | $ | 10,952 |
| | $ | 10,800 |
| | $ | 152 |
| | 1% |
| Products | 123,732 |
| | 130,258 |
| | (6,526 | ) | | (5)% |
| Total revenues | 134,684 |
| | 141,058 |
| | (6,374 | ) | | (5)% |
| | | | | | | |
|
| Cost of products sold | 82,760 |
| | 88,325 |
| | (5,565 | ) | | (6)% |
| Operating expenses | 13,783 |
| | 13,771 |
| | 12 |
| | —% |
| Selling, general and administrative expenses | 4,136 |
| | 3,861 |
| | 275 |
| | 7% |
| Depreciation and amortization | 8,117 |
| | 7,995 |
| | 122 |
| | 2% |
| | 25,888 |
| | 27,106 |
| | (1,218 | ) | | (4)% |
| Other operating loss, net | (26 | ) | | (291 | ) | | 265 |
| | 91% |
| Operating income | $ | 25,862 |
| | $ | 26,815 |
| | $ | (953 | ) | | (4)% |
| | | | | | | | |
| Sulfur (long tons) | 807.0 |
| | 797.0 |
| | 10.0 |
| | 1% |
| Fertilizer (long tons) | 276.0 |
| | 262.0 |
| | 14.0 |
| | 5% |
| Sulfur services volumes (long tons) | 1,083.0 |
| | 1,059.0 |
| | 24.0 |
| | 2% |
Services Revenues. Services revenues increased as a result of a contractually prescribed index based fee adjustment.
Products Revenues. Products revenues decreased $9.3 million as a result of a 7% decline in average sales price. Offsetting, products revenues increased $2.8$2.4 million due to a 2% increase in sales volumes, primarily related to a 5% increase in fertilizer volumes.
Cost of products sold. An 8% decrease in prices reduced cost of products sold by $7.4 million, resulting from a decline in commodity prices. A 2% increase in sales volumes caused an offsetting increase in cost of products sold of $1.9 million. Margin per ton decreased $1.78, or 4%.
Selling, generaltransportation rates and administrative expenses. Our selling, general and administrative expenses increased $0.3 million due to increased compensation expense offset slightly by a decrease of $0.1 million in bad debt expense.
Depreciation and amortization. Depreciation expense increased $0.1 million due to capital projects being completed and placed in service during the second half of 2016.
Other operating loss, net. Other operating loss, net represents losses from the disposition of property, plant and equipment.
Marine Transportation Segment
Comparative Results of Operations for the Twelve Months Ended December 31, 2018 and 2017
|
| | | | | | | | | | | | | |
| | Year Ended December 31, | | Variance | | Percent Change |
| | 2018 | | 2017 | | |
| | (In thousands) | | |
| Revenues | $ | 52,830 |
| | $ | 51,915 |
| | $ | 915 |
| | 2% |
| Operating expenses | 41,086 |
| | 44,028 |
| | (2,942 | ) | | (7)% |
| Selling, general and administrative expenses | 1,060 |
| | 358 |
| | 702 |
| | 196% |
| Impairment of long-lived assets | — |
| | 1,625 |
| | (1,625 | ) | | (100)% |
| Depreciation and amortization | 7,590 |
| | 7,002 |
| | 588 |
| | 8% |
| | 3,094 |
| | (1,098 | ) | | 4,192 |
| | 382% |
| Other operating loss, net | (381 | ) | | (113 | ) | | (268 | ) | | (237)% |
| Operating income (loss) | $ | 2,713 |
| | $ | (1,211 | ) | | $ | 3,924 |
| | 324% |
Revenues. An increase of $1.8 million in inland revenue was primarily related to new equipment being placed in service.utilization. Revenue was also impacted by an increasea decrease in pass-through revenue (primarily fuel) of $2.1$3.3 million. An offsetting decrease of $3.1 million is attributable to revenue related to equipment sold or being classified as idle or held for sale. A $0.2 million increase in offshore revenues is primarily the result of increased utilization.
Land Transportation Revenues. An 11% decrease in miles of product transported resulted in a decrease to freight revenue of $11.5 million. Transportation rates increased 2% resulting in an offsetting increase of $1.5 million. Additionally, fuel surcharge revenue decreased $6.6 million.
Operating expenses. The decrease in operating expenses is primarily a result of decreased labor and burden of $1.8 million, a reclassification of labor and burden from operating expense to selling general and administrative expense for the 2018 period of $0.7 million, repairs and maintenance of $0.8 million, barge rental expense of $1.0 million, property and liability insurance premiums of $1.0 million, and outside towing of $0.3 million. These decreases were offset by an increase in pass through expenses (primarily fuel) of $2.2$8.5 million, marine Jones Act claimscompensation expense of $0.4$8.1 million, repairs and maintenance of $2.1 million, and contract laboroutside services of $0.3$0.7 million.
Selling, general and administrative expenses. Selling, general and administrative expenses increased primarily due to the reclassification of expenses from operating expense to selling, general, and administrative expense of $0.7 million for the 2018 period.remained relatively consistent.
Impairment of long-lived assets. This represents the loss on impairment of non-core operating assets.
Depreciation and amortization. Depreciation and amortization increased as a result of recent capital expenditures offset by asset disposals.
Other operating loss,income (loss), net. Other operating loss represents losses from the disposition of property, plant and equipment.
Sulfur Services Segment
Comparative Results of Operations for the Years Ended December 31, 2020 and 2019
| | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | Variance | | Percent Change |
| | 2020 | | 2019 | | |
| | (In thousands) | | |
| Revenues: | | | | | | | |
| Services | $ | 11,659 | | | $ | 11,434 | | | $ | 225 | | | 2% |
| Products | 96,361 | | | 99,906 | | | (3,545) | | | (4)% |
| Total revenues | 108,020 | | | 111,340 | | | (3,320) | | | (3)% |
| | | | | | | |
| Cost of products sold | 62,920 | | | 71,806 | | | (8,886) | | | (12)% |
| Operating expenses | 10,891 | | | 10,639 | | | 252 | | | 2% |
| Selling, general and administrative expenses | 4,791 | | | 4,784 | | | 7 | | | —% |
| Depreciation and amortization | 12,012 | | | 11,332 | | | 680 | | | 6% |
| | 17,406 | | | 12,779 | | | 4,627 | | | 36% |
| Other operating income, net | 6,751 | | | 1,210 | | | 5,541 | | | 458% |
| Gain on involuntary conversion of property, plant and equipment | 4,844 | | | — | | | 4,844 | | | |
| Operating income | $ | 29,001 | | | $ | 13,989 | | | $ | 15,012 | | | 107% |
| | | | | | | |
| Sulfur (long tons) | 642.0 | | | 665.0 | | | (23.0) | | | (3)% |
| Fertilizer (long tons) | 275.0 | | | 260.0 | | | 15.0 | | | 6% |
| Sulfur services volumes (long tons) | 917.0 | | | 925.0 | | | (8.0) | | | (1)% |
Services Revenues. Services revenues increased slightly as a result of a contractually prescribed, index-based fee adjustment.
Products Revenues. Products revenues decreased $2.7 million as a result of a 3% decline in average sulfur services sales prices. Products revenues decreased an additional $0.8 million due to a 1% decrease in sales volumes, primarily related to a 3% decrease in sulfur volumes.
Cost of products sold. A 12% decline in product cost impacted cost of products sold by $8.3 million, resulting from a decrease in commodity prices. A 1% decrease in sales volumes resulted in an additional decrease in cost of products sold of $0.5 million. Margin per ton increased $6.09, or 20%.
Operating expenses. Our operating expenses increased $0.4 million due to insurance claims and $0.4 million due to outside towing. Offsetting were decreases in marine fuel and lube of $0.3 million, assist tugs of $0.1 million and repairs and maintenance of $0.1 million.
Selling, general and administrative expenses. Selling, general and administrative expenses remained relatively consistent.
Depreciation and amortization. Depreciation and amortization expense increased $0.7 million as a result of recent capital expenditures.
Other operating income (loss), net. Other operating income, net increased $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 increase is related to a net gain from the disposition of property, plant and equipment.
Gain on involuntary conversion of property, plant and equipment. The $4.8 million gain 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 Twelve MonthsYears Ended December 31, 20172020 and 20162019
|
| | | | | | | | | | | | | |
| | Year Ended December 31, | | Variance | | Percent Change |
| | 2017 | | 2016 | | |
| | (In thousands) | | |
| Revenues | $ | 51,915 |
| | $ | 61,233 |
| | $ | (9,318 | ) | | (15)% |
| Operating expenses | 44,028 |
| | 53,118 |
| | (9,090 | ) | | (17)% |
| Selling, general and administrative expenses | 358 |
| | 18 |
| | 340 |
| | 1,889% |
| Impairment of long lived assets | 1,625 |
| | 11,701 |
| | (10,076 | ) | | (86)% |
| Impairment of goodwill | — |
| | 4,145 |
| | (4,145 | ) | | (100)% |
| Depreciation and amortization | 7,002 |
| | 10,572 |
| | (3,570 | ) | | (34)% |
| | (1,098 | ) | | (18,321 | ) | | 17,223 |
| | 94% |
| Other operating loss, net | (113 | ) | | (1,567 | ) | | 1,454 |
| | 93% |
| Operating income (loss) | $ | (1,211 | ) | | $ | (19,888 | ) | | $ | 18,677 |
| | 94% |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | Variance | | Percent Change |
| | 2020 | | 2019 | | |
| | (In thousands) | | |
| Products Revenues | $ | 247,484 | | | $ | 366,502 | | | (119,018) | | | (32)% |
| Cost of products sold | 228,345 | | | 341,800 | | | (113,455) | | | (33)% |
| Operating expenses | 3,008 | | | 6,300 | | | (3,292) | | | (52)% |
| Selling, general and administrative expenses | 4,013 | | | 4,739 | | | (726) | | | (15)% |
| Depreciation and amortization | 2,456 | | | 2,469 | | | (13) | | | (1)% |
| | 9,662 | | | 11,194 | | | (1,532) | | | (14)% |
| Other operating income (loss), net | (2) | | | 16,402 | | | (16,404) | | | (100)% |
| Operating income | $ | 9,660 | | | $ | 27,596 | | | $ | (17,936) | | | (65)% |
| | | | | | | |
| NGLs Volumes (barrels) | 9,231 | | | 9,820 | | | (589) | | | (6)% |
Inland
Products Revenues. Our NGL average sales price per barrel decreased $10.51, or 28%, resulting in a decrease to products revenues of $103.2 million. The decrease in average sales price per barrel was a result of a decrease in market prices. Product sales volumes decreased 6%, decreasing revenues $15.8 million.
Cost of products sold. AOur average cost per barrel decreased $10.07, or 29%, decreasing cost of products sold by $98.9 million. The decrease in average cost per barrel was a result of $7.2 million is primarily attributable to decreased transportation rates and decreased utilizationa decrease in market prices. The decrease in sales volume of the inland fleet resulting from an abundance of supply of marine equipment6% resulted in our predominantly Gulf Coast market.
Offshore revenues. A $2.4a $14.6 million decrease in offshore revenues is primarilyto cost of products sold. Our margins decreased $0.44 per barrel, or 18% during the result of the 2016 period including the recognition of previously deferred revenues of $1.5 million and decreased utilization of the offshore fleet due to downtime associated with regulatory inspections of $0.7 million.period.
Operating expenses. The decrease inOperating expenses decreased $2.3 million related to the divestiture of assets and the elimination of the associated expenses. In addition, operating expenses is primarily a resultdecreased $1.0 million related to the settlement of decreased labor and burden of $3.9 million, repairs and maintenance of $1.3 million, Jones Act claims of $0.8 million, pass-through expenses (primarily barge tank cleaning) of $0.7 million, outside towing of $0.4 million, barge rental expense of $0.4 million, property taxes of $0.3 million, operating supplies of $0.3 million, and propertyan insurance premiums of $0.2 million.claim for less than anticipated.
Selling, general and administrative expenses. Selling, general and administrative expenses increased primarily due to the 2016 period including the collection of a previously deemed uncollectible receivable of $0.5decreased $0.7 million offset by decreased legal fees of $0.1 million.
Impairment of long-lived assets. This represents the loss on impairment of non-core operating assets.
Loss on impairment of goodwill. This represents the loss on impairment of goodwill in the Marine Transportation reporting unit during the second quarter of 2016.
Depreciation and amortization. Depreciation and amortization decreased as a result of the disposal of property, plant and equipment combined with the impairment of long-lived assets recognized in the fourth quarter of 2016, offset by recent capital expenditures.decreased compensation expense.
Other operating loss,income (loss), net. Other operating lossincome (loss), net represents losses fromthe gains associated with the disposition of property, plant and equipment.the East Texas Pipeline in 2019.
Interest Expense
Comparative Components of Interest Expense, Net for the Twelve MonthsYears Ended December 31, 20182020 and 20172019
| | | | | | | | | | | Year Ended December 31, | | Variance | | Percent Change |
| | Year Ended December 31, | | Variance | | Percent Change | | 2020 | | 2019 | |
| | 2018 | | 2017 | | | (In thousands) | | |
| | (In thousands) | | |
| Revolving loan facility | $ | 20,193 |
| | $ | 18,192 |
| | $ | 2,001 |
| | 11% | |
| 7.250 % senior unsecured notes | 27,101 |
| | 27,101 |
| | — |
| | —% | |
| Revolving credit facility | | Revolving credit facility | $ | 8,719 | | | $ | 18,550 | | | $ | (9,831) | | | (53)% |
| 7.250% senior unsecured notes | | 7.250% senior unsecured notes | 16,969 | | | 27,101 | | | (10,132) | | | (37)% |
| 11.5% senior secured notes | | 11.5% senior secured notes | 13,151 | | | — | | | 13,151 | | |
| 10.0% senior secured notes | | 10.0% senior secured notes | 2,105 | | | — | | | 2,105 | | |
| Amortization of deferred debt issuance costs | 3,445 |
| | 2,897 |
| | 548 |
| | 19% | Amortization of deferred debt issuance costs | 3,422 | | | 4,041 | | | (619) | | | (15)% |
| Amortization of debt premium | (306 | ) | | (306 | ) | | — |
| | —% | Amortization of debt premium | (191) | | | (306) | | | 115 | | | 38% |
| Other | 2,258 |
| | 1,532 |
| | 726 |
| | 47% | Other | 1,787 | | | 1,728 | | | 59 | | | 3% |
| Finance leases | | Finance leases | 291 | | | 672 | | | (381) | | | (57)% |
| Capitalized interest | (624 | ) | | (730 | ) | | 106 |
| | 15% | Capitalized interest | (43) | | | (5) | | | (38) | | | (760)% |
| Interest income | (30 | ) | | (943 | ) | | 913 |
| | 97% | Interest income | — | | | (91) | | | 91 | | | 100% |
| Total interest expense, net | $ | 52,037 |
| | $ | 47,743 |
| | $ | 4,294 |
| | 9% | Total interest expense, net | $ | 46,210 | | | $ | 51,690 | | | $ | (5,480) | | | (11)% |
Comparative Components of Interest Expense, Net for the Twelve Months Ended December 31, 2017 and 2016
|
| | | | | | | | | | | | | |
| | Year Ended December 31, | | Variance | | Percent Change |
| | 2017 | | 2016 | | |
| | (In thousands) | | |
| Revolving loan facility | $ | 18,192 |
| | $ | 19,482 |
| | $ | (1,290 | ) | | (7)% |
| 7.250 % senior unsecured notes | 27,101 |
| | 27,326 |
| | (225 | ) | | (1)% |
| Amortization of deferred debt issuance costs | 2,897 |
| | 3,684 |
| | (787 | ) | | (21)% |
| Amortization of debt premium | (306 | ) | | (306 | ) | | — |
| | —% |
| Impact of interest rate derivative activity, including cash settlements | — |
| | (995 | ) | | 995 |
| | 100% |
| Other | 1,532 |
| | 291 |
| | 1,241 |
| | 426% |
| Capitalized interest | (730 | ) | | (1,126 | ) | | 396 |
| | 35% |
| Interest income | (943 | ) | | (2,256 | ) | | $ | 1,313 |
| | 58% |
| Total interest expense, net | $ | 47,743 |
| | $ | 46,100 |
| | $ | 1,643 |
| | 4% |
Indirect Selling, General and Administrative Expenses
| | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | Variance | | Percent Change |
| | 2020 | | 2019 | | |
| | (In thousands) | | |
| Indirect selling, general and administrative expenses | $ | 17,909 | | | $ | 17,981 | | | $ | (72) | | | —% |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | Variance | | Percent Change | | Year Ended December 31, | | Variance | | Percent Change |
| | 2018 | | 2017 | | | | 2017 | | 2016 | | |
| | (In thousands) | | | | (In thousands) | | |
| Indirect selling, general and administrative expenses | $ | 17,901 |
| | $ | 17,332 |
| | $ | 569 |
| | 3% | | $ | 17,332 |
| | $ | 16,795 |
| | $ | 537 |
| | 3% |
The increase in indirect Indirect selling, general and administrative expenses remained consistent from 20172019 to 2018 is primarily a result of increased unit based compensation expense.
The increase in indirect selling, general and administrative expenses from 2016 to 2017 is primarily a result of a $0.6 million increase in audit, consulting and other professional fees.
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 Conflicts Committeeboard of directors of our general partner approved the following reimbursement amounts:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | Variance | | Percent Change |
| | 2020 | | 2019 | | |
| | (In thousands) | | |
| Board approved reimbursement amount | $ | 16,410 | | | $ | 16,657 | | | $ | (247) | | | (1)% |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | Variance | | Percent Change | | Year Ended December 31, | | Variance | | Percent Change |
| | 2018 | | 2017 | | | | 2017 | | 2016 | | |
| | (In thousands) | | | | (In thousands) | | |
| Conflicts Committee approved reimbursement amount | $ | 16,416 |
| | $ | 16,416 |
| | $ | — |
| | —% | | $ | 16,416 |
| | $ | 13,033 |
| | $ | 3,383 |
| | 26% |
The amounts reflected above represent our allocable share of such expenses. The Conflicts Committeeboard of directors of our general partner will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.
Liquidity and Capital Resources
General
Our primary sources of liquidity to meet operating expenses, service our indebtedness, pay distributions to our unitholders and fund capital expenditures have historically been cash flows generated by our operations, borrowings under our revolving credit facility and access to debt and equity capital markets, both public and private. Management believes that expenditures forSet forth below is a description of our current capital projects will be funded with cash flows from operations, current cash balances and our current borrowing capacity under the expanded revolving credit facility. Given the current environment, we have altered and reduced our planned growth capital expenditures. We believe that controlling our spending in an effort to preserve liquidity is prudent and reduces our need for near-term access to the somewhat uncertain capital markets.
Our ability to satisfy our working capital requirements, to fund planned capital expenditures and to satisfy our debt service obligations will also depend upon our future operating performance, which is subject to certain risks. Please read "Item 1A. Risk Factors - Risks related to Our Business" for a discussion of such risks.
Recent Debt Financing Activity
Credit Facility Amendment. On February 21, 2018, we amended our revolving credit facility in order to achieve two primary objectives, the first of which was to accommodate growth capital expenditures necessary for the previously announced WTLPG expansion project. Starting in the first quarter of 2018, the amendment provided short-term (5 quarters) covenant relief by increasing the total leverage ratio to 5.75 to 1.00 (first and second quarters of 2018) with step downs to 5.50 to 1.00 (third and fourth quarters of 2018 and first quarter of 2019) and to 5.25 to 1.00 beginning in the second quarter of 2019. Additionally, the facility was amended to establish an inventory financing sublimit tranche for borrowings related to our NGL (butane) marketing business, which is a part of and not in addition to the already existing commitments under the revolving credit facility. This sublimit is not to exceed $75.0 million, with seasonal step downs to $10.0 million for the months of March through June of each fiscal year. The sublimit is subject to a monthly borrowing base not to exceed 90% of the value of forward sold/hedged inventory. In conjunction with the sale of WTLPG on July 31, 2018, we amended our revolving credit facility which included, among other things, further revising our leverage covenants from the February 21, 2018 amendment (discussed in detail above). Total Indebtedness to EBITDA and Senior Secured Indebtedness to EBITDA (each as defined in the credit agreement) was amended to 5.25 times and 3.50 times, respectively. No changes were made to the Consolidated Interest Coverage Ratio (as defined in the credit agreement) of 2.50 times. periods indicated.
Due to the foregoing, we believe that cash generated from operations and our borrowing capacity under our credit facility will be sufficient to meet our working capital requirements and anticipated maintenance capital expenditures in 2019.
Finally, our ability to satisfy our working capital requirements, to fund planned capital expenditures and to satisfy our debt service obligations will depend upon our future operating performance, which is subject to certain risks. Please read "Item 1A. Risk Factors - Risks Relating to Our Business" for a discussion of such risks.
Cash Flows - Twelve MonthsYear Ended December 31, 20182020 Compared to Twelve MonthsYear Ended December 31, 20172019
The following table details the cash flow changes between the twelve monthsyears ended December 31, 20182020 and 2017:2019:
|
| | | | | | | | | | | | | |
| | Years Ended December 31, | | Variance | | Percent Change |
| | 2018 | | 2017 | | |
| | (In thousands) | | |
| Net cash provided by (used in): | | | | | | | |
| Operating activities | $ | 90,726 |
| | $ | 67,506 |
| | $ | 23,220 |
| | 34% |
| Investing activities | 147,654 |
| | (37,878 | ) | | 185,532 |
| | 490% |
| Financing activities | (238,170 | ) | | (29,616 | ) | | (208,554 | ) | | (704)% |
| Net increase (decrease) in cash and cash equivalents | $ | 210 |
| | $ | 12 |
| | $ | 198 |
| | 34% |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, | | Variance | | Percent Change |
| | 2020 | | 2019 | | |
| | (In thousands) | | |
| Net cash provided by (used in): | | | | | | | |
| Operating activities | $ | 64,785 | | | $ | 75,815 | | | $ | (11,030) | | | (15)% |
| Investing activities | 2,604 | | | 174,828 | | | (172,224) | | | (99)% |
| Financing activities | (65,287) | | | (248,087) | | | 182,800 | | | 74% |
| Net decrease in cash and cash equivalents | $ | 2,102 | | | $ | 2,556 | | | $ | (454) | | | (18)% |
Net cash provided by operating activities.The increasedecrease in net cash provided by operating activities for the twelve monthsyear ended December 31, 20182020 includes a $52.6 million favorable variance in working capital and a $4.8$7.8 million decrease in other non-cash charges. Offsetting wasnet cash received from discontinued operating activities, a decrease in operating results of $20.6$11.3 million, and an unfavorable variance in other non-current assets and liabilities of $2.1$0.9 million. Net cash provided by discontinued operating activities decreased $2.0An additional $6.0 million decrease in other non-cash charges was primarily due to a $4.9 million gain on involuntary conversion of property, plant and equipment. Offsetting this decrease was a favorable variance in working capital of $15.0 million.
Net cash provided by (used in) investing activities. Net cash provided by investing activities for the twelve monthsyear ended December 31, 2018 increased primarily as a result of a $177.3 million increase in net cash provided by2020 decreased $172.2 million. Cash received from discontinued investing activities. Additionally, aactivities decreased $209.2 million. Offsetting such decrease, in cash used in investing activities as a resultnet proceeds from the sale of property, plant and equipment increased $4.5 million and proceeds received from the acquisitioninvoluntary conversion of certain asphalt terminalling assets from Martin Resource Management in 2017, compared to no acquisitions in 2018, resulted in an increase of $19.5property, plant and equipment increased $2.5 million. Further, aA decrease in cash used of $2.3$6.2 million is due to lowerresulted from higher payments for capital expenditures and plant turnaround costs in 20182019 as well as a $1.0decrease of $23.7 million increase in proceeds received as a result of higher sales of property, plant and equipment in 2018. Offsetting was a $15.0 million decline in proceeds receivedcash used resulting from repaymentassets acquired from MTI in January of the Note receivable - affiliate in 2017 as compared to none in 2018.2019.
Net cash used in financing activities. Net cash used in financing activities increased for the twelve monthsyear ended December 31, 20182020 decreased primarily as a result of an increase in net repayments of long-term borrowings of $160.0a $102.4 million as well as a decrease in proceeds received from the issuance of common units (including the related general partner contribution) of $52.3 million. Also contributing was an increase in cash distributions paid of $1.5 million and an additional $1.2 million in costs associated with our credit facility amendment. Offsetting was a decrease in cash used of $6.7 million related to excess purchase price over the carrying value of acquired assets in common control transactions.
Cash Flows - Twelve Months Ended December 31, 2017 Compared to Twelve Months Ended December 31, 2016
The following table details the cash flow changes between the twelve months ended December 31, 2017 and 2016:
|
| | | | | | | | | | | | | |
| | Years Ended December 31, | | Variance | | Percent Change |
| | 2017 | | 2016 | | |
| | (In thousands) | | |
| Net cash provided by (used in): | | | | | | | |
| Operating activities | $ | 67,506 |
| | $ | 110,848 |
| | $ | (43,342 | ) | | (39)% |
| Investing activities | (37,878 | ) | | 63,839 |
| | (101,717 | ) | | (159)% |
| Financing activities | (29,616 | ) | | (174,703 | ) | | 145,087 |
| | 83% |
| Net decrease in cash and cash equivalents | $ | 12 |
| | $ | (16 | ) | | $ | 28 |
| | 175% |
Net cash provided by operating activities. The decline intransactions during 2019. Additionally, net cash provided by operating activities includes a decrease in operating results from continuing operations of $14.5 million and a $29.6 million unfavorable variance in working capital. Further decreases were due to an $11.8 million decrease in other non-cash charges and a decrease in distributions received from WTLPG of $2.1 million. Offsetting was an increase of $14.6 million attributable to a favorable variance in other non-current assets and liabilities.
Net cash (used in) provided by investing activities. Net cash from investing activities decreased as a result of a decrease of $100.1 million in net proceeds from the sale of property, plant and equipment. The 2017 period also included an
acquisition of $19.5 million compared to an acquisition of $2.2 million in 2016, resulting in a $17.4 million decrease in cash. Offsetting these decreases was an increase of $15.0 million for proceeds received from repayment of the Note receivable - affiliate and a decrease in payments for capital expenditures and plant turnaround costs of $1.2 million.
Net cash used in financing activities. Net cash used in financing activities decreased for the year ended December 31, 2017 as a result of a decrease in net repayments of long-term borrowings of $57.0 million. Proceeds received from the issuance of common units (including the related general partner contribution) increased net cash by $52.2 million. Also contributing was a decrease indecreased $35.3 million and cash distributions paid of $41.2 million and $5.2 million less indecreased $43.8 million. Offsetting such decrease, costs associated with our credit facility amendment. Offsetting was an increase of $10.9 million related to excess purchase price over the carrying value of acquired assets in common control transactions.increased $0.6 million.
Capital Resources
Historically, we have generally satisfied our working capital requirements and funded our capital expenditures with cash generated from operations and borrowings. We expect our primary sources of funds for short-term liquidity will be cash flows from operations and borrowings under our credit facility.
Total Contractual Obligations. Obligations
A summary of our total contractual obligations as of December 31, 2018,2020 is as follows (dollars in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Payments due by period |
| Type of Obligation | Total
Obligation | | Less than
One Year | | 1-3
Years | | 3-5
Years | | Due
Thereafter |
| Revolving credit facility | $ | 148,000 | | | $ | — | | | $ | 148,000 | | | $ | — | | | $ | — | |
| 7.25% senior unsecured notes, due 2021 | 28,790 | | | 28,790 | | | — | | | — | | | — | |
| 10.0% senior secured notes, due 2024 | 53,750 | | | — | | | — | | | 53,750 | | | — | |
| 11.5% senior secured notes, due 2025 | 291,970 | | | — | | | — | | | 291,970 | | | — | |
| Throughput commitment | 9,711 | | | 6,439 | | | 3,272 | | | — | | | — | |
| Operating leases | 26,379 | | | 8,445 | | | 9,266 | | | 2,838 | | | 5,830 | |
| Finance lease obligations | 2,996 | | | 2,707 | | | 289 | | | — | | | — | |
| Interest payable on finance lease obligations | 35 | | | 26 | | | 9 | | | — | | | — | |
| Interest payable on fixed long-term debt obligations | 157,633 | | | 39,213 | | | 77,903 | | | 40,517 | | | — | |
| Total contractual cash obligations | $ | 719,264 | | | $ | 85,620 | | | $ | 238,739 | | | $ | 389,075 | | | $ | 5,830 | |
|
| | | | | | | | | | | | | | | | | | | |
| | Payments due by period |
| Type of Obligation | Total Obligation | | Less than One Year | | 1-3 Years | | 3-5 Years | | More than 5 years |
| Revolving credit facility | $ | 287,000 |
| | $ | — |
| | $ | 287,000 |
| | $ | — |
| | $ | — |
|
| 2021 senior unsecured notes | 373,800 |
| | — |
| | 373,800 |
| | — |
| | — |
|
| Throughput commitment | 16,030 |
| | 6,194 |
| | 9,836 |
| | — |
| | — |
|
| Operating leases | 27,921 |
| | 7,869 |
| | 8,633 |
| | 3,596 |
| | 7,823 |
|
| Interest payable on fixed long-term obligations | 57,589 |
| | 27,101 |
| | 30,488 |
| | — |
| | — |
|
| Total contractual cash obligations | $ | 762,340 |
| | $ | 41,164 |
| | $ | 709,757 |
| | $ | 3,596 |
| | $ | 7,823 |
|
The interest payable under our revolving credit facility is not reflected in the above table because such amounts depend on the outstanding balances and interest rates, which vary from time to time.
Letter of Credit. At December 31, 2018,2020, we had outstanding irrevocable letters of credit in the amount of $16.9$16.7 million, which were issued under our revolving credit facility.
Off Balance Sheet Arrangements. We do not have any off-balance sheet financing arrangements.
Description of Our Long-Term Debt
2021 Senior Notes
We and Martin Midstream Finance Corp., a subsidiary of us (collectively, the "Issuers"), entered into (i) an Indenture, dated as of February 11, 2013 (the "2021 Indenture") among the Issuers, certain subsidiary guarantors (the "2021 Guarantors") and Wells Fargo Bank, National Association, as trustee (the "2021 Trustee") and (ii) a Registration Rights Agreement, dated as of February 11, 2013 (the "2021 Registration Rights Agreement"), among the Issuers, the 2021 Guarantors and Wells Fargo Securities, LLC, RBC Capital Markets, LLC, RBS Securities Inc., SunTrust Robinson Humphrey, Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representatives of a group of initial purchasers, in connection with a private placement to eligible purchasers of $250.0 million in aggregate principal amount of the Issuers' 7.25% senior unsecured notes due 2021 (the "2021 Notes"). On April 1, 2014, we completed a private placement add-on of $150.0 million of the 2021 Notes. In 2015, we repurchased on the open market and subsequently retired an aggregate $26.2 million of our outstanding 2021 Notes.
Interest and Maturity.
The Issuers issued the 2021 Notes pursuant to the 2021 Indenture in transactions exempt from registration requirements under the Securities Act of 1933, as amended (the "Securities Act"). The 2021 Notes were resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. The 2021 Notes will mature on February 15, 2021. The interest payment dates are February 15 and August 15.
Optional Redemption. Prior to February 15, 2017, the Issuers may on any one or more occasions redeem all or a part of the 2021 Notes at the redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. On or after February 15, 2017, the Issuers may on any one or more occasions redeem all or a part of the 2021 Notes at the redemption prices (expressed as percentages of principal amount) equal to 103.625% for the twelve-month period beginning on February 15, 2017, 101.813% for the twelve-month period beginning on February 15, 2018 and 100.00% for the twelve-month period beginning on February 15, 2019 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the 2021 Notes.
Certain Covenants. The 2021 Indenture restricts our ability and the ability of certain of our subsidiaries to: (i) sell assets including equity interests in our subsidiaries; (ii) pay distributions on, redeem or repurchase our units or redeem or repurchase our subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us; (vii) consolidate, merge or transfer all or substantially all of our assets; (viii) engage in transactions with affiliates; (ix) create unrestricted subsidiaries; (x) enter into sale and leaseback transactions; or (xi) engage in certain business activities. These covenants are subject to a number of important exceptions and qualifications. If the 2021 Notes achieve an investment grade rating from each of Moody's Investors Service, Inc. and Standard & Poor's Ratings Services and no Default (as defined in the 2021 Indenture) has occurred and is continuing, many of these covenants will terminate.
Events of Default. The 2021 Indenture provides that each of the following is an Event of Default: (i) default for 30 days in the payment when due of interest on the 2021 Notes; (ii) default in payment when due of the principal of, or premium, if any, on the 2021 Notes; (iii) failure by us to comply with certain covenants relating to asset sales, repurchases of the 2021 Notes upon a change of control and mergers or consolidations; (iv) failure by us for 180 days after notice to comply with our reporting obligations under the Securities Exchange Act of 1934; (v) failure by us for 60 days after notice to comply with any of the other agreements in the 2021 Indenture; (vi) default under any mortgage, indenture or instrument governing any indebtedness for money borrowed or guaranteed by us or any of our restricted subsidiaries, whether such indebtedness or guarantee now exists or is created after the date of the 2021 Indenture, if such default: (a) is caused by a payment default; or (b) results in the acceleration of such indebtedness prior to its stated maturity, and, in each case, the principal amount of the indebtedness, together with the principal amount of any other such indebtedness under which there has been a payment default or acceleration of maturity, aggregates $20.0 million or more, subject to a cure provision; (vii) failure by us or any of our restricted subsidiaries to pay final judgments aggregating in excess of $20.0 million, which judgments are not paid, discharged or stayed for a period of 60 days; (viii) except as permitted by the 2021 Indenture, any subsidiary guarantee is held in any judicial proceeding to be unenforceable or invalid or ceases for any reason to be in full force or effect, or any 2021 Guarantor, or any person acting on behalf of any Guarantor, denies or disaffirms its obligations under its subsidiary guarantee; and (ix) certain events of bankruptcy, insolvency or reorganization described in the 2021 Indenture with respect to the Issuers or any of our restricted subsidiaries that is a significant subsidiary or any group of restricted subsidiaries that, taken together, would constitute a significant subsidiary of us. Upon a continuing Event of Default, the 2021 Trustee, by notice to the Issuers, or the holders of at least 25% in principal amount of the then outstanding 2021 Notes, by notice to the Issuers and the 2021 Trustee, may declare the 2021 Notes immediately due and payable, except that an Event of Default resulting from entry into a bankruptcy, insolvency or reorganization with respect to the Issuers, any restricted subsidiary of us that is a significant subsidiary or any group of its restricted subsidiaries that, taken together, would constitute a significant subsidiary of us, will automatically cause the 2021 Notes to become due and payable.
