10-K 1 a2014123110-k.htm 10-K 2014.12.31 10-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K
Mark One
Annual Report Pursuant to Section 13 or 15(d) of the
 
ý
Securities Exchange Act of 1934
 
 
For the fiscal year ended December 31, 2014
 
OR
o
Transition Report Pursuant to Section 13 or 15(d) of the
 
 
Securities Exchange Act of 1934
 
  
For the transition period from  _____ to _____.
Commission file number 000-50056
 MARTIN MIDSTREAM PARTNERS L.P.
(Exact name of registrant as specified in its charter)
Delaware
 
05-0527861
State or other jurisdiction of incorporation or organization
 
(I.R.S. Employer Identification No.)
 
4200 Stone Road Kilgore, Texas  75662
(Address of principal executive offices)  (Zip Code)

903-983-6200
(Registrant’s telephone number, including area code)
_______________________
 
Securities Registered Pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange on which registered
Common Units representing limited partnership interests
 
NASDAQ Global Select Market
Securities Registered Pursuant to Section 12(g) of the Act:
NONE

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes  ý                       No o
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes o                        No ý
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements the past 90 days.
 Yes ý                        No o
 
Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).
 Yes ý                        No o
 



Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   ý
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer x
Accelerated filer o
Non-accelerated filer o
Smaller reporting company o
 
 
(Do not check if a smaller reporting company)
 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o                        No ý
 
As of June 30, 2014, 30,639,432 common units were outstanding.  The aggregate market value of the common units held by non-affiliates of the registrant as of such date approximated $1,051,991,075 based on the closing sale price on that date.  There were 35,449,662 of the registrant’s common units outstanding as of March 2, 2015.
 
DOCUMENTS INCORPORATED BY REFERENCE:         None.
 



TABLE OF CONTENTS

 
 
Page
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
 
 
 
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
 
 
 
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
 
 
 
PART IV
 
Item 15.
Exhibits, Financial Statement Schedules
 




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PART I

Item 1.
Business

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

Forward-Looking Statements

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

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

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

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

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

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

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

Marine transportation services for petroleum products and by-products.

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

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

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and capitalized on the needs of producers and purchasers of petroleum products and by-products and other bulk liquids. Martin Resource Management is an important supplier and customer of ours. As of December 31, 2014, Martin Resource Management owned 17.7% of our total outstanding common limited partner units. Furthermore, Martin Resource Management controls Martin Midstream GP LLC (“MMGP”), our general partner, by virtue of its 51% voting interest in MMGP Holdings, LLC (“Holdings”), the sole member of MMGP. MMGP owns a 2.0% general partner interest in us and all of our incentive distribution rights. Martin Resource Management directs our business operations through its ownership interests in and control of our general partner.

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

The historical operation of our business segments by Martin Resource Management provides us with several decades of experience and a demonstrated track record of customer service across our operations.  Our current lines of business have been developed and systematically integrated over this period of more than 60 years, including natural gas services (1950s); sulfur (1960s); marine transportation (late 1980s); and terminalling and storage (early 1990s).  This development of a diversified and integrated set of assets and operations has produced a complementary portfolio of midstream services that facilitates the maintenance of long-term customer relationships and encourages the development of new customer relationships.

Primary Business Segments
 
Our primary business segments can be generally described as follows:
 
Terminalling and Storage.  We own or operate 29 marine shore-based terminal facilities and 18 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, blending and packaging of various grades and quantities of naphthenic lubricants and related products. Our facilities and resources provide us with the ability to handle various products that require specialized treatment, such as molten sulfur and asphalt. We also provide land rental to oil and gas companies along with storage and handling services for lubricants and fuels. We provide these terminalling and storage services on a fee basis primarily under long-term contracts. A significant portion of the contracts in this segment provide for minimum fee arrangements that are not based on the volumes handled.

Natural Gas Services.  We distribute natural gas liquids (“NGLs”). We purchase NGLs primarily from refineries and natural gas processors. We store and transport NGLs for wholesale deliveries to propane retailers, refineries and industrial NGL users in Texas and the Southeastern U.S. We own a NGL pipeline, which spans approximately 200 miles from Kilgore, Texas to Beaumont, Texas. We own approximately 2.4 million barrels of underground storage capacity for NGLs. Additionally, we own 100% of the interests in Cardinal Gas Storage Partners LLC (“Cardinal”), which is focused on the development, construction, operation and management of natural gas storage facilities across northern Louisiana and Mississippi. We own a combined 20% interest in West Texas LPG Pipeline L.P. ("WTLPG"). WTLPG is operated by ONEOK Partners, L.P. ("ONEOK"), which owns the remaining 80.0% interest. WTLPG owns an approximate 2,300 mile common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. This asset enables us to participate in the transportation of the growing NGL production of West Texas and other basins along the WTLPG pipeline route. We owned six liquefied petroleum gas (“LPG”) pressure barges, (collectively referred to as the "Floating Storage Assets"). These assets were primarily operated under the floating storage component of our NGL distribution business. On February 12, 2015, we sold the barges for $41.3 million.

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

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is primarily used in the production of fertilizers and industrial chemicals. We own and operate six 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 Illinois and Texas. Demand for our sulfur products exists in both the domestic and foreign markets, and we believe our asset base provides us with additional opportunities to handle increases in U.S. supply and access to foreign demand.

Marine Transportation.  We operate a fleet of 42 inland marine tank barges, 25 inland push boats and four offshore tug and barge units that transport petroleum products and by-products largely in the U.S. Gulf Coast region. We provide these transportation services on a fee basis primarily under annual contracts and many of our customers have long standing contractual relationships with us. Our modernized asset base is attractive both to our existing customers as well as potential new customers. In addition, our fleet contains several vessels that reflect our focus on specialty products.