Revolving Credit Facility
At December 31, 2018,2020, we maintained a $664.4$300.0 million revolving credit facility. This facility was most recentlywhich matures on August 31, 2023. On July 8, 2020, the Partnership amended on July 24, 2018, which included,its revolving credit facility to, among other things, revisingpermit the Exchange Offer. Please see Note 16 in Part II of this Form 10-K for more information about the July 8, 2020 amendment to our existing leverage covenants. Total Indebtedness to EBITDA and Senior Secured Indebtedness to EBITDA (each as defined in revolving credit facility ("the credit agreement) was amended to 5.25 times and 3.50 times, respectively. No changes were made to the Consolidated Interest Coverage Ratio (as defined in the credit agreement) of 2.50 times.Credit Facility Amendment")..
As of December 31, 2018,2020, we had $287.0$148.0 million outstanding under the revolving credit facility and $16.9$16.7 million of outstanding irrevocable letters of credit, issued, leaving a maximum available to be borrowed under our credit facility for future revolving credit borrowings and letters of credit of $360.5$135.3 million. SubjectAfter giving effect to our then current borrowings, outstanding letters of credit and the financial covenants contained in our revolving credit facility, and based on our existing EBITDA (as defined in our credit facility) calculations, as of December 31, 2018, we havehad the ability to borrow approximately $25.8$20.5 million of that amount. We were in compliance with all financial covenants atadditional amounts thereunder as of December 31, 2018.2020.
The revolving credit facility is used for ongoing working capital needs and general partnership purposes, and to finance permitted investments, acquisitions and capital expenditures. During the year ended December 31, 2018,2020, the leveloutstanding balance of outstanding draws on our revolving credit facility has ranged from a low of $287.0$148.0 million to a high of $500.0$223.0 million.
The credit facility is guaranteed by substantially all of our subsidiaries. Obligations under the credit facility are secured by first priority liens on substantially all of our assets and those of the guarantors, including, without limitation, inventory, accounts receivable, bank accounts, marine vessels, equipment, fixed assets and the interests in our subsidiaries.
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. If we sell assets and receive net cash proceeds in excess of $25.0 million, the commitments of the lenders under the revolving credit facility will be reduced by $25.0 million.
Indebtedness under the credit facility bears interest at our option at the Eurodollar Rate (the British Bankers Association(LIBOR), with a floor for LIBOR Rate)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 revolving credit availabilitycommitments under the credit facility. The letter of credit fee, the commitment fee and the applicable margins for our interest rate vary quarterly based on our leverage ratioTotal Leverage Ratio (as defined in the credit facility,Credit Facility Amendment, 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, 2018:2020:
| | Leverage Ratio | Base Rate Loans | | Eurodollar Rate Loans | | Letters of Credit | Leverage Ratio | Base Rate Loans | | Eurodollar
Rate
Loans | | Letters of Credit |
| Less than 3.00 to 1.00 | 1.00 | % | | 2.00 | % | | 2.00 | % | 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 | 1.25 | % | | 2.25 | % | | 2.25 | % | 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 | 1.50 | % | | 2.50 | % | | 2.50 | % | 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 | 1.75 | % | | 2.75 | % | | 2.75 | % | 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 | 2.00 | % | | 3.00 | % | | 3.00 | % | |
| Greater than or equal to 4.50 to 1.00 and less than 5.00 to 1.00 | | 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 | | Greater than or equal to 5.00 to 1.00 | 3.00 | % | | 4.00 | % | | 4.00 | % |
At December 31, 2018, the applicable margin for revolving loans that are LIBOR loans ranges from 2.00% to 3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 1.00% to 2.00%. The applicable margin for LIBOR borrowings at December 31, 20182020 is 2.75%.3.75%, with a 1% floor for LIBOR.
The credit facility includes financial covenants that are tested on a quarterly basis, based on the rolling four-quarterfour quarter period that ends on the last day of each fiscal quarter.
In addition, the credit facility contains various covenants, which, among other things, limit our and our subsidiaries’ ability to: (i) grant or assume liens; (ii) make investments (including investments in our joint ventures) and acquisitions; (iii) enter into certain types of hedging agreements; (iv) incur or assume indebtedness; (v) sell, transfer, assign or convey assets; (vi) repurchase our equity, make distributions and certain other restricted payments, but the credit facility permits us(including a limit on our ability to make quarterly distributions to unitholders so long as no default or eventin excess of default exists under$0.005 per unit unless our Total Leverage Ratio (as defined in the credit facility;Credit Facility Amendment) 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; (xi) make capital expenditures; and (xii)(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.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.
2025 Senior Secured Notes and Indenture
General
Pursuant to the Exchange Offer, 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 ending 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 revolving 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 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 the 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.
2021 Senior Notes and Indenture
The Issuers entered into an Indenture, dated as of February 11, 2013. among the Issuers, certain subsidiary guarantors and Wells Fargo Bank, National Association, as trustee, under which the Issuers issued $400.0 million in aggregate principal amount of their 7.25% senior unsecured notes due 2021 (the "2021 Notes"). In 2015, we repurchased on the open market and subsequently retired an aggregate $26.2 million of our outstanding 2021 Notes. In 2020, we repurchased on the open market and subsequently retired an aggregate $9.3 million of our outstanding 2021 Notes. On August 12, 2020, we completed the Exchange Offer and Cash Tender Offer. In connection with the completion of the Exchange Offer and consent solicitation to certain eligible holders of the 2021 Notes, on August 12, 2020, we entered into a supplemental indenture to eliminate
substantially all of the restrictive covenants in the indenture governing the 2021 Notes. On February 15, 2021, our 2021 Notes matured and we retired the outstanding balance of $28.8 million using proceeds from our revolving credit facility.
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, 2020, we had cash and cash equivalents of $5.0 million and available borrowing capacity of $20.5 million under our revolving credit facility with $148.0 million of borrowings outstanding. Our revolving credit facility matures on August 31, 2023.
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 revolving 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 revolving 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, 2020 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.
The Partnership is in compliance with all debt covenants as of December 31, 2018 and expects to be in compliance for the next twelve months.
Seasonality
A substantial portion of our revenues areis dependent on sales prices of products, particularly NGLs and fertilizers, which fluctuate in part based on winter and spring weather conditions. The demand for NGLs is strongest during the winter heating season and the refinery blending season. The demand for fertilizers is strongest during the early spring planting season. However, natural gas storage division of the Natural Gas Services segment provides stable cash flows and is not generally subject to seasonal demand factors. Additionally, our Terminalling and Storage and Marine 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 terminallingTerminalling and storage, sulfurStorage, Sulfur Services and marine transportation businesses. Therefore, we do not expect that our overall net income will be impacted by seasonality factors. However,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 Marine Transportation business segments.
Impact of Inflation
Inflation did not have a material impact on our results of operations in 2018, 20172020, 2019 or 2016.2018. Although the impact of inflation has been insignificant in recent years, it is still a factor in the U.S. economy and may increase the cost to acquire or replace property, plant and equipment. It may also increase the costs of labor and supplies. In the future, increasing energy prices could adversely affect our results of operations. Diesel fuel, natural gas, chemicals and other supplies are recorded in operating expenses. An increase in price of these products would increase our operating expenses which could adversely affect net income. We cannot provide assurance that we will be able to pass along increased operating expenses to our customers.
Environmental Matters
Our operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. We incurred no material environmental costs, liabilities or expenditures to mitigate or eliminate environmental contamination during 2018, 20172020, 2019 or 2016.
|
| | | | |
| Item 7A. | Quantitative and Qualitative Disclosures about Market Risk |
Commodity Risk. The Partnership from time to time uses derivatives to manage the risk of commodity price fluctuation. Commodity risk is the adverse effect on the value of a liability or future purchase that results from a change in commodity price. We have established a hedging policy and monitor and manage the commodity market risk associated with potential commodity risk exposure. In addition, we focus on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction.
We have entered into hedging transactions as of December 31, 20182020 to protectmitigate a portion of our commodity price risk exposure. These hedging arrangements are in the form of swaps for NGLs. We have instruments totaling a gross notional quantity of 55,000137,000 barrels settling during the period from January 31, 20192021 through February 28, 2019.2021. These instruments settle against the applicable pricing source for each grade and location. These instruments are recorded on our Consolidated Balance Sheets at December 31, 20182020 in "Fair value of derivatives" as a current assetliability of $0.04$0.2 million. Based on the current net notional volume hedged as of December 31, 2018,2020, a $0.10 change in the expected settlement price of these contracts would result in an impact of $0.2$0.6 million to the Partnership's net income.
Interest Rate Risk. We are exposed to changes in interest rates as a result ofBorrowings under our revolving credit facility whichare at variable rates and include a LIBOR floor of 1.00%. Our revolving credit facility had a weighted-average interest rate of 5.24%4.75% as of December 31, 2018.2020. Based on the amount of unhedged floating rate debt owed by us on December 31, 2018,2020, 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 $2.9$0.2 million annually.
We are not exposed to changes in interest rates with respect to our senior unsecured notes2021 Notes, 2024 Notes and 2025 Notes as these obligations are fixed rate. TheBased on the quoted prices for identical liabilities in markets that are not active at December 31, 2020, the estimated fair value of the senior unsecured notes2021 Notes, 2024 Notes and 2025 Notes was approximately $360.1$28.6 million, as of December 31, 2018, based on market prices of similar debt at December 31, 2018.$55.2 million and $288.7 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, 2020 would result in approximately a $6.8$0.5 million decrease in the fair value of our long-term debt at December 31, 2018.2021 Notes, a $0.9 million decrease in the fair value of our 2024 Notes, and a $5.0 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 revolving credit facility.
|
| | | | |
| Item 8. | Financial Statements and Supplementary Data |
The following financial statements of Martin Midstream Partners L.P. (Partnership) are listed below:
|
| | | | |
| Page |
ReportsReport of Independent Registered Public Accounting Firm | |
Consolidated Balance Sheets as of December 31, 20182020 and 20172019 | |
Consolidated Statements of Operations for the years ended December 31, 2018, 20172020, 2019 and 20162018 | |
| |
Consolidated Statements of Changes in Capital (Deficit) for the years ended December 31, 2018, 20172020, 2019 and 20162018 | |
Consolidated Statements of Cash Flows for the years ended December 31, 2018, 20172020, 2019 and 20162018 | |
| Notes to Consolidated Financial Statements | |
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”)Partnership) as of December 31, 20182020 and 2017,2019, the related consolidated statements of operations, changes in capital (deficit), and cash flows for each of the years in the three‑yearthree-year period ended December 31, 2018,2020, and the related notes (collectively, the “consolidatedconsolidated financial statements”)statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 20182020 and 2017,2019, and the results of its operations and its cash flows for each of the years in the three‑yearthree-year period ended December 31, 2018,2020, in conformity with U.S. generally accepted accounting principles.
Change in Accounting Principle
We also have audited,
As discussed in accordance withnote 3 to the standardsconsolidated financial statements, the Partnership has changed its method of accounting for leases in 2019 due to the Public Companyadoption of Accounting Oversight Board (United States) (“PCAOB”), the Partnership’s internal control over financial reporting as of December 31, 2018, based on criteria established inStandards Codification 842, Internal Control Leases- Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 19, 2019 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 PCAOBPublic Company Accounting Oversight Board (United States) (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. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion.
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.
Valuation of goodwill for the terminalling and storage reporting unit
As discussed in Notes 2 and 9 to the consolidated financial statements, the goodwill balance as of December 31, 2020 was $16,823 thousand, of which $10,985 thousand related to the terminalling and storage reporting unit. The Partnership performs goodwill impairment testing on an annual basis and more often if events or circumstances indicate there may be impairment. During the first quarter of 2020, the Partnership determined that triggering events, including declines in the market price of its units and the economic downturn, required an evaluation of goodwill at March 31, 2020. The fair value of the reporting unit was determined using a combination of income and market approach methods. The Partnership determined that goodwill was not impaired based on both its interim and annual evaluations.
We identified the evaluation of the goodwill impairment assessments for the terminalling and storage reporting unit as a critical audit matter. Significant auditor judgment was required to evaluate the discounted cash flow projections used in the determinations of fair value, specifically assumptions related to forecasted revenues, earnings before interest, taxes, depreciation, and amortization (EBITDA), and the discount rates. These assumptions were challenging to test as the estimated fair values of the terminalling and storage reporting unit were sensitive to possible changes to such assumptions. The audit effort to evaluate the discount rates used in the income approaches and the market multiples used in the market approaches required specialized skills and knowledge.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the Partnership’s forecasted revenues and EBITDA by comparing them to historical results and analyst reports, considering the portion of revenues and EBITDA projections supported by long-term, fixed fee contracts and the portion impacted by current market conditions. We compared historical forecasts of revenues and EBITDA to actual results to assess the Company’s ability to estimate such amounts. We performed sensitivity analyses over forecasted revenues and EBITDA and the discount rates to assess their impact on the Partnership’s determinations of the fair value of the reporting unit.
In addition, we involved valuation professionals with specialized skills and knowledge, who assisted in:
–evaluating the discount rates used in the terminalling and storage reporting unit’s discounted cash flow models, by comparing them against discount rate ranges that were independently developed using publicly available market data for comparable entities
–evaluating the market multiples used within the guideline public company methods, by developing independent calculations of the guideline comparable companies’ multiples using publicly available market data
–evaluating the market multiples used within the guideline transaction methods, by comparing against independent transaction searches of publicly available market data from the previous two years
–evaluating the control premiums implied in reconciling the sum of the fair values of the individual reporting units with the Partnership’s market capitalizations, by comparing against implied control premiums based on publicly available market data.
/s/ KPMG LLP
We have served as the Partnership’s auditor since 19812002.
Dallas, Texas
February 19, 2019
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, 2018, 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, 2018, 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, 2018 and 2017, the related consolidated statements of operations, changes in capital, and cash flows for each of the years in the three‑year period ended December 31, 2018, and the related notes (collectively, the “consolidated financial statements”), and our report dated February 19, 2019, expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ KPMG LLP
Dallas, Texas
February 19, 2019
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
| | | | | | | | | | | |
| | December 31, |
| 2020 | | 2019 |
| Assets | | | |
| Cash | $ | 4,958 | | | $ | 2,856 | |
| Trade and accrued accounts receivable, less allowance for doubtful accounts of $261 and $532, respectively | 52,748 | | | 87,254 | |
| | | |
| Inventories | 54,122 | | | 62,540 | |
| Due from affiliates | 14,807 | | | 17,829 | |
| | | |
| Other current assets | 8,991 | | | 5,833 | |
| Assets held for sale | 0 | | | 5,052 | |
| Total current assets | 135,626 | | | 181,364 | |
| | | |
| Property, plant and equipment, at cost | 889,108 | | | 884,728 | |
| Accumulated depreciation | (509,237) | | | (467,531) | |
| Property, plant and equipment, net | 379,871 | | | 417,197 | |
| | | |
| Goodwill | 16,823 | | | 17,705 | |
| Right-of-use assets | 22,260 | | | 23,901 | |
| Deferred income taxes, net | 22,253 | | | 23,422 | |
| Intangibles and other assets, net | 2,805 | | | 3,567 | |
| | | |
| | $ | 579,638 | | | $ | 667,156 | |
| Liabilities and Partners’ Capital (Deficit) | | | |
| Current portion of long term debt and finance lease obligations | $ | 31,497 | | | $ | 6,758 | |
| Trade and other accounts payable | 51,900 | | | 64,802 | |
| Product exchange payables | 373 | | | 4,322 | |
| Due to affiliates | 435 | | | 1,470 | |
| Income taxes payable | 556 | | | 472 | |
| Fair value of derivatives | 207 | | | 667 | |
| Other accrued liabilities | 34,407 | | | 28,789 | |
| | | |
| Total current liabilities | 119,375 | | | 107,280 | |
| | | |
| Long-term debt, net | 484,597 | | | 569,788 | |
| Finance lease obligations | 289 | | | 717 | |
| Operating lease liabilities | 15,181 | | | 16,656 | |
| | | |
| Other long-term obligations | 7,067 | | | 8,911 | |
| Total liabilities | 626,509 | | | 703,352 | |
| Commitments and contingencies | 0 | | 0 |
| Partners’ capital (deficit) | (46,871) | | | (36,196) | |
| Total partners’ capital (deficit) | (46,871) | | | (36,196) | |
| | $ | 579,638 | | | $ | 667,156 | |
|
| | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
| Assets | | | |
| Cash | $ | 237 |
| | $ | 27 |
|
| Trade and accrued accounts receivable, less allowance for doubtful accounts of $291 and $314, respectively | 79,031 |
| | 107,242 |
|
| Product exchange receivables | 166 |
| | 29 |
|
| Inventories (Note 7) | 85,068 |
| | 97,252 |
|
| Due from affiliates | 18,609 |
| | 23,668 |
|
| Fair value of derivatives (Note 13) | 4 |
| | — |
|
| Other current assets | 5,275 |
| | 4,866 |
|
| Assets held for sale (Note 5) | 5,652 |
| | 9,579 |
|
| Total current assets | 194,042 |
| | 242,663 |
|
| | | | |
| Property, plant and equipment, at cost (Note 8) | 1,264,730 |
| | 1,253,065 |
|
| Accumulated depreciation | (466,381 | ) | | (421,137 | ) |
| Property, plant and equipment, net | 798,349 |
| | 831,928 |
|
| | | | |
| Goodwill (Note 9) | 17,296 |
| | 17,296 |
|
| Investment in WTLPG (Note 11) | — |
| | 128,810 |
|
| Intangibles and other assets, net (Note 15) | 23,711 |
| | 32,801 |
|
| | $ | 1,033,398 |
| | $ | 1,253,498 |
|
| Liabilities and Partners’ Capital | | | |
| Trade and other accounts payable | $ | 63,157 |
| | $ | 92,567 |
|
| Product exchange payables | 13,237 |
| | 11,751 |
|
| Due to affiliates | 2,459 |
| | 3,168 |
|
| Income taxes payable | 445 |
| | 510 |
|
| Fair value of derivatives (Note 13) | — |
| | 72 |
|
| Other accrued liabilities (Note 15) | 22,215 |
| | 26,340 |
|
| Total current liabilities | 101,513 |
| | 134,408 |
|
| | | | |
| Long-term debt, net (Note 16) | 656,459 |
| | 812,632 |
|
| Other long-term obligations | 10,714 |
| | 8,217 |
|
| Total liabilities | 768,686 |
| | 955,257 |
|
| Commitments and contingencies (Note 22) |
|
| |
|
|
| Partners’ capital (Note 17) | 264,712 |
| | 298,241 |
|
| Total partners’ capital | 264,712 |
| | 298,241 |
|
| | $ | 1,033,398 |
| | $ | 1,253,498 |
|
See accompanying notes to consolidated financial statements.
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in thousands, except per unit amounts)
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | 20181 |
| Revenues: | | | | | |
| Terminalling and storage * | $ | 80,864 | | | $ | 87,397 | | | $ | 96,204 | |
| Transportation * | 132,492 | | | 159,622 | | | 150,121 | |
| | | | | |
| Sulfur services | 11,659 | | | 11,434 | | | 11,148 | |
| Product sales: * | | | | | |
| Natural gas liquids | 247,479 | | | 366,502 | | | 496,007 | |
| Sulfur services | 96,348 | | | 99,906 | | | 121,388 | |
| Terminalling and storage | 103,300 | | | 122,257 | | | 145,236 | |
| 447,127 | | | 588,665 | | | 762,631 | |
| Total revenues | 672,142 | | | 847,118 | | | 1,020,104 | |
| | | | | |
| Costs and expenses: | | | | | |
| Cost of products sold: (excluding depreciation and amortization) | | | | | |
| Natural gas liquids * | 215,895 | | | 325,376 | | | 449,103 | |
| Sulfur services * | 58,515 | | | 65,893 | | | 83,641 | |
| Terminalling and storage * | 82,516 | | | 101,526 | | | 126,562 | |
| 356,926 | | | 492,795 | | | 659,306 | |
| Expenses: | | | | | |
| Operating expenses * | 183,747 | | | 209,313 | | | 216,182 | |
| Selling, general and administrative * | 40,900 | | | 41,433 | | | 39,116 | |
| Impairment of long-lived assets | 0 | | | 0 | | | 0 | |
| Impairment of goodwill | 0 | | | 0 | | | 0 | |
| Depreciation and amortization | 61,462 | | | 60,060 | | | 61,484 | |
| Total costs and expenses | 643,035 | | | 803,601 | | | 976,088 | |
| Other operating income, net | 12,488 | | | 14,587 | | | 1,041 | |
| Gain on involuntary conversion of property, plant and equipment | 4,907 | | | 0 | | | 0 | |
| Operating income | 46,502 | | | 58,104 | | | 45,057 | |
| | | | | |
| Other income (expense): | | | | | |
| | | | | |
| Interest expense, net | (46,210) | | | (51,690) | | | (52,349) | |
| Gain on retirement of senior unsecured notes | 3,484 | | | 0 | | | 0 | |
| Loss on exchange of senior unsecured notes | (8,817) | | | 0 | | | 0 | |
| Other, net | 6 | | | 6 | | | 38 | |
| Total other income (expense) | (51,537) | | | (51,684) | | | (52,311) | |
| Net income (loss) before taxes | (5,035) | | | 6,420 | | | (7,254) | |
| Income tax expense | (1,736) | | | (1,900) | | | (577) | |
| Income (loss) from continuing operations | (6,771) | | | 4,520 | | | (7,831) | |
| Income (loss) from discontinued operations, net of income taxes | 0 | | | (179,466) | | | 63,486 | |
| Net income (loss) | (6,771) | | | (174,946) | | | 55,655 | |
| Less general partner's interest in net (income) loss | 135 | | | 3,499 | | | (882) | |
| Less pre-acquisition income allocated to the general partner | 0 | | | 0 | | | (11,550) | |
| Less (income) loss allocable to unvested restricted units | 21 | | | (41) | | | (28) | |
| Limited partners' interest in net income (loss) | $ | (6,615) | | | $ | (171,488) | | | $ | 43,195 | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Revenues: | | | | | |
| Terminalling and storage * | $ | 96,287 |
| | $ | 99,705 |
| | $ | 123,132 |
|
| Marine transportation * | 50,370 |
| | 48,579 |
| | 58,290 |
|
| Natural gas storage services * | 52,109 |
| | 58,817 |
| | 61,133 |
|
| Sulfur services | 11,148 |
| | 10,952 |
| | 10,800 |
|
| Product sales: * | | | | | |
| Natural gas services | 496,026 |
| | 473,865 |
| | 330,200 |
|
| Sulfur services | 121,388 |
| | 123,732 |
| | 130,258 |
|
| Terminalling and storage | 145,327 |
| | 130,466 |
| | 113,578 |
|
| | 762,741 |
| | 728,063 |
| | 574,036 |
|
| Total revenues | 972,655 |
| | 946,116 |
| | 827,391 |
|
| | | | | | |
| Costs and expenses: | | | | | |
| Cost of products sold: (excluding depreciation and amortization) | | | | | |
| Natural gas services * | 463,939 |
| | 421,444 |
| | 289,516 |
|
| Sulfur services * | 90,418 |
| | 82,338 |
| | 87,963 |
|
| Terminalling and storage * | 130,253 |
| | 116,495 |
| | 100,714 |
|
| | 684,610 |
| | 620,277 |
| | 478,193 |
|
| Expenses: | | | | | |
| Operating expenses * | 128,337 |
| | 140,177 |
| | 152,325 |
|
| Selling, general and administrative * | 37,677 |
| | 38,764 |
| | 34,320 |
|
| Impairment of long-lived assets | — |
| | 2,225 |
| | 26,953 |
|
| Impairment of goodwill | — |
| | — |
| | 4,145 |
|
| Depreciation and amortization | 76,866 |
| | 85,195 |
| | 92,132 |
|
| Total costs and expenses | 927,490 |
| | 886,638 |
| | 788,068 |
|
| Other operating income (loss), net | (379 | ) | | 523 |
| | 33,400 |
|
| Operating income | 44,786 |
| | 60,001 |
| | 72,723 |
|
| | | | | | |
| Other income (expense): | | | | | |
| Interest expense, net | (52,037 | ) | | (47,743 | ) | | (46,100 | ) |
| Other, net | 25 |
| | 1,101 |
| | 1,106 |
|
| Total other income (expense) | (52,012 | ) | | (46,642 | ) | | (44,994 | ) |
| Net income (loss) before taxes | (7,226 | ) | | 13,359 |
| | 27,729 |
|
| Income tax expense | (369 | ) | | (352 | ) | | (726 | ) |
| Income (loss) from continuing operations | (7,595 | ) | | 13,007 |
| | 27,003 |
|
| Income from discontinued operations, net of income taxes | 51,700 |
| | 4,128 |
| | 4,649 |
|
| Net income | 44,105 |
| | 17,135 |
| | 31,652 |
|
| Less general partner's interest in net income | (882 | ) | | (343 | ) | | (8,419 | ) |
| Less income allocable to unvested restricted units | (28 | ) | | (42 | ) | | (90 | ) |
| Limited partner's interest in net income | $ | 43,195 |
| | $ | 16,750 |
| | $ | 23,143 |
|
*Related Party Transactions Shown Below
See accompanying notes to consolidated financial statements.
1 Financial information has been revised to include results attributable to MTI acquired from Martin Resource Management Corporation. See Note 2 – Significant Accounting Policies and Practices.
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, |
| | 2020 | | 2019 | | 20181 |
| Revenues: | | | | | |
| Terminalling and storage | $ | 63,823 | | | $ | 71,733 | | | $ | 79,137 | |
| Transportation | 21,997 | | | 24,243 | | | 27,588 | |
| | | | | |
| Product sales | 317 | | | 931 | | | 1,297 | |
| Costs and expenses: | | | | | |
| Cost of products sold: (excluding depreciation and amortization) | | | | | |
| | | | | |
| Sulfur services | 10,519 | | | 10,765 | | | 10,641 | |
| Terminalling and storage | 18,429 | | | 23,859 | | | 24,613 | |
| Expenses: | | | | | |
| Operating expenses | 80,075 | | | 88,194 | | | 90,878 | |
| Selling, general and administrative | 32,886 | | | 32,622 | | | 26,441 | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Revenues: | | | | | |
| Terminalling and storage | $ | 79,219 |
| | $ | 82,205 |
| | $ | 82,437 |
|
| Marine transportation | 15,442 |
| | 16,801 |
| | 21,767 |
|
| Natural gas services | — |
| | 122 |
| | 699 |
|
| Product sales | 1,407 |
| | 3,578 |
| | 3,034 |
|
| Costs and expenses: | |
| | |
| | |
|
| Cost of products sold: (excluding depreciation and amortization) | |
| | |
| | |
|
| Natural gas services | 14,816 |
| | 18,946 |
| | 22,886 |
|
| Sulfur services | 17,418 |
| | 15,564 |
| | 15,339 |
|
| Terminalling and storage | 28,304 |
| | 17,612 |
| | 13,838 |
|
| Expenses: | |
| | |
| | |
|
| Operating expenses | 55,528 |
| | 64,344 |
| | 70,841 |
|
| Selling, general and administrative | 28,246 |
| | 29,416 |
| | 25,890 |
|
See accompanying notes to consolidated financial statements.
1 Financial information has been revised to include results attributable to MTI acquired from Martin Resource Management Corporation. See Note 2 – Significant Accounting Policies and Practices.
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in thousands, except per unit amounts)
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| | 2020 | | 2019 | | 20181 |
| Allocation of net income (loss) attributable to: | | | | | |
| Limited partner interest: | | | | | |
| Continuing operations | $ | (6,615) | | | $ | 4,430 | | | $ | (18,982) | |
| Discontinued operations | 0 | | | (175,918) | | | 62,177 | |
| | $ | (6,615) | | | $ | (171,488) | | | $ | 43,195 | |
| General partner interest: | | | | | |
| Continuing operations | $ | (135) | | | $ | 91 | | | $ | (387) | |
| Discontinued operations | 0 | | | (3,590) | | | 1,269 | |
| | $ | (135) | | | $ | (3,499) | | | $ | 882 | |
| | | | | |
| Net income (loss) per unit attributable to limited partners: | | | | | |
| Basic: | | | | | |
| Continuing operations | $ | (0.17) | | | $ | 0.11 | | | $ | (0.49) | |
| Discontinued operations | 0 | | | (4.55) | | | 1.60 | |
| | $ | (0.17) | | | $ | (4.44) | | | $ | 1.11 | |
| | | | | |
| Weighted average limited partner units - basic | 38,657 | | | 38,659 | | | 38,907 | |
| | | | | |
| Diluted: | | | | | |
| Continuing operations | $ | (0.17) | | | $ | 0.11 | | | $ | (0.49) | |
| Discontinued operations | 0 | | | (4.55) | | | 1.60 | |
| | $ | (0.17) | | | $ | (4.44) | | | $ | 1.11 | |
| | | | | |
| Weighted average limited partner units - diluted | 38,657 | | | 38,659 | | | 38,923 | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Allocation of net income attributable to: | | | | | |
| Limited partner interest: | | | | | |
| Continuing operations | $ | (7,438 | ) | | $ | 12,715 |
| | $ | 19,744 |
|
| Discontinued operations | 50,633 |
| | 4,035 |
| | 3,399 |
|
| | $ | 43,195 |
| | $ | 16,750 |
| | $ | 23,143 |
|
| General partner interest: | | | | | |
| Continuing operations | $ | (152 | ) | | $ | 260 |
| | $ | 7,182 |
|
| Discontinued operations | 1,034 |
| | 83 |
| | 1,237 |
|
| | $ | 882 |
| | $ | 343 |
| | $ | 8,419 |
|
| | | | | | |
| Net income per unit attributable to limited partners: | | | | | |
| Basic: | | | | | |
| Continuing operations | $ | (0.19 | ) | | $ | 0.33 |
| | $ | 0.55 |
|
| Discontinued operations | 1.30 |
| | 0.11 |
| | 0.10 |
|
| | $ | 1.11 |
| | $ | 0.44 |
| | $ | 0.65 |
|
| | | | | | |
| Weighted average limited partner units - basic | 38,907 |
| | 38,102 |
| | 35,347 |
|
| | | | | | |
| Diluted: | | | | | |
| Continuing operations | $ | (0.19 | ) | | $ | 0.33 |
| | $ | 0.55 |
|
| Discontinued operations | 1.30 |
| | 0.11 |
| | 0.10 |
|
| | $ | 1.11 |
| | $ | 0.44 |
| | $ | 0.65 |
|
| | | | | | |
| Weighted average limited partner units - diluted | 38,923 |
| | 38,165 |
| | 35,375 |
|
See accompanying notes to consolidated financial statements.
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CHANGES IN CAPITAL (DEFICIT)
(Dollars in thousands)
|
| | | | | | | | | | | | | | |
| | Partners’ Capital | | |
| | Common | | General Partner | | |
| | Units | | Amount | | Amount | | Total |
| Balances – December 31, 2015 | 35,456,612 |
| | $ | 380,845 |
| | $ | 13,034 |
| | $ | 393,879 |
|
| | | | | | | | |
| Net income | — |
| | 23,233 |
| | 8,419 |
| | 31,652 |
|
| Issuance of common units, net | — |
| | (29 | ) | | — |
| | (29 | ) |
| Issuance of restricted units | 13,800 |
| | — |
| | — |
| | — |
|
| Forfeiture of restricted units | (2,250 | ) | | — |
| | — |
| | — |
|
| Cash distributions | — |
| | (104,137 | ) | | (14,041 | ) | | (118,178 | ) |
| Reimbursement of excess purchase price over carrying value of acquired assets | — |
| | 4,125 |
| | — |
| | 4,125 |
|
| Unit-based compensation | — |
| | 904 |
| | — |
| | 904 |
|
| Purchase of treasury units | (16,100 | ) | | (347 | ) | | — |
| | (347 | ) |
| Balances – December 31, 2016 | 35,452,062 |
| | 304,594 |
| | 7,412 |
| | 312,006 |
|
| | | | | | | | |
| Net income | — |
| | 16,792 |
| | 343 |
| | 17,135 |
|
| Issuance of common units, net | 2,990,000 |
| | 51,056 |
| | — |
| | 51,056 |
|
| Issuance of restricted units | 12,000 |
| | — |
| | — |
| | — |
|
| Forfeiture of restricted units | (9,250 | ) | | — |
| | — |
| | — |
|
| General partner contribution | — |
| | — |
| | 1,098 |
| | 1,098 |
|
| Cash distributions | — |
| | (75,399 | ) | | (1,539 | ) | | (76,938 | ) |
| Reimbursement of excess purchase price over carrying value of acquired assets | — |
| | 1,125 |
| | — |
| | 1,125 |
|
| Excess purchase price over carrying value of acquired assets | — |
| | (7,887 | ) | | — |
| | (7,887 | ) |
| Unit-based compensation | — |
| | 650 |
| | — |
| | 650 |
|
| Purchase of treasury units | (200 | ) | | (4 | ) | | — |
| | (4 | ) |
| Balances – December 31, 2017 | 38,444,612 |
| | 290,927 |
| | 7,314 |
| | 298,241 |
|
| | | | | | | | |
| Net income | — |
| | 43,223 |
| | 882 |
| | 44,105 |
|
| Issuance of common units, net | — |
| | (118 | ) | | — |
| | (118 | ) |
| Issuance of time-based restricted units | 315,500 |
| | — |
| | — |
| | — |
|
| Issuance of performance-based restricted units | 317,925 |
| | — |
| | — |
| | — |
|
| Forfeiture of restricted units | (27,000 | ) | | — |
| | — |
| | — |
|
| Cash distributions | — |
| | (76,872 | ) | | (1,569 | ) | | (78,441 | ) |
| Excess purchase price over carrying value of acquired assets | — |
| | (26 | ) | | — |
| | (26 | ) |
| Unit-based compensation | — |
| | 1,224 |
| | — |
| | 1,224 |
|
| Purchase of treasury units | (18,800 | ) | | (273 | ) | | — |
| | (273 | ) |
| Balances – December 31, 2018 | 39,032,237 |
| | $ | 258,085 |
| | $ | 6,627 |
| | $ | 264,712 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Partners’ Capital (Deficit) | | | | |
| Parent Net Investment | | Common | | | | General Partner | | | | |
| | Units | | Amount | | | | | | Amount | | | | Total |
Balances – December 31, 20171 | $ | 24,240 | | | 38,444,612 | | | $ | 290,927 | | | | | | | $ | 7,314 | | | | | $ | 322,481 | |
| | | | | | | | | | | | | | | |
| Net income | 11,550 | | | — | | | 43,223 | | | | | | | 882 | | | | | 55,655 | |
| Issuance of common units, net | — | | | — | | | (118) | | | | | | | — | | | | | (118) | |
| Issuance of time-based restricted units | — | | | 315,500 | | | — | | | | | | | — | | | | | — | |
| Issuance of performance-based restricted units | | | 317,925 | | | | | | | | | | | | | — | |
| Forfeiture of restricted units | — | | | (27,000) | | | — | | | | | | | — | | | | | — | |
| General partner contribution | — | | | — | | | — | | | | | | | 0 | | | | | 0 | |
| Cash distributions | — | | | — | | | (76,872) | | | | | | | (1,569) | | | | | (78,441) | |
| Deemed distribution from Martin Resource Management Corporation | (12,070) | | | — | | | — | | | | | | | — | | | | | (12,070) | |
| Reimbursement of excess purchase price over carrying value of acquired assets | — | | | — | | | 0 | | | | | | | — | | | | | 0 | |
| Excess carrying value of the assets over the purchase price paid by Martin Resource Management | — | | | — | | | (26) | | | | | | | — | | | | | (26) | |
| Unit-based compensation | — | | | — | | | 1,224 | | | | | | | — | | | | | 1,224 | |
| Purchase of treasury units | — | | | (18,800) | | | (273) | | | | | | | — | | | | | (273) | |
Balances – December 31, 20181 | 23,720 | | | 39,032,237 | | | 258,085 | | | | | | | 6,627 | | | | | 288,432 | |
| | | | | | | | | | | | | | | |
| Net loss | 0 | | | — | | | (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 purchase price over carrying value of acquired assets | — | | | — | | | (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 | 0 | | | 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 | $ | 0 | | | 38,851,174 | | | $ | (48,776) | | | | | | | $ | 1,905 | | | | | $ | (46,871) | |
See accompanying notes to consolidated financial statements.
1 Financial information has been revised to include results attributable to MTI acquired from Martin Resource Management Corporation. See Note 2 – Significant Accounting Policies and Practices.
MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in thousands)
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Cash flows from operating activities: | | | | | |
| Net income | $ | 44,105 |
| | $ | 17,135 |
| | $ | 31,652 |
|
| Less: Income from discontinued operations | (51,700 | ) | | (4,128 | ) | | (4,649 | ) |
| Net income (loss) from continuing operations | (7,595 | ) | | 13,007 |
| | 27,003 |
|
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | |
| Depreciation and amortization | 76,866 |
| | 85,195 |
| | 92,132 |
|
| Amortization and write-off of deferred debt issue costs | 3,445 |
| | 2,897 |
| | 3,684 |
|
| Amortization of premium on notes payable | (306 | ) | | (306 | ) | | (306 | ) |
| (Gain) loss on disposition or sale of property, plant, and equipment | 379 |
| | (523 | ) | | (33,400 | ) |
| Impairment of long lived assets | — |
| | 2,225 |
| | 26,953 |
|
| Impairment of goodwill | — |
| | — |
| | 4,145 |
|
| Derivative (income) loss | (14,024 | ) | | 1,304 |
| | 4,133 |
|
| Net cash (paid) received for commodity derivatives | 13,948 |
| | (5,136 | ) | | (550 | ) |
| Net cash received for interest rate derivatives | — |
| | — |
| | 160 |
|
| Net premiums received on derivatives that settled during the year on interest rate swaption contracts | — |
| | — |
| | 630 |
|
| Unit-based compensation | 1,224 |
| | 650 |
| | 904 |
|
| Change in current assets and liabilities, excluding effects of acquisitions and dispositions: | | | | | |
| Accounts and other receivables | 28,440 |
| | (26,739 | ) | | (6,153 | ) |
| Product exchange receivables | (137 | ) | | 178 |
| | 843 |
|
| Inventories | 11,844 |
| | (14,656 | ) | | (6,761 | ) |
| Due from affiliates | 5,059 |
| | (12,096 | ) | | (1,441 | ) |
| Other current assets | 1,178 |
| | (1,699 | ) | | 2,478 |
|
| Trade and other accounts payable | (27,478 | ) | | 20,037 |
| | 3,254 |
|
| Product exchange payables | 1,486 |
| | 4,391 |
| | (5,372 | ) |
| Due to affiliates | (709 | ) | | (5,306 | ) | | 2,736 |
|
| Income taxes payable | (65 | ) | | (360 | ) | | (115 | ) |
| Other accrued liabilities | (6,415 | ) | | (3,187 | ) | | 686 |
|
| Change in other non-current assets and liabilities | 332 |
| | 2,416 |
| | (12,230 | ) |
| Net cash provided by continuing operating activities | 87,472 |
| | 62,292 |
| | 103,413 |
|
| Net cash provided by discontinued operating activities | 3,254 |
| | 5,214 |
| | 7,435 |
|
| Net cash provided by operating activities | 90,726 |
| | 67,506 |
| | 110,848 |
|
| Cash flows from investing activities: | | | | | |
| Payments for property, plant, and equipment | (37,090 | ) | | (39,749 | ) | | (40,455 | ) |
| Acquisitions, net of cash acquired | — |
| | (19,533 | ) | | (2,150 | ) |
| Payments for plant turnaround costs | (1,893 | ) | | (1,583 | ) | | (2,061 | ) |
| Proceeds from sale of property, plant, and equipment | 9,381 |
| | 8,377 |
| | 108,505 |
|
| Proceeds from repayment of Note receivable - affiliate | — |
| | 15,000 |
| | — |
|
| Net cash provided by (used in) continuing investing activities | (29,602 | ) | | (37,488 | ) | | 63,839 |
|
| Net cash provided by (used in) discontinued investing activities | 177,256 |
| | (390 | ) | | — |
|
| Net cash provided by (used in) investing activities | 147,654 |
| | (37,878 | ) | | 63,839 |
|
| Cash flows from financing activities: | | | | | |
| Payments of long-term debt | (557,000 | ) | | (339,000 | ) | | (386,700 | ) |
| Proceeds from long-term debt | 399,000 |
| | 341,000 |
| | 331,700 |
|
| Net proceeds from issuance of common units | (118 | ) | | 51,056 |
| | (29 | ) |
| General partner contributions | — |
| | 1,098 |
| | — |
|
| Excess purchase price over carrying value of acquired assets | (26 | ) | | (7,887 | ) | | — |
|
| Reimbursement of excess purchase price over carrying value of acquired assets | — |
| | 1,125 |
| | 4,125 |
|
| Purchase of treasury units | (273 | ) | | (4 | ) | | (347 | ) |
| Payments of debt issuance costs | (1,312 | ) | | (66 | ) | | (5,274 | ) |
| Cash distributions paid | (78,441 | ) | | (76,938 | ) | | (118,178 | ) |
| Net cash used in financing activities | (238,170 | ) | | (29,616 | ) | | (174,703 | ) |
| | | | | | |
| Net increase (decrease) in cash | 210 |
| | 12 |
| | (16 | ) |
| Cash at beginning of year | 27 |
| | 15 |
| | 31 |
|
| Cash at end of year | $ | 237 |
| | $ | 27 |
| | $ | 15 |
|
| | | | | | |
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | 20181 |
| Cash flows from operating activities: | | | | | |
| Net income (loss) | $ | (6,771) | | | $ | (174,946) | | | $ | 55,655 | |
| Less: (Income) loss from discontinued operations | 0 | | | 179,466 | | | (63,486) | |
| Net income (loss) from continuing operations | (6,771) | | | 4,520 | | | (7,831) | |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | |
| Depreciation and amortization | 61,462 | | | 60,060 | | | 61,484 | |
| Amortization and write-off of deferred debt issue costs | 3,422 | | | 4,041 | | | 3,445 | |
| | | | | |
| Amortization of premium on notes payable | (191) | | | (306) | | | (306) | |
| Deferred income tax expense | 1,169 | | | 1,360 | | | 208 | |
| Gain on disposition or sale of property, plant, and equipment | (9,788) | | | (13,332) | | | (1,041) | |
| Gain on involuntary conversion of property, plant and equipment | (4,907) | | | 0 | | | 0 | |
| Gain on retirement of senior unsecured notes | (3,484) | | | 0 | | | 0 | |
| Non-cash impact related to exchange of senior unsecured notes | (749) | | | 0 | | | 0 | |
| | | | | |
| | | | | |
| | | | | |
| Derivative (income) loss | 8,209 | | | 5,137 | | | (14,024) | |
| Net cash (paid) received for commodity derivatives | (8,669) | | | (4,466) | | | 13,948 | |
| | | | | |
| Unit-based compensation | 1,422 | | | 1,424 | | | 1,224 | |
| Change in current assets and liabilities, excluding effects of acquisitions and dispositions: | | | | | |
| Accounts and other receivables | 30,741 | | | 62 | | | 29,085 | |
| Product exchange receivables | 0 | | | 166 | | | (137) | |
| Inventories | 5,264 | | | 21,493 | | | 13,370 | |
| Due from affiliates | 2,932 | | | 1,822 | | | 5,961 | |
| Other current assets | (5,733) | | | (254) | | | 1,485 | |
| Trade and other accounts payable | (7,318) | | | (898) | | | (27,321) | |
| Product exchange payables | (3,949) | | | (7,781) | | | 555 | |
| Due to affiliates | (1,035) | | | (1,469) | | | 99 | |
| Income taxes payable | 84 | | | 27 | | | (65) | |
| Other accrued liabilities | 4,144 | | | (3,017) | | | (6,636) | |
| Change in other non-current assets and liabilities | (1,470) | | | (543) | | | 1,206 | |
| Net cash provided by continuing operating activities | 64,785 | | | 68,046 | | | 74,709 | |
| Net cash provided by discontinued operating activities | 0 | | | 7,769 | | | 30,321 | |
| Net cash provided by operating activities | 64,785 | | | 75,815 | | | 105,030 | |
| Cash flows from investing activities: | | | | | |
| Payments for property, plant, and equipment | (28,622) | | | (30,621) | | | (35,255) | |
| Acquisitions, net of cash acquired | 0 | | | (23,720) | | | 0 | |
| Payments for plant turnaround costs | (1,478) | | | (5,677) | | | (1,893) | |
| Proceeds from sale of property, plant, and equipment | 25,154 | | | 20,660 | | | 11,483 | |
| Proceeds from involuntary conversion of property, plant and equipment | 7,550 | | | 5,031 | | | 0 | |
| | | | | |
| Net cash provided by (used) in continuing investing activities | 2,604 | | | (34,327) | | | (25,665) | |
| Net cash provided by (used in) discontinued investing activities | 0 | | | 209,155 | | | 173,287 | |
| Net cash provided by (used in) investing activities | 2,604 | | | 174,828 | | | 147,622 | |
| Cash flows from financing activities: | | | | | |
| Payments of long-term debt and finance lease obligations | (338,199) | | | (729,514) | | | (559,201) | |
| | | | | |
| Proceeds from long-term debt | 282,019 | | | 638,000 | | | 399,000 | |
| Proceeds from issuance of common units, net of issuance related costs | 0 | | | (289) | | | (118) | |
| | | | | |
| Deemed contribution from (distribution to) Martin Resource Management | 0 | | | 0 | | | (12,070) | |
| Excess purchase price over carrying value of acquired assets | 0 | | | (102,393) | | | (26) | |
| | | | | |
| Purchase of treasury units | (9) | | | (392) | | | (273) | |
| Payments of debt issuance costs | (3,781) | | | (4,406) | | | (1,312) | |
| Cash distributions paid | (5,317) | | | (49,093) | | | (78,441) | |
| Net cash used in financing activities | (65,287) | | | (248,087) | | | (252,441) | |
| | | | | |
| Net increase in cash | 2,102 | | | 2,556 | | | 211 | |
| Cash at beginning of year | 2,856 | | | 300 | | | 89 | |
| Cash at end of year | $ | 4,958 | | | $ | 2,856 | | | $ | 300 | |
| | | | | |
| | | | | |
| | | | | |
See accompanying notes to consolidated financial statements.
1 Financial information has been revised to include results attributable to MTI acquired from Martin Resource Management Corporation. See Note 2 – Significant Accounting Policies and Practices.
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 United States ("U.S.") Gulf Coast region. Its four4 primary business lines include: terminalling, processing, storage and storagepackaging services for petroleum products and by-products including the refining of naphthenic crude oiloil; land and the blendingmarine transportation services for petroleum products and packaging of finished lubricants; natural gas services, including liquids transportationby-products, chemicals, and distribution services and natural gas storage;specialty products; sulfur and sulfur-based products processing, manufacturing, marketing and distribution; and marineNGL marketing, distribution, and transportation services for petroleum products and by-products.services.
The petroleum products and by-products the Partnership collects, transports, stores and distributes are produced primarily byprovides specialty services to major and independent oil and gas companies, who often turn to third parties, such as the Partnership, for the transportation and disposition of these products. In addition to these major and independent oil and gas companies, the Partnership's primary customers include independent refiners, large chemical companies, fertilizer manufacturers and other wholesale purchasers of these products. The Partnership operates primarily incertain petroleum products and by-products, with significant business concentrated around the U.S. Gulf Coast region,refinery complex, which is a major hub for petroleum refining, natural gas gathering and processing, and support services for the oil and gas exploration and production industry.
On August 30, 2013, Martin Resource Management Corporation completed the sale of a 49% non-controlling voting interest (50%(50% economic interest) in MMGP Holdings, LLC ("Holdings"), a newly-formed sole member of Martin Midstream GP LLC ("MMGP"), the general partner of the Partnership, to certain affiliated investment funds managed by Alinda Capital Partners ("Alinda"). Upon closing the transaction, Alinda appointed two2 representatives to serve on the board of directors of the general partner of the Partnership.
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 exist as of December 31, 20182020 or 2017.2019.
Impact of COVID-19 Pandemic. Due to the economic impacts of the COVID-19 pandemic, 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 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 United States, have greatly impacted the demand for refined products resulting in a significant reduction in refinery utilization, which has impacted the Partnership's 2020 performance. This impact started in February of 2020 and continued through the end of the year, during which time the Partnership has seen unfavorable trends in certain key metrics across several of its business lines compared to historical periods. The significant reduction in refinery utilization as a result of reduced refined products demand significantly impacted the Partnership's Transportation and NGL segments. As the volume of products produced or purchased by refineries has been reduced, demand for the Partnership's services has decreased.
Looking forward, we expect to continue to experience some adverse impacts of COVID-19 in our transportation segment during the first half of 2021 but we believe that refinery utilization will continue to increase in the second half of 2021 as a result of widespread vaccinations, government stimulus, and a rebounding economy. This should ultimately improve refined product demand as people get back to work and begin traveling again. We expect this will positively impact our transportation segment 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.
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
Accordingly, it is possible that the impact of the pandemic could have a material adverse effect on the Partnership's results of operations, financial position and cash flows for the year ended December 31, 2021 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. Management identified triggering events requiring the performance of impairment testing of long-lived assets and goodwill related to both the performance of the Partnership's unit price during the first quarter of 2020 and certain of the Partnership's businesses that are sensitive to reductions in refined product demand and refinery utilization. As a result, the Partnership recorded impairment charges totaling $4,352 related to long-lived assets during the first quarter of 2020. See Note 5 for more information. No impairments were identified related to goodwill. 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 the Partnership's results as of December 31, 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 revolving 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 years ended December 31, 2019 and 2018. See Note 5 for more information.
Acquisition of Martin Transport, Inc. On January 2, 2019, the Partnership acquired all of the issued and outstanding equity interests of MTI from Martin Resource Management Corporation. MTI operates a fleet of trucks providing transportation of petroleum products, liquid petroleum gas, chemicals, sulfur and other products, as well as owns 23 terminals located throughout the U.S. Gulf Coast and Southeastern United States.
The acquisition of MTI was considered a transfer of net assets between entities under common control. As a result, the acquisition of MTI was recorded at amounts based on the historical carrying value of these assets at January 1, 2019, and the Partnership is required to update its historical financial statements to include the activities of MTI as of the date of common control. See Note 4 for more information. The Partnership’s accompanying historical financial statements have been retrospectively updated to reflect the effects on financial position, cash flows and results of operations attributable to the activities of MTI as if the Partnership owned these assets for the periods presented. See Note 4 for separate results of MTI for the year ended December 31, 2018. Net income attributable to MTI for periods prior to the Partnership’s acquisition of the assets is not allocated to the limited partners for purposes of calculating net income per limited partner unit. See Note 17.
Divestiture of WTLPG Partnership Interest. On July 31, 2018, the Partnership completed the sale of its 20 percent non-operating interest in West Texas LPG Pipeline L.P. ("WTLPG") to ONEOK, Inc. (“ONEOK”("ONEOK"). WTLPG owns an approximate 2,300 mile common-carrier pipeline system that primarily transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. A wholly-owned subsidiary of ONEOK, Inc. is the operator of the assets. The Partnership has 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 its equity method investment in WTLPG as discontinued operations for the yearsyear ended December 31, 2018, 2017, and 2016.2018. See Note 5 for more information.
Correction of Immaterial Error. The year to date amounts for 2017 and 2016 have been revised to reflect a reclassification in the presentation of certain expenses associated with the manufacturing and shipping of product related to a location in the Partnership's Terminalling and Storage operating segment. The reclassification resulted in a decrease in operating expenses from $146,874 to $140,177 and an increase in cost of products sold from $613,580 to $620,277 for the year ended December 31, 2017, and a decrease in operating expenses from $158,864 to $152,325 and an increase in cost of products sold from $471,654 to $478,193 for the year ended December 31, 2016.
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 natural gas liquids ("NGLs")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 customers as title tocustomer or when the product transfersleaves 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.
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.
Sulfur Services – Revenue from sulfur and fertilizer product sales is recognized when the customer physically receivestakes 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.
Natural Gas ServicesLiquids – NGL distribution revenue is recognized when product is delivered by truck, rail, or pipeline to the Partnership's NGL customers. Revenue is recognized on title transfer of the product to the customer. Delivery of product is invoiced as the transaction occurs and are generally paid within a month. Natural gas storage revenue is recognized when the service is provided to the customer. The performance of the service is invoiced as the transaction occurs and are generally paid within a month.
Sulfur Services – Revenue from sulfur product sales is recognized when the customer takes title to the product. Delivery of product is invoiced as the transaction occurs and are generally paid within a month. Revenue from sulfur services is recognized as deliveries are made during each monthly period. The performance of the service is invoiced as the transaction occurs and are generally paid within a month.
Marine Transportation – Revenue is recognized for time charters based on a per day rate. For contracted trips, revenue is recognized upon completion of the particular trip. The performance of the service is invoiced as the transaction occurs and are 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 straight-line method over the estimated lives of the respective assets.
Equipment under capitalfinance leases is stated at the present value of minimum lease payments less accumulated amortization. Equipment under capitalfinance leases is amortized on a straight line basis over the estimated useful life of the asset.
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 four4 reporting units, the terminalling and storage, natural gas services,transportation, and sulfur services reporting units contain goodwill. NoNaN goodwill impairment was recorded for the yearyears ended December 31, 20182020, 2019, or 2017. During the second quarter of 2016, the Partnership experienced an impairment of all the goodwill in the Partnership's marine transportation reporting unit.2018.
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 2020 and elected to bypass the qualitative assessment and perform a quantitative assessment. Based upon the most recent annual review as of August 31, 2020, no goodwill impairment exists within the Partnership's reporting units for the year ended December 31, 2020. NaN goodwill impairment was recorded during the years ended December 31, 2019 or 2018.
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 no0 intangible asset impairments in 2018, 2017for the years ended December 31, 2020, 2019 or 2016.
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
(h) Debt Issuance Costs
Debt issuance costs relating to the Partnership’s revolving credit facility and senior unsecured notes are deferred and amortized over the terms of the debt arrangements and are shown, net of accumulated amortization, as a reduction of the related long-term debt.
In connection with the issuance, amendment, expansion and restatement of debt arrangements, the Partnership incurred debt issuance costs of $1,312, $66$3,781, $4,406 and $5,274$1,312 in the years ended December 31, 2018, 20172020, 2019 and 2016,2018, respectively.
During 2016, the Partnership made certain strategic amendments to its credit facility which, among other things, decreased its borrowing capacity from $700,000 to $664,444 and extended the maturity date of the facility from March 28, 2018 to March 28, 2020. In connection with the amendment, the Partnership expensed $820 of unamortized debt issuance costs determined not to have continuing benefit.
Remaining unamortized deferred issuance costs are amortized over the term of each respective revised debt arrangement.
Amortization and write-off of debt issuance costs, which is included in interest expense, totaled $3,445, $2,897$3,422, $4,041 and $3,684$3,445 for the years ended December 31, 2018, 20172020, 2019 and 2016,2018, respectively. Accumulated amortization amounted to $20,607$22,655 and $17,162$24,644 at December 31, 20182020 and 2017,2019, respectively.
(i) Impairment of Long-Lived Assets
In accordance with ASC 360-10, long-lived assets, such as property, plant and equipment, and intangible assets with definite lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset. Assets to be disposed of would be separately presented in the balance sheet and reported at the lower of the carrying amount or fair value less costs to sell and would no longer be depreciated. The assets and liabilities of a disposed group classified as held for sale would be presented separately in the appropriate asset and liability sections of the balance sheet.
In the fourth quarter of 2017, the Partnership identified a triggering event related to the planned disposition of certain assets that were no longer deemed core assets in the Partnership's Marine Transportation business. The triggering event was the assets' inability to generate cash flows in recent quarters and going forward. As a result, an impairment charge of $1,625 was recorded in the Marine Transportation segment results of operations in the fourth quarter of 2017. Additionally, the Partnership recorded an adjustment to the fair value less cost to sell of a certain asset classified as held for sale in the Martin Lubricants division of the Terminalling and Storage segment. As a result, an impairment charge of $600 was recorded in the Terminalling and Storage segment results of operations in the fourth quarter of 2017.
On August 25, 2017, Hurricane Harvey made landfall as a Category 4 hurricane. The storm lingered over Texas and Louisiana for days producing over 50 inches of rain in some areas, resulting in widespread flooding and damage. The Partnership experienced an impact from Hurricane Harvey in our Terminalling and Storage and Sulfur Services segments, where damages were suffered to the Partnership's property, plant, and equipment at its Neches, Stanolind, Galveston, and Harbor Island terminals located along the Texas gulf coast. The damage incurred did not exceed the insurance deductible at these locations and therefore the Partnership does not expect to receive any insurance proceeds resulting from the damage from Hurricane Harvey. In the third quarter of 2017, the Partnership recorded a write-off in the amount of $186 related to assets damaged.
In the fourth quarter of 2016, the Partnership identified a triggering event related to certain organic growth projects in the Smackover Refinery and Specialty Terminals divisions of the Partnership's Terminalling and Storage segment. These triggering events were the decision to not move forward with certain expansion projects due to the evaporation of the economic viability of the projects. Additionally, a triggering event was identified related to the planned disposition of certain assets that were no longer deemed core assets to the Partnership's Martin Lubricants division. As a result, an impairment charge of $15,252 was recorded
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
in the Terminalling and Storage segment results of operations for the year ended December 31, 2016. Also, in the fourth quarter of 2016, the Partnership identified a triggering event related to the planned disposition of certain assets that were no longer deemed core assets in the Partnership's Marine Transportation business. The triggering event was the assets' inability to generate cash flows in recent quarters and going forward. As a result, an impairment charge of $11,701 was recorded in the Marine Transportation segment results of operations in the fourth quarter of 2016.
(j) Asset Retirement Obligations
Under ASC 410-20, which relates to accounting requirements for costs associated with legal obligations to retire tangible, long-lived assets, the Partnership records an asset retirement obligation ("ARO") at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted over time towards the ultimate obligation amount and the capitalized costs are depreciated over the useful life of the related asset.
(k) Derivative Instruments and Hedging Activities
In accordance with certain provisions of ASC 815-10 related to accounting for derivative instruments and hedging activities, all derivatives and hedging instruments are included in the Consolidated Balance Sheets as an asset or liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings.
Derivative instruments not designated as hedges are marked to market with all market value adjustments being recorded in the Consolidated Statements of Operations.
(l) Use of Estimates
Management has made a number of estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with accounting principles generally accepted in the U.S. Actual results could differ from those estimates.
MARTIN MIDSTREAM PARTNERS L.P.
(m) Indirect Selling, General and Administrative ExpensesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Indirect selling, general and administrative expenses are incurred by Martin Resource Management and allocated to the Partnership to cover costs of centralized corporate functions such as accounting, treasury, engineering, information technology, risk management and other corporate services. Such expenses are based on the percentage of time spent by Martin Resource Management’s personnel that provide such centralized services. Under an omnibus agreement with Martin Resource Management, the Partnership is required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. For the years ended December 31, 2018, 2017 and 2016, the conflicts committee of the Partnership's general partner ("Conflicts Committee") approved reimbursement amounts of $16,416, $16,416 and $13,033, respectively, reflecting the Partnership's allocable share of such expenses. The Conflicts Committee will review and approve future adjustments(Dollars in the reimbursement amount for indirect expenses, if any, annually.thousands, except where otherwise indicated)
(n)(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.
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
(o)(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.
(p)(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.
(q)(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.
(r)(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.
(s)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 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. 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 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
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
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. There are no items of other comprehensive income or loss in any of the years presented.
NOTE 3. RECENT ACCOUNTING PRONOUNCEMENTS
In December 2019, FASB issued Accounting Standards Update ("ASU") 2019-12, Income Taxes (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 US generally accepted accounting principles (US GAAP). The standard is effective for the Partnership’s financial statements issued for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. The Partnership will adopt this ASU beginning January 1, 2021 and plans to use the modified retrospective approach, with a cumulative-effect adjustment recorded through retained earnings, for hybrid tax regimes. All other applicable amendments will be applied on a prospective basis. The result of this adoption will have no 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. Consequently, financial information was not updated and the disclosures required under the new standard are not provided for dates and periods before January 1, 2019.
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.
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
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.
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU replaced most existing revenue recognition guidance in U.S. GAAP. The new standard iswas effective for the Partnership on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method. The Partnership adopted the new standard utilizing the cumulative effect method which resulted in no cumulative effect of the adoption being recorded as of January 1, 2018. The Partnership adopted ASU 2014-09 on January 1, 2018 and did not identify any significant changes in the timing of revenue recognition when considering the amended accounting guidance. Additional disclosures related to revenue recognition appear in "Note 6. Revenue."
NOTE 4. ACQUISITIONS
In February 2016, the FASB issued ASU 2016-02,
Martin Transport, Inc. Stock Purchase Agreement. 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 andOn January 2, 2019, the Partnership believes substantiallyacquired all of our leases will continuethe 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 23 terminals located throughout the U.S. Gulf Coast and Southeastern United States for total consideration as follows:
| | | | | |
Purchase price1 | $ | 135,000 | |
| Plus: Working Capital Adjustment | 2,795 | |
| Less: Finance lease obligations assumed | (11,682) | |
| Cash consideration paid | $ | 126,113 | |
1The stock purchase agreement also includes a $10,000 earn-out based on certain performance thresholds. The performance threshold related to be classifiedfinancial 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.
The transaction closed on January 2, 2019 and was effective as operating leases under the new standard. Additional qualitative and quantitative disclosures, including significant judgments made by management, will be 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 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. Based on the effective date, this guidance will apply and the Partnership will adopt this ASU beginning on January 1, 2019 and plans to elect the transition option provided under ASU 2018-11. Consequently, financial information will not be updated and the disclosures requiredwas funded with borrowings under the new standard will not be provided for datesPartnership's revolving 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 periods before January 1, 2019.was recorded as an adjustment to "Partners' capital (deficit)".
81
The new standard provides a number of optional practical expedients in transition. The Partnership expects to elect 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 expects to elect the short-term lease recognition exemption for
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
all leases that qualify. This means, The separate results of operations related to MTI for those assets that qualify, the Partnership will not recognize 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.
Based on its current lease portfolio, the Partnership estimates that the adoption of this ASU will result in approximately $19,879 of additional assets and liabilities being reflected on its Consolidated Balance Sheet as of January 1, 2019.
NOTE 4. ACQUISITIONS
Acquisition of Terminalling Assets. On February 22, 2017, the Partnership acquired 100% of the membership interests of MEH South Texas Terminals LLC (“MEH”), a subsidiary of Martin Resource Management, for a purchase price of $27,420 (the “Hondo Acquisition”),year ended December 31, 2018, which was was funded with borrowings under the Partnership's revolving credit facility. At the date of acquisition, MEH was in the process of constructing an asphalt terminal facility in Hondo, Texas (the "Hondo Terminal”), which will serve the asphalt market in San Antonio, Texas and surrounding areas. This acquisition is considered a transfer of net assets between entities under common control. The acquisition of these assets was recorded at the historical carrying value of the assets at the acquisition date. The excess of the purchase price over the carrying value of the assets of $7,887 was recordedrecast as an adjustment to "Partners' capital."
|
| | | |
| Purchase price | $ | 27,420 |
|
| Historical carrying value of assets allocated to "Property, plant and equipment" | 19,533 |
|
| Excess purchase price over carrying value of acquired assets | $ | 7,887 |
|
As no individual line item of the historical financial statements of the acquired assets was in excess of 3%part of the Partnership's relative consolidated financial statement captions, the Partnership elected not to retrospectively recast the historical financial information to include these assets.Consolidated Statements of Operations, were as follows:
| | | | | |
| For the Year Ended December 31, |
| 2018 |
| |
| Transportation revenue | $ | 125,333 | |
| |
| Operating expenses | 105,212 | |
| Selling, general and administrative | 5,246 | |
| Depreciation and amortization | 3,413 | |
| Total costs and expenses | 113,871 | |
| |
| Other operating income, net | 596 | |
| Operating income | 12,058 | |
| |
| Other income (expense): | |
| Interest expense | (312) | |
| Other, net | 12 | |
| |
| Income before income taxes | 11,758 | |
| Income tax expense | 208 | |
| Net income | $ | 11,550 | |
NOTE 5. DISCONTINUED OPERATIONS, DIVESTITURES, AND ASSETS HELD FOR SALE
Divestitures
Divestiture of Mega Lubricants. On December 22, 2020, the Partnership completed the sale of 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 revolving 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 revolving credit facility. The divestiture of the East Texas Pipeline assets did not qualify for discontinued operations presentation under the guidance of ASC 205-20.
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
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 revolving 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 years ended December 31, 2019 and 2018.
The operating results, which are included in income (loss) from discontinued operations, were as follows:
| | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2019 | | 2018 |
| | | | |
| Total revenues | $ | 22,836 | | | $ | 52,108 | |
| Total costs and expenses and other, net, excluding depreciation and amortization | (15,360) | | | (20,703) | |
| Depreciation and amortization | (8,161) | | | (18,795) | |
Other operating loss, net1 | (178,781) | | | (824) | |
| Other, net | 0 | | | 0 | |
| Income (loss) from discontinued operations before income taxes | (179,466) | | | 11,786 | |
| Income tax expense | 0 | | | 0 | |
| Income (loss) from discontinued operations, net of income taxes | $ | (179,466) | | | $ | 11,786 | |
1 The year ended December 31, 2019 includes a loss on the disposition of the Natural Gas Storage Assets of $178,781.
Divestiture of WTLPG Partnership Interest. On July 31, 2018, the Partnership completed the sale of its 20 percent non-operating interest in WTLPG to ONEOK. WTLPG owns an approximate 2,300 mile common-carrier pipeline system that primarily transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. A wholly-owned subsidiary of ONEOK is the operator of the assets. In consideration for the sale of these assets, the Partnership received cash proceeds of $193,705, after transaction fees and expenses. The proceeds from the sale were used to reduce outstanding borrowings under the Partnership's revolving credit facility. The Partnership has 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 its equity method investment in WTLPG as discontinued operations for the years ended December 31, 2018 2017, and 2016.2017.