Recent Developments

We believe one of the rationales driving investment in master limited partnerships, including us, is the opportunity for distribution growth offered by the partnerships. Such distribution growth is a function of having access to liquidity in the financial markets used for incremental capital investment (development projects and acquisitions) to grow distributable cash flow.
 
We continually adjust our business strategy to focus on maximizing liquidity, maintaining a stable asset base which generates fee based revenues not sensitive to commodity prices, and improving profitability by increasing asset utilization and controlling costs. Over the past year, we have had access to the capital markets and have appropriate levels of liquidity and operating cash flows to adequately fund our growth.

Recent Acquisitions
    
Cardinal Gas Storage. On August 29, 2014, Redbird Gas Storage LLC (“Redbird”), a wholly owned subsidiary of the Partnership, completed the previously announced purchase of all of the outstanding membership interests of Cardinal from Energy Capital Partners I, LP, Energy Capital Partners I-A, LP, Energy Capital Partners I-B IP, LP and Energy Capital Partners I (Cardinal IP), LP (together, “ECP”) for cash of approximately $121.0 million. Prior to the acquisition, we owned an approximate 42.2% interest in the Category A membership interests in Cardinal. As a result of the acquisition, Redbird owns 100% of the outstanding membership interests in Cardinal. Concurrent with the closing of the transaction, we retired all of the project level financing of various Cardinal subsidiaries. This transaction and repayment of the project financings was funded with borrowings under our revolving credit facility. On October 27, 2014, Cardinal merged with and into Redbird, and Redbird subsequently changed its name to Cardinal.

NGL Storage Assets. On May 31, 2014, we acquired certain NGL storage assets, located in Arcadia, Louisiana, from Martin Resource Management for $7.4 million. This transaction was funded with borrowings under our revolving credit facility.

West Texas LPG Pipeline Limited Partnership. On May 14, 2014, we acquired from a subsidiary of Atlas Pipeline Partners L.P. ("Atlas"), all of the outstanding membership interests in Atlas Pipeline NGL Holdings, LLC and Atlas Pipeline NGL Holdings II, LLC (collectively, "Atlas Holdings") for cash of approximately $133.9 million. Atlas Holdings owned a 19.8% limited partnership interest and a 0.2% general partnership interest in WTLPG. WTLPG is currently operated by ONEOK, which owns the remaining 80.0% interest. WTLPG owns an approximate 2,300 mile common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. This transaction was funded with borrowings under our revolving credit facility.

Financing Activities

Public Offering. On September 29, 2014, we completed a public offering of 3,450,000 common units at a price of $36.91 per common unit, before the payment of underwriters' discounts, commissions and offering expenses (per unit value is in dollars, not thousands).  Total proceeds from the sale of the 3,450,000 common units, net of underwriters' discounts, commissions and offering expenses ,were $122.2 million.  Our general partner contributed $2.6 million in cash to us in conjunction with the issuance in order to maintain its 2.0% general partner interest in us.  All of the net proceeds were used to reduce outstanding indebtedness under our revolving credit facility.


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Private Placement of Common Units. On August 29, 2014, we closed a private equity sale with Martin Resource Management, under which Martin Resource Management invested $45.0 million in cash in exchange for 1,171,265 common units. The pricing of $38.42 per common unit was based on the 10-day weighted average price of our common units for the 10 trading days ending August 8, 2014 (per unit value is in dollars, not thousands).  In connection with the issuance of these common units, our general partner contributed $0.9 million in order to maintain its 2.0% general partner interest in us. All of the net proceeds were used to reduce outstanding indebtedness under our revolving credit facility.

Amendment to Revolving Credit Facility. On June 27, 2014, we increased the maximum amount of borrowings and letters of credit available under our revolving credit facility from $637.5 million to $900.0 million. In addition, we amended certain financial covenants that govern our credit facility.

Public Offering. On May 12, 2014, the Partnership completed a public offering of 3,600,000 common units at a price of $41.51 per common unit, before the payment of underwriters' discounts, commissions and offering expenses (per unit value is in dollars, not thousands).  Total proceeds from the sale of the 3,600,000 common units, net of underwriters' discounts, commissions and offering expenses, were $143.4 million.  Our general partner contributed $3.1 million in cash to us in conjunction with the issuance in order to maintain its 2.0% general partner interest in us.  All of the net proceeds were used to reduce outstanding indebtedness under our revolving credit facility.

Equity Distribution Program. In March 2014, we entered into an equity distribution agreement with multiple underwriters (the “Sales Agents”) for the ongoing distribution of our common units. Pursuant to this program, we offered and sold common unit equity through the Sales Agents for aggregate proceeds of $21.1 million for the year ended December 31, 2014. We paid $0.4 million in compensation to the Sales Agents for the year ended December 31, 2014. Under the program, we issued 522,121 common units during the year ended December 31, 2014. Common units issued were at market prices prevailing at the time of the sale. We also received capital contributions from our general partner of $0.4 million during the year ended December 31, 2014 related to these issuances to maintain its 2.0% general partner interest in us. The net proceeds from the common unit issuances were used to pay down outstanding amounts under our revolving credit facility.

Issuance of 7.250% Senior Unsecured Notes Due 2021. On April 1, 2014, we completed a private placement add-on of $150.0 million of the 7.250% senior unsecured notes due 2021.  We filed with the SEC a registration statement on Form S-4 to exchange these notes for substantially identical notes that are registered under the Securities Act and commenced an exchange offer on April 28, 2014. The exchange offer was completed during the second quarter of 2014.

Redemption of 8.875% Senior Unsecured Notes Due 2018. On April 1, 2014, we redeemed all $175.0 million of the 8.875% senior unsecured notes due in 2018 from their holders.  In conjunction with the redemption, the Partnership incurred a debt prepayment premium of $7.8 million and a non-cash charge of $3.9 million for the write-off of unamortized debt issuance costs and unamortized debt discount related to the redemption of the senior unsecured notes.

For a more detailed discussion regarding our financing activities, see “Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

Subsequent Events

Disposition of Floating Storage Assets. On February 12, 2015, we sold the Floating Storage Assets for $41.3 million. These assets were primarily operated under the floating storage component of our NGL distribution business. The proceeds from the disposition were used to reduce outstanding indebtedness under our revolving credit facility.    
    
Quarterly Distribution.  On January 22, 2015, we declared a quarterly cash distribution of $0.8125 per common unit for the fourth quarter of 2014, or $3.25 per common unit on an annualized basis, which was paid on February 13, 2015 to unitholders of record as of February 6, 2015. Additionally, we paid a distribution to our general partner in the amount of $4.4 million. Of this amount, $0.7 million is related to the base general partner distribution and $3.7 million represents incentive distribution rights paid to our general partner.

Common Unit Grants.   On January 5, 2015, we issued 84,750 restricted common units under our long-term incentive plan to the executive officers of our general partner and certain Martin Resource Management employees who provide services to us. These restricted units vest 100% on January 5, 2018.

Our Growth Strategy


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The key components of our growth strategy are:

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

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

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

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

Competitive Strengths

We believe we are well positioned to execute our business strategy because of the following competitive strengths:
Fee Based Contracts. We generate a majority of our cash flow from fee-based contracts with our customers. A significant portion of the fee-based contracts consist of reservation charges or minimum fee arrangements, which reduce the volatility of our cash flows due to volume fluctuations.
Asset Base and Integrated Distribution Network. We operate a diversified asset base that enables us to offer our customers an integrated distribution network consisting of transportation, terminalling and storage and midstream logistical services while minimizing our dependence on the availability and pricing of services provided by third parties. Our integrated distribution network enables us to provide customers with a complementary portfolio of transportation, terminalling, distribution and other midstream services for petroleum products and by-products.
Strategically Located Assets. We are one of the largest operators of marine service shore-based terminals in the U.S. Gulf Coast region providing broad geographic coverage and distribution capability of our products and services to our customers. Our natural gas storage and NGL distribution and storage assets are located in areas highly desirable for our customers. Finally, many of our sulfur services assets are strategically located to source sulfur from the largest refinery sources in the U.S.
Specialized Transportation Equipment and Storage Facilities. We have the assets and expertise to handle and transport certain petroleum products and by-products with unique requirements for transportation and storage. For example, we own facilities and resources to transport a variety of specialty products, including ammonia, molten sulfur and asphalt. Some of these specialty products require treatment across a wide range of temperatures ranging between approximately -30 to +400 degrees Fahrenheit to remain in liquid form, which our facilities are designed to accommodate. These capabilities help us enhance relationships with our customers by offering them services to handle their unique product requirements.
Strong Industry Reputation and Established Relationships with Suppliers and Customers. We have established a reputation in our industry as a reliable and cost-effective supplier of services to our customers and have a track record of safe, efficient operation of our facilities. Our management has also established long-term relationships with many of our suppliers and customers. We benefit from our management's reputation and track record and from these long-term relationships.
Experienced Management Team and Operational Expertise. Members of our executive management team and the heads of our principal business lines have a significant amount of experience in the industries in which we operate. Our management team has a successful track record of creating internal growth and completing acquisitions. Our management

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team's experience and familiarity with our industry and businesses are important assets that assist us in implementing our business strategies.

Terminalling and Storage Segment
 
Industry Overview.  The U.S. petroleum distribution system moves petroleum products and by-products from oil refineries and natural gas processing facilities to end users. This distribution system is comprised of a network of terminals, storage facilities, pipelines, tankers, barges, railcars and trucks. Terminals play a key role in moving these products throughout the distribution system by providing storage, blending and other ancillary services.
 
Although many large energy and chemical companies own terminalling and storage facilities, these companies also use third-party terminalling and storage services. Major energy and chemical companies typically have a strong demand for terminals owned by independent operators when such terminals are strategically located at or near key transportation links, such as deep-water ports. Major energy and chemical companies also need independent terminal storage when their owned storage facilities are inadequate, either because of lack of capacity, the nature of the stored material or specialized handling requirements.

The Gulf Coast region is a major hub for petroleum refining. Approximately 50% of U.S. refining capacity exists in this region. Growth in the refining and natural gas processing industries has increased the volume of petroleum products and by-products that are transported within the Gulf Coast region, which consequently has increased the need for terminalling and storage services.
 
The marine and offshore oil and gas exploration and production industries use terminal facilities in the Gulf Coast region as shore bases that provide them logistical support services as well as provide a broad range of products, including fuel oil, lubricants, chemicals and supplies. The demand for these types of terminals, services and products is driven primarily by offshore exploration, development and production in the Gulf of Mexico. Offshore activity is greatly influenced by current and projected prices of oil and natural gas.
 
Specialty Petroleum Terminals.  We own or operate 18 terminalling facilities providing storage, handling and transportation of various petroleum products and by-products. The locations and capabilities of our terminals are structured to complement our other businesses and reflect our strategy to provide a broad range of integrated services in the storage, handling and transportation of products. We developed our terminalling and storage assets by acquisition and upgrades of existing facilities as well as developing our own properties strategically located near rail, waterways and pipelines. We anticipate further expansion of our terminalling facilities through both acquisition and organic growth.

The Tampa terminal is located on approximately 10 acres of land owned by the Tampa Port Authority that was leased to us under a 10-year lease that commenced on December 16, 2006. This lease may be extended at the option of the tenant for two consecutive extension option periods of five years. The Stanolind terminal is located on approximately 11 acres of land owned by us located on the Neches River in Beaumont, Texas.  The Neches terminal is a deep water marine terminal located near Beaumont, Texas, on approximately 50 acres of land owned by us, and an additional 96 acres leased to us under terms of a 20-year lease commencing May 1, 2014 with three five-year options. The Corpus Christi, Texas barge terminal is located on approximately 25 acres of land owned by us and has access to the waterfront via marine docks owned by the Port of Corpus Christi. The Corpus Christi, Texas crude terminal is located on 10 acres leased from the Port of Corpus Christi under terms of a five-year lease commencing on May 18, 2011 with five five-year extension options.