The operating results, which are included in income from discontinued operations, were as follows:
| | | | | |
| For the Year Ended December 31, |
| 2018 |
| |
Total costs and expenses and other, net, excluding depreciation and amortization1 | $ | (247) | |
Other operating income2 | 48,564 | |
| Equity in earnings | 3,383 | |
| Income from discontinued operations before income taxes | 51,700 | |
| Income tax expense | 0 | |
| Income from discontinued operations, net of income taxes | $ | 51,700 | |
|
| | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | | | | | |
Total costs and expenses and other, net, excluding depreciation and amortization1 | $ | (247 | ) | | $ | (186 | ) | | $ | (65 | ) |
Other operating income2 | 48,564 |
| | — |
| | — |
|
| Equity in earnings | 3,383 |
| | 4,314 |
| | 4,714 |
|
| Income from discontinued operations before income taxes | 51,700 |
| | 4,128 |
| | 4,649 |
|
| Income tax expense | — |
| | — |
| | — |
|
| Income from discontinued operations, net of income taxes | $ | 51,700 |
| | $ | 4,128 |
| | $ | 4,649 |
|
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
1 These expenses represent direct operating expenses as a result of the Partnership's ownership interest in WTLPG.
2 Other operating income represents the gain on the disposition of the investment in WTLPG.
Divestiture of Terminalling Assets. On December 21, 2016, the Partnership sold its 900,000 barrel crude oil storage terminal, refined product barge terminal, certain pipelines and related easements as well as dockage and trans-loading assets located in Corpus Christi, Texas (collectively the "CCCT Assets") to NuStar Logistics, L.P. (“NuStar”) for gross consideration of $107,000 plus the reimbursement of certain capital expenditures and prepaid items of $2,057. The Partnership received net proceeds of approximately $93,347 after transaction fees and expenses as well as the application of certain net cash payments previously received by us in conjunction with its mandated relocation of certain dockage assets to the purchase price in the amount of $13,400. Proceeds from the sale were used to reduce outstanding borrowings under the Partnership's revolving credit facility. The Partnership recorded a gain from the divestiture of $37,345, which was included in "Other operating income, net" on the Partnership's Consolidated Statements of Operations for the year ended December 31, 2016. Net income attributable to the CCCT Assets included in the Partnership's Consolidated Statements of Operations was $0, $0, and $43,804 for the years ended December 31, 2018, 2017, and 2016, respectively.
The divestiture of the CCCT Assets did not qualify for discontinued operations presentation under the guidance of ASC 205-20.
Long-Lived Assets Held for Sale
In the fourth quarter of 2017, the Partnership identified certain assets that were no longer deemed core to the operations of the Partnership in the inland division of the Marine Transportation segment. Additionally, the Partnership recorded an adjustment to the fair value less cost to sell of a certain asset classified as held for sale in the Martin Lubricants division of the Terminalling and Storage segment. As a result, an impairment charge of $600 and $1,625 was recorded in the Terminalling and Storage and Marine Transportation segments, respectively, in the fourth quarter of 2017 and was presented as "Impairment of long-lived assets" in the Partnership's Consolidated Statements of Operations.
In the fourth quarter of 2016, the Partnership identified certain assets that were no longer deemed core to the operations of the Partnership in the Smackover refinery and Martin Lubricants divisions of the Terminalling and Storage segment as well as the inland and offshore divisions of the Marine Transportation segment. These assets were deemed non-core due to the each asset's inability to generate cash flows in recent quarters as well as the expected cash flows in future quarters. As a result, an impairment charge of $15,252 and $11,701 was recorded in the Terminalling and Storage and Marine Transportation segments, respectively, in the fourth quarter of 2016 and was presented as "Impairment of long-lived assets" in the Partnership's Consolidated Statements of Operations.
At December 31, 20182019, certain terminalling and 2017, thestorage and transportation assets met the criteria to be classified as held for sale in accordance with ASC 360-10 and are presented at the lower of the assets' carrying amount or fair value less cost to sell by segment in current assets as follows:in the table below. These assets are considered non-core assets to the Partnership's operations and did not qualify for discontinued operations presentation under the guidance of ASC 205-20.
| | | | | | | | | | | |
| | December 31, 2020 | | December 31, 2019 |
| | | | |
| Terminalling and storage | $ | 0 | | | $ | 3,552 | |
| Transportation | 0 | | | 1,500 | |
| Assets held for sale | $ | 0 | | | $ | 5,052 | |
|
| | | | | | | |
| | December 31, 2018 | | December 31, 2017 |
| | | | |
| Terminalling and storage | $ | 3,552 |
| | $ | 4,152 |
|
| Marine transportation | 2,100 |
| | 5,427 |
|
| Assets held for sale | $ | 5,652 |
| | $ | 9,579 |
|
During 2018,In the first quarter of 2020, the Partnership received $1,002identified a triggering event related to a decline in proceeds from the sale offair value related to the assets classified as held for sale resultingat December 31, 2019. As a result, an impairment charge of $3,052 and $1,300 was recorded in a loss of $1,022, whichthe Terminalling and Storage and Transportation segments, respectively, during the year ended December 31, 2020 and was presented as a component ofrecorded in "Other operating income (loss), net"" in the Partnership's Consolidated Statements of Operations.
During 2017, At December 31, 2020, the Partnership received $8,341 in proceeds from the sale ofremaining assets previously classified as held for sale resulting in a gain of $822, which was presented as a component of "Other operating income (loss), net" in the Partnership's Consolidated Statementsamount of Operations.$700 no longer met the criteria to be classified as held for sale in accordance with ASC 360-10.
The non-core assets discussed above did not qualify for discontinued operations presentation under the guidance of ASC 205-20.
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
The non-core assets discussed above did not qualify for discontinued operations presentation under the guidance of ASC 205-20.
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:
| | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | 2018 |
| | | | | |
| Terminalling and storage segment | | | | | |
| Lubricant product sales | $ | 103,300 | | | $ | 122,257 | | | $ | 145,236 | |
| Throughput and storage | 80,864 | | | 87,397 | | | 96,204 | |
| $ | 184,164 | | | $ | 209,654 | | | $ | 241,440 | |
| Transportation segment | | | | | |
| Land transportation | $ | 88,652 | | | $ | 98,895 | | | $ | 99,751 | |
| Inland transportation | 40,507 | | | 54,834 | | | 44,580 | |
| Offshore transportation | 3,333 | | | 5,893 | | | 5,790 | |
| $ | 132,492 | | | $ | 159,622 | | | $ | 150,121 | |
| Sulfur service segment | | | | | |
| Sulfur product sales | $ | 24,176 | | | $ | 30,135 | | | $ | 46,347 | |
| Fertilizer product sales | 72,172 | | | 69,771 | | | 75,041 | |
| Sulfur services | 11,659 | | | 11,434 | | | 11,148 | |
| $ | 108,007 | | | $ | 111,340 | | | $ | 132,536 | |
| Natural gas liquids segment | | | | | |
| Natural gas liquids product sales | $ | 247,479 | | | $ | 366,502 | | | $ | 496,007 | |
| $ | 247,479 | | | $ | 366,502 | | | $ | 496,007 | |
|
| | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 |
| | | | | | |
| Terminalling and storage segment | | | | | |
| Lubricant product sales | $ | 145,327 |
| | $ | 130,466 |
| | $ | 113,578 |
|
| Throughput and storage | 96,287 |
| | 99,705 |
| | 123,132 |
|
| | $ | 241,614 |
| | $ | 230,171 |
| | $ | 236,710 |
|
| Natural gas services segment | | | | | |
| Natural gas liquids product sales | $ | 496,026 |
| | $ | 473,865 |
| | $ | 330,200 |
|
| Natural gas storage | 52,109 |
| | 58,817 |
| | 61,133 |
|
| | $ | 548,135 |
| | $ | 532,682 |
| | $ | 391,333 |
|
| Sulfur service segment | | | | | |
| Sulfur product sales | $ | 46,347 |
| | $ | 49,204 |
| | $ | 53,327 |
|
| Fertilizer product sales | 75,041 |
| | 74,528 |
| | 76,931 |
|
| Sulfur services | 11,148 |
| | 10,952 |
| | 10,800 |
|
| | $ | 132,536 |
| | $ | 134,684 |
| | $ | 141,058 |
|
| Marine transportation segment | | | | | |
| Inland transportation | $ | 44,580 |
| | $ | 42,874 |
| | $ | 50,556 |
|
| Offshore transportation | 5,790 |
| | 5,705 |
| | 7,734 |
|
| | $ | 50,370 |
| | $ | 48,579 |
| | $ | 58,290 |
|
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 ServicesLiquids Segment
Natural Gas Liquids ("NGL") distribution revenue is recognized when product is delivered by truck, rail, or pipeline to the Partnership's NGL customers. Revenue is recognized on title transfer of the product to the customer. Delivery of product is invoiced as the transaction occurs and are generally paid within a month. Natural gas storage revenue is recognized when the service is provided to the customer. The performance of the service is invoiced as the transaction occurs and is generally paid within a month.
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 areis generally paid within a month. Revenue from sulfur services is recognized as services are performed during each monthly period. The performance of the service is invoiced as the transaction occurs and is generally paid within a month.
Marine Transportation Segment
Revenue 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.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2022 | | 2023 | | 2024 | | 2025 | | Thereafter | | Total |
| Terminalling and storage | | | | | | | | | | | | | |
| Throughput and storage | $ | 43,253 | | | $ | 40,394 | | | $ | 41,605 | | | $ | 42,854 | | | $ | 44,197 | | | $ | 294,141 | | | $ | 506,444 | |
| Sulfur services | | | | | | | | | | | | | |
| Sulfur product sales | 17,165 | | | 16,279 | | | 15,234 | | | 975 | | | 975 | | | 0 | | | 50,628 | |
| Total | $ | 60,418 | | | $ | 56,673 | | | $ | 56,839 | | | $ | 43,829 | | | $ | 45,172 | | | $ | 294,141 | | | $ | 557,072 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | Thereafter | | Total |
| Terminalling and storage | | | | | | | | | | | | | |
| Throughput and storage | $ | 50,079 |
| | $ | 49,354 |
| | $ | 46,642 |
| | $ | 42,735 |
| | $ | 42,854 |
| | $ | 392,624 |
| | $ | 624,288 |
|
| Natural gas services | | | | | | | | | | | | | |
| Natural gas storage | 37,979 |
| | 32,119 |
| | 26,276 |
| | 24,615 |
| | 10,107 |
| | — |
| | 131,096 |
|
| Sulfur services | | | | | | | | | | | | | |
| Sulfur product sales | 17,082 |
| | 4,898 |
| | 1,181 |
| | 295 |
| | — |
| | — |
| | 23,456 |
|
| Marine transportation | | | | | | | | | | | | | |
| Offshore transportation | 6,205 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 6,205 |
|
| Total | $ | 111,345 |
| | $ | 86,371 |
| | $ | 74,099 |
| | $ | 67,645 |
| | $ | 52,961 |
| | $ | 392,624 |
| | $ | 785,045 |
|
NOTE 7. INVENTORIES
Components of inventories at December 31, 20182020 and 20172019 were as follows:
| | | | | | | | | | | |
| | 2020 | | 2019 |
| Natural gas liquids | $ | 27,878 | | | $ | 19,097 | |
| Sulfur | 24 | | | 4,586 | |
| Fertilizer | 10,854 | | | 15,852 | |
| Lubricants | 11,002 | | | 18,925 | |
| Other | 4,364 | | | 4,080 | |
| | $ | 54,122 | | | $ | 62,540 | |
|
| | | | | | | |
| | 2018 | | 2017 |
| Natural gas liquids | $ | 32,388 |
| | $ | 47,462 |
|
| Sulfur | 12,818 |
| | 8,436 |
|
| Fertilizer | 14,208 |
| | 18,674 |
|
| Lubricants | 22,887 |
| | 20,086 |
|
| Other | 2,767 |
| | 2,594 |
|
| | $ | 85,068 |
| | $ | 97,252 |
|
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, 20182020 and 2017,2019, property, plant and equipment consisted of the following: | | | | | | | | | | | | | | | | | |
| | Depreciable Lives | | 2020 | | 2019 |
| Land | — | | $ | 21,459 | | | $ | 22,083 | |
| Improvements to land and buildings | 10-25 years | | 135,227 | | | 135,666 | |
| Storage equipment | 5-50 years | | 121,437 | | | 120,788 | |
| Marine vessels | 4-25 years | | 179,666 | | | 182,115 | |
| Operating plant and equipment | 3-50 years | | 356,293 | | | 343,236 | |
| Furniture, fixtures and other equipment | 3-20 years | | 14,209 | | | 12,896 | |
| Transportation equipment | 3-7 years | | 49,836 | | | 47,525 | |
| Construction in progress | | | 10,981 | | | 20,419 | |
| | | | $ | 889,108 | | | $ | 884,728 | |
|
| | | | | | | | | |
| | Depreciable Lives | | 2018 | | 2017 |
| Land | — | | $ | 22,293 |
| | $ | 21,719 |
|
| Improvements to land and buildings | 10-25 years | | 129,985 |
| | 135,896 |
|
| Storage equipment | 5-50 years | | 174,851 |
| | 178,815 |
|
| Marine vessels | 4-25 years | | 191,070 |
| | 176,782 |
|
| Operating plant and equipment | 3-50 years | | 673,909 |
| | 659,854 |
|
| Base Gas | — | | 43,755 |
| | 43,799 |
|
| Furniture, fixtures and other equipment | 3-20 years | | 11,832 |
| | 11,134 |
|
| Transportation equipment | 3-7 years | | 1,821 |
| | 1,535 |
|
| Construction in progress | | | 15,214 |
| | 23,531 |
|
| | | | $ | 1,264,730 |
| | $ | 1,253,065 |
|
Depreciation expense for the years ended December 31, 2020, 2019 and 2018 2017was $55,817, $53,856 and 2016$58,615, respectively, which includes amortization of fixed assets acquired under capital lease obligations of $1,755, $2,686, and $1,174. Gross assets under capital leases were $10,352 and $15,367 at December 31, 2020 and 2019, respectively. Accumulated amortization associated with capital leases was $67,122, $70,904$3,703 and $72,405.$3,941 at December 31, 2020 and 2019, respectively.
Additions to property, plant and equipment included in accounts payable at December 31, 2020, 2019 and 2018 were $468, $3,791, and 2017 were $2,166, respectively. Equipment purchased under capital lease obligations was $83, $1,308, and $4,100,$10,472 for the years ended December 31, 2020, 2019, and 2018, respectively.
NOTE 9. GOODWILL
The following table represents the goodwill balance by reporting unit at December 31, 20182020 and 20172019 as follows:
| | | | | | | | | | | |
| 2020 | | 2019 |
| Carrying amount of goodwill: | | | |
Terminalling and storage1 | $ | 10,985 | | | $ | 11,867 | |
| | | |
| Sulfur services | 5,349 | | | 5,349 | |
| Transportation | 489 | | | 489 | |
| Total goodwill | $ | 16,823 | | | $ | 17,705 | |
|
| | | | | | | |
| | 2018 | | 2017 |
| Carrying amount of goodwill: | | | |
| Terminalling and storage | $ | 11,868 |
| | $ | 11,868 |
|
| Natural gas services | 79 |
| | 79 |
|
| Sulfur services | 5,349 |
| | 5,349 |
|
| Total goodwill | $ | 17,296 |
| | $ | 17,296 |
|
During the impairment evaluation performed at August 31, 2018 and 2017, the Partnership first assessed qualitative factors in determining whether it is more likely than not that the fair value of a reporting unit or other intangible asset is less than its carrying amount. After assessing qualitative factors, the Partnership determined that it is not more likely than not that the fair value of its reporting units are less than its carrying amount. Therefore, no impairment was recorded for the year ended December 31, 2018 or 2017.
During the second quarter of 2016, the Partnership determined that the state of market conditions in the Marine Transportation reporting unit, including the demand for utilization, day rates and the current oversupply of inland tank barges, indicated that an impairment of goodwill may exist. As a result, the Partnership assessed qualitative factors and determined that the Partnership could not conclude it was more likely than not that the fair value of goodwill exceeded its carrying value. In turn, the Partnership prepared a quantitative analysis of the fair value of the goodwill as of June 30, 2016, based on the weighted average valuation of the aforementioned income and market based valuation approaches. The underlying results of the valuation were driven by actual results during the six months ended June 30, 2016 and the pricing and market conditions existing as of June 30, 2016, which were below forecasts at the time of the previous goodwill assessments. Other key estimates, assumptions and inputs used in the valuation included long-term growth rates, discounts rates, terminal values, valuation multiples and relative valuations when comparing the reporting unit to similar businesses or asset bases. Upon completion of the analysis, a $4,145 impairment of all goodwill in the Marine Transportation reporting unit was incurred during the second quarter of 2016. The Partnership did not recognize any other goodwill impairment losses for the year ended December 31, 2016.
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
NOTE 10. LEASES
The Partnership has numerous non-cancelable operating leases primarily for terminal facilities and transportation and other equipment. The leases generally provide that all expenses related to the equipment are to be paid by the lessee.
Operating lease Right-of-Use ("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.
Our leases have remaining lease terms of 1 year to 16 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 also has cancelable operatingincludes extension periods and excludes termination periods from its lease land rentalsterm if, at commencement, it is reasonably likely that the Partnership will exercise the option.
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
The components of lease expense for the years ended December 31, 2020 and outside marine vessel charters.2019 were as follows:
| | | | | | | | | | | |
| 2020 | | 2019 |
| Operating lease cost | $ | 10,672 | | | $ | 10,805 | |
| Finance lease cost: | | | |
| Amortization of right-of-use assets | 1,755 | | | 2,686 | |
| Interest on lease liabilities | 294 | | | 671 | |
| Short-term lease cost | 13,187 | | | 13,756 | |
| Variable lease cost | 109 | | | 92 | |
| Total lease cost | $ | 26,017 | | | $ | 28,010 | |
Supplemental cash flow information for the years ended December 31, 2020 and 2019 related to leases were as follows:
| | | | | | | | | | | |
| 2020 | | 2019 |
| Cash paid for amounts included in the measurement of lease liabilities: | | | |
| Operating cash flows from operating leases | $ | 23,996 | | | $ | 24,526 | |
| Operating cash flows from finance leases | 294 | | | 671 | |
| Financing cash flows from finance leases | 3,701 | | | 5,517 | |
| | | |
| Right-of-use assets obtained in exchange for lease obligations: | | | |
| Operating leases | $ | 7,779 | | | $ | 9,122 | |
| Finance leases | 83 | | | 1,309 | |
Supplemental balance sheet information related to leases was as follows: | | | | | | | | | | | |
| 2020 | | 2019 |
| Operating Leases | | | |
| Operating lease right-of-use assets | $ | 22,260 | | | $ | 23,901 | |
| | | |
| Current portion of operating lease liabilities included in "Other accrued liabilities" | $ | 7,529 | | | $ | 7,722 | |
| Operating lease liabilities | 15,181 | | | 16,656 | |
| Total operating lease liabilities | $ | 22,710 | | | $ | 24,378 | |
| | | |
| Finance Leases | | | |
| Property, plant and equipment, at cost | $ | 10,352 | | | $ | 15,367 | |
| Accumulated depreciation | (3,703) | | | (3,941) | |
| Property, plant and equipment, net | $ | 6,649 | | | $ | 11,426 | |
| | | |
| Current installments of finance lease obligations | $ | 2,707 | | | $ | 6,758 | |
| Finance lease obligations | 289 | | | 717 | |
| Total finance lease obligations | $ | 2,996 | | | $ | 7,475 | |
| | | |
| Weighted Average Remaining Lease Term (years) | | | |
| Operating leases | 5.87 | | 6.26 |
| Finance leases | 1.39 | | 0.97 |
| Weighted Average Discount Rate | | | |
| Operating leases | 5.04 | % | | 5.27 | % |
| Finance leases | 6.04 | % | | 6.83 | % |
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
The Partnership’s future minimum lease obligations as of December 31, 20182020 consist of the following:
| | | | | | | | | | | |
| Operating Leases | | Finance Leases |
| Year 1 | $ | 8,445 | | | $ | 2,733 | |
| Year 2 | 6,016 | | | 289 | |
| Year 3 | 3,250 | | | 9 | |
| Year 4 | 1,727 | | | 0 | |
| Year 5 | 1,111 | | | 0 | |
| Thereafter | 5,830 | | | 0 | |
| Total | 26,379 | | | 3,031 | |
| Less amounts representing interest costs | (3,669) | | | (35) | |
| Total lease liability | $ | 22,710 | | | $ | 2,996 | |
|
| | | |
| Fiscal year | Operating Leases |
| | |
| 2019 | $ | 7,869 |
|
| 2020 | 5,417 |
|
| 2021 | 3,216 |
|
| 2022 | 2,129 |
|
| 2023 | 1,467 |
|
| Thereafter | 7,823 |
|
| Total | $ | 27,921 |
|
Rent expense 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 continuing operating leases fora minimum fee. Future minimum revenues the years endedPartnership expects to receive under these non-cancelable arrangements as of December 31, 2018, 2017 and 2016 was $14,076, $15,908 and $19,005, respectively.2020 are as follows: 2021 - $20,333; 2022 - $13,692; 2023 - $13,297; 2024 - $13,297; 2025 - $12,908; subsequent years - $38,539.
NOTE 11. INVESTMENT IN WTLPG
As discussed in Note 5, on July 31, 2018, the Partnership completed the sale of its 20 percent20% non-operating interest in WTLPG. Prior to the sale, the Partnership owned a 19.8% limited partnership and 0.2% general partnership interest in WTLPG. A wholly-owned subsidiary of ONEOK is the operator of the assets. WTLPG owns an approximate 2,300 mile common-carrier pipeline system that primarily transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. The Partnership recognized its 20% interest in WTLPG as "Investment in WTLPG" on its Consolidated Balance Sheets. The Partnership accounted for its ownership interest in WTLPG under the equity method of accounting. As discussed in Note 5, the Partnership sold its 20% non-operating partnership interest to ONEOK on July 31, 2018.
Selected financial information for WTLPG during the period of ownership is as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
|
As of July 31, | | Seven Months Ended July 31, |
| Total Assets | | Long-Term Debt | | Members’ Equity/Partners' Capital | | Revenues | | Net Income |
| 2018 | | | | | | | | | |
| WTLPG | $ | 928,349 | | | $ | 0 | | | $ | 868,894 | | | $ | 55,534 | | | $ | 16,642 | |
| | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| |
As of July 31, | | Seven Months Ended July 31, |
| | Total Assets | | Long-Term Debt | | Members’ Equity/Partners' Capital | | Revenues | | Net Income |
| 2018 | | | | | | | | | |
| WTLPG | $ | 928,349 |
| | $ | — |
| | $ | 868,894 |
| | $ | 55,534 |
| | $ | 16,642 |
|
| | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| |
As of December 31, | | Years ended December 31, |
| | Total Assets | | Long-Term Debt | | Members’ Equity/Partners' Capital | | Revenues | | Net Income |
| 2017 | | | | | | | | | |
| WTLPG | $ | 837,163 |
| | $ | — |
| | $ | 787,426 |
| | $ | 87,048 |
| | $ | 21,571 |
|
| 2016 | | | | | | | | | |
| WTLPG | $ | 812,464 |
| | $ | — |
| | $ | 790,406 |
| | $ | 88,468 |
| | $ | 23,883 |
|
| | | | | | | | | | |
NOTE 12. FAIR VALUE MEASUREMENTS
The Partnership uses a valuation framework based upon inputs that market participants use in pricing certain assets and liabilities. These inputs are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources. Unobservable inputs represent the Partnership's own market assumptions. Unobservable inputs are used only if observable inputs are unavailable or not reasonably available without undue cost and effort. The two types of inputs are further prioritized into the following hierarchy:
Level 1: Quoted market prices in active markets for identical assets or liabilities.
Level 2: Observable market based inputs or unobservable inputs that are corroborated by market data.
Level 3: Unobservable inputs that reflect the entity's own assumptions and are not corroborated by market data.
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
Assets and liabilities measured at fair value on a recurring basis are summarized below:
| | | | | | | | | | | |
| Level 2 |
| December 31, |
| 2020 | | 2019 |
| Commodity derivative contracts, net | $ | (207) | | | $ | (667) | |
|
| | | | | | | |
| | Level 2 |
| | December 31, |
| | 2018 | | 2017 |
| Commodity derivative contracts, net | $ | 4 |
| | $ | (72 | ) |
The Partnership is required to disclose estimated fair values for its financial instruments. Fair value estimates are set forth below for these financial instruments. The following methods and assumptions were used to estimate the fair value of each class of financial instrument:
•Accounts and other receivables, trade and other accounts payable, accrued interest payable, other accrued liabilities, income taxes payable and due from/to affiliates: The carrying amounts approximate fair value due to the short maturity and highly liquid nature of these instruments, and as such these have been excluded from the table below. There is negligible credit risk associated with these instruments.
Long-term•Current and non-current portion of long-term debt: The carrying amount of the revolving credit facility approximates fair value due to the debt having a variable interest rate and is in Level 2. The Partnership has not had any indicators which represent a change in the market spread associated with its variable interest rate debt. The estimated fair value of the senior unsecured notes2021 Notes, 2024 Notes, and 2025 Notes (collectively, the "senior notes") is considered Level 1,2, as the fair value is based onupon quoted market prices for identical liabilities in active markets.markets that are not active.
| | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2020 | | December 31, 2019 |
| Carrying
Value | | Fair
Value | | Carrying
Value | | Fair
Value |
| 2021 Notes | $ | 28,790 | | | $ | 28,581 | | | $ | 373,374 | | | $ | 343,470 | |
| 2024 Notes | $ | 50,173 | | | $ | 55,214 | | | $ | 0 | | | $ | 0 | |
| 2025 Notes | $ | 290,250 | | | $ | 288,692 | | | $ | 0 | | | $ | 0 | |
| Total | $ | 369,213 | | | $ | 372,487 | | | $ | 373,374 | | | $ | 343,470 | |
|
| | | | | | | | | | | | | | | |
| | December 31, 2018 | | December 31, 2017 |
| | Carrying Value | | Fair Value | | Carrying Value | | Fair Value |
| 2021 Senior unsecured notes | $ | 372,996 |
| | $ | 360,138 |
| | $ | 372,618 |
| | $ | 381,657 |
|
NOTE 13. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
The Partnership’s results of operations could be materially impacted by changes in NGL 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. All derivatives and hedging instruments are included on the balance sheet as an asset or a liability measured at fair value and changes in fair value are recognized currently in earnings. All of the Partnership's derivatives are non-hedge derivatives and therefore all changes in fair values are recognized as gains and losses in the earnings of the periods in which they occur.
(a) Commodity Derivative Instruments
The Partnership from time to time has used derivatives to manage the risk of commodity price fluctuation. Commodity risk is the adverse effect on the value of a liability or future purchase that results from a change in commodity price. The Partnership has established a hedging policy and monitors and manages the commodity market risk associated with potential commodity risk exposure. In addition, the Partnership has focused on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction. The Partnership has entered into hedging transactions as of December 31, 20182020 to protect a portion of its commodity price risk exposure. These hedging arrangements are in the form of swaps for NGLs. The Partnership has instruments totaling a gross notional quantity of 55137,000 barrels settling during the period from January 31, 20192021 through February 28, 2019.2021. At December 31, 2017,2019, the Partnership had instruments totaling a gross notional quantity of 145452,000 barrels settling during the period from January 31, 20182020 through February 28, 2018.29, 2020. These instruments settle against the applicable pricing source for each grade and location.
(b) Interest Rate Derivative Instruments90
The Partnership is exposed to market risks associated with interest rates. Market risk is the adverse effect on the value of a financial instrument that results from a change in interest rates. We minimize this market risk by establishing and monitoring parameters that limit the types and degree of market risk that may be undertaken. The Partnership enters into
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
interest rate swaps to manage interest rate risk associated with the Partnership’s variable rate credit facility and its senior unsecured notes.
During the twelve months ended December 31, 2016, the Partnership entered into contracts which provided the counterparty the option to enter into swap contracts to hedge the Partnership's exposure to changes in the fair value of its senior unsecured notes ("interest rate swaptions"). In connection with the interest rate swaption contracts, the Partnership received premiums of $630, which represented the fair value on the date the transactions were initiated and were initially recorded as a derivative liability on the Partnership's Consolidated Balance Sheet, during the twelve months ended December 31, 2016. Each of the interest rate swaptions was fully amortized as of December 31, 2016. Interest rate swaption contract premiums received are amortized over the period from initiation of the contract through their termination date. For the twelve months ended December 31, 2016, the Partnership recognized $630 of premium in "Interest expense, net" on the Partnership's Consolidated Statement of Operations related to the interest rate swaption contracts.
For information regarding fair value amounts and gains and losses on interest rate derivative instruments and related hedged items, see "Tabular Presentation of Gains and Losses on Derivative Instruments and Related Hedged Items" below.
(c) (b) Tabular Presentation of Gains and Losses on Derivative Instruments
The following table summarizes the fair values and classification of the Partnership’s derivative instruments in its Consolidated Balance Sheets:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Fair Values of Derivative Instruments in the Consolidated Balance Sheet |
| Derivative Assets | Derivative Liabilities |
| | | Fair Values | | Fair Values |
| | Balance Sheet Location | December 31, 2020 | | December 31, 2019 | Balance Sheet Location | December 31, 2020 | | December 31, 2019 |
| Derivatives not designated as hedging instruments: | Current: | | | | | | | |
| Commodity contracts | Fair value of derivatives | $ | 0 | | | $ | 0 | | Fair value of derivatives | $ | 207 | | | $ | 667 | |
| Total derivatives not designated as hedging instruments | | $ | 0 | | | $ | 0 | | | $ | 207 | | | $ | 667 | |
|
| | | | | | | | | | | | | | | | |
| | Fair Values of Derivative Instruments in the Consolidated Balance Sheet |
| | Derivative Assets | Derivative Liabilities |
| | | Fair Values | | Fair Values |
| | Balance Sheet Location | December 31, 2018 | | December 31, 2017 | Balance Sheet Location | December 31, 2018 | | December 31, 2017 |
| Derivatives not designated as hedging instruments: | Current: | | | | | | | |
| Commodity contracts | Fair value of derivatives | $ | 4 |
| | $ | — |
| Fair value of derivatives | $ | — |
| | $ | 72 |
|
| Total derivatives not designated as hedging instruments | | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | 72 |
|
Effect of Derivative Instruments on the Consolidated Statement of Operations For the Twelve MonthsYears Ended December 31, 2018, 2017,2020, 2019, and 20162018
| | | | | | | | | | | | | | | | | | | | |
| | Location of Gain or (Loss) Recognized in Income on Derivatives | Amount of (Gain) or Loss Recognized in Income on Derivatives |
| | | 2020 | | 2019 | | 2018 |
| Derivatives not designated as hedging instruments: | | | | |
| Commodity contracts | Cost of products sold | 8,209 | | | 5,137 | | | (14,024) | |
| Total derivatives not designated as hedging instruments | $ | 8,209 | | | $ | 5,137 | | | $ | (14,024) | |
|
| | | | | | | | | | | | |
| | Location of Gain or (Loss) Recognized in Income on Derivatives | Amount of (Gain) or Loss Recognized in Income on Derivatives |
| | | 2018 | | 2017 | | 2016 |
| Derivatives not designated as hedging instruments: | | | | |
| Interest rate swaption contracts | Interest expense | $ | — |
| | $ | — |
| | $ | (630 | ) |
| Interest rate contracts | Interest expense | — |
| | — |
| | (366 | ) |
| Commodity contracts | Cost of products sold | (14,024 | ) | | 1,304 |
| | 5,129 |
|
| Total derivatives not designated as hedging instruments | $ | (14,024 | ) | | $ | 1,304 |
| | $ | 4,133 |
|
NOTE 14. RELATED PARTY TRANSACTIONS
As of December 31, 2018,2020, Martin Resource Management Corporation owned 6,114,532 of the Partnership’s common units representing approximately 15.7% of the Partnership’s outstanding limited partnership units. Martin Resource Management Corporation controls the Partnership's general partner by virtue of its 51% voting interest in Holdings, the sole member of the Partnership's general partner. The Partnership’s general partner, MMGP, owns a 2% general partner interest in the Partnership and the Partnership’s incentive distribution rights. The Partnership’s general partner’s ability, as general partner, to manage and operate the Partnership, and Martin Resource Management’sManagement Corporation’s ownership as of December 31, 2018,2020 of approximately 15.7% of the
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
Partnership’s outstanding limited partnership units, effectively gives Martin Resource Management 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.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:
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
•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 by-products;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:
| |
◦ | providing land transportation of various liquids; |
| |
◦ | distributing fuel oil, asphalt, marine fuel and other liquids; |
| |
◦ | providing marine bunkering and other shore-based marine services in Texas, Louisiana, Mississippi, Alabama, and Florida; |
| |
◦ | operating a crude oil gathering business in Stephens, Arkansas; |
| |
◦ | providing crude oil gathering, refining, and marketing services of base oils, asphalt, and distillate products in Smackover, Arkansas; |
| |
◦ | providing crude oil marketing and transportation from the well head to the end market; |
| |
◦ | operating an environmental consulting company; |
| |
◦ | operating an engineering services company; |
| |
◦ | supplying employees and services for the operation of the Partnership's business; and |
| |
◦ | operating, solely for the Partnership's account, the asphalt facilities in Omaha, Nebraska, Port Neches, Texas, Hondo, Texas, and South Houston, Texas. |
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS◦distributing asphalt, marine fuel and other liquids;
(Dollars
◦providing shore-based marine services in thousands, except where otherwise indicated)
Texas, Louisiana, Mississippi, and Alabama;
◦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 the Partnership's account, the asphalt facilities in Omaha, Nebraska, Port Neches, Texas, and South Houston, Texas.
•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.
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
Effective January 1, 2018,2020, through December 31, 2018,2020, the Conflicts Committeeboard of directors of our general partner approved an annual reimbursement amount for indirect expenses of $16,416.$16,410. The Partnership reimbursed Martin Resource Management Corporation for $16,416, $16,416$16,410, $16,657 and $13,033$16,416 of indirect expenses for the years ended December 31, 2018, 20172020, 2019 and 2016,2018, respectively. The Conflicts Committeeboard 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 forto 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’sManagement 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"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.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.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.Management Corporation.
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
Motor CarrierMaster Transportation Services Agreement
Motor Carrier Master Transportation Services Agreement. TheMTI, a wholly owned subsidiary of the Partnership, is a party to a motor carriermaster transportation services agreement effective January 1, 2006 as amended,2019, with Martin Transport, Inc., acertain wholly owned subsidiarysubsidiaries of Martin Resource Management through which Martin Transport, Inc. operates its land transportation operations.Corporation. Under the agreement, Martin Transport, Inc.MTI agreed to transport the Partnership's NGLs as well as other liquid products.Martin Resource Management Corporation's petroleum products and by-products.