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

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


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

In Smackover, Arkansas, we own and operate a terminal used for lubricant blending, processing, packaging, marketing and distribution. This terminal is used as our central hub for branded and private label packaged lubricants where we receive, package and ship heavy-duty, passenger car, and industrial lubricants to a network of retailers and distributors. A secondary warehousing and distribution operation is owned in Kansas City, Kansas, that allows us to serve markets that we cannot out of our Smackover facility.     

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

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

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

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

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

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

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

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

The following is a summary description of our shore-based specialty terminals:
Terminal
 
Location
 
Aggregate Capacity
 
Products
 
Description
Tampa (1)
 
Tampa, Florida
 
718,000 barrels
 
Asphalt, sulfur and fuel oil
 
Marine terminal, loading/unloading for vessels, barges, railcars and trucks
Stanolind
 
Beaumont, Texas
 
581,000 barrels
 
Asphalt, crude oil, sulfur, sulfuric acid and fuel oil
 
Marine terminal, marine dock for loading/unloading of vessels, barges, railcars and trucks
Neches
 
Beaumont, Texas
 
555,800 barrels
 
Molten sulfur, ammonia, asphalt, fuel oil, crude oil and sulfur-based fertilizer
 
Marine terminal, loading/unloading for vessels, barges, railcars and trucks
Corpus Christi Barge Terminal
 
Corpus Christi, Texas
 
250,000 barrels
 
Fuel oil and diesel
 
Marine terminal, loading/unloading barges and vessels and unloading trucks
Corpus Christi Crude Terminal (2)
 
Corpus Christi, Texas
 
900,000 barrels
 
Crude oil
 
Marine terminal, loading/unloading barges and vessels, trucks, and pipeline access
 
(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 2016. This lease may be extended at the option of the tenant for two consecutive option periods of five years.

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(2)
Our Corpus Christi, Texas crude terminal is located on 10 acres leased from the Port of Corpus Christi under terms of a five-year lease commencing on May 18, 2011 with five five-year options.

The following is a summary description of our non shore-based specialty terminals:
Terminal
 
Location
 
Aggregate Capacity
 
Products
 
Description
Channelview
 
Houston, Texas
 
44,000 sq. ft. Warehouse; 39,800 barrels
 
Lubricants
 
Lubricants blending, storage, packaging and distribution
Smackover Refinery
 
Smackover, Arkansas
 
7,700 barrels per day
 
Naphthenic lubricants, distillates, asphalt
 
Crude refining facility
Martin Lubricants
 
Smackover, Arkansas
 
235,000 sq. ft. Warehouse; 3.9 million gallons bulk storage
 
Gard, SynGard, Unimark and Xtreme brands, and automotive grease
 
Lubricants packaging facility
Martin Lubricants
 
Kansas City, Kansas
 
65,000 sq. ft. Warehouse; 1.2 million gallons bulk storage
 
Various
 
Lubricants and grease warehousing and distribution facility
Martin Lubricants (6)
 
Kansas City, Missouri
 
75,000 sq. ft. Warehouse; 0.2 million gallons bulk storage
 
Automotive, commercial and industrial greases
 
Grease manufacturing and packaging facility
South Houston Asphalt
 
Houston, Texas
 
71,400 barrels
 
Asphalt
 
Asphalt processing and storage
Port Neches Asphalt
 
Port Neches, Texas
 
31,300 barrels
 
Asphalt
 
Asphalt processing and storage
Omaha Asphalt
 
Omaha, Nebraska
 
114,200 barrels
 
Asphalt
 
Asphalt processing and storage
Dunphy
 
Elko, Nevada
 
63,200 barrels
 
Sulfuric acid
 
Sulfuric acid storage
Spindletop
 
Beaumont, Texas
 
90,000 barrels
 
Natural gasoline
 
Pipeline receipts and shipments
Broussard Bulk Facility (4)(5)(7)
 
Broussard, Louisiana
 
43,000 sq. ft. Warehouse;
8,200 barrels
 
Lubricants, fuel
 
Lubricants and fuel storage
Jennings Bulk Plant (5)
 
Jennings, Louisiana
 
36,000 sq. ft. building;
6,000 barrels
 
Lubricants, fuel
 
Lubricants and fuel storage
Lake Charles (3)
 
Lake Charles, Louisiana
 
18,000 sq. ft.Warehouse; 6,800 barrels
 
Lubricants
 
Lubricants storage

(3)
This terminal is located on land owned by third parties and leased under a lease that expires in January 2016 and can be extended by us through January 2021.  This terminal was acquired from Martin Resource Management on January 31, 2011.
(4)
This terminal is located on land owned by third parties and leased under a lease that expires in November 2015.
(5)
These terminals were acquired from the purchase of Talen's on December 31, 2012.
(6)
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 and was acquired from the purchase of the NL Grease assets on June 13, 2013.
(7)
This terminal is currently in caretaker status.

Marine Shore-Based Terminals.  We own or operate 29 marine shore-based terminals along the Gulf Coast from Theodore, Alabama to Corpus Christi, Texas.   Our terminalling assets are located at strategic distribution points for the products we handle and are in close proximity to our customers. We are one of the largest operators of marine shore-based terminals in the Gulf Coast region. These terminals are used to distribute and market fuel and lubricants. Additionally, full service terminals also provide shore bases for companies that are operating in the offshore exploration and production industry. Customers are primarily oil and gas exploration and production companies and oilfield service companies, such as drilling fluid companies, marine transportation companies and offshore construction companies. Shore bases typically provide logistical

8


support, including the storing and handling of tubular goods, loading and unloading bulk materials, providing facilities from which major and independent oil companies can communicate with and control offshore operations and leasing dockside facilities to companies which provide complementary products and services such as drilling fluids and cementing services. We generate revenues from our terminals that have shore bases by fees that we charge our customers under land rental contracts for the use of our terminal facility for these shore bases. These contracts generally provide us a fixed land rental fee and additional rental fees that are determined based on a percentage of the sales value of the products and services delivered from the shore base. In addition, Martin Resource Management, through contractual arrangements, pays us for terminalling and storage of fuels and lubricants at these terminal facilities.
 
Our 29 marine shore-based terminals are divided into two classes of terminals: (i) full service terminals and (ii) fuel and lubricant terminals.
 
Full Service Terminals.  We own or operate 10 full service terminals. These facilities provide logistical support services and storage and handling services for fuel and lubricants.  The significant difference between our full service terminals and our fuel and lubricant terminals is that our full service terminals generate additional revenues by providing shore bases to support our customer’s operating activities related to the offshore exploration and production industry. One typical use for our shore bases is for drilling fluids manufacturers to manufacture and sell drilling fluids to the offshore drilling industry. Offshore drilling companies may also set up service facilities at these terminals to support their offshore operations. Customers of our full service terminals are primarily oil and gas exploration and production companies, oilfield service companies such as drilling fluids companies, marine transportation companies and offshore construction companies.
 
The following is a summary description of our 10 full service terminals:
Terminal
 
Location
 
Aggregate Capacity (barrels)
Amelia 2 (3)(4)
 
Amelia, Louisiana
 
13,100
Cameron East (2)
 
Cameron, Louisiana
 
27,500
Dock 193 (7)(11)
 
Gueydan, Louisiana
 
11,000
Fourchon 15 (3)(6)
 
Fourchon, Louisiana
 
7,600
Freshwater City (7)(8)(9)
 
Freshwater City, Louisiana
 
10,000
Harbor Island (1)
 
Harbor Island, Texas
 
6,700
Intracoastal City-2 (3)(5)
 
Intracoastal City, Louisiana
 
18,100
Pelican Island
 
Galveston, Texas
 
88,400
Theodore
 
Theodore, Alabama
 
19,900
Venice (3)(10)
 
Venice, Louisiana
 
25,100

(1)
A portion of this terminal is located on land owned by a third party and leased under a lease that expires in January 2020 and can be extended by us through January 2025.
(2)
This terminal is located on land owned by third parties and leased under a lease that expires in March 2017 and can be extended by us through February 2022.
(3)
These terminals were acquired from Martin Resource Management on January 31, 2011.
(4)
This terminal is located on land owned by a third party and leased under a lease that expires in August 2018 and can be extended by us through August 2023.
(5)
This terminal is located on land owned by a third party and leased under a lease that expires in December 2015 and can be extended by us through December 2025.
(6)
This terminal is located on land owned by a third party and leased under a lease that expires in February 2017.
(7)
These terminals were acquired from the purchase of Talen's on December 31, 2012.
(8)
This terminal is located on land owned by a third party and leased under a lease that expires in March 2017.
(9)
This terminal has a warehousing agreement with a third party and under a lease that expires in March 2017.
(10)
This terminal is located on land owned by third parties and leased under multiple leases that expire in September 2017 and can be extended by us through December 2027
(11)
A portion of this terminal is located on land owned by a third party and leased under a lease that expires in May 2016.

Fuel and Lubricant Terminals.  We own or operate 19 lubricant and fuel terminals located in the Gulf Coast region that provide storage and handling services for lubricants and fuel oil.
 

9


The following is a summary description of our fuel and lubricant terminals:
Terminal
 
Location
 
Aggregate Capacity (barrels)
Berwick (1)
 
Berwick, Louisiana
 
24,600
Cameron 7 (9)(18)
 
Cameron, Louisiana
 
15,400
Cameron 8 (9)(6)
 
Cameron, Louisiana
 
31,900
Cameron West (5)(20)
 
Cameron, Louisiana
 
17,900
Dulac (9)(11)
 
Dulac, Louisiana
 
1,800
Fourchon (8)
 
Fourchon, Louisiana
 
80,900
Fourchon 16 (9)(15)
 
Fourchon, Louisiana
 
16,400
Fourchon 17 (9)(12)
 
Fourchon, Louisiana
 
41,200
Fourchon T (4)(10)
 
Fourchon, Louisiana
 
39,100
Freeport
 
Freeport, Texas
 
8,600
Galveston T (4)(17)
 
Galveston Texas
 
10,400
Intracoastal City (7)(20)
 
Intracoastal City, Louisiana
 
45,900
Lake Charles T (4)(16)
 
Lake Charles, Louisiana
 
1,000
Morgan City DWC 31(9)(14)
 
Morgan City, Louisiana
 
7,100
Pascagoula (18)
 
Pascagoula, Mississippi
 
11,000
Port Arthur (4)(19)
 
Port Arthur, Texas
 
16,300
Port O'Connor (2)
 
Port O'Connor, Texas
 
6,600
River Ridge (9)(13)
 
River Ridge, Louisiana
 
8,700
Sabine Pass (3)(20)
 