Term and Pricing. The agreement has an initial term that expired in December 2007 but automatically renews for consecutive one year periodswill continue unless either party terminates the agreement by giving at least 30 days' written notice to the other party at least 30 days prior to the expiration of the then-applicable term. The Partnership has the right to terminate this agreement at any time by providing 90 days prior notice.party. These rates are subject to any adjustments which are mutually agreed upon or in accordance with a price index. Additionally, during the term of the agreement, shipping charges are also subject to fuel surcharges determined on a weekly basis in accordance with the U.S. Department of Energy’s national diesel price list.
Indemnification. MTI has agreed to indemnify Martin TransportResource 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 indemnified usagreed to indemnify MTI against all claims arising out of the negligence or willful misconduct of Martin TransportResource Management Corporation and its officers, employees, agents, representatives and subcontractors. We indemnified Martin Transport against all claims arising out of the negligence or willful misconduct of us and our officers, employees, agents, representatives and subcontractors. In the event a claim is the result of the joint negligence or misconduct of MTI and Martin Transport and us, ourResource Management Corporation, indemnification obligations will be shared in proportion to each party’s allocable share of such joint negligence or misconduct.
As discussed in Item 1. Business, the Partnership purchased Martin Transport, Inc. effective January 1, 2019.
MARTIN MIDSTREAM PARTNERS L.P.
Marine AgreementsNOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Marine Transportation Agreement. The Partnership is a party to a marine transportation agreement effective January 1, 2006, as amended, under which the Partnership provides marine transportation services to Martin Resource Management on a spot-contract basis at applicable market rates. Effective each January 1, this agreement automatically renews for consecutive one year periods unless either party terminates the agreement by giving written notice to the other party at least 60 days prior to the expiration of the then applicable term. The fees the Partnership charges Martin Resource Management are based on applicable market rates.
Marine Fuel. The Partnership is a party to an agreement with Martin Resource Management dated November 1, 2002 under which Martin Resource Management provides the Partnership with marine fuel from its locations(Dollars in the Gulf of Mexico at a fixed rate in excess of a price index. Under this agreement, the Partnership agreed to purchase all of its marine fuel requirements that occur in the areas serviced by Martin Resource Management.thousands, except where otherwise indicated)
Terminal Services Agreements
Diesel Fuel Terminal Services Agreement. Effective January 1, 2016, the Partnership entered into a second amended and restated terminalling services agreement under which the Partnership provides terminal services to Martin Resource Management Corporation for marine fuel distribution. At such time, the per gallonper-gallon throughput fee the Partnership charged under this agreement was increased when compared to the previous agreement and may be adjusted annually based on a price index. This agreement was further amended on January 1, 2017, and October 1, 2017, April 1, 2019, and January 1, 2020 to modify its minimum throughput requirements and throughput fees. ThisThe term of this agreement as amended, expired September 30, 2018is currently evergreen and continued thereafterit 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 a price index. Under this agreement, the Partnership agreed to purchase all of its marine fuel requirements that occur in the areas serviced by Martin Resource Management Corporation.
Other Agreements
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
Cross Tolling Agreement. The Partnership is a party to an amended and restated tolling agreement with Cross Oil Refining and Marketing, Inc. ("Cross") dated October 28, 2014, under which the Partnership processes crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts for Cross. The tolling agreement expires November 25, 2031. Under this tolling agreement, Cross agreed to process a minimum of 6,500 barrels per day of crude oil at the facility at a fixed price per barrel. Any additional barrels are processed at a modified price per barrel. In addition, Cross agreed to pay a monthly reservation fee and a periodic fuel surcharge fee based on certain parameters specified in the tolling agreement. 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)surcharge and capital recovery fee) are subject to escalation annually based upon the greater of 3% or the increase in the Consumer Price Index for a specified annual period. In addition, onAlso, the third, sixthPartnership 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 ninth anniversariestrailers, 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 agreement,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 parties can negotiate an upward or downward adjustment in the fees subject to their mutual agreement.fiscal years ended December 31, 2020, 2019 and 2018 were approximately $650, $875, and $2,466, respectively.
Sulfuric Acid Sales Agency Agreement. The Partnership was previously a party to a third amended and restated sulfuric acid sales agency agreement dated August 2, 2017 but effective October 1, 2017, under which a successor in interest to the agreement from Martin Resource Management, Saconix LLC ("Saconix"), a limited liability company in which Martin Resource Management held a minority equity interest, purchased and marketed the sulfuric acid produced by the Partnership’s sulfuric acid production plant at Plainview, Texas, that was not consumed by the Partnership’s internal operations. This agreement, as amended, was to remain in place until September 30, 2020 and automatically renew year to year thereafter until either party provided 90 days’ written notice of termination prior to the expiration of the then existing term. Under this agreement, the Partnership sold all of its excess sulfuric acid to Saconix, who then marketed and sold such acid to third-parties. The Partnership shared in the profit of such sales. Effective May 31, 2018, Martin Resource Management no longer holds an equity interest in Saconix. These transactions are reported below as related party transactions during the period the equity interest was held. Transactions subsequent to Martin Resource Management's disposition of the equity interest will be reported as third party transactions.
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
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
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: | 2020 | | 2019 | | 2018 |
| Terminalling and storage | $ | 63,823 | | | $ | 71,733 | | | $ | 79,137 | |
| Transportation | 21,997 | | | 24,243 | | | 27,588 | |
| | | | | |
| Product sales: | | | | | |
| | | | | |
| Sulfur services | 60 | | | 54 | | | 630 | |
| Terminalling and storage | 257 | | | 877 | | | 667 | |
| 317 | | | 931 | | | 1,297 | |
| $ | 86,137 | | | $ | 96,907 | | | $ | 108,022 | |
|
| | | | | | | | | | | |
| Revenues: | 2018 | | 2017 | | 2016 |
| Terminalling and storage | $ | 79,219 |
| | $ | 82,205 |
| | $ | 82,437 |
|
| Marine transportation | 15,442 |
| | 16,801 |
| | 21,767 |
|
| Natural gas services | — |
| | 122 |
| | 699 |
|
| Product sales: | | | | | |
| Natural gas services | 19 |
| | 1,043 |
| | 8 |
|
| Sulfur services | 630 |
| | 1,963 |
| | 2,006 |
|
| Terminalling and storage | 758 |
| | 572 |
| | 1,020 |
|
| | 1,407 |
| | 3,578 |
| | 3,034 |
|
| | $ | 96,068 |
| | $ | 102,706 |
| | $ | 107,937 |
|
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 | $ | 10,519 | | | $ | 10,765 | | | $ | 10,641 | |
| Terminalling and storage | 18,429 | | | 23,859 | | | 24,613 | |
| $ | 28,948 | | | $ | 34,624 | | | $ | 35,254 | |
|
| | | | | | | | | | | |
| Cost of products sold: | | | | | |
| Natural gas services | $ | 14,816 |
| | $ | 18,946 |
| | $ | 22,886 |
|
| Sulfur services | 17,418 |
| | 15,564 |
| | 15,339 |
|
| Terminalling and storage | 28,304 |
| | 17,612 |
| | 13,838 |
|
| | $ | 60,538 |
| | $ | 52,122 |
| | $ | 52,063 |
|
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
The impact of related party operating expenses is reflected in the Consolidated Statements of Operations as follows:
| | | | | | | | | | | | | | | | | |
| Operating expenses: | | | | | |
| Transportation | $ | 55,786 | | | $ | 61,376 | | | $ | 62,965 | |
| Natural gas liquids | 2,003 | | | 3,446 | | | 3,779 | |
| Sulfur services | 4,489 | | | 4,810 | | | 5,381 | |
| Terminalling and storage | 17,797 | | | 18,562 | | | 18,753 | |
| $ | 80,075 | | | $ | 88,194 | | | $ | 90,878 | |
|
| | | | | | | | | | | |
| Operating expenses: | | | | | |
| Marine transportation | $ | 22,326 |
| | $ | 23,815 |
| | $ | 28,107 |
|
| Natural gas services | 8,851 |
| | 9,007 |
| | 9,258 |
|
| Sulfur services | 5,497 |
| | 5,821 |
| | 5,995 |
|
| Terminalling and storage | 18,854 |
| | 25,701 |
| | 27,481 |
|
| | $ | 55,528 |
| | $ | 64,344 |
| | $ | 70,841 |
|
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 | $ | 7,358 | | | $ | 7,107 | | | $ | 1,606 | |
| Natural gas liquids | 2,397 | | | 2,804 | | | 2,942 | |
| Sulfur services | 3,080 | | | 2,850 | | | 2,684 | |
| Terminalling and storage | 3,403 | | | 3,083 | | | 2,766 | |
| Indirect overhead allocation, net of reimbursement | 16,648 | | | 16,778 | | | 16,443 | |
| $ | 32,886 | | | $ | 32,622 | | | $ | 26,441 | |
|
| | | | | | | | | | | |
| Selling, general and administrative: | | | | | |
| Marine transportation | $ | 704 |
| | $ | 34 |
| | $ | 30 |
|
| Natural gas services | 5,568 |
| | 8,162 |
| | 7,566 |
|
| Sulfur services | 2,684 |
| | 2,526 |
| | 2,732 |
|
| Terminalling and storage | 2,847 |
| | 2,278 |
| | 2,526 |
|
| Indirect overhead allocation, net of reimbursement | 16,443 |
| | 16,416 |
| | 13,036 |
|
| | $ | 28,246 |
| | $ | 29,416 |
| | $ | 25,890 |
|
Other Related Party Transactions
The Partnership had a $15,000 note receivable from an affiliate of Martin Resource Management which previously bore an annual interest rate of 15% and had a maturity date of August 31, 2026, the balance of which could be prepaid on or after September 1, 2016. On February 14, 2017, the Partnership notified Martin Resource Management that it would be requesting voluntary repayment of the long-term Note Receivable plus accrued interest. During second quarter of 2017, the Note Receivable was fully repaid. The note has historically been recorded in "Note receivable - affiliates" on the Partnership's Consolidated Balance Sheets. Interest income for the years ended December 31, 2018, 2017, and 2016 was $0, $943 and $2,256, respectively, and is included in "Interest expense, net" in the Consolidated Statements of Operations.
NOTE 15. SUPPLEMENTAL BALANCE SHEET INFORMATION
Components of "Intangibles and other assets, net" at December 31, 20182020 and 20172019 were as follows:
|
| | | | | | | |
| | 2018 | | 2017 |
| Customer contracts and relationships, net | $ | 18,222 |
| | $ | 25,252 |
|
| Other intangible assets | 1,310 |
| | 1,752 |
|
| Other | 4,179 |
| | 5,797 |
|
| | $ | 23,711 |
| | $ | 32,801 |
|
95
Other intangible assets consist of covenants not-to-compete and technology-based assets.
Aggregate amortization expense for customer contracts and other intangible assets included in continuing operations was $9,228, $13,887, and $19,548, for the years ended December 31, 2018, 2017 and 2016, respectively, and accumulated amortization amounted to $44,510 and $39,462 at December 31, 2018 and 2017, respectively.
Estimated amortization expense for intangibles and other assets for the years subsequent to December 31, 2018 are as follows: 2019 - $6,063; 2020 - $5,272; 2021 - $4,319; 2022 - $4,295; 2023 - $1,952; subsequent years - $55.
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
| | | | | | | | | | | |
| | 2020 | | 2019 |
| Catalyst and turnaround costs | $ | 803 | | | $ | 1,655 | |
| Other intangible assets | 586 | | | 936 | |
| Other | 1,416 | | | 976 | |
| | $ | 2,805 | | | $ | 3,567 | |
Other intangible assets consist of covenants not-to-compete and 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 $5,235, $5,797, and $2,353, for the years ended December 31, 2020, 2019 and 2018, respectively.
Estimated amortization expense for the years subsequent to December 31, 2020 are as follows: 2021 - $3,222; 2022 - $926; 2023 - $245; 2024 - $62; 2025 - $33; subsequent years - $1.
Components of "Other accrued liabilities" at December 31, 20182020 and 20172019 were as follows:
| | | | | | | | | | | |
| | 2020 | | 2019 |
| Accrued interest | $ | 16,104 | | | $ | 10,761 | |
| Asset retirement obligations | 1,692 | | | 25 | |
| Property and other taxes payable | 4,869 | | | 5,411 | |
| Accrued payroll | 3,244 | | | 3,011 | |
| Operating lease liabilities | 7,529 | | | 7,722 | |
| Other | 969 | | | 1,859 | |
| | $ | 34,407 | | | $ | 28,789 | |
|
| | | | | | | |
| | 2018 | | 2017 |
| Accrued interest | $ | 10,735 |
| | $ | 11,726 |
|
| Asset retirement obligations | 2,721 |
| | 5,429 |
|
| Property and other taxes payable | 5,621 |
| | 5,638 |
|
| Accrued payroll | 3,109 |
| | 3,385 |
|
| Other | 29 |
| | 162 |
|
| | $ | 22,215 |
| | $ | 26,340 |
|
The schedule below summarizes the changes in our asset retirement obligations:
|
| | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 |
| | (In thousands) |
| | | | |
| Beginning asset retirement obligations | $ | 13,512 |
| | $ | 16,418 |
|
Revisions to existing liabilities1 | 4,041 |
| | 5,547 |
|
| Accretion expense | 516 |
| | 404 |
|
| Liabilities settled | (5,640 | ) | | (8,857 | ) |
| Ending asset retirement obligations | 12,429 |
| | 13,512 |
|
Current portion of asset retirement obligations2 | (2,721 | ) | | (5,429 | ) |
Long-term portion of asset retirement obligations3 | $ | 9,708 |
| | $ | 8,083 |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2020 | | 2019 |
| | (In thousands) |
| | | |
| Beginning asset retirement obligations | $ | 8,936 | | | $ | 12,429 | |
Revisions to existing liabilities1 | 918 | | | 0 | |
| Accretion expense | 410 | | | 407 | |
| Liabilities settled | (1,505) | | | (3,900) | |
| Ending asset retirement obligations | 8,759 | | | 8,936 | |
Current portion of asset retirement obligations2 | (1,692) | | | (25) | |
Long-term portion of asset retirement obligations3 | $ | 7,067 | | | $ | 8,911 | |
1Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, discount rates, and the estimated remaining useful life of the assets.
2The current portion of asset retirement obligations is included in "Other current liabilities" on the Partnership's Consolidated Balance Sheets.
3The non-current portion of asset retirement obligations is included in "Other long-term obligations" on the Partnership's Consolidated Balance Sheets.
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in thousands, except where otherwise indicated)
NOTE 16. LONG-TERM DEBT
At December 31, 20182020 and 2017,2019, long-term debt consisted of the following:
| | | | | | | | | | | |
| 2020 | | 2019 |
$300,000 Revolving credit facility at variable interest rate (4.75%1 weighted average at December 31, 2020), due August 20234 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 $3,826 and $4,586, respectively2,6 | $ | 144,174 | | | $ | 196,414 | |
$400,000 Senior notes, 7.25% interest, net of unamortized debt issuance costs of $0 and $770 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, due February 2021, unsecured2,3,4,5 | 28,790 | | | 373,374 | |
$53,750 Senior notes, 10.0% interest, net of unamortized debt issuance costs of $3,577 and $0, respectively, due February 2024 2,3,4 | $ | 50,173 | | | $ | 0 | |
$291,970 Senior notes, 11.5% interest, net of unamortized debt issuance costs of $1,720 and $0, respectively, due February 2025 2,3,4 | $ | 290,250 | | | $ | 0 | |
| Total | 513,387 | | | 569,788 | |
| Less: current portion | (28,790) | | | 0 | |
| Total long-term debt, net of current portion | $ | 484,597 | | | $ | 569,788 | |
| | | |
| Current installments of finance lease obligations | $ | 2,707 | | | $ | 6,758 | |
| Finance lease obligations | 289 | | | 717 | |
| Total finance lease obligations | $ | 2,996 | | | $ | 7,475 | |
|
| | | | | | | |
| | 2018 | | 2017 |
$664,444 Revolving credit facility at variable interest rate (5.24%1 weighted average at December 31, 2018), due March 2020 secured by substantially all of the Partnership’s assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in the Partnership’s operating subsidiaries, net of unamortized debt issuance costs of $3,537 and $4,986, respectively3 | $ | 283,463 |
| | $ | 440,014 |
|
$400,000 Senior notes, 7.25% interest, including unamortized premium of $650 and $956, respectively, also net of unamortized debt issuance costs of $1,454 and $2,138 respectively, issued $250,000 February 2013 and $150,000 April 2014, $26,200 repurchased during 2015, due February 2021, unsecured3,4 | 372,996 |
| | 372,618 |
|
| Total long-term debt | $ | 656,459 |
| | $ | 812,632 |
|
1 Interest rate fluctuates based on the LIBOR rate plus an applicable margin set on the date of each advance. The margin above LIBOR is set every three months. Indebtedness under the credit facility bears interest at LIBOR plus an
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
applicable margin or the base prime rate plus an applicable margin. All amounts outstanding at December 31, 2018 and 20172020 were at LIBOR plus an applicable margin. Themargin of 3.75%, with LIBOR having a floor of 1.0% per annum in accordance with the July 8, 2020 amendment to the Partnership's revolving credit facility described in further detail below. At December 31, 2020 the applicable margin for revolving loans that are LIBOR loans ranges from 2.00%2.75% to 3.00%4.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 1.00%1.75% to 2.00%. The applicable margin for LIBOR borrowings at December 31, 2018 is 2.75%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 Omnibus Agreement. The Partnership is permitted to make quarterly distributions so long as no event of default exists.
32 The Partnership is in compliance with all debt covenants as of December 31, 2018.2020.
4 3 The 2021 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 August 12, 2020 (the "Settlement Date"), the Partnership and Martin Midstream Finance Corp. (collectively, the "Issuers") completed an exchange offer (the "Exchange Offer") and consent solicitation to certain eligible holders of the 2021 Notes and separate but related cash tender offer (the "Cash Tender Offer" and, together with the Exchange Offer, the "Offers") and consent solicitation to certain other holders of the 2021 Notes.
Pursuant to the Exchange Offer, in exchange for $334,441 in aggregate principal amount of 2021 Notes, representing approximately 91.76% of the outstanding aggregate principal amount of the 2021 Notes, the Issuers (i) paid $41,967 in cash, plus $11,854 of accrued and unpaid interest from and including February 15, 2020 until the Settlement Date, (ii) issued $291,970 in aggregate principal amount of the Issuers’ 11.50% senior secured second lien notes due 2025 (the "2025 Notes"),
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
and (iii) pursuant to the rights offering in connection with the Exchange Offer, issued $53,750 aggregate principal amount of the Issuers’ 10.00% senior secured 1.5 lien notes due 2024 (the "2024 Notes"), which amount includes the previously disclosed $3,750 backstop commitment fee which was paid in 2024 Notes.
Pursuant to the Cash Tender Offer, in exchange for $1,225 in aggregate principal amount of 2021 Notes, representing approximately 0.34% of the outstanding aggregate principal amount of 2021 Notes, the Issuers paid $791 in cash, plus $43 of accrued and unpaid interest on such existing 2021 Notes from February 15, 2020 up to, but not including, the Settlement Date.
Whether a debt exchange should be accounted for pursuant to ASC 470-60, Troubled Debt Restructurings by Debtors, or pursuant to ASC 470-50, Modifications and Extinguishments, requires judgments to be made with respect to whether or not an entity is experiencing financial difficulty and if a concession was granted by the creditor. As it was determined that the Partnership did not experience a decrease in the effective borrowing rate of the Partnership’s restructured debt when compared to the Partnership’s existing debt, a concession was not provided and the accounting for troubled debt restructuring was not applied. Further, the Partnership applied the provisions of ASC 470-50 in determining whether to account for the debt exchange as a modification or extinguishment and concluded the debt instruments were not substantially different. Accordingly, the Partnership accounted for the debt exchange as a modification. In conjunction with the transactions above, the Partnership recorded a loss on the Exchange Offer in the amount of $8,817, which includes $9,566 in transaction costs related to the Exchange Offer, plus $189 in net unamortized issuance costs and premiums related to the 2021 Notes, offset by a gain on retirement of the 2021 Notes of $938. In accordance with ASC 470-50 related to debt modifications, the Partnership capitalized certain lender related costs of $5,883 (including the backstop commitment fee described above), which was allocated between the respective senior note issuances and will be amortized over the contractual terms of the 2025 Notes and 2024 Notes.
As of December 31, 2020, the remaining portion of the 2021 Notes were due within twelve months and have therefore been presented as a current liability on the Consolidated Balance Sheets at December 31, 2020. On February 15, 2021, the 2021 Notes matured and the Partnership retired the outstanding balance of $28,790 using its revolving 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.
6 Amendment to Credit Facility. On July 8, 2020, the Partnership amended its revolving credit facility (the "Credit Facility Amendment") to, among other things, permit the Exchange Offer. On August 12, 2020, upon the closing of the Exchange Offer and Cash Tender Offer and satisfaction of certain other conditions set forth in the Credit Facility Amendment, the Credit Facility Amendment, among other things:
•reduced the aggregate amount of commitments under the revolving credit facility from $400 million to $300 million;
•requires an additional $25 million reduction in the commitments under the revolving credit facility if the Partnership receives $25 million or more in net cash proceeds from any asset sale;
•limits the Partnership’s ability to make quarterly distributions to its unitholders in excess of $0.005 per unit unless the Partnership’s Total Leverage Ratio (as defined in the Credit Facility Amendment) is below 3.75:1:00;
•increases the pricing under the revolving credit facility and adds a 1.0% LIBOR floor;
•requires the Partnership to maintain a minimum Interest Coverage Ratio (as defined in the revolving credit facility) of 2.0:1.0 with respect to the fiscal quarters ending in September and December of 2020, 1.75:1.0 with respect to each fiscal quarter ending in 2021, and 2.0:1.0 with respect to each fiscal quarter thereafter;
•requires the Partnership to maintain a maximum Total Leverage Ratio of not more than 5.75:1.0 with respect to the fiscal quarters ending in September and December of 2020 and March and June of 2021, 5.50 with respect to the fiscal quarter ending in September of 2021, 5.00 with respect to the fiscal quarter ending in December of 2021 and the fiscal quarters ending in March, June and September of 2022, and 4.50:1.0 with respect to each fiscal quarter thereafter, which financial covenant replaces the existing maximum Leverage Ratio (as defined in the revolving credit facility in effect prior to the Credit Facility Amendment);
•requires the Partnership to maintain a maximum First Lien Leverage Ratio (as defined in the Credit Facility Amendment) of not more than 2.25:1.0 with respect to the fiscal quarters ending in September and December of 2020
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
and each fiscal quarter ending in 2021, and 2.0:1.0 with respect to each fiscal quarter thereafter, which financial covenant replaces the existing maximum Senior Leverage Ratio (as defined in the revolving credit facility in effect prior to the Credit Facility Amendment).
In conjunction with the Credit Facility Amendment, the Partnership expensed $1,063 in unamortized debt issuance costs related to the revolving credit facility for the year ended December 31, 2020, the amount of which is included in "Interest expense" in the Partnership's Consolidated Statements of Operations.
The Partnership paid cash interest, net of proceeds received fromcapitalized interest, rate swaptions, in the amount of $50,543, $45,728,$37,678, $48,025, and $46,046$50,543 for the years ended December 31, 2018, 20172020, 2019 and 2016,2018, respectively. Capitalized interest was $624, $730,$43, $5, and $1,126$624 for the years ended December 31, 2018, 20172020, 2019 and 2016,2018, respectively.
NOTE 17. PARTNERS' CAPITAL
As of December 31, 2018,2020, partners’ capital consisted of 39,032,23738,851,174 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 15.7% of the Partnership's outstanding common limited partnership units. MMGP, the Partnership's general partner, owns the 2% general partnership interest.
The partnership agreement of the Partnership (the "Partnership Agreement")Agreement contains specific provisions for the allocation of net income and losses to each of the partners for purposes of maintaining their respective partner capital accounts.
Issuance of Common Units
On February 22, 2017, the Partnership completed a public offering of 2,990,000 common units at a price of $18.00 per common unit, before the payment of underwriters' discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Total proceeds from the sale of the 2,990,000 common units, net of underwriters' discounts, commissions and offering expenses, were $51,056. Additionally, the Partnership's general partner contributed $1,098 in cash to the Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the Partnership. All of the net proceeds were used to pay down outstanding amounts under the Partnership's revolving credit facility.
Incentive Distribution Rights
MMGP holds a 2% general partner interest and certain incentive distribution rights ("IDRs") in the Partnership. IDRs are a separate class of non-voting limited partner interest that may be transferred or sold by the general partner under the terms of the Partnership Agreement, and represent the right to receive an increasing percentage of cash distributions after the minimum quarterly distribution and any cumulative arrearages on common units once certain target distribution levels have been achieved. The Partnership is required to distribute all of its available cash from operating surplus, as defined in the Partnership Agreement.
The target distribution levels entitle the general partner to receive 2% of quarterly cash distributions up to $0.55 per unit, 15% of quarterly cash distributions in excess of $0.55 per unit until all unitholders have received $0.625 per unit, 25% of quarterly cash distributions in excess of $0.625 per unit until all unitholders have received $0.75 per unit and 50% of quarterly cash distributions in excess of $0.75 per unit.
For the years ended December 31, 2018, 20172020, 2019 and 2016,2018, the general partner was allocated $0, $0, and $7,786 in0 incentive distributions.
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
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
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
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, |
| | 2020 | | 2019 | | 2018 |
| Continuing operations: | | | | | |
| Income (loss) from continuing operations | $ | (6,771) | | | $ | 4,520 | | | $ | (7,831) | |
| Less pre-acquisition income allocated to Parent | 0 | | | 0 | | | (11,550) | |
| Less general partner’s interest in net income: | | | | | |
| Distributions payable on behalf of IDRs | 0 | | | 0 | | | 0 | |
| Distributions payable on behalf of general partner interest | 61 | | | (20) | | | (689) | |
| General partner interest in undistributed income (loss) | (196) | | | 111 | | | 302 | |
| Less income allocable to unvested restricted units | (21) | | | (1) | | | (12) | |
| Limited partners’ interest in net income | $ | (6,615) | | | $ | 4,430 | | | $ | (18,982) | |
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Continuing operations: | | | | | |
| Income from continuing operations | $ | (7,595 | ) | | $ | 13,007 |
| | $ | 27,003 |
|
| Less general partner’s interest in net income: | | | | | |
| Distributions payable on behalf of IDRs | — |
| | — |
| | 6,642 |
|
| Distributions payable on behalf of general partner interest | (270 | ) | | 1,191 |
| | 1,756 |
|
| General partner interest in undistributed loss | 118 |
| | (931 | ) | | (1,216 | ) |
| Less income allocable to unvested restricted units | (5 | ) | | 32 |
| | 77 |
|
| Limited partners’ interest in net income | $ | (7,438 | ) | | $ | 12,715 |
| | $ | 19,744 |
|
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Discontinued operations: | | | | | |
| Income from discontinued operations | $ | 51,700 |
| | $ | 4,128 |
| | $ | 4,649 |
|
| Less general partner’s interest in net income: | | | | | |
| Distributions payable on behalf of IDRs | — |
| | — |
| | 1,144 |
|
| Distributions payable on behalf of general partner interest | 1,839 |
| | 378 |
| | 302 |
|
| General partner interest in undistributed loss | (805 | ) | | (295 | ) | | (209 | ) |
| Less income allocable to unvested restricted units | 33 |
| | 10 |
| | 13 |
|
| Limited partners’ interest in net income | $ | 50,633 |
| | $ | 4,035 |
| | $ | 3,399 |
|
| | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| Discontinued operations: | | | | | |
| Income (loss) from discontinued operations | $ | 0 | | | $ | (179,466) | | | $ | 63,486 | |
| Less general partner’s interest in net income: | | | | | |
| Distributions payable on behalf of IDRs | 0 | | | 0 | | | 0 | |
| Distributions payable on behalf of general partner interest | 0 | | | 806 | | | 2,258 | |
| General partner interest in undistributed loss | 0 | | | (4,396) | | | (989) | |
| Less income allocable to unvested restricted units | 0 | | | 42 | | | 40 | |
| Limited partners’ interest in net income | $ | 0 | | | $ | (175,918) | | | $ | 62,177 | |
The Partnership allocates the general partner's share of earnings between continuing and discontinued operations as a proportion of net income from continuing and discontinued operations to total net income.
The following are the unit amounts used to compute the basic and diluted earnings per limited partner unit for the periods presented:
| | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2020 | | 2019 | | 2018 |
| Basic weighted average limited partner units outstanding | | 38,656,559 | | | 38,658,881 | | | 38,907,000 | |
| Dilutive effect of restricted units issued | | 0 | | | 0 | | | 15,678 | |
| Total weighted average limited partner diluted units outstanding | | 38,656,559 | | | 38,658,881 | | | 38,922,678 | |
|
| | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| Basic weighted average limited partner units outstanding | | 38,907,000 |
| | 38,101,583 |
| | 35,347,032 |
|
| Dilutive effect of restricted units issued | | 15,678 |
| | 63,318 |
| | 28,231 |
|
| Total weighted average limited partner diluted units outstanding | | 38,922,678 |
| | 38,164,901 |
| | 35,375,263 |
|
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
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, 2020 and 2019 because the limited partners were allocated a net loss in this period.
NOTE 18. UNIT BASED AWARDS
The Partnership recognizes compensation cost related to stock-basedunit-based awards to both employees and non-employees in its consolidated financial statements in accordance with certain provisions of ASC 718. The Partnership recognizes compensation costs related to stock-based awards to directors under certain provisions of ASC 505-50-55 related to equity-based payments to non-employees. Amounts recognized in selling, general, and administrative expense in the consolidated financial statements with respect to these plans are as follows:
| | | | For the Year Ended December 31, | | For the Year Ended December 31, |
| | 2018 | | 2017 | | 2016 | | 2020 | | 2019 | | 2018 |
| Employees | $ | 1,098 |
| | $ | 534 |
| | $ | 783 |
| Employees | $ | 1,204 | | | $ | 1,226 | | | $ | 1,098 | |
| Non-employee directors | 126 |
| | 116 |
| | 121 |
| Non-employee directors | 218 | | | 198 | | | 126 | |
| Total unit-based compensation expense | $ | 1,224 |
| | $ | 650 |
| | $ | 904 |
| Total unit-based compensation expense | $ | 1,422 | | | $ | 1,424 | | | $ | 1,224 | |
Long-Term Incentive Plans
The Partnership's general partner has a long termlong-term incentive plan for employees and directors of the general partner and its affiliates who perform services for the Partnership.
On May 26, 2017, the unitholders of the Partnership approved the Martin Midstream Partners L.P. 2017 Restricted Unit Plan. The plan currently permits the grant of awards covering an aggregate of 3,000,000 common units, all of which can be awarded in the form of restricted units. The plan is administered by the compensation committee of the general partner’s board of directors (the "Compensation Committee").
A restricted unit is a unit that is granted to grantees with certain vesting restrictions, which may be time-based and/or performance-based. Once these restrictions lapse, the grantee is entitled to full ownership of the unit without restrictions. The Compensation Committee may determine to make grants under the plan containing such terms as the Compensation Committee shall determine under the plan. With respect to time-based restricted units ("TBRU's"), the Compensation Committee will determine the time period over which restricted units granted to employees and directors will vest. The Compensation Committee may also award a percentage of restricted units with vesting requirements based upon the achievement of specified pre-established performance targets ("Performance Based Restricted Units" or "PBRU's"). The performance targets may include, but are not limited to, the following: revenue and income measures, cash flow measures, net income before interest expense and income tax expense ("EBIT"), net income before interest expense, income tax expense, and depreciation and amortization ("EBITDA"), distribution coverage metrics, expense measures, liquidity measures, market measures, corporate sustainability metrics, and other measures related to acquisitions, dispositions, operational objectives and succession planning objectives. PBRU's are earned only upon our achievement of an objective performance measure for the performance period. PBRU's which vest are payable in common units. Unvested units granted under the 2017 LTIP may or may not participate in cash distributions depending on the terms of each individual award agreement.
The restricted units issued to directors generally vest in equal annual installments over a four-year period.
On February 20, 2018,12, 2020, the Partnership issued 4,65027,000 TBRU's to each of the Partnership's three3 independent directors under the 2017 LTIP. These restricted common units vest in equal installments of 1,162.56,750 units on January 24, 2019, 2020, 2021, 2022, 2023, and 2022.2024.
On March 1, 2018, the Partnership issued 301,550 TBRU's and 317,925 PBRU's to certain employees of Martin Resource Management.Management Corporation. The TBRU's vest in equal installments over a three-year service period. The PBRU's will vest at the conclusion of a three-year performance period based on certain performance targets. In addition, the PBRU's awarded on March 1, 2018 that are achieved will only vest if the grantee is employed by Martin Resource Management
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
Corporation on March 31, 2021. As of December 31, 2018,2020, the Partnership is unable to ascertain if thecertain performance conditions will be achieved and, as such, has not recognized compensation expense for the vesting of the units. The Partnership will record compensation expense for the vested portion of the units once the achievement of the performance condition is deemed probable.
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, 20182020 is provided below: |
| | | | | | | |
| | Number of Units | | Weighted Average Grant-Date Fair Value Per Unit |
| Non-vested, beginning of year | 98,750 |
| | $ | 24.80 |
|
| Granted (TBRU) | 315,500 |
| | $ | 13.89 |
|
| Granted (PRBU) | 317,925 |
| | $ | 13.89 |
|
| Vested | (81,050 | ) | | $ | 27.77 |
|
| Forfeited | (27,000 | ) | | $ | 13.90 |
|
| Non-Vested, end of year | 624,125 |
| | $ | 13.78 |
|
| | | | |
| Aggregate intrinsic value, end of year | $ | 6,416 |
| | |
| | | | | | | | | | | |
| Number of Units | | Weighted Average Grant-Date Fair Value Per Unit |
| Non-vested, beginning of year | 379,019 | | | $ | 13.91 | |
| Granted (TBRU) | 81,000 | | | $ | 2.53 | |
| | | |
| Vested | (101,128) | | | $ | 13.95 | |
| Forfeited | (85,467) | | | $ | 13.90 | |
| Non-Vested, end of year | 273,424 | | | $ | 10.52 | |
| | | |
| Aggregate intrinsic value, end of year | $ | 391 | | | |
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, 2018, 20172020, 2019 and 20162018 is provided below:
| | | | | | | | | | | | | | | | | |
| For the Year Ended
December 31, |
| 2020 | | 2019 | | 2018 |
| Aggregate intrinsic value of units vested | $ | 151 | | | $ | 1,351 | | | $ | 1,195 | |
| Fair value of units vested | $ | 1,427 | | | $ | 1,551 | | | $ | 2,250 | |
|
| | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Aggregate intrinsic value of units vested | $ | 1,195 |
| | $ | 143 |
| | $ | 1,233 |
|
| Fair value of units vested | $ | 2,250 |
| | $ | 208 |
| | $ | 1,773 |
|
As of December 31, 2018,2020, there was $3,083$527 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 2.31.53 years.