Sabine Pass, Texas
 
16,500

(1)
This terminal is located on land owned by third parties and leased under a lease that expires in September 2017.
(2)
This terminal is located on land owned by a third party and leased under a lease that expires in March 2015. We intend to extend this lease.
(3)
This terminal is located on land owned by a third party and leased under a lease that expires in September 2016 and can be extended by us through September 2036.
(4)
These terminals were acquired from the purchase of Talen's on December 31, 2012.
(5)
This terminal is located on land owned by a third party and leased under a lease that expires in February 2018 and can be extended by us through February 2033.
(6)
This terminal is located on land owned by a third party and leased under a lease that expires in July 2016 and can be extended by us through July 2036.
(7)
A portion of this location is leased pursuant to a month-to-month throughput agreement and a portion is under a lease, which expires April of 2015. We intend to renew the lease.
(8)
This terminal is located on land owned by a third party at which we throughput lubricants and fuel oil pursuant to an agreement that expires in May 2027.
(9)
These terminals were acquired from Martin Resource Management on January 31, 2011.
(10)
This terminal is located on land owned by a third party at which we throughput lubricants and fuel oil pursuant to an agreement that expires in October 2018 and can be extended by us through October 2038.
(11)
This terminal is located on land owned by third parties and leased under a lease that expires in December 2021 and can be extended by us through December 2041.
(12)
This terminal is located on land owned by third parties and leased under a lease that expires in December 2018 and can be extended by us through December 2023.
(13)
This terminal is located on land owned by third parties and leased under multiple leases that expire in April 2019 and February 2020.
(14)
This terminal is located on land owned by third parties and leased under a lease that expires in December 2019 and can be extended by us through December 2034. In addition, there is an office sublease that expires December 2019.
(15)
This terminal is located on land owned by third parties and leased under multiple leases that expire in July 2017, July 2016, and March 2017.  These leases can be extended by us through July 2022, July 2026, and March 2022, respectively.
(16)
This terminal is located on land owned by third parties and leased under a lease that expires in April 2018 and can be extended by us through April 2023.
(17)
This terminal was converted from full services terminals to fuel and lube terminals during 2013.

10


(18)
This terminal is located on land owned by a third party and leased under a lease that expires in July 2017 and can be extended by us through July 2027.
(19)
This terminal is located on land owned by third parties and leased under a lease that expires in November 2015 and can be extended by us through November 2025.
(20)
These terminals are currently in caretaker status.
 
Competition.  We compete with independent terminal operators and major energy and chemical companies that own their own terminalling and storage facilities. Many customers prefer to contract with independent terminal operators rather than terminal operators owned by integrated energy and chemical companies that may have refining or marketing interests that compete with the customers.

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

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

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

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

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

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

storage of NGLs purchased in off-peak months;

efficient use of the transportation fleet of vehicles owned by Martin Resource Management; and

product management expertise to obtain supplies when needed.


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The following is a summary description of our owned and leased NGL facilities:
NGL Facility 
 
Location                         
 
Capacity                   
 
Description                           
Wholesale terminals
 
Arcadia, Louisiana
 
2,400,000 barrels
 
Underground storage
 
 
Breaux Bridge, Louisiana (1)
 
503,000 barrels
 
Underground storage
 
 
Hattiesburg, Mississippi (1)
 
115,000 barrels
 
Underground storage
 
 
Mt. Belvieu, Texas (1)
 
95,000 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

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

Our NGL customers consist of refiners, industrial processors and retail propane distributors. For the year ended December 31, 2014, we sold approximately 90% of our NGL volume to refiners and industrial processors and approximately 10% of our NGL volume to independent retail propane distributors located in Texas and the southeastern U.S.
 
We generally maintain consistent margins in our natural gas services business because we attempt to pass increases and decreases in the cost of NGLs directly to our customers. We generally try to coordinate our sales and purchases of NGLs based on the same daily price index of NGLs in order to decrease the impact of NGL price volatility on our profitability.

Natural Gas Storage. Cardinal is focused on the development, construction, operation and management of natural gas storage facilities across northern Louisiana and Mississippi.  On August 29, 2014, we acquired the remaining outstanding 57.8% interest in Cardinal from ECP. As a result of the acquisition, we own 100% of the outstanding membership interests in Cardinal. Concurrent with the closing of the transaction, we retired all of the project level financing of various Cardinal subsidiaries. This transaction and repayment of the project financings was funded with borrowings under our revolving credit facility. On October 27, 2014, Cardinal merged with and into Redbird, and Redbird subsequently changed its name to Cardinal.

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.

Cardinal facilities are summarized below:
Facility Name / Location
 
Facility Type
 
Storage Capacity
 
Percent of Capacity Contracted
 
Weighted Average Life of Remaining Contract Term
Arcadia Gas Storage, LLC Bienville Parish, Louisiana
 
Salt dome
 
17.5 billion cubic feet (bcf)
 
71%
 
2.2 years
Cadeville Gas Storage, LLC Ouachita Parish, Louisiana
 
Depleted reservoir
 
17.0 bcf
 
100%
 
8.4 years
Perryville Gas Storage, LLC Franklin Parish, Louisiana
 
Salt dome
 
8.7 bcf
 
98%
 
4.0 years
Monroe Gas Storage Company, LLC Monroe County, Mississippi
 
Depleted reservoir
 
7.0 bcf
 
100%
 
< 1 year

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

12



NGL Marine Storage. We owned six LPG pressure barges, which we acquired in February 2013. These assets were primarily operated under the floating storage component of our NGL distribution business. On February 3, 2015, we agreed to sell the barges for $41.3 million. The transaction closed on February 12, 2015.

LPG Pipeline Investment. On May 14, 2014, we acquired a combined 20% interest in WTLPG. WTLPG owns an approximate 2,300 mile common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. This acquisition will enable the Partnership to participate in the transportation of the growing NGL production of West Texas and other basins along the WTLPG pipeline route.

Competition.  We compete with large integrated NGL producers and marketers, as well as small local independent marketers. The primary components of competition related to our natural gas storage operations are location, rates, terms and flexibility of service and supply. Our natural gas storage facilities compete with other storage providers and increased competition could result form newly developed storage facilities or expanded capacity from existing competitors.
 
Seasonality.  The level of NGL supply and demand is subject to changes in domestic production, weather, inventory levels and other factors. While production is not seasonal, residential, refinery, and wholesale demand is highly seasonal. This imbalance causes increases in inventories during summer months when consumption is low and decreases in inventories during winter months when consumption is high. If inventories are low at the start of the winter, higher prices are more likely to occur during the winter. Additionally, abnormally cold weather can put extra upward pressure on propane prices during the winter because there are less readily available sources of additional supply except for imports, which are less accessible and may take several weeks to arrive. General economic conditions and inventory levels have a greater impact on industrial and refinery use of NGLs than the weather.