NOTE 19. INCOME TAXES
The components of income tax expense (benefit) from operations for the years ended December 31, 2020, 2019 and 2018 are as follows:
| | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | 2018 |
| Current: | | | | | |
| Federal | $ | (174) | | | $ | 174 | | | $ | 0 | |
| State | 741 | | | 366 | | | 369 | |
| 567 | | | 540 | | | 369 | |
| Deferred: | | | | | |
| Federal | 1,027 | | | 882 | | | 0 | |
| State | 142 | | | 478 | | | 208 | |
| 1,169 | | | 1,360 | | | 208 | |
| Total income tax expense | $ | 1,736 | | | $ | 1,900 | | | $ | 577 | |
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 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
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
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 $369, $352the Partnership of $468, $458 and $726$369 were recorded in income tax expense for the years ended December 31, 2020, 2019 and 2018, 2017respectively.
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 2016,losses flow through to shareholders and are reported on their individual returns. State income taxes attributable to the preacquisition QSub of $0 were recorded in income tax expense for the year ended December 31, 2018. 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 $1,268 and $1,442 was recorded in income tax expense for the years ended December 31, 2020 and 2019, respectively.
A currentThe income tax liability of $445 and $510 existed atexpense from the Taxable Subsidiary operations for the years ended December 31, 20182020 and 2017, respectively.2019 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:
| | | | | | | | | | | |
| 2020 | | 2019 |
| "Expected" tax expense | $ | 361 | | | $ | 1,116 | |
| Increase in income taxes resulting from: | | | |
| State income taxes, net of federal income tax expense | 327 | | | 235 | |
| Other non-deductible items | 472 | | | 19 | |
| Other, net | 108 | | | 72 | |
| Actual tax expense | $ | 1,268 | | | $ | 1,442 | |
Cash paid for income taxes was $434, $712,$416, $515 and $841$431 for the years ended December 31, 2020, 2019 and 2018, 2017respectively.
Deferred taxes are the result of differences between the bases of assets and 2016, respectively. liabilities for financial reporting and income tax purposes. Significant components of deferred tax assets and liabilities at December 31, 2020 and 2019 are as follows:
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
| | | | | | | | | | | |
| 2020 | | 2019 |
| Deferred tax assets: | | | |
| Bad debt reserves | $ | 59 | | | $ | 64 | |
| Goodwill and intangibles | 13,893 | | | 15,245 | |
| Employee benefits | 244 | | | 500 | |
| Interest expense | 0 | | | 658 | |
| Tax loss carryforwards | 12,671 | | | 12,879 | |
| Other | 251 | | | 147 | |
| Subtotal | 27,118 | | | 29,493 | |
| Less: Valuation allowance | 0 | | | 0 | |
| Total net deferred tax assets | 27,118 | | | 29,493 | |
| | | |
| Deferred tax liabilities: | | | |
| Property and equipment | (4,861) | | | (6,069) | |
| Operating leases | (4) | | | (2) | |
| Other | 0 | | | 0 | |
| Total deferred tax liabilities | (4,865) | | | (6,071) | |
| Net deferred tax assets | $ | 22,253 | | | $ | 23,422 | |
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 22, 2017,31, 2020, management believes it is more likely than not that the President signed into law Public Law No. 115-97,Taxable Subsidiary will realize the benefit of the existing deferred tax assets.
"Income taxes payable" includes a comprehensivestate income tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”) that makes significant changesliability related to the U.S. Internal Revenue Code. Among other changes, the Tax Act includes a new deduction on certain pass-through income, a repealoperation of the partnership technical termination rule,Partnership of $455 and new limitations on certain deductions$298 for the years ended December 31, 2020 and credits, including interest expense deductions. Since2019, respectively. Also included in "Income taxes payable" is a federal income tax liability related to the operation of the Taxable Subsidiary of $0 and $174 for the years ended December 31, 2020 and 2019, respectively, and state income tax liabilities related to the operation of the Taxable Subsidiary of $101 for the year ended December 31, 2020. State income taxes refundable related to the operation of the Taxable Subsidiary of $117 for the year ended December 31, 2019 are included in "Other current assets".
At December 31, 2020, MTI had net operating loss carryforwards for income tax purposes of approximately $80,093 related to federal and state taxes. Of these net operating loss carryforwards, approximately $22,469 will expire between 2027 and 2040 and approximately $57,624 may be carried forward indefinitely.
The operations of a partnershipthe Partnership are generally not subject to federal income taxes, except as discussed above, because its income is taxed directly to its partners. The net tax basis in the legislation has no material impactPartnership's assets and liabilities is greater (less) than the reported amounts on ourthe financial statements in 2018.by approximately $88,526 and $78,649 as of December 31, 2020 and 2019, respectively.
As of December 31, 2018,2020, the tax years that remain open to assessment by federal and state jurisdictions are 2015-2017.2017-2019.
NOTE 20. BUSINESS SEGMENTS
The Partnership has four4 reportable segments: terminalling and storage, natural gas services, marineliquids, 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.
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
The accounting policies of the operating segments are the same as those described in Note 2. The Partnership evaluates the performance of its reportable segments based on operating income. There is no allocation of administrative expenses or interest expense.
MARTIN MIDSTREAM PARTNERS L.P. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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, 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 | — | | | — | | | — | | | 0 | | | (17,909) | | | 0 | |
| 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 | | | 0 | | | 366,502 | | | 2,469 | | | 44,020 | | | 1,870 | |
| Sulfur services | 111,340 | | | 0 | | | 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 | — | | | — | | | — | | | 0 | | | (17,981) | | | 0 | |
| Total | $ | 877,895 | | | $ | (30,777) | | | $ | 847,118 | | | $ | 60,060 | | | $ | 58,104 | | | $ | 37,923 | |
| | | | | | | | | | | |
| Year Ended December 31, 2018: | | | | | | | | | | | |
| Terminalling and storage | $ | 247,840 | | | $ | (6,400) | | | $ | 241,440 | | | $ | 39,508 | | | $ | 17,540 | | | $ | 13,704 | |
| Natural gas liquids | 496,026 | | | (19) | | | 496,007 | | | 2,488 | | | 31,581 | | | 746 | |
| Sulfur services | 132,536 | | | 0 | | | 132,536 | | | 8,485 | | | 27,397 | | | 4,429 | |
| Transportation | 178,163 | | | (28,042) | | | 150,121 | | | 11,003 | | | (13,560) | | | 16,335 | |
| Indirect selling, general, and administrative | — | | | — | | | — | | | 0 | | | (17,901) | | | 0 | |
| Total | $ | 1,054,565 | | | $ | (34,461) | | | $ | 1,020,104 | | | $ | 61,484 | | | $ | 45,057 | | | $ | 35,214 | |
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, 2018: | | | | | | | | | | | |
| Terminalling and storage | $ | 247,840 |
| | $ | (6,226 | ) | | $ | 241,614 |
| | $ | 39,508 |
| | $ | 13,725 |
| | $ | 13,704 |
|
| Natural gas services | 548,135 |
| | — |
| | 548,135 |
| | 21,283 |
| | 28,570 |
| | 4,728 |
|
| Sulfur services | 132,536 |
| | — |
| | 132,536 |
| | 8,485 |
| | 14,276 |
| | 4,429 |
|
| Marine transportation | 52,830 |
| | (2,460 | ) | | 50,370 |
| | 7,590 |
| | 6,116 |
| | 14,188 |
|
| Indirect selling, general, and administrative | — |
| | — |
| | — |
| | — |
| | (17,901 | ) | | — |
|
| Total | $ | 981,341 |
| | $ | (8,686 | ) | | $ | 972,655 |
| | $ | 76,866 |
| | $ | 44,786 |
| | $ | 37,049 |
|
| | | | | | | | | | | | |
| Year Ended December 31, 2017: | | | | | | | | | | | |
| Terminalling and storage | $ | 236,169 |
| | $ | (5,998 | ) | | $ | 230,171 |
| | $ | 45,160 |
| | $ | 629 |
| | $ | 29,644 |
|
| Natural gas services | 532,908 |
| | (226 | ) | | 532,682 |
| | 24,916 |
| | 51,849 |
| | 7,430 |
|
| Sulfur services | 134,684 |
| | — |
| | 134,684 |
| | 8,117 |
| | 23,205 |
| | 2,611 |
|
| Marine transportation | 51,915 |
| | (3,336 | ) | | 48,579 |
| | 7,002 |
| | 1,650 |
| | 3,929 |
|
| Indirect selling, general, and administrative | — |
| | — |
| | — |
| | — |
| | (17,332 | ) | | — |
|
| Total | $ | 955,676 |
| | $ | (9,560 | ) | | $ | 946,116 |
| | $ | 85,195 |
| | $ | 60,001 |
| | $ | 43,614 |
|
| | | | | | | | | | | | |
| Year Ended December 31, 2016: | | | | | | | | | | | |
| Terminalling and storage | $ | 242,363 |
| | $ | (5,653 | ) | | $ | 236,710 |
| | $ | 45,484 |
| | $ | 40,660 |
| | $ | 26,097 |
|
| Natural gas services | 391,333 |
| | — |
| | 391,333 |
| | 28,081 |
| | 41,503 |
| | 4,807 |
|
| Sulfur services | 141,058 |
| | — |
| | 141,058 |
| | 7,995 |
| | 23,393 |
| | 5,093 |
|
| Marine transportation | 61,233 |
| | (2,943 | ) | | 58,290 |
| | 10,572 |
| | (16,039 | ) | | 2,334 |
|
| Indirect selling, general, and administrative | — |
| | — |
| | — |
| | — |
| | (16,794 | ) | | — |
|
| Total | $ | 835,987 |
| | $ | (8,596 | ) | | $ | 827,391 |
| | $ | 92,132 |
| | $ | 72,723 |
| | $ | 38,331 |
|
Revenues from two customersone customer in the Natural Gas ServicesLiquids segment were $179,729, $169,504was $74,722, $112,280 and $122,381$148,103 for the years ended December 31, 2018, 20172020, 2019 and 2016,2018, respectively.
The Partnership's assets by reportable segment as of December 31, 20182020 and 2017,2019 are as follows:
| | | | | | | | | | | |
| 2020 | | 2019 |
| Total assets: | | | |
| Terminalling and storage | $ | 252,794 | | | $ | 292,136 | |
| Natural gas liquids | 80,737 | | | 94,195 | |
| Sulfur services | 94,154 | | | 110,780 | |
| Transportation | 151,953 | | | 170,045 | |
| Total assets | $ | 579,638 | | | $ | 667,156 | |
|
| | | | | | | |
| | 2018 | | 2017 |
| Total assets: | | | |
| Terminalling and storage | $ | 298,784 |
| | $ | 326,920 |
|
| Natural gas services | 512,817 |
| | 704,524 |
|
| Sulfur services | 115,498 |
| | 120,790 |
|
| Marine transportation | 106,299 |
| | 101,264 |
|
| Total assets | $ | 1,033,398 |
| | $ | 1,253,498 |
|
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
NOTE 21. QUARTERLY FINANCIAL INFORMATION
Consolidated Quarterly Income Statement Information
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | (Unaudited) |
| | First Quarter | | Second Quarter | | Third Quarter | | Fourth
Quarter |
| | (Dollar in thousands, except per unit amounts) |
| 2020 | | | | | | | | |
| Revenues | $ | 198,883 | | | $ | 140,638 | | | $ | 152,533 | | | $ | 180,088 | |
| Operating income | 15,600 | | | 7,960 | | | 11,013 | | | 11,928 | |
| | | | | | | |
| Income (loss) from continuing operations | 8,815 | | | (2,203) | | | (10,819) | | | (2,564) | |
| Income (loss) from discontinued operations | 0 | | | 0 | | | 0 | | | 0 | |
| Net income (loss) | 8,815 | | | (2,203) | | | (10,819) | | | (2,564) | |
| Income (loss) from continuing operations per unit | 0.23 | | | (0.06) | | | (0.28) | | | (0.07) | |
| Limited partners' interest in net income (loss) per limited partner unit | 0.22 | | | (0.06) | | | (0.27) | | | (0.06) | |
| | | | | | | | |
| | First Quarter | | Second Quarter | | Third Quarter | | Fourth
Quarter |
| | (Dollar in thousands, except per unit amounts) |
| 2019 | | | | | | | | |
| Revenues | $ | 240,033 | | | $ | 187,323 | | | $ | 177,900 | | | $ | 241,862 | |
| Operating income | 9,606 | | | 5,010 | | | 25,461 | | | 18,027 | |
| | | | | | | |
| Income (loss) from continuing operations | (4,758) | | | (10,614) | | | 13,250 | | | 6,642 | |
| Income from discontinued operations | 1,102 | | | (180,568) | | | 0 | | | 0 | |
| Net income (loss) | (3,656) | | | (191,182) | | | 13,250 | | | 6,642 | |
| Income (loss) from continuing operations per unit | (0.12) | | | (0.27) | | | 0.34 | | | 0.17 | |
| Limited partners' interest in net income (loss) per limited partner unit | 0.09 | | | (4.82) | | | 0.33 | | | 0.14 | |
|
| | | | | | | | | | | | | | | | |
| | | (Unaudited) |
| | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter |
| | | (Dollar in thousands, except per unit amounts) |
| 2018 | | | | | | | | |
| Revenues | $ | 284,204 |
| | $ | 216,571 |
| | $ | 219,047 |
| | $ | 252,833 |
|
| Operating income (loss) | 24,120 |
| | 5,616 |
| | 3,527 |
| | 11,523 |
|
| Income (loss) from continuing operations | 11,286 |
| | (8,282 | ) | | (9,686 | ) | | (913 | ) |
| Income from discontinued operations | 1,532 |
| | 1,036 |
| | 49,132 |
| | — |
|
| Net income (loss) | 12,818 |
| | (7,246 | ) | | 39,446 |
| | (913 | ) |
| Income (loss) from continuing operations per unit | 0.29 |
| | (0.21 | ) | | (0.25 | ) | | (0.02 | ) |
| Limited partners' interest in net income (loss) per limited partner unit | 0.33 |
| | (0.18 | ) | | 1.00 |
| | (0.04 | ) |
| | | | | | | | | |
| | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter |
| | | (Dollar in thousands, except per unit amounts) |
| 2017 | | | | | | | | |
| Revenues | $ | 253,325 |
| | $ | 193,922 |
| | $ | 193,128 |
| | $ | 305,741 |
|
| Operating income | 23,804 |
| | 10,891 |
| | (4,440 | ) | | 29,746 |
|
| Income (loss) from continuing operations | 12,734 |
| | 179 |
| | (17,031 | ) | | 17,125 |
|
| Income from discontinued operations | 849 |
| | 810 |
| | 745 |
| | 1,724 |
|
| Net income (loss) | 13,583 |
| | 989 |
| | (16,286 | ) | | 18,849 |
|
| Income (loss) from continuing operations per unit | 0.34 |
| | — |
| | (0.44 | ) | | 0.45 |
|
| Limited partners' interest in net income (loss) per limited partner unit | 0.36 |
| | 0.03 |
| | (0.42 | ) | | 0.47 |
|
NOTE 22. COMMITMENTS AND CONTINGENCIES
Contingencies
From time to time, the Partnership is subject to various claims and legal actions arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Partnership.
Pursuant to a Purchase Price Reimbursement Agreement between the Partnership and Martin Resource Management related to the Partnership’s acquisition of the Redbird Gas Storage LLC ("Redbird") Class A interests on October 2, 2012,
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
beginning in the second quarter of 2015, Martin Resource Management will reimburse the Partnership $750 each quarter for four consecutive quarters as a reduction in the purchase price of the Redbird Class A interests. These payments are a result of Cardinal Gas Storage Partners LLC ("Cardinal") not achieving certain financial targets set forth in the Purchase Price Reimbursement Agreement. These payments are considered a reduction of the excess of the purchase price over the carrying value of the assets transferred to the Partnership from Martin Resource Management and will be recorded as an adjustment to "Partners' capital" in each quarter the payments are made. The agreement further provided for purchase price reimbursements of up to $4,500 in 2016 in the event certain financial conditions were not met. For the year ended December 31, 2017, the Partnership received $1,125, respectively, related to the Purchase Price Reimbursement Agreement. The amount received in the first quarter of 2017 represented the final payment under the Purchase Price Reimbursement Agreement.
In 2015, the Partnership was named as a defendant in the cause J. A. Davis Properties, LLC v. Martin Operating Partnership L.P., in the 38th Judicial District Court, Cameron Parish, Louisiana. The plaintiff alleged that the Partnership breached a lease agreement by failing to perform work to the plaintiff's property as required under the lease agreement. The plaintiff originally sought to evict the Partnership from the leased property and to recover damages. Prior to trial, this matter was settled for a confidential amount in September of 2017. The Partnership's financial statements reflect the terms of the settlement and all amounts have been accrued as asset retirement obligations.
On December 31, 2015, the Partnership received a demand from a customer in its lubricants packaging business for defense and indemnity in connection with lawsuits filed against it in various United States District Courts, which generally allege that the customer engaged in unlawful and deceptive business practices in connection with its marketing and advertising of its private label motor oil. The Partnership disputes that it has any obligation to defend or indemnify the customer for its conduct. Accordingly, on January 7, 2016, the Partnership filed a Complaint for Declaratory Judgment in the Chancery Court of Davidson County, Tennessee requesting a judicial determination that the Partnership does not owe the customer the demanded defense and indemnity obligations. The lawsuits against the customer have been transferred to the United States District Court for the Western District of Missouri for consolidated pretrial proceedings. On March 1, 2017, at the request of the parties, the Chancery Court of Davidson County, Tennessee administratively closed the Partnership's lawsuit pending rulings in the United States District Court for the Western District of Missouri. In the event that either party moves the Chancery Court of Davidson County, Tennessee to reopen the case, we expect the Court would grant such motion and reopen the case. Further, the same customer has made a claim under the Partnership’s insurance policy. The insurer has denied the claim. However, in the event that the customer is successful in pursuing the claim, such action would negatively impact the Partnership because the Partnership may have certain reimbursement obligations it would owe the insurance company. If the
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
case is reopened or the insurance claim by the customer is successful, we are currently unable to determine the exposure we may have in this matter, if any.
Commitments
The Partnership has non-cancelable revenue arrangements whereby we have committed certain terminalling and storage assets in exchange for a minimum fee. Future minimum revenues we expect to receive under these non-cancelable arrangements as of December 31, 2018, are as follows: 2019 - $17,343; 2020 - $13,345; 2021 - $10,576; 2022 - $10,576; 2023 - $10,576; subsequent years - $58,128.
NOTE 23. CONDENSED CONSOLIDATIINGCONSOLIDATING FINANCIAL INFORMATION
The Partnership's operations are conducted by its operating subsidiaries as it has no independent assets or operations. Martin Operating Partnership L.P. (the "Operating Partnership"), the Partnership’s wholly-owned subsidiary, and the Partnership's other operating subsidiaries have issued in the past, and may issue in the future, unconditional guarantees of senior or subordinated debt securities of the Partnership. The guarantees that have been issued are full, irrevocable and unconditional and joint and several. In addition, the Operating Partnership may also issue senior or subordinated debt securities which, if issued, will be fully, irrevocably and unconditionally guaranteed by the Partnership. Substantially all of the Partnership's operating subsidiaries are subsidiary guarantors of its outstanding senior unsecured notes and any subsidiaries other than the subsidiary guarantors are minor.
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
NOTE 24. SUBSEQUENT EVENTS
Martin Transport Inc. Stock Purchase Agreement.Retirement of 2021 Notes. On October 22, 2018,February 15, 2021, the Operating2021 Notes matured and the Partnership entered into a stock purchase agreement (the “Stock Purchase Agreement”) with Martin Resource Management Corporation (“MRMC”) to acquire allretired the outstanding balance of the issued and outstanding equity of Martin Transport, Inc. (“MTI”), a wholly-owned subsidiary of MRMC which operates a fleet of tank trucks providing transportation of petroleum products, liquid petroleum gas, chemicals, sulfur and other products, as well as owns twenty-three terminals located throughout the Gulf Coast and Midwest for total consideration as follows:$28,790 using its revolving credit facility.
MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except where otherwise indicated)
|
| | | |
Purchase price1 | $ | 135,000 |
|
| Plus: Working Capital Adjustment | 2,796 |
|
| Less: Capital leases assumed | (11,682 | ) |
| Cash consideration paid | $ | 126,114 |
|
1The Stock Purchase Agreement also includes a $10,000 earn-out based on certain performance thresholds. The transaction closed on January 2, 2019 and was effective as of January 1, 2019. The Stock Purchase Agreement contained customary representations and warranties.
The Partnership also acquired certain operating leases that will result in additional assets and liabilities being recorded at the transaction date in accordance with ASU 2016-02 in the amount of $7,082.
Quarterly Distribution. On January 17, 2019,25, 2021, the Partnership declared a quarterly cash distribution of $0.50$0.005 per common unit for the fourth quarter of 2018,2020, or $2.00$0.02 per common unit on an annualized basis, which was paid on February 14, 201912, 2021 to unitholders of record as of February 7, 2019.5, 2021.
|
| | | | |
| Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
None.
|
| | | | |
| Item 9A. | Controls and Procedures |
(a) Evaluation of Disclosure Controls and Procedures. In accordance with Rules 13a-15 and 15d-15 of the Securities Exchange Act, of 1934, as amended (the "Exchange Act"), we, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of our general partner, carried out an evaluation of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15(d)-15(e) of the Exchange Act) as of December 31, 2018.2020. 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, 20182020 to provide reasonable assurance that information required to be disclosed by the CompanyPartnership in reports that it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms and (ii) accumulated and communicated to the Company’sPartnership’s management, including its principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.
During 2017 we began implementation of a new enterprise resource planning ("ERP") system. The new ERP system is expected to take several years to fully implement, and has and will continue to require significant capital and human resources to deploy. During the year ended December 31, 2018, we completed the implementation of certain functional areas of the ERP implementation project that affect the processes that constitute our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) and this initial deployment will require testing for effectiveness throughout 2018. Management has taken steps to ensure that appropriate controls are designed and implemented as each functional area of the new ERP system is enacted.
Beginning January 1, 2018, we implemented ASC 606, Revenue from Contracts with Customers. Although the new revenue standard is expected to have an immaterial impact on our ongoing net income, we did implement changes to our processes related to revenue recognition and the control activities within them. These included the development of new policies based on the five-step model provided in the new revenue standard, new training, ongoing contract review requirements, and gathering of information provided for disclosures.
(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, 2018. The effectiveness of our internal control over financial reporting as of December 31, 2018 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."2020.
(c) Changes in Internal Control Over Financial Reporting. Other than as described above, thereThere 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.
|
| | | | |
| Item 9B. | Other Information |
None.
PART III
|
| | | | |
| Item 10. | Directors, Executive Officers and Corporate Governance |
Management of Martin Midstream Partners L.P.
Martin Midstream GP LLC, as our general partner, manages our operations and activities on our behalf. Our general partner was not elected by our unitholders and will not be subject to re-election in the future. Unitholders do not directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to our unitholders. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically non-recourse to it. However, whenever possible, our general partner seeks to provide that our indebtedness or other obligations are non-recourse to our general partner.
Three directors of our general partner serve on a conflicts committee of the Partnership's general partner ("Conflicts Committee")Committee to review specific matters that the directors believe may involve conflicts of interest. The Conflicts Committee determines if the resolution of the conflict of interest is fair and reasonable to us. The members of the Conflicts Committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates and must meet the independence standards established by NASDAQ to serve on an audit committee of a board of directors. Any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders. The current members of our Conflicts Committee are outside directors, James M. Collingsworth, C. Scott Massey and Byron R. Kelley, all of whom meet the independence standards established by NASDAQ, except as referenced above.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.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.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.
Directors and Executive Officers of Martin Midstream GP LLC
The following table shows information for the directors and executive officers of our general partner. Directors and executive officers are elected for one-year terms.
|
| | | | | | | | | | | | | |
| Name | | Age | | Position with the General Partner |
| Ruben S. Martin (1) | | 6769 | | Chairman of the Board of Directors |
| Robert D. Bondurant (2) | | 62 | | President and Chief Executive Officer and Director |
Robert D. Bondurant | | 60 | | Executive Vice President and Chief Financial Officer and Director |
| Randall L. Tauscher | | 5355 | | Executive Vice President and Chief Operating Officer |
| Chris H. Booth | | 4951 | | Executive Vice President, Chief Legal Officer, General Counsel and Secretary |
| Sharon L. Taylor (3) | | 56 | | Vice President and Chief Financial Officer |
| Scot A. Shoup | | 5860 | | Senior Vice President of Operations |
| C. Scott Massey | | 6668 | | Director |
| James M. Collingsworth | | 6466 | | Director |
| Byron R. Kelley | | 7173 | | Director |
| Zachary S. Stanton | | 45 | | Director |
| Christopher M. Reid | | 33 | | Director (Appointed effective February 8, 2021) |
| Sean P. Dolan | | 4547 | | Director |
Zachary S. Stanton | | 43 | | Director (Departed effective February 4, 2021) |
(1) Mr. Martin retired as President and Chief Executive Officer effective December 31, 2020 and was appointed Chairman of the Board of Directors of our general partner effective January 1, 2021.
(2) Mr. Bondurant was appointed President and Chief Executive Officer effective January 1, 2021, and previously served as Executive Vice President and Chief Financial Officer.
(3) Ms. Taylor was appointed Vice President and Chief Financial Officer effective January 1, 2021.
Ruben S. Martin serveswas 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 in such capacities since June 2002. 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 position withinprevious experience as Chief Executive Officer of the Partnership.
Robert D. Bondurant serveswas 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 a member ofhas served on the board of directors of our general partner. Mr. Bondurant has served in such capacities since June 2002.2014. 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 in this capacityas an officer of our general partner since May 2011. From September 2007 through May 2011, Mr. Tauscher served as Executive Vice President.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 with a concentration in finance from the University of Houston. Additionally, Mr. Booth holds a Bachelor of
Science degree in business management from LeTourneau University. Mr. Booth is an attorney licensed to practice in the State of Texas.
Scot A. Shoup serves as Senior Vice President of Operations for our general partner. Mr. Shoup joined Martin Resource Management Corporation in May 2011. Prior to joining Martin, Mr. Shoup was employed by Exline, Inc. as Executive Vice President from 2005 to 2011 and was employed by Koch Industries in various capacities for 18 years. Mr. Shoup holds a bachelorBachelor of scienceScience degree in Civil Engineeringcivil 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 41 years in all facets of the midstream and petrochemical industry. In 2013, Mr. Collingsworth retired from Enterprise Products Company as a Sr. Vice President of Regulated NGL Pipelines & Natural Gas Storage. Mr. Collingsworth currently serves on the board of directors of NGL Energy Partners LP, and has served on the board of directors of Texaco Canada, Dixie Pipeline Company, Seminole Pipeline Company and the Petrochemical Feedstock Association of America. Mr. Collingsworth has served as a Director since October 2014. Mr. Collingsworth received a bachelor’sBachelor’s degree in Financefinance and Marketingmarketing from Northeastern State University. Mr. Collingsworth was selected to serve as a director on our general partner's board of directors due to his extensive corporate business experience.
Byron R. Kelley serves as a member of the board of directors of our general partner and also served as an Advisory Director from April 2011 to August 2012. On December 31, 2013, Mr. Kelley retired as CEO, President and a member of the board of directors of CVR Partners, LP, a chemical company engaged in the production of nitrogen based fertilizers and served in this position from June 2011 through December 2013. Prior to joining CVR Partners in June of 2011 he served as President, Chief Executive Officer and a member of the board of directors of Regency GP, LLC from April 2008 to November 2010. From 2004 through March of 2008, Mr. Kelley served as Senior Vice President and Group President of Pipeline and Field Services at CenterPoint Energy. Preceding his work at CenterPoint, Mr. Kelley served as Executive Vice President of Development, Operations and Engineering, and as President of El Paso Energy International. Mr. Kelley is a past member and Chairman of the board of directors of the Interstate National Gas Association and previously served as one of the association's representatives on the United States Natural Gas Council of America. Mr. Kelley received a Bachelor of Science degree in civil engineering from Auburn University. Mr. Kelley was selected to serve as a director on our general partner's board of directors due to his extensive corporate business experience.
Sean P. Dolan serves as a member of the board of directors of our general partner. Mr. Dolan has served as a Director since 2013. Mr. Dolan is a Managing Director of Alinda Capital Partners, which he joined in 2009. Prior to joining Alinda, Mr. Dolan spent over 12 years with Citigroup Global Markets in investment banking primarily focused in the energy sector. Mr. Dolan received a bachelor's degree from Georgetown University. Mr. Dolan was selected to serve as a director on our general partner's board of directors due to his affiliation with Alinda, his knowledge of the energy industry and his financial and business expertise.
Zachary S. Stanton serves as a member of the board of directors of our general partner.Mr. Stanton was appointed to the board of directors on February 24,has served as a director since 2016. Mr. Stanton is a Managing Director of Alinda Capital Partners, which he joined in 2011.Prior to joining Alinda, he was a Director at Zolfo Cooper, LLC, a consulting firm based in New York. Mr. Stanton has over 15 years of experience focused on the corporate development and operations of energy and transportation infrastructure businesses as well as diversified industrial companies. Mr. Stanton received a bachelor'sBachelor's degree from Wesleyan University. Mr. Stanton was selected to serve as a director on our general partner's board of directors due to his affiliation with Alinda, his knowledge of the energy industry and his financial and business expertise.
Christopher M. Reid serves as a member of the board of directors of our general partner. Mr. Reid has served as a Director since his appointment on February 8, 2021. Mr. Reid is a Director and member of the Global Investments Team at Alinda Capital Partners and has 10 years of experience in infrastructure. Prior to joining Alinda in 2012, he was an analyst in the industrials group at Deutsche Bank. Mr. Reid received a Bachelor's degree from Yale University. Mr. Reid was selected to
serve as a director on our general partner's board of directors due to his affiliation with Alinda, his knowledge of infrastructure and his financial and business expertise.
Independence of Directors
Messrs. Massey, Collingsworth, and Kelley qualify as "independent" in accordance with the published listing requirements of NASDAQ and applicable securities laws. The NASDAQ independence definition includes a series of objective tests, such as that the director is not an employee of us and has not engaged in various types of business dealings with us. In addition, as further required by the NASDAQ rules, the board of directors has made a subjective determination as to each independent director that no relationships exist which, in the opinion of the board, would interfere with the exercise of independent judgment in carrying out the responsibilities of a director. In making these determinations, the directors reviewed and discussed information provided by the directors and us with regard to each director's business and personal activities as they may relate to us and our management.
Board Meetings and Committees
From January 1, 20182020 to December 31, 2018,2020, the board of directors of our general partner held 1014 meetings. AllIn 2020, all directors then in officeof our general partner attended eachat least 75% of thesethe meetings either in person, by teleconference or by videoconference with the exception of: Zach Stanton, who was not in attendance at the meeting of the board of directors and the committees on the dates of April 19, 2018 and July 19, 2018.which they served. Additionally, the board of directors undertook action one timefive times during 20182020 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 ww.martinmidstream.comwww.MMLP.com under the "Corporate Governance" section. The current members of the committees, the number of meetings held by each committee from January 1, 20182020 to December 31, 2018,2020, and a brief description of the functions performed by each committee are set forth below:
Conflicts Committee (9 meetings)(1 meeting). 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 (2(3 meetings). The members of the Compensation Committee are Messrs. Collingsworth (chairman), Massey and Kelley. All members attended the meeting of the Compensation Committee for the period noted above. The primary responsibility of the Compensation Committee is to oversee compensation decisions for the outside directors of our general partner and executive officers of our general partner (in the event they are to be paid by our general partner) as well as our long-term incentive plan.
Nominating Committee (1 meetings)meeting). The members of the Nominating Committee are Messrs. Collingsworth (chairman), Massey, and Kelley. All of the members attended the meeting of the Nominating Committee for the period noted above. The primary responsibility of the nominating committee is to select and recommend nominees for election to the board of directors of our general partner.
Code of Ethics and Business Conduct
Our general partner has adopted a Code of Ethics and Business Conduct applicable to all of our general partner's employees (including any employees of Martin Resource Management 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.martinmidstream.com)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.
Section 16(a) Beneficial Ownership Reporting Compliance
Our general partner's directors and officers and beneficial owners of more than 10% of a registered class of our equity securities are required to file reports of ownership and reports of changes in ownership with the SEC and NASDAQ. Directors, officers and beneficial owners of more than 10% of our equity securities are also required to furnish us with copies of all such reports that are filed. Based solely on our review of copies of such forms and amendments previously provided to us, we believe directors, officers and greater than 10% beneficial owners complied with all filing requirements during the year ended December 31, 2018, with the exception of one Form 4 for Scot Shoup which was filed late.
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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, 2018,2020, 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. TheWith the exception of our President and Chief Executive Officer as of January 1, 2021, 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’sManagement 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 between us and our general partner, as amended on October 1, 2012 ("Omnibus Agreement").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, 2020, 2019 and 2018 2017 and 2016 the conflicts committeeboard of directors of our general partner ("Conflicts Committee") approved reimbursement amounts of $16.4 million, $16.4$16.7 million and $13.0$16.4 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’sManagement Corporation’s compensation program discussed below, along with Martin Resource Management’sManagement 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’sManagement 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.Management Corporation. During 2018,2020, 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’sManagement 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. 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’sManagement Corporation’s business objectives. Named Executive Officers may also be eligible to receive a cash award based upon their services provided to us in the event that any such Named Executive Officer has devoted a significant amount of their time to working for us. Any such award is determined in
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. 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.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.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’sManagement Corporation’s properties located in Texas,and use of Martin Resource Management Corporation vehicles, including aircraft. 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.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 and Conflicts Committee haveof 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.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. We bear substantially less than a majority of Martin Resource Management’s costs of providing compensation and benefits to the Named Executive Officers.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 as of January 1, 2021, are determined by the Management Compensation Committee of Martin Resource Management Corporation comprised of its Chief Executive Officer, Mr. Ruben Martin, Chief Executive Officer, Mr. Robert Bondurant, Chief FinancialOperating Officer, Mr. Randall Tauscher, Chief Operating Officer, and Vice President-Human Resources, Mrs. Melanie Mathews Vice President-Human Resources (collectively, the "Management Compensation Committee of Martin Resource Management"Management Corporation") based on a periodic performance review of each Named Executive Officer. As of January 1, 2021, the Compensation Committee of our board of directors will be responsible for setting the compensation of our President and Chief Executive Officer. Except in the case of an exceptional amount of time devoted to us, discretionary annual cash awards are based on the performance of Martin Resource Management.Management Corporation. Annual discretionary cash awards, if any, are calculated first by allocating a portion of Martin Resource Management’sManagement Corporation’s earnings as determined by the Management Compensation Committee of Martin Resource Management Corporation for distribution to key employees of Martin Resource Management.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 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 under our long-term incentive plan, which to date have consisted of the grant of restricted common units to the independent directors and employees of our general partner, are approved by the Compensation Committee.
Determination of 20182020 Compensation Amounts
During 2018,2020, 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. 2017 Restricted Unit Plan and Martin Resource Management Corporation employee benefit plans; and (4) other compensation, including limited perquisites. With respect to the Named Executive Officers, they were paid an allocated portion of their base salaries.
Annual Base Salary. The portions of the annual base salaries paid by Martin Resource Management 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 55.5%70.2% of the aggregate annual base salaries paid to the Named Executive Officers by Martin Resource Management Corporation during 2017.2020. 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 50%55% to 75%100%. OurDuring 2020, our Named Executive Officers arewere Mr. Ruben Martin, the President and Chief Executive Officer of our general partner, Mr. Robert Bondurant, an Executive Vice President and Chief Financial Officer of our general partner, Mr. Randall Tauscher, an Executive Vice President and Chief Operating Officer of our general partner, Mr. Chris Booth, the Executive Vice President, General Counsel and Secretary of our general partner, and Mr. Scot A. Shoup, Senior Vice President of Operations. Aggregate annual base salariesAs of theDecember 31, 2020 Ruben Martin retired and ceased being a Named Executive Officers were not increased during 2016 or 2017.Officer and Robert D. Bondurant was appointed President and Chief Executive Officer. Sharon L. Taylor became Vice President and Chief Financial Officer and a Named Executive Officer.
Discretionary Annual Cash Awards. Discretionary annual cash awards paid to the Named Executive Officers which are allocable to us are reflected in the summary compensation table below.
Martin Midstream Partners L.P. Long-Term Incentive Plan
On May 26, 2017, the unitholders of the Partnership approved the Martin Midstream Partners L.P. 2017 Restricted Unit Plan (the "2017 LTIP"). The plan currently permits the grant of awards covering an aggregate of 3,000,000 common units, all of which can be awarded in the form of restricted units. The plan is administered by the Compensation Committee of our general partner’s board of directors. The purpose of the 2017 LTIP is designed to enhance our ability to attract, retain, reward and motivate the services of certain key employees, officers, and directors of the General Partnergeneral partner and Martin Resource Management.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.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 ("TBRU's"), the Compensation Committee will determine the time period over which restricted units granted to employees and directors will
vest. The Compensation Committee may also award a percentage of restricted units with vesting requirements based upon the achievement of specified pre-established performance targets ("Performance Based Restricted Units" or "PBRU's"). The performance targets may include, but are not limited to, the following: revenue and income measures, cash flow measures, EBIT, EBITDA, distribution coverage metrics, expense measures, liquidity measures, market measures, corporate sustainability metrics, and other measures related to acquisitions, dispositions, operational objectives and succession planning objectives. PBRU's are earned only upon our achievement of an objective performance measure for the performance period. PBRU's which vest are payable in common units. The Compensation Committee believes this type of incentive award strengthens the tie between each grantee's pay and our financial performance. We intend the issuance of the common units
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 LTIP, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units upon vesting of the restricted units, the total number of common units outstanding will increase.
On February 20, 2018, we issued 4,650 TBRU's to each of our three independent directors under the 2017 LTIP. These restricted common units vest in equal installments of 1,162.5 units on January 24, 2019, 2020, 2021, and 2022.
On March 1, 2018, we issued 301,550 TBRU's and 317,925 PBRU's to certain employees of Martin Resource Management. The TBRU's vest in equal installments over a three-year service period. The PBRU's will vest at the conclusion of a three-performance period based on certain performance targets. In addition, the PBRU's awarded on March 1, 2018 that are achieved will only vest if the grantee is employed by Martin Resource Management on March 31, 2021.
Martin Resource Management Corporation Employee Benefit Plans
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 CompanyPartnership 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 Unitscommon 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 Employee Stock Ownership Plan.Plan ("ESOP"). Martin Resource Management Corporation maintains an employee stock ownership plan that covers employees who satisfy certain minimum age and service requirements ("ESOP").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.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 Stock Ownership Plan.Plan (the "Plan"). Martin Resource Management Corporation maintains an employee stock ownership plan that covers employees who satisfied certain minimum age and service requirements but no Employeeemployee shall become eligible to participate in the Plan on or after January 1, 2013. This planPlan is referred to as the "Martin
Employee Stock Ownership Plan". Under the terms of the plan,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 Martin Employee Stock Ownership Plan and invested primarily in the common stock of Martin Resource Management.Management Corporation. No contributions will be made to the Plan for any Plan Yearyear 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 shall beare fully vested and non-forfeitable. This planThe 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. Matching contributions are made to the 401(k) Plan equal to 50% of the first 4% of eligible 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.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 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, 2018.2020.
Change of Compensation Policy. As of January 1, 2021, the Compensation Committee of our general partner will be solely responsible for determining the base salary, bonus compensation, long-term incentive compensation and other compensation of our President and Chief Executive Officer. The Compensation Committee will be responsible for the development of the compensation objectives and methodology applicable to the President and Chief Executive Officer.
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’sManagement 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, 2018, 20172020, 2019 and 2016.2018.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Name and Principal Position | | Year | | Salary | | Retention Bonus | | Stock Awards (1) | | Total Compensation |
| Ruben S. Martin, President and Chief Executive Officer | | 2020 | | $ | 341,250 | | | $ | — | | | $ | — | | | $ | 341,250 | |
| 2019 | | $ | 341,250 | | | $ | — | | | $ | — | | | $ | 341,250 | |
| 2018 | | $ | 262,500 | | | $ | — | | | $ | 1,158,913 | | | $ | 1,421,413 | |
| Robert D. Bondurant, Executive Vice President and Chief Financial Officer | | 2020 | | $ | 312,000 | | | $ | 100,000 | | | $ | — | | | $ | 412,000 | |
| 2019 | | $ | 312,000 | | | $ | — | | | $ | — | | | $ | 312,000 | |
| 2018 | | $ | 240,000 | | | $ | — | | | $ | 740,870 | | | $ | 980,870 | |
| Randall L. Tauscher, Executive Vice President and Chief Operating Officer | | 2020 | | $ | 336,000 | | | $ | 100,000 | | | $ | — | | | $ | 436,000 | |
| 2019 | | $ | 336,000 | | | $ | — | | | $ | — | | | $ | 336,000 | |
| 2018 | | $ | 288,000 | | | $ | — | | | $ | 740,870 | | | $ | 1,028,870 | |
| Chris H. Booth, Executive Vice President, General Counsel and Secretary | | 2020 | | $ | 211,750 | | | $ | 100,000 | | | $ | — | | | $ | 311,750 | |
| 2019 | | $ | 250,250 | | | $ | — | | | $ | — | | | $ | 250,250 | |
| 2018 | | $ | 192,500 | | | $ | — | | | $ | 556,000 | | | $ | 748,500 | |
| Scot A. Shoup, Senior Vice President of Operations | | 2020 | | $ | 372,000 | | | $ | — | | | $ | — | | | $ | 372,000 | |
| 2019 | | $ | 372,000 | | | $ | — | | | $ | — | | | $ | 372,000 | |
| 2018 | | $ | 279,000 | | | $ | — | | | $ | 222,400 | | | $ | 501,400 | |
|
| | | | | | | | | | | | | | | | | | |
| Name and Principal Position | | Year | | Salary | | Bonus | | Stock Awards (1) | | Total Compensation |
| Ruben S. Martin, President and Chief Executive Officer | | 2018 | | $ | 262,500 |
| | $ | — |
| | $ | 1,158,913 |
| | $ | 1,421,413 |
|
| | 2017 | | $ | 412,500 |
| | $ | — |
| | $ | — |
| | $ | 412,500 |
|
| | 2016 | | $ | 412,500 |
| | $ | — |
| | $ | — |
| | $ | 412,500 |
|
| Robert D. Bondurant, Executive Vice President and Chief Financial Officer | | 2018 | | $ | 240,000 |
| | $ | — |
| | $ | 740,870 |
| | $ | 980,870 |
|
| | 2017 | | $ | 230,000 |
| | $ | — |
| | $ | — |
| | $ | 230,000 |
|
| | 2016 | | $ | 230,000 |
| | $ | — |
| | $ | — |
| | $ | 230,000 |
|
| Randall L. Tauscher, Executive Vice President and Chief Operating Officer | | 2018 | | $ | 288,000 |
| | $ | — |
| | $ | 740,870 |
| | $ | 1,028,870 |
|
| | 2017 | | $ | 276,000 |
| | $ | — |
| | $ | — |
| | $ | 276,000 |
|
| | 2016 | | $ | 308,200 |
| | $ | — |
| | $ | — |
| | $ | 308,200 |
|
| Chris H. Booth, Executive Vice President, General Counsel and Secretary | | 2018 | | $ | 192,500 |
| | $ | — |
| | $ | 556,000 |
| | $ | 748,500 |
|
| | 2017 | | $ | 183,600 |
| | $ | — |
| | $ | — |
| | $ | 183,600 |
|
| | 2016 | | $ | 165,240 |
| | $ | — |
| | $ | — |
| | $ | 165,240 |
|
| Scot A. Shoup, Senior Vice President of Operations | | 2018 | | $ | 279,000 |
| | $ | — |
| | $ | 222,400 |
| | $ | 501,400 |
|
| | 2017 | | $ | 270,000 |
| | $ | — |
| | $ | — |
| | $ | 270,000 |
|
| | 2016 | | $ | 180,000 |
| | $ | — |
| | $ | — |
| | $ | 180,000 |
|
(1) The amounts shown represent the grant date fair value of awards computed in accordance with FASB ASC 718, however, such awards are subject to vesting requirements for TBRU's and PBRU's which have not been met as it relates to the 2018 stock award. See Note 18 included in Item 8 herein for the assumptions made in our valuation of such awards.
Director Compensation
As a partnership, we are managed by our general partner. The board of directors of our general partner performs for us the functions of a board of directors of a business corporation. Directors of our general partner are entitled to receive total quarterly retainer fees of $16,250 each, which are paid by the general partner. Martin Resource Management 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, 20182020 through December 31, 2018.2020.
| | | | | | | | | | | | | | | | | | | | |
Name | | Fees Earned Paid in
Cash | | Stock
Awards (2) | | Total |
| Ruben S. Martin | | $ | — | | | $ | — | | | $ | — | |
| Robert D. Bondurant | | $ | — | | | $ | — | | | $ | — | |
| C. Scott Massey (1) | | $ | 65,000 | | | $ | 67,770 | | | $ | 132,770 | |
| Byron R. Kelley (1) | | $ | 65,000 | | | $ | 67,770 | | | $ | 132,770 | |
| James M. Collingsworth (1) | | $ | 65,000 | | | $ | 67,770 | | | $ | 132,770 | |
| Sean P. Dolan | | $ | — | | | $ | — | | | $ | — | |
| Zachary S. Stanton | | $ | — | | | $ | — | | | $ | — | |
|
| | | | | | | | | | | | |
Name | | Fees Earned Paid in Cash | | Stock Awards (2) | | Total |
| Ruben S. Martin | | $ | — |
| | $ | 1,158,913 |
| | $ | 1,158,913 |
|
| Robert D. Bondurant | | $ | — |
| | $ | 740,870 |
| | $ | 740,870 |
|
| C. Scott Massey (1) | | $ | 65,000 |
| | $ | 74,633 |
| | $ | 139,633 |
|
| Byron R. Kelley (1) | | $ | 65,000 |
| | $ | 74,633 |
| | $ | 139,633 |
|
| James M. Collingsworth (1) | | $ | 65,000 |
| | $ | 74,633 |
| | $ | 139,633 |
|
| Sean P. Dolan | | $ | — |
| | $ | — |
| | $ | — |
|
| Zachary S. Stanton | | $ | — |
| | $ | — |
| | $ | — |
|
(1) On February 20, 2018,12, 2020, the Partnership issued 4,65027,000 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 1,162.56,750 units on January 24, 2019, 2020, 2021, 2022, 2023 and 2022,2024, 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.
(2) 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 TBRU's and PBRU's which have not been met as it relates to the 2018 stock award. See Note 18 included in Item 8 herein for the assumptions made in our valuation of such awards.
COMPENSATION REPORT OF THE COMPENSATION COMMITTEE
The Compensation Committee of the general partner of Martin Midstream Partners L.P. has reviewed and discussed the Compensation Discussion and Analysis section of this report with management of the general partner of Martin Midstream Partners L.P. and, based on that review and discussions, has recommended that the Compensation Discussion and Analysis be included in this report.
Members of the Compensation Committee:
| | |
|
| /s/ James M. Collingsworth |
| James M. Collingsworth, Committee Chair |
|
| /s/ Byron R. Kelley |
| Byron R. Kelley |
|
| /s/ C. Scott Massey |
| C. Scott Massey |
|
Compensation Committee Interlocks and Insider Participation
Other than these independent directors, no other officer or employee of our general partner or its subsidiaries is a member of the Compensation Committee. Employees of Martin Resource Management Corporation, through our general partner, are the individuals who work on our matters.
|
| | | | |
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
The following table sets forth the beneficial ownership of our units as of February 19, 2019March 3, 2021 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) | 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% | MRMC ESOP Trust (4) | | 6,114,532 | | | 15.7% |
| Martin Resource Management Corporation (5) | | 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 Resource, LLC (5) | | 4,203,823 | | | 10.8% |
| Martin Product Sales LLC (5) | | 1,021,265 |
| | 2.6% | Martin Product Sales LLC (5) | | 1,021,265 | | | 2.6% |
| Cross Oil Refining & Marketing Inc. (6) | | 889,444 |
| | 2.3% | Cross Oil Refining & Marketing Inc. (6) | | 889,444 | | | 2.3% |
| OppenheimerFunds, Inc. (2) | | 7,760,760 |
| | 19.9% | |
| Invesco Ltd. (2) | | Invesco Ltd. (2) | | 8,216,779 | | | 21.1% |
| Ruben S. Martin (6) | | 6,446,851 |
| | 16.5% | Ruben S. Martin (6) | | 6,575,896 | | | 16.9% |
| Robert D. Bondurant | | 69,772 |
| | —% | Robert D. Bondurant | | 113,595 | | | —% |
| Randall L. Tauscher | | 55,145 |
| | —% | Randall L. Tauscher | | 74,433 | | | —% |
| Chris H. Booth | | 31,330 |
| | —% | |
| Chris H. Booth (7) | | Chris H. Booth (7) | | 48,218 | | | —% |
| Sharon L. Taylor (8) | | Sharon L. Taylor (8) | | 10,064 | | | —% |
| Scot A. Shoup | | 10,100 |
| | —% | Scot A. Shoup | | 22,956 | | | —% |
| Sean Dolan | | — |
| | —% | |
| Christopher M. Reid | | Christopher M. Reid | | — | | | —% |
| Zachary S. Stanton | | — |
| | —% | Zachary S. Stanton | | — | | | —% |
C. Scott Massey (7)(9) | | 41,298 |
| | —% | | 85,854 | | | —% |
| Byron R. Kelley | | 26,898 |
| | —% | Byron R. Kelley | | 67,954 | | | —% |
| James M. Collingsworth (8) | | 24,298 |
| | —% | |
| All directors and executive officers as a group (10 persons) (9) | | 6,705,692 |
| | 17.2% | |
| James M. Collingsworth (10) | | James M. Collingsworth (10) | | 66,129 | | | —% |
| All directors and executive officers as a group (10 persons) (11) | | All directors and executive officers as a group (10 persons) (11) | | 7,065,099 | | | 18.2% |
|
| |
(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. |
(1)The address for Martin Resource Management Corporation and all of the individuals listed in this table, unless otherwise indicated, is c/o Martin Midstream Partners L.P., 4200 Stone Road, Kilgore, Texas, 75662.
| |
(2) | The address for OppenheimerFunds, Inc. is 225 Liberty Street, New York, NY 10281. |
(2)Based solely upon the Schedule 13G/A filed on February 12, 2021 with the SEC by the beneficial owner as of December 31, 2020. Invesco Ltd. has sole voting power and sole dispositive power over 8,216,779 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. |
(3)The percent of class shown is less than one percent unless otherwise noted.
| |
(4) | By virtue of its ownership of 87.87%(4)By virtue of its ownership of 88.39% 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.
(6)Includes 461,364 common units owned directly by Mr. Martin, 406,447 of which are pledged to third parties to secure payment for loans. By virtue of serving as the Chairman of the Board and President of Martin Resource Management Corporation, ("Martin Resource Management"), the MRMC ESOP Trust (the "MRMC ESOP") is the controlling shareholder of Martin Resource Management, and may be deemed to beneficially own the 6,114,532 MMLP Common Units held by Martin Resource LLC, Cross Oil Refining & Marketing Inc., and Martin Product Sales LLC. Wilmington Trust Retirement and Institutional Services Company serves as trustee of the MRMC ESOP but all of its voting and investment decisions are directed by the board of directors of Martin Resource Management. The MRMC ESOP expressly disclaims beneficial ownership of the MMLP Common Units as voting and investment decisions are directed by the board of directors of Martin Resource Management. |
| |
(5) | Martin Resource Management is the owner of Martin Resource, LLC, Martin Product Sales LLC, and Cross Oil Refining & Marketing Inc., and as such may be deemed to beneficially own the common units held by Martin Resource LLC, Cross Oil Refining & Marketing Inc, and Martin Product Sales LLC. The 4,203,823 common units beneficially owned by Martin Resource Management through its ownership of Martin Resource, LLC have been pledged as security to a third party to secure payment for a loan made by such third party. The 1,021,265 common units beneficially owned by Martin Resource Management through its ownership of Martin Product Sales LLC have been pledged as security to a third party to secure payment for a loan made by such third party. The 889,444 common units beneficially owned by Martin Resource Management through its ownership of Cross Oil Refining & Marketing Inc. have been pledged as security to a third party to secure payment for a loan made by such third party. |
| |
(6) | Includes 332,319 common units owned directly by Mr. Martin, 297,147 of which are pledged to third parties to secure payment for loans. By virtue of serving as the Chairman of the Board and President of Martin Resource |
Management, 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. Massey may be deemed to be the beneficial owner of 1,500 common units held by his wife. |
(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) | Mr. Collingsworth may be deemed to be the beneficial owner of 775 common units held by his wife. |
(8)Ms. Taylor may be deemed to be the beneficial owner of the 1,450 common units held by her husband.
| |
(9) | The total for all directors and executive officers as a group includes the common units directly owned by such directors and executive officers as well as the common units beneficially owned by Martin Resource Management as Ruben S. Martin may be deemed to be the beneficial owner thereof. |
(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 owns a 51% voting interest in the holding company that is the sole member of our general partner and, together with our general partner, owns approximately 15.7% of our outstanding common limited partner units as of December 31, 2018.2020. The table below sets forth information as of December 31, 20182020 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) | | 162,772.70 | | | 88.39 | % |
| Martin ESOP Trust (3) | | 21,382.92 | | | 11.61 | % |
| Robert D. Bondurant (3) | | 21,382.92 | | | 11.61 | % |
| Randall Tauscher (3) | | 21,382.92 | | | 11.61 | % |
(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 162,772.70 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, 139,893.57 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
|
| | | | | | |
| | | Beneficial Ownership of Voting Common Stock |
| Name of Beneficial Owner(1) | | Number of Shares | | Percent of Outstanding Voting Stock |
| MRMC ESOP Trust (2) | | 170,278.81 |
| | 87.87 | % |
| Martin ESOP Trust (3) | | 23,510.25 |
| | 12.13 | % |
| Robert D. Bondurant (3) | | 23,510.25 |
| | 12.13 | % |
| Randall Tauscher (3) | | 23,510.25 |
| | 12.13 | % |
| |
(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 170,278.81 shares of common stock of Martin Resource Management. Wilmington Trust Retirement and Institutional Services Company serves as trustee of the MRMC ESOP but all of its voting and investment decisions related to the unallocated shares of common stock are directed by the board of directors of Martin Resource Management. Of the common stock held by the MRMC ESOP, 99,195.49 shares of common stock are allocated to participant accounts, and 71,083.32 shares of common stock are unallocated. |
| |
(3) | Robert D. Bondurant and Randall Tauscher (the "Co-Trustees") are co-trustees of the Martin Employee Stock Ownership Trust which converted from a profit sharing plan known as the Martin Employees' Stock Profit Sharing Plan on January 1, 2014. The Co-Trustees exercise shared control over the voting and disposition of the securities owned by this trust. As a result, the Co-Trustees may be deemed to be the beneficial owner of the securities held by such trust; thus, the number of shares of common stock reported herein as beneficially owned by the Co-Trustees includes the 23,510 shares owned by such trust. The Co-Trustees disclaim beneficial ownership of these 23,510 shares. |
The following table sets forth information regarding securities authorized for issuance under our equity compensation plans as of December 31, 2018:2020:
Equity Compensation Plan Information
|
| | | | | | | | | | | | | | | | |
| Number of
securities to be
issued upon exercise
of outstanding
options, Warrants
and rights
| | Weighted-average
exercise price of
outstanding options,
warrants and rights
| | Number of securities
remaining available for
future issuance under equity compensation
plans (excluding
securities reflected in
column (a))
|
| Plan Category | (a) | | (b) | | (c) |
| Equity compensation plans approved by security holders | N/A |
| N/A | N/A |
| | 2,393,575 |
|
| Total | — |
| | $ | — |
| | 2,393,5752,574,638 |
|
(1) Our general partner has adopted and maintains the Martin Midstream Partners L.P. Long-Term Incentive Plan. For a description of the material features of this plan, please see "Item 11. Executive Compensation – Employee Benefit Plans – Martin Midstream Partners L.P. Long-Term Incentive Plan".
In February 2019, we issued 5,648 restricted common units to independent directors under our long-term incentive plan. These restricted common units vest in equal installments of 1,412 units on January 24, 2020, 2021, 2022 and 2023.
|
| | | | |
| 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 15.7% of our outstanding common limited partnership units as of February 19, 2019.March 3, 2021. Martin Resource Management Corporation controls Martin Midstream GP LLC, our general partner, by virtue of its 51% voting interest in MMGP Holdings, LLC, the sole member of our general partner. Our general partner owns a 2% general partner interest in us and all of our incentive distribution rights. Our general partner’s ability to manage and operate us and Martin Resource Management’sManagement Corporation’s ownership of approximately 15.7% 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 | Ÿ4,253,362 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)
|
| Ÿ 2% general partner interest; and
Ÿ the incentive distribution rights.
|
| Operational Stage | |
| Distributions of available cash to our general partner | We will generally make cash distributions 98% to our unitholders, including Martin Resource Management Corporation as holder of all of the subordinated units, and 2% to our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target levels, our general partner will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target level as a result of its incentive distribution rights. |
| Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner would receive an annual aggregate distribution of approximately $1.6$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 conflicts committeeboard of directors of our general partner ("Conflicts Committee") will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually. Please read "Agreements — Omnibus Agreement" below. |
| Withdrawal or removal of our general partner | If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. |
| Liquidation Stage | |
| Liquidation | Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances. |
Agreements
Omnibus Agreement
We and our general partner are parties to an omnibus agreementthe Omnibus Agreement with Martin Resource Management (the "Omnibus Agreement")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’sManagement 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.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, processing, storage and storagepackaging services for petroleum products and by-products including the refining blending and packaging of finished lubricants;naphthenic crude oil;
•providingland and marine transportation ofservices for petroleum products and by-products;by-products, chemicals, and specialty products;
•distributing NGLs;sulfur and sulfur-based products processing, manufacturing, marketing, and distribution; and
•manufacturingNGL marketing, distribution, and selling sulfur-based fertilizer products and other sulfur-related products.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:
| |
◦ | providing land transportation of various liquids (the Partnership acquired MTI effective January 1, 2019); |
| |
◦ | distributing fuel oil, asphalt, marine fuel and other liquids; |
| |
◦ | providing marine bunkering and other shore-based marine services in Texas, Louisiana, Mississippi, Alabama, and Florida; |
| |
◦ | operating a crude oil gathering business in Stephens, Arkansas; |
| |
◦ | providing crude oil gathering, refining, and marketing services of base oils, asphalt, and distillate products in Smackover, Arkansas; |
| |
◦ | providing crude oil marketing and transportation from the well head to the end market; |
| |
◦ | operating an environmental consulting company; |
| |
◦ | operating an engineering services company; |
| |
◦ | supplying employees and services for the operation of the Partnership's business; and |
| |
◦ | operating, solely for the Partnership's account, the asphalt facilities in Omaha, Nebraska, Port Neches, Texas, Hondo, Texas, and South Houston, Texas. |
•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 of the board of directors of the general partner of the Partnership (the "Conflicts Committee");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 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, 2020, 2019 and 2018, 2017 and 2016, the Conflicts Committeeboard of directors of our general partner approved and we reimbursed Martin Resource Management Corporation of $16.4 million, $16.4$16.7 million and $13.0$16.4 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committeeboard 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’sManagement 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.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.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.Management Corporation.
Motor CarrierMaster Transportation Services Agreement
We are a party to a motor carrier agreement effective January 1, 2006, as amended, with Martin Transport, Inc., 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 through whichCorporation. Under the agreement, MTI agreed to transport Martin Resource Management operates its land transportation operations. Under the agreement, Martin Transport, Inc. agrees to ship our NGL shipments as well as other liquid products.
Term and Pricing.The agreement has an initial term that expired in December 2007 but automatically renews for consecutive one-year periodswill continue unless either party terminates the agreement by giving at least 30 days' written notice to the other party at least 30 days prior to the expiration of the then-applicable term. We have the right to terminate this agreement at anytime by providing 90 days prior notice. Under this agreement, Martin Transport, Inc. transports our NGL shipments as well as other liquid products.party. These rates are subject to any adjustment toadjustments which are mutually agreed upon or in accordance with a price index. Additionally, during the term of the agreement, shipping charges are also subject to fuel surcharges determined on a weekly basis in accordance with the United StatesU.S. Department of Energy’s national diesel price list.
Indemnification. MTI has agreed to indemnify Martin Transport, Inc.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 indemnified usagreed to indemnify MTI against all claims arising out of the negligence or willful misconduct of Martin Transport, Inc.Resource Management Corporation and its officers, employees, agents, representatives and subcontractors. We indemnified Martin Transport against all claims arising out of the negligence or willful misconduct of us and our officers, employees, agents, representatives and subcontractors. In the event a claim is the result of the joint negligence or misconduct of Martin
TransportMTI and us, ourMartin Resource Management Corporation, indemnification obligations will be shared in proportion to each party’s allocable share of such joint negligence or misconduct.
As discussed in
Item 8. Financial Statements and Supplementary Data, the Partnership purchased Martin Transport, Inc. effective January 1, 2019.
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 January 1, 2017, and October 1, 2017, April 1, 2019, and January 1, 2020 to modify its minimum throughput requirements and throughput fees. ThisThe term of this agreement as amended, expired September 30, 2018is currently evergreen and continued thereafterit 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 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 a price index. Under this agreement, we agreed to purchase all of its marine fuel requirements that occur in the areas serviced by Martin Resource Management.Management Corporation.
Other Agreements
Cross Tolling Agreement. We are a party to an amended and restated tolling agreement with Cross dated October 28, 2014 under which we process crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts for Cross. The tolling agreement expires November 25, 2031. Under this tolling agreement, Martin Resource Management Corporation agreed to refine a minimum of 6,500 barrels per day of crude oil at the refinery at a fixed price per barrel. Any additional barrels are refined at a modified price per barrel. In addition, Martin Resource Management Corporation agreed to pay a monthly reservation fee and a periodic fuel surcharge fee based on certain parameters specified in the tolling agreement. All of these fees (other than the fuel surcharge) are subject to escalation annually based upon the greater of 3% or the increase in the Consumer Price Index for a specified annual period. In addition, every three years, the parties can negotiate an upward or downward adjustment in the fees subject to their mutual agreement.
Sulfuric Acid Sales Agency Agreement. We were previously a party to a third amended and restated sulfuric acid sales agency agreement dated August 2, 2017 but effective October 1, 2017, under which a successor in interest to the agreement from Martin Resource Management, Saconix LLC ("Saconix"), a limited liability company in which Martin Resource Management held a minority equity interest, purchased and marketed the sulfuric acid produced by our sulfuric acid production plant at Plainview, Texas, that was not consumed by our internal operations. This agreement, as amended, was to remain in place until September 30, 2020 and automatically renew year to year thereafter until either party provided 90 days’ written notice of termination prior to the expiration of the then existing term. Under this agreement, we sold all of our excess sulfuric acid to Saconix, who then marketed and sold such acid to third-parties. We shared in the profit of such sales.
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.
Other Related Party Transactions
Related Party Note Receivable
We had a $15.0 million note receivable from an affiliate of Martin Resource Management which previously bore an annual interest rate of 15% and had a maturity date of August 31, 2026, the balance of which could be prepaid on or after September 1, 2016. On February 14, 2017, we notified Martin Resource Management that we would be requesting voluntary repayment of the long-term Note Receivable plus accrued interest. During second quarter of 2017, the Note Receivable was fully repaid. Interest income for the years ended December 31, 2017 and 2016 was $0.9 million and $2.3 million, respectively.
2017 Public Offerings
In conjunction with a public offering, our general partner contributed $1.1 million in order to maintain its 2% general partner interest in us.
Transfers of Assets Between Entities Under Common Control
Acquisition of Terminalling Assets.Martin Transport, Inc. On February 22, 2017,January 2, 2019, we acquired 100%all of the membershipissued and outstanding equity interests of MEH South Texas Terminals LLC (“MEH”), a subsidiary ofMTI from Martin Resource Management Corporation for a purchase price of $27.4 million (the “Hondo Acquisition”). At$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 23 terminals located throughout the date of acquisition, MEH was in the process of constructing an asphalt terminal facility in Hondo, Texas (the "Hondo Terminal”), which will serve the asphalt market in San Antonio, TexasU.S. Gulf Coast and surrounding areas.Southeastern United States. The excess of the purchase price over the carrying value of the assets of $7.9$102.4 million was recorded as an adjustment to "Partners' capital."
East Texas Mack Leases. MTI leases equipment, including tractors and trailers, from East Texas Mack Sales ("East Texas Mack"). 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, 2020, 2019 and 2018 were approximately $0.7, $0.9 and $2.5, 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 FootnoteNote 14, "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.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.
|
| | | | |
| Item 14. | Principal Accounting Fees and Services |
KPMG, LLP served as our independent auditors for the fiscal years ended December 31, 20182020 and 2017.2019. The following fees were paid to KPMG, LLP for services rendered during our last two fiscal years:
| | | | | | | | | | | | | | | | | |
| | | 2020 | | 2019 | |
| Audit fees | | $ | 1,045,000 | | (1) | $ | 1,188,000 | | (1) |
| Audit related fees | | — | | | — | | |
| Audit and audit related fees | | 1,045,000 | | | 1,188,000 | | |
| Tax fees | | 169,912 | | (2) | 82,000 | | (2) |
| All other fees | | — | | | — | | |
| Total fees | | $ | 1,214,912 | | | $ | 1,270,000 | | |
|
| | | | | | | | | |
| | | 2018 | | 2017 | |
| Audit fees | | $ | 1,238,500 |
| (1) | $ | 1,349,934 |
| (1) |
| Audit related fees | | — |
| | — |
| |
| Audit and audit related fees | | 1,238,500 |
| | 1,349,934 |
| |
| Tax fees | | 82,106 |
| (2) | 123,167 |
| (2) |
| All other fees | | — |
| | 124,550 |
| (3) |
| Total fees | | $ | 1,320,606 |
| | $ | 1,597,651 |
| |
| |
(1) | 2018 audit fees include fees for the annual integrated audit and fees related to services in connection with transactions. 2017 audit fees include fees for the annual integrated audit and fees related to services in connection with transactions. |
| |
(2) | Tax fees are for services related to the review of our partnership K-1's returns, and research and consultations on other tax related matters. |
| |
(3) | All other fees are for accounting advisory services related to the adoption of ASC 606. |
(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, 20182020 and December 31, 20172019 were approved in advance by the Audit Committee.
PART IV
|
| | | | |
| Item 15. | Exhibits, Financial Statement Schedules |
(a) Financial Statements, Schedules
| |
(1) | (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. |
| |
(3) | Financial Statements of West Texas LPG Pipeline Limited Partnership, an affiliate accounted for by the equity method, which constituted a significant subsidiary. |
(2) Financial Statement ScheduleSchedules: 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.