Sulfur Services Segment
 
Industry Overview.  Sulfur is a natural element and is required to produce a variety of industrial products. In the U.S., approximately 10 million tons of sulfur are consumed annually with the Tampa, Florida area being the largest single market. Currently, all sulfur produced in the U.S. is “recovered sulfur,” or sulfur that is a by-product from oil refineries and natural gas processing plants.  Sulfur production in the U.S. is principally located along the Gulf Coast, along major inland waterways and in some areas of the western U.S.
 
Sulfur is an important plant nutrient and is primarily used in the manufacture of phosphate fertilizers with the balance used for industrial purposes. The primary application of sulfur in fertilizers occurs in the form of sulfuric acid. Burning sulfur creates sulfur dioxide, which is subsequently oxidized and dissolved in water to create sulfuric acid. The sulfuric acid is then combined with phosphate rock to make phosphoric acid, the base material for most high-grade phosphate fertilizers.
 
Sulfur-based fertilizers are manufactured chemicals containing nutrients known to improve the fertility of soils. Nitrogen, phosphorus, potassium and sulfur are the four most important nutrients for crop growth.  These nutrients are found naturally in soils. However, soils used for agriculture become depleted of these nutrients and frequently require fertilizers rich in these essential nutrients to restore fertility.
 
Industrial sulfur products (including sulfuric acid) are used in a wide variety of industries. For example, these products are used in power plants, paper mills, auto and tire manufacturing plants, food processing plants, road construction, cosmetics and pharmaceuticals.
 
Our Operations and Products.  We maintain an integrated system of transportation assets and facilities relating to our sulfur services.  We gather molten sulfur from refiners, primarily located on the Gulf Coast. We transport sulfur by inland and offshore barges, railcars and trucks.  In the U.S., recovered sulfur is mainly kept in liquid form from production to usage at a temperature of approximately 275 degrees Fahrenheit. Because of the temperature requirement, the sulfur industry uses specialized equipment to store and transport molten sulfur. We have the necessary assets and expertise to handle the unique requirements for transportation and storage of molten sulfur.
 
The terms of our commercial sulfur contracts typically range from one to five years in length. We handle molten sulfur on cost-plus contracts and margin-based contracts, and the prices in such contracts 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 integrated oil companies that produce sulfur and fertilizer manufacturers that consume sulfur under transportation and storage contracts with remaining terms from one to two years in duration.
 

13


The sulfur assets located at the Port of Stockton in California are used to process (prill) molten sulfur into pellets. The Stockton facility can process approximately 1,000 metric tons of molten sulfur per day and the resulting dry pellets are stored in bulk until sold into certain U.S. and international agricultural markets. In 2006, we completed the construction of a sulfur priller at our Neches facility in Beaumont, Texas with construction of a second priller completed in 2009. Forming capacity was further increased in 2012 with the addition of a granulator. The two Beaumont prillers along with the granulator have the capacity to process approximately 5,500 metric tons of molten sulfur per day.  We process molten sulfur into formed sulfur on take-or-pay fee contracts, providing refiners access to the export market for the sale of their residual sulfur.
 
In September 2007, we completed construction of a sulfuric acid production facility at our Plainview, Texas location.  This facility processes molten sulfur to produce approximately 150,000 tons of sulfuric acid per year.  This acid production provides a dedicated supply of raw material sulfuric acid to our ammonium sulfate production plant that was completed in March of 2011.  The ammonium sulfate plant produces approximately 400 tons per day of quality ammonium sulfate and is marketed to our customers throughout the U.S.  The sulfuric acid produced and not consumed by the captive ammonium sulfate production is sold to Martin Resource Management which markets the excess production to third parties.

Fertilizer and related sulfur products are a natural extension of our molten sulfur business because of our access to sulfur and our distribution capabilities.  These products allow us to leverage the Sulfur Services segment of our business. Our annual fertilizer and industrial sulfur products sales have grown significantly as a result of acquisitions and internal growth.
 
In the U.S., fertilizer is generally sold to farmers through local dealers.  These dealers are typically owned and supplied by much larger wholesale distributors. We sell to these wholesale distributors.  Our industrial sulfur products are marketed primarily in the southern U.S., where many paper manufacturers and power plants are located.  Our products are sold in accordance with price lists that vary from state to state. These price lists are updated periodically to reflect changes in seasonal or competitive prices.  We transport our fertilizer and industrial sulfur products to our customers using third-party common carriers.  We utilize rail shipments for large volume and long distance shipments where available.
 
We manufacture and market the following sulfur-based fertilizer and related sulfur products:
 
Plant nutrient sulfur products.  We produce plant nutrient and agricultural ground sulfur products at our facilities in Odessa, Texas, Seneca, Illinois and Cactus, Texas. Our plant nutrient sulfur product is a 90% degradable sulfur product marketed under the Disper-Sul® trade name and sold throughout the U.S. to direct application agricultural markets. Our agricultural ground sulfur products are used primarily in the western U.S. on grapes and vegetable crops.

Ammonium sulfate products.  We produce various grades of ammonium sulfate including granular, coarse and standard grades, a 40% ammonium sulfate solution.  These products primarily serve direct application agricultural markets. We blend our ammonium sulfate to make custom grades of lawn and garden fertilizer at our facility in Salt Lake City, Utah. We package these custom grade products under both proprietary and private labels and sell them to major retail distributors and other retail customers of these products.