Pursuant to Item 15(a)(3)
131
West Texas LPG Pipeline Limited Partnership
Financial Statements
For the seven-month period from January 1, 2018 to July 31, 2018 and each of the years ended December 31, 2017 and 2016 (unaudited)
Independent Auditor’s Report
To thePartnership Committee of West Texas LPG Pipeline Limited Partnership
We have audited the accompanying financial statements of West Texas LPG Pipeline Limited Partnership, which comprise thebalance sheetsas of July 31, 2018 and December 31, 2017, and the related statements of operations, changes in partners’ capital and cash flows for the period from January 1, 2018 to July 31, 2018 and the year ended December 31, 2017.
Management's Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.
Auditors’ Responsibility
Our responsibility is to express an opinion on the financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the Partnership's preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of West Texas LPG Pipeline Limited Partnershipas of July 31, 2018 and December 31, 2017, and the results of its operations and its cash flows for the period from January 1, 2018 to July 31, 2018 and the year ended December 31, 2017 in accordance with accounting principles generally accepted in the United States of America.
Other Matter
The accompanying statements of operations, changes in partners’ capital and cash flows for the year ended December 31, 2016 are presented for purposes of complying with Rule 3-09 of SEC Regulation S-X; however, Rule 3-09 does not require the 2016 financial statements to be audited and they are therefore not covered by this report.
/s/PricewaterhouseCoopers LLP
Tulsa, Oklahoma
February 19, 2019
West Texas LPG Pipeline Limited Partnership
Balance Sheets
(Dollars in thousands)
|
| | | | | | | |
| | July 31, | | December 31, |
| | 2018 | | 2017 |
| | | | |
| Assets | | | |
| Current assets | | | |
| Cash and cash equivalents | $ | 6,247 |
| | $ | 27,927 |
|
| Accounts receivable | 17,069 |
| | 17,151 |
|
| Materials and supplies inventories | 2,168 |
| | 2,168 |
|
| Other current assets | 208 |
| | 66 |
|
| Total current assets | 25,692 |
| | 47,312 |
|
| | | | |
| Property and equipment | 952,969 |
| | 831,823 |
|
| Accumulated depreciation | (50,468 | ) | | (42,308 | ) |
| Property, plant and equipment, net | 902,501 |
| | 789,515 |
|
| | | | |
| Other assets | 311 |
| | 337 |
|
| | | | |
| Total assets | $ | 928,504 |
| | $ | 837,164 |
|
| | | | |
| Liabilities and Partners' Capital | | | |
| Current liabilities | | | |
| Accounts payable | $ | 49,706 |
| | $ | 40,919 |
|
| Taxes payable | 1,575 |
| | 2,396 |
|
| Other current liabilities | 2,436 |
| | 459 |
|
| Total current liabilities | 53,717 |
| | 43,774 |
|
| | | | |
| Environmental reserve | 5,488 |
| | 5,964 |
|
| Other liabilities | 405 |
| | — |
|
| Total liabilities | 59,610 |
| | 49,738 |
|
| | | | |
| Commitments and contingencies (Note 6) | | | |
| Partners' capital | 868,894 |
| | 787,426 |
|
| Total liabilities and partners' capital | $ | 928,504 |
| | $ | 837,164 |
|
See accompanying notes to the financial statements.
West Texas LPG Pipeline Limited Partnership
Statements of Operations
(Dollars in thousands)
|
| | | | | | | | | | | |
| | Period from January 1, 2018 through July 31, 2018 | | Year Ended December 31, 2017 | | Year Ended December 31, 2016* |
| | | | | | (unaudited) |
| | | | | | |
| Revenue (Note 3) | $ | 55,534 |
| | $ | 87,049 |
| | $ | 88,467 |
|
| | | | | | |
| Costs and expenses | | | | | |
| Cost of services (exclusive of items shown separately below) | 8,379 |
| | 12,336 |
| | 11,401 |
|
| Operations and maintenance | 20,464 |
| | 36,510 |
| | 36,824 |
|
| Depreciation | 8,144 |
| | 13,842 |
| | 13,686 |
|
| Taxes other than income | 1,866 |
| | 2,842 |
| | 2,651 |
|
| Total costs and expenses | 38,853 |
| | 65,530 |
| | 64,562 |
|
| | | | | | |
| Other income (expense), net | (39 | ) | | 53 |
| | (22 | ) |
| | | | | | |
| Net income | $ | 16,642 |
| | $ | 21,572 |
| | $ | 23,883 |
|
*Not covered by the auditor’s report
See accompanying notes to the financial statements.
West Texas LPG Pipeline Limited Partnership
Statements of Changes in Partners' Capital
(Dollars in thousands)
|
| | | | | | | | | | | | | | | | | | | |
| | ONEOK Permian NGL Pipeline LP, LLC | | ONEOK Permian NGL Pipeline GP, LLC | | Martin Midstream Holdings II, LLC | | Martin Midstream Holdings, LLC | | Total |
| | | | | | | | | | |
| Balances - December 31, 2015 | $ | 636,786 |
| | $ | 6,432 |
| | $ | 159,197 |
| | $ | 1,608 |
| | $ | 804,023 |
|
| | | | | | | | | | |
| Net income (unaudited) | 18,915 |
| | 191 |
| | 4,729 |
| | 48 |
| | 23,883 |
|
| Distributions to partners (unaudited) | (29,700 | ) | | (300 | ) | | (7,425 | ) | | (75 | ) | | (37,500 | ) |
| Balances - December 31, 2016 (unaudited)* | 626,001 |
| | 6,323 |
| | 156,501 |
| | 1,581 |
| | 790,406 |
|
| | | | | | | | | | |
| Net income (unaudited) | 17,086 |
| | 172 |
| | 4,270 |
| | 44 |
| | 21,572 |
|
| Contributions by partners | 1,542 |
| | 16 |
| | 386 |
| | 4 |
| | 1,948 |
|
| Distributions to partners | (20,988 | ) | | (212 | ) | | (5,247 | ) | | (53 | ) | | (26,500 | ) |
| Balances - December 31, 2017 | 623,641 |
| | 6,299 |
| | 155,910 |
| | 1,576 |
| | 787,426 |
|
| | | | | | | | | | |
| Cumulative effect of adoption of ASC 606 (Note 2) | 65 |
| | 1 |
| | 17 |
| | — |
| | 83 |
|
| Net income | 13,181 |
| | 133 |
| | 3,295 |
| | 33 |
| | 16,642 |
|
| Contributions by partners | 65,137 |
| | 658 |
| | 16,284 |
| | 164 |
| | 82,243 |
|
| Distributions to partners | (13,860 | ) | | (140 | ) | | (3,465 | ) | | (35 | ) | | (17,500 | ) |
| Purchase and sale of Partnership interest (Note 1) | $ | 172,041 |
| | $ | 1,738 |
| | $ | (172,041 | ) | | $ | (1,738 | ) | | — |
|
| Balances - July 31, 2018 | $ | 860,205 |
| | $ | 8,689 |
| | $ | — |
| | $ | — |
| | $ | 868,894 |
|
*Not covered by the auditor’s report
See accompanying notes to the financial statements.
West Texas LPG Pipeline Limited Partnership
Statements of Cash Flows
(Dollars in thousands)
|
| | | | | | | | | | | |
| | Period from January 1, 2018 through July 31, 2018 | | Year Ended December 31, 2017 | | Year Ended December 31, 2016* |
| | | | | | (unaudited) |
| Cash flows from operating activities: | | | | | |
| Net income | $ | 16,642 |
| | $ | 21,572 |
| | $ | 23,883 |
|
| Adjustments to reconcile net income and net cash provided by operating activities: | | | | | |
| Depreciation | 8,144 |
| | 13,842 |
| | 13,686 |
|
| Change in assets and liabilities: | | | | | |
| Accounts receivable | 82 |
| | (4,008 | ) | | (4,169 | ) |
| Materials and supplies inventories | — |
| | (221 | ) | | 59 |
|
| Other current assets | (142 | ) | | (24 | ) | | (42 | ) |
| Other assets | 26 |
| | 28 |
| | (365 | ) |
| Accounts payable | (21,665 | ) | | 23,971 |
| | 7,797 |
|
| Taxes other than income | (821 | ) | | 226 |
| | 88 |
|
| Other current liabilities | (83 | ) | | 368 |
| | (219 | ) |
| Other liabilities | (36 | ) | | — |
| | — |
|
| Environmental reserve | (476 | ) | | (877 | ) | | (1,413 | ) |
| Net cash provided by operating activities | 1,671 |
| | 54,877 |
| | 39,305 |
|
| | | | | | |
| Cash flows from investing activities: | | | | | |
| Payments for property and equipment | (90,094 | ) | | (5,555 | ) | | (3,946 | ) |
| Net cash used in investing activities | (90,094 | ) | | (5,555 | ) | | (3,946 | ) |
| | | | | | |
| Cash flows from financing activities: | | | | | |
| Contributions by partners | 82,243 |
| | 1,948 |
| | — |
|
| Distributions to partners | (15,500 | ) | | (26,500 | ) | | (37,500 | ) |
| Net cash used in financing activities | 66,743 |
| | (24,552 | ) | | (37,500 | ) |
| | | | | | |
| Net increase (decrease) in cash and cash equivalents | (21,680 | ) | | 24,770 |
| | (2,141 | ) |
| | | | | | |
| Cash and cash equivalents at beginning of period | 27,927 |
| | 3,157 |
| | 5,298 |
|
| | | | | | |
| Cash and cash equivalents at end of period | $ | 6,247 |
| | $ | 27,927 |
| | $ | 3,157 |
|
*Not covered by the auditor’s report
See accompanying notes to the financial statements.
West Texas LPG Pipeline Limited Partnership
Notes to Financial Statements
(Dollars in thousands, except where otherwise indicated)
| |
(1) | Organization and Basis of Presentation |
West Texas LPG Pipeline Limited Partnership (the “Partnership” or “WTLPG”) is a Texas limited partnership. The Partnership was formed in 1999 and owns an approximately 2,300 mile common-carrier pipeline system that transports natural gas liquids (“NGLs”) from New Mexico and Texas to Mont Belvieu, Texas for fractionation. On July 31, 2018, ONEOK Permian NGL Pipeline GP, L.L.C. acquired the 0.2% General Partner Interest from Martin Midstream NGL Holdings, LLC, and ONEOK Permian NGL Pipeline LP, L.L.C. acquired the 19.8% Limited Partner Interest from Martin Midstream NGL Holdings II, LLC. As of July 31, 2018, the Partnership is a wholly owned subsidiary of ONEOK. Prior to the sale of partnership interests on July 31, 2018, the partners’ capital interests were owned by the following:
|
| | | | |
Owner | Interest | | Interest Type |
ONEOK Permian NGL Pipeline GP, L.L.C | 0.8 | % | | General Partner |
ONEOK Permian NGL Pipeline LP, L.L.C. | 79.2 | % | | Limited Partner |
Martin Midstream NGL Holdings, LLC | 0.2 | % | | General Partner |
Martin Midstream NGL Holdings II, LLC | 19.8 | % | | Limited Partner |
| 100 | % | | |
ONEOK Permian NGL Pipeline GP, L.L.C. and ONEOK Permian NGL Pipeline LP, L.L.C. are wholly owned subsidiaries of ONEOK, Inc. (“ONEOK”). A subsidiary of ONEOK is also the pipeline operator (“Operator”). Martin Midstream NGL Holdings, LLC and Martin Midstream NGL Holdings II, LLC are wholly owned subsidiaries of Martin Midstream Partners, L.P. (“Martin”).
The operating agreement among the partners provides that net income and distributions are to be allocated among the partner interests in proportion to their respective capital interests. Partners’ liabilities are limited to the amount of capital contributed.
The limited partnership agreement of WTLPG provides that distributions to the partners are to be made on a pro rata basis according to each partner’s ownership interest. Cash distributions to the partners are declared and paid by WTLPG each calendar quarter. Any changes to, or suspension of, the cash distributions from WTLPG required the approval of a minimum of 90 percent of the ownership interest and a minimum of two general partners of WTLPG. Cash distributions are equal to 100 percent of distributable cash as defined in the limited partnership agreement of WTLPG.
| |
(2) | Significant Accounting Policies |
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 financial statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ from those estimates.
The Partnership’s revenue is derived from fees collected for transporting NGLs. Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies, including the Federal Energy Regulatory Commission (“FERC”) and the Railroad Commission of Texas (“RRC”), or contractual arrangements. Our tariffs specify the maximum rates we may charge our customers and the general terms and conditions for NGL transportation service on our pipelines. Revenue is recognized when transportation services are provided. See Note 3 for additional disclosures.
| |
(c) | Cash and Cash Equivalents |
The Partnership considers all highly liquid cash investments with maturities of three months or less at the time of purchase to be cash equivalents.
West Texas LPG Pipeline Limited Partnership
Notes to Financial Statements
(Dollars in thousands, except where otherwise indicated)
| |
(d) | Property and Equipment |
Property and equipment is stated at cost, less accumulated depreciation. Our property and equipment are depreciated using the straight-line method over their estimated useful lives. We periodically conduct depreciation studies to assess the economic lives of our assets. These depreciation studies are completed as a part of our rate proceedings, and the changes in economic lives, if applicable, are implemented prospectively.
Property and equipment on our Balance Sheets includes construction work in process for capital projects that have not yet been placed in service and therefore are not being depreciated. Assets are transferred out of construction work in process when they are substantially complete and ready for their intended use.
Property and equipment consists of the following:
|
| | | | | | | | | |
| | Useful Life | | July 31, 2018 | | December 31, 2017 |
| | | | | | |
| | | | | | |
| Gathering lines and related equipment | 20-88 | | $ | 819,780 |
| | $ | 813,037 |
|
| General plant and other | 71-80 | | 8,238 |
| | 8,097 |
|
| Construction work in process | | | 124,951 |
| | 10,689 |
|
| Property and equipment | | | 952,969 |
| | 831,823 |
|
| Accumulated depreciation | | | (50,468 | ) | | (42,308 | ) |
| Property and equipment, net | | | $ | 902,501 |
| | $ | 789,515 |
|
Additions to property and equipment included in accounts payable as of July 31, 2018 and December 31, 2017 were $35,528 and $4,000, respectively.
| |
(a) | Impairment of Long-Lived Assets |
In accordance with ASC 360-10, long-lived assets such as property and equipment 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 for the amount by which the carrying amount of the asset exceeds the fair value of the asset. We determined that there were no asset impairments for the seven-month period from January 1, 2018 to July 31, 2018 or the years ended December 31, 2017 and 2016.
| |
(a) | Asset Retirement Obligations |
Asset retirement obligations represent legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. We are not able to estimate reasonably the fair value of the asset retirement obligations for our assets because the settlement dates are indeterminable given the expected continued use of the assets with proper maintenance. We expect our pipeline assets, for which we are unable to estimate reasonably the fair value of the asset retirement obligation, will continue in operation as long as supply and demand for NGLs exists. Based on the widespread use of NGLs by the petrochemical industry, we expect supply and demand to exist for the foreseeable future.
| |
(a) | Fair Value Measurements and Financial Instruments |
We use 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 our 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:
West Texas LPG Pipeline Limited Partnership
Notes to Financial Statements
(Dollars in thousands, except where otherwise indicated)
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.
We classify the fair value of an asset or liability based on the lowest level of input significant to its measurement. A fair value initially reported as Level 3 will be subsequently reported as Level 2 if the unobservable inputs become inconsequential to its measurement, or corroborating market data becomes available. Asset and liability fair values initially reported as Level 2 will be subsequently reported as Level 3 if corroborating market data becomes unavailable.
Our financial instruments consist of cash and cash equivalents, accounts receivable, and accounts payable. The carrying amounts of financial instruments approximate fair value due to their short maturities. Our cash and cash equivalents are comprised of bank and money market accounts and are classified as Level 1.
| |
(h) | Operating and Maintenance Expenses |
Operating and maintenance expenses are incurred by the Operator and charged for the cost of personnel that operate the pipeline and other operating costs. Where costs are incurred specifically on our behalf, the costs are billed directly to us by the Operator. In other situations, the costs may be allocated to us through a variety of methods, depending upon the nature of the expense and activities. Under our operating agreement, we are required to reimburse the Operator for such operating expenses.
| |
(i) | Environmental Reserves |
Our policy is to accrue for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable. We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us and potential third-party liability claims. 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. These revisions are reflected in our income in the period in which they are probable and can be reasonably estimated. Estimated 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.
| |
(j) | Accounts Receivable and Allowance for Doubtful Accounts. |
Trade accounts receivable are recorded at the invoiced amount and do not bear interest. We assess collectability at the inception of an arrangement based upon credit ratings and prior collections history. In general, we conduct business with customers with whom we have a long collection history. As a result, we have not experienced significant credit losses nor has our revenue recognition been impacted due to assessments of collectability. We have not recorded an allowance for doubtful accounts as of July 31, 2018 or December 31, 2017, as all accounts receivable were determined to be collectible.
| |
(k) | Transportation Imbalances |
In the course of transporting NGLs for others, we may receive for redelivery different quantities of NGLs than the quantities we ultimately redeliver. We record these differences as transportation and exchange imbalance receivables or payables that are subject to cash-out provisions. Imbalance receivables are included in accounts receivable, and imbalance payables are included in accounts payable on the balance sheet at current market prices in effect for the reporting period of the outstanding imbalances. As of July 31, 2018 and December 31, 2017, we had imbalance receivables and payables totaling $7,964 and $8,409, respectively.
| |
(l) | Concentration of Credit Risk |
Substantially all of our accounts receivable at July 31, 2018 and December 31, 2017, results from transportation fees earned from companies in the oil and gas industry and transportation imbalances. This concentration of customers may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by industry-wide changes in economic or other conditions. Such receivables are generally not collateralized. However, we perform credit evaluations on
West Texas LPG Pipeline Limited Partnership
Notes to Financial Statements
(Dollars in thousands, except where otherwise indicated)
all our customers to minimize exposure to credit risk. For the seven-month period from January 1, 2018 to July 31, 2018 and years ended December 31, 2017 and 2016 credit losses were not material.
As of July 31, 2018, accounts receivable includes receivables from one customer representing 52% of total accounts receivable. As of December 31, 2017, accounts receivable includes receivables from two customers representing 47% and 13% of total accounts receivable.
For the seven-month period from January 1, 2018 to July 31, 2018, revenue includes transportation fees received from three customers representing 23%, 20% and 17% of total revenue, respectively. For the year ended December 31, 2017, revenue includes transportation fees received from three customers representing 23%, 16% and 15% of total revenue, respectively. For the year ended December 31, 2016, revenue includes transportation fees received from two customers representing 18% (unaudited) and 12% (unaudited) of total revenue, respectively.
We are a limited partnership for federal and state income taxes. Income taxes are the responsibility of our members and, with the exception of the Texas franchise tax, are not reflected in our financial statements.
| |
(n) | Materials and Supplies Inventory |
The cost of materials, supplies and other inventories is principally determined using the average-cost method.
We have evaluated subsequent events through February 19, 2019, the date our financial statements were available, and we believe all required subsequent events disclosures have been made.
| |
(p) | Recent Accounting Pronouncements |
In February 2016, the FASB issued ASU 2016-02, Leases. This ASU amends the existing accounting standards for lease accounting, including requiring lessees to recognize most leases on their balance sheets and making targeted changes to lessor accounting. ASU 2016-02 is effective for annual reporting periods beginning after December 15, 2019. The standard requires a modified retrospective transition approach for all leases existing at, or entered into after, the date of initial application, with an option to use certain transition relief. We expect to record right of use assets and lease obligations on our balance sheet upon adoption. We do not expect the impact of adopting this standard to be material to our income statement or related disclosures.
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. Topic 606 replaced most existing revenue recognition guidance in U.S. GAAP. The Partnership adopted the standard on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method. The Partnership utilized the cumulative effect method which resulted an increase of $83 to retained earnings as of January 1, 2018. Results for reporting periods beginning on or after January 1, 2018, are presented under the new standard, while prior periods are not adjusted and continue to be reported under the accounting standards in effect for those periods. The Partnership did not identify any significant changes in the timing of revenue recognition when considering the amended accounting guidance.
In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. The standard clarifies the classification of certain cash receipts and cash payments on the statement of cash flows where diversity in practice has been identified. ASU 2016-15 is effective for annual reporting periods beginning after December 15, 2019. We do not expect the impact of adopting this standard to be material to our financial statements and related disclosures.
On January 1, 2018, we adopted Topic 606 using the cumulative effect transition method applied to those contracts which were not completed as of January 1, 2018. Results for reporting periods beginning on or after January 1, 2018 are
West Texas LPG Pipeline Limited Partnership
Notes to Financial Statements
(Dollars in thousands, except where otherwise indicated)
presented under Topic 606, while prior period amounts are not adjusted and continue to be reported in accordance with our historic accounting under ASC Topic 605, Revenue Recognition. The following disclosures discuss the Partnership’s revised revenue recognition policies upon the adoption of Topic 606, as discussed in Note 2.
There were no material impacts to revenues, or any other income statement caption, for the period from January 1, 2018 to July 31, 2018 as a result of applying Topic 606. The impact to the Balance Sheet resulted from contributions in aid of construction as follows:
|
| | | | | | | | | | | |
| | July 31, 2018 |
| | As reported | | Balance without adoption of Topic 606 | | Effect of change increase / (decrease) |
| | | | | | |
| Property and equipment | $ | 952,969 |
| | $ | 952,369 |
| | $ | 600 |
|
| Accumulated depreciation | 50,468 |
| | 50,445 |
| | 23 |
|
| Other current liabilities | 2,436 |
| | 2,376 |
| | 60 |
|
| Other liabilities | 405 |
| | 0 |
| | 405 |
|
| Partners’ capital | 868,894 |
| | 868,782 |
| | 112 |
|
Under Topic 606, we disaggregate our revenues by interstate transportation contracts, intrastate transportation contracts, and other contractual arrangements. These categories depict the nature, amount, timing and uncertainty of revenues. Disaggregated revenue for the period from January 1, 2018 through July 31, 2018 is as follows:
|
| | | | |
| Revenue | | |
| Interstate transportation services | | $ | 32,654 |
|
| Intrastate transportation services | | 19,007 |
|
| Other services | | 3,775 |
|
| Total revenue from contracts with customers | | 55,436 |
|
| Noncustomer revenue | | 98 |
|
| Total revenue | | $ | 55,534 |
|
The Partnership satisfies its obligations by providing services in exchange for consideration from customers. The timing of performance may differ from the timing of the associated consideration received from the customer, thus resulting in the recognition of a contract asset or a contract liability. As of July 31, 2018 and January 1, 2018, no contract assets have been recognized.
The Partnership recognizes a contract liability if the customer's payment of consideration precedes the Partnership’s fulfillment of the performance obligations. Our contract liabilities represent deferred revenue on contributions in aid of construction received from customers and are recorded in Other current liabilities and Other liabilities. These amounts are recognized in revenue as services are provided over the contract period, which averages approximately 10 years. The change in the contract liability is as follows:
|
| | | | |
| Contract Liability | | |
| | | |
| As of January 1, 2018 | | $ | 500 |
|
| Revenue recognized included in beginning balance | | (35 | ) |
| As of July 31, 2018 | | $ | 465 |
|
We expect to record approximately $50 per year through 2027.
| |
(4) | Related Party Transactions |
West Texas LPG Pipeline Limited Partnership
Notes to Financial Statements
(Dollars in thousands, except where otherwise indicated)
Related Party Transactions - We provide transportation services to affiliates of our partners. Affiliate services are recorded on the same basis as services to unaffiliated customers.
We do not have any employees; therefore, the Operator’s employees support and maintain our assets as provided by the terms of the operating agreement. We record direct costs for all compensation, benefits, employer taxes and other employer expenses for these employees. Pursuant to the operating agreement, we pay a management fee, which is reflected in operations and maintenance expenses in our Statements of Operations, to the Operator for administrative costs associated with operating our pipelines.
We also lease an approximate 300 mile pipeline, the Mesquite Pipeline, from affiliates of ONEOK, the cost of which is reflected in cost of services in our Statements of Operations.
The following table sets forth the transactions with related parties for the periods indicated:
|
| | | | | | | | | | | |
| | Period from January 1, 2018 through July 31, 2018 | | Year Ended December 31, 2017 | | Year Ended December 31, 2016 |
| | | | | | (unaudited) |
| | | | | | |
| Revenues | $ | 12,735 |
| | $ | 13,309 |
| | $ | 7,606 |
|
| | | | | | |
| Expenses: | | | | | |
| Cost of serivces | $ | 1,305 |
| | $ | 2,172 |
| | $ | 2,117 |
|
| Operating costs | 3,735 |
| | 8,924 |
| | 9,359 |
|
| Administrative costs | 5,821 |
| | 5,608 |
| | 5,546 |
|
| Total Expenses | $ | 10,861 |
| | $ | 16,704 |
| | $ | 17,022 |
|
Related Party Balances - We reimburse the Operator for direct costs of employees that support and maintain our assets. We also reimburse the Operator for direct third-party costs incurred on our behalf such as costs for materials, supplies and other charges. As of July 31, 2018, and December 31, 2017, we had accounts payable to the Operator of$47,668 and $39,306, respectively, related to management fees and reimbursements of expenditures. As of July 31, 2018 and December 31, 2017, we had accounts receivable from affiliates of ONEOK of $8,885 and $8,042, respectively, related to amounts due for transportation services provided and imbalance receivables.
We have non-cancelable operating leases primarily for the Mesquite Pipeline and other equipment. The leases generally provide that all expenses related to the pipeline and equipment are to be paid by the lessee.
Our future minimum lease obligations as of July 31, 2018 consist of the following:
|
| | | |
| 2018 | $ | 1,145 |
|
| 2019 | 2,729 |
|
| 2020 | 2,389 |
|
| 2121 | 955 |
|
| Thereafter | — |
|
| Total | $ | 7,218 |
|
Lease expense for operating leases for the period from January 1, 2018 through July 31, 2018, and years ended December 31, 2017 and 2016 was$5,626, $8,534 and $7,683 (unaudited) respectively.
West Texas LPG Pipeline Limited Partnership
Notes to Financial Statements
(Dollars in thousands, except where otherwise indicated)
| |
(6) | Commitments and Contingencies |
2015 Rate Complaints - On July 1, 2015, WTLPG began charging market-based common carrier rates for intrastate transportation service under a tariff on file with the Railroad Commission of Texas (“RRC”). Certain shippers filed complaints with the RRC challenging the increased rates WTLPG implemented effective July 1, 2015. The complaints requested that the rate increase be suspended until the RRC has determined appropriate new rates. On March 8, 2016, the RRC issued an order directing that WTLPG’s rates “in effect prior to July 1, 2015 are the lawful rates for the duration of this docket unless changed by Commission order.” The RRC indicated that WTLPG’s rates should be reviewed on a market basis, without consideration of cost of service, if market information is available.
In September 2017, the hearings examiner issued his Proposal for Decision rejecting the rates WTLPG filed on July 1, 2015, and finding that WTLPG could not charge rates similar to rates charged by new or expansion pipelines, since the rates of those newer pipelines included amounts associated with construction costs and those newer pipelines were allegedly “more reliable.” In January 2018, the Commissioners remanded the case back to the hearing examiner “for the limited scope of admitting and considering additional relevant evidence on common carrier market competition, transportation options, and pricing in the Permian Basin, Barnett Shale and Haynesville Shale markets, including pertinent market studies and/or analysis.”
The shippers’ complaints about increased rates implemented by WTLPG in July 2015 were resolved by a settlement that was formally approved by the RRC in January 2019. All prior claims have been resolved, and no contingency exists.
Occidental Energy Marketing, Inc. v. WTLPG - In December 2014, Occidental Energy Marketing, Inc. (“Oxy”) filed a lawsuit against WTLPG in state court in Houston, Texas asserting breach of contract and related claims arising from allegations that during a period from 2010 through 2014, WTLPG failed to redeliver approximately 11.7 million gallons of product received by WTLPG from Oxy. Oxy asserts approximately $11 million in damages. In August 2016, the Court granted summary judgment in favor of WTLPG on all of Oxy’s claims. In January 2017, the Court entered Final Judgment in favor of WTLPG, including an award of $257 thousand in attorneys’ fees. Oxy filed a Notice of Appeal in January 2017. All briefs have been filed and the oral argument was heard by the Texas Court of Appeals in November 2017.
In October 2018, the Texas Court of Appeals issued its decision affirming in part, reversing in part and remanding the case to the trial court for further proceedings consistent with its opinion. Oxy did not seek rehearing of the case en banc or request review by the Texas Supreme Court. Accordingly, the case was remanded to the trial court for further proceedings consistent with the decision of the Court of Appeals.
Because of the uncertainty surrounding the Oxy litigation, we cannot estimate a reasonably possible range of potential exposure at this time. However, it is reasonably possible that the ultimate resolution of this matter could result in future charges that may be material to our results of operations.
(b) Exhibits
INDEX TO EXHIBITS
| | | | | |
Exhibit
Number | Exhibit Name |
| |
Exhibit
Number
| Exhibit Name |
| |
| 3.1 | |
| 3.2 | |
| 3.3 | |
| 3.4 | |
| 3.5 | |
| 3.6 | |
| 3.7 | |
| 3.8 | |
| 3.9 | |
| 3.10 | |
| 3.11 | |
| 3.12 | |
| 3.13 | |
| 3.14 | |
| 3.15 | |
| 3.16 | |
| 3.17 | |
| 3.18 | |
| | | | | |
| 3.20 | |
| 3.21 | |
| 3.22 | |
| 3.23 | |
| 3.24 | |
| 3.25 | |
| 3.26 | |
| 3.27 | |
| 3.28 | |
| 3.29 | |
| 4.1 | Indenture (including form of 7.250% Senior Notes due 2021), dated February 11, 2013, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed February 12, 2013, and incorporated herein by reference). |
| 4.2 | First Supplemental Indenture, to the Indenture dated as of February 11, 2013 dated as of July 21, 2014, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Bank National Association, as trustee (filed as Exhibit 4.4 to the Partnership's Form 10-Q (SEC File No. 000-50056), filed July 31, 2014, and incorporated herein by reference). |
| 4.3 | |
4.34.4 | |
4.44.5 | |
10.14.6 | Fifth Supplemental Indenture, to the Indenture dated February 11, 2013, dated as of August 11, 2020, by and among the Partnership, Martin Midstream Finance Corp., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Partnership's Current Report on Form 8-K (SEC File No. 000-50056), filed August 12, 2020 and incorporated herein by reference). |
| 4.7 | |
|
| |
| 10.4 | |
| 10.5 | |
| 10.6 | |
| 10.7 | |
| 10.8 | |
10.9*10.9 | |
| 10.10 | |
| 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 | |
| 10.14 | |
| | | | | |
10.10*10.15 | |
10.1110.16 | |
10.1210.17 | |
10.1310.18 | |
10.1410.19 | |
10.1510.20 | |
10.1610.21 | |
10.1710.22 | |
10.1810.23 | |
10.1910.24 | |
10.20†10.25† | |
10.21†10.26† | |
10.2210.27 | |
|
| |
10.2310.28 | |
10.2410.29 | |
10.25(1)10.30(1) | |
10.26(1)10.31(1) | |
10.2710.32†
| |
10.2810.33 | |
10.2910.34 | |
10.3010.35 | |
| | | | | |
10.3110.36 | |
10.3210.37 | |
10.3310.38 | |
10.3410.39 | |
10.35(1)10.40(1) | |
10.36(1)10.41(1) | |
10.37(1)10.42(1) | |
10.3810.43 | |
10.3910.44 | |
10.4010.45 | |
10.4110.46 | |
21.1*10.47 | |
| 10.48 | |
| 10.49 | |
| 10.50 | 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). |
| 10.51 | |
| 10.52 | |
| 10.53 | |
| 21.1* | |
| 23.1* | |
23.2* | |
|
| | | | |
| 31.1* | |
| 31.2* | |
| 32.1* | |
| 32.2* | |
| 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, 2018,2020, formatted in Extensible Business Reporting Language: (1) the Consolidated Balance Sheets; (2) the Consolidated Statements of Income; (3) the Consolidated Statements of Cash Flows; (4) the Consolidated Statements of Capital; and (6) the Notes to Consolidated Financial Statements. |
*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 Securities Exchange Act, of 1934, as amended, which has been granted.
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| | | | |
| Item 16. | Form 10-K Summary |
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.
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| | | | | | | |
| Martin Midstream Partners L.P |
| (Registrant) |
| | |
| By: | Martin Midstream GP LLC |
| | It's General Partner |
| | |
February 19, 2019March 3, 2021 | By: | /s/ Ruben S. MartinRobert D. Bondurant |
| | Ruben S. MartinRobert D. Bondurant |
| | President and Chief Executive Officer |
| | |
| | | | | | | | |
| Martin Midstream Partners L.P |
| (Registrant) |
| | |
| By: | Martin Midstream GP LLC |
| | It's General Partner |
| | |
| March 3, 2021 | 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 February 19, 2019.March 3, 2021.
| | | | | | | | |
| Signature | | Title |
| | |
Signature | | Title |
| | |
/s/ Ruben S. MartinRobert D. Bondurant | | President, Director, and Chief Executive Officer and Director of Martin Midstream GP LLC (Principal Executive Officer) |
| Robert D. Bondurant | | |
| | |
| /s/Ruben S. Martin | | |
| | |
/s/ Robert D. Bondurant | | Executive Vice President, Director, and Chief Financial OfficerChairman of the Board of Directors of Martin Midstream GP LLC (Principal Financial Officer, Principal Accounting Officer) |
Robert D. BondurantRuben S. Martin | | |
| | |
| /s/Zachary S. Stanton | | Director of Martin Midstream GP LLC |
| Zachary S. Stanton | | |
| | |
| /s/James M. Collingsworth | | Director of Martin Midstream GP LLC |
| James M. Collingsworth | | |
| | |
/s/ Sean P. DolanChristopher M. Reid | | Director of Martin Midstream GP LLC |
Sean P. DolanChristopher M. Reid | | |
| | |
| /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 | | |