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 Texarkana, 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 56 railcars and lease 105 railcars equipped to transport molten sulfur. We own the following marine assets and use them to transport molten sulfur from our Beaumont, Texas terminal to our Tampa, Florida terminal as well as provide third party marine transportation services to others:

14


Asset                   
 
Class of Equipment 
 
Capacity/Horsepower
 
Products Transported
Margaret Sue
 
Offshore tank barge
 
10,450 long tons
 
Molten sulfur
M/V Martin Explorer
 
Offshore tugboat
 
7,200 horsepower
 
N/A
M/V Martin Express
 
Inland push boat
 
1,200 horsepower
 
N/A
MGM 101
 
Inland tank barge
 
2,450 long tons
 
Molten sulfur
MGM 102
 
Inland tank barge
 
2,450 long tons
 
Molten sulfur
 
We own the following sulfur forming facilities as part of our sulfur services business: 
Terminal 
 
Location
 
Daily Production Capacity
 
Products Stored
Neches
 
Beaumont, Texas
 
5,500 metric tons per day
 
Molten, prilled and granulated sulfur
Stockton
 
Stockton, California
 
1,000 metric tons per day
 
Molten and prilled sulfur

We lease 132 railcars to transport our fertilizer products.  We own the following manufacturing plants as part of our sulfur services business:
Facility 
 
Location                     
 
Annual Capacity                   
 
Description                              
Fertilizer plant
 
Plainview, Texas
 
150,000 tons
 
Fertilizer production
Fertilizer plant
 
Beaumont, Texas
 
110,000 tons
 
Liquid sulfur fertilizer production
Fertilizer plants
 
Odessa, Texas
 
35,000 tons
 
Dry sulfur fertilizer production
Fertilizer plant
 
Seneca, Illinois
 
36,000 tons
 
Dry sulfur fertilizer production
Fertilizer plant
 
Salt Lake City, Utah
 
25,000 tons
 
Blending and packaging
Fertilizer plant
 
Cactus, Texas
 
20,000 tons
 
Dry sulfur fertilizer production
Industrial sulfur plant
 
Texarkana, Texas
 
18,000 tons
 
Emulsified sulfur production
Sulfuric acid plant
 
Plainview, Texas
 
150,000 tons
 
Sulfuric acid production
 
Competition.  We own one of the 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 vast majority of the sulfur produced in the U.S., which they purchase from resellers as well as directly from producers. We compete primarily with U.S. producers that sell directly to consumers with access to transportation and storage assets as well as foreign suppliers from Mexico or Venezuela that may sell into the Florida market. Our sulfur-based fertilizer products compete with several large fertilizer and sulfur products manufacturers.  However, the close proximity of our manufacturing plants to our customer base is a competitive advantage for us in the markets we serve and allows us to minimize freight costs and respond quickly to customer requests. Our sulfuric acid products compete with regional producers and importers in the South and Southwest portion of the U.S. from Louisiana to California.  
 
Seasonality.  Sales of our agricultural fertilizer products are partly seasonal as a result of increased demand during the growing season.

Marine Transportation Segment
 
Industry Overview.  The U.S. inland waterway system is a vast and heavily used transportation system. This inland waterway system is composed of a network of interconnected rivers and canals that serve as water highways and is used to transport vast quantities of products annually. This waterway system extends approximately 26,000 miles, of which 12,000 miles are generally considered significant for domestic commerce.
 
The Gulf Coast region is a major hub for petroleum refining. The petroleum refining process generates products and by-products that require transportation in large quantities from the refinery or processor. Convenient access to and use of this waterway system by the petroleum and petrochemical industry is a major reason for the current location of U.S. refineries and petrochemical facilities. The marine transportation industry uses push boats and tugboats as power sources and tank barges for freight capacity. The combination of the power source and tank barge freight capacity is called a tow.

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Marine Fleet.  We utilize a fleet of inland and offshore tows that provide marine transportation of petroleum products and by-products produced in oil refining and natural gas processing. Our marine transportation business operates coastwise along the Gulf of Mexico and East Coast and on the U.S. inland waterway system, primarily between domestic ports along the Gulf of Mexico, Intracoastal Waterway, the Mississippi River system and the Tennessee-Tombigbee Waterway system.   Additionally, we participate in Caribbean, Central America, and South American transport.  Our inland tows generally consist of one push boat and one to three tank barges, depending upon the horsepower of the push boat, the river or canal capacity and conditions, and customer requirements. Each of our offshore tows consist 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 
 
Description of Products Carried 
Inland tank barges
 
12
 
Under 20,000 barrels
 
Asphalt, crude oil, fuel oil, gasoline and sulfur
Inland tank barges
 
30
 
20,000 - 31,000 barrels
 
Asphalt, crude oil, fuel oil and gasoline
Inland push boats
 
25
 
800 - 3,800 horsepower
 
N/A
Offshore tank barges
 
4
 
45,000 barrels and 95,000 barrels
 
Asphalt, fuel oil and NGLs
Offshore tugboats
 
4
 
2,400 - 7,200 horsepower
 
N/A

Our largest marine transportation customers include major and independent oil and gas refining companies, petroleum marketing companies and Martin Resource Management. We conduct our marine transportation services on a fee basis primarily under annual contracts.
 
We are a party to a marine transportation agreement under which we provide marine transportation services to Martin Resource Management on a spot contract basis at applicable market rates.  Effective each January 1, this agreement automatically renews for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at least 60 days prior to the expiration of the then-applicable term.
 
Competition.  We compete primarily with other marine transportation companies. Competition in this industry has historically been based primarily on price. However, customers are placing an increased emphasis on safety, environmental compliance, quality of service and the availability of a single source of supply of services. Specifically, customers are increasingly seeking suppliers that can offer marine, land, rail and terminal distribution services while providing a high level of flexibility, health, safety, environmental and financial responsibility, adequate insurance and quality of services consistent with the customer’s standards.
 
In addition to competitors that provide marine transportation services, we also compete with providers of other modes of transportation, such as rail, trucks and, to a lesser extent, pipelines. For example, a typical two inland barge unit carries a volume of product equal to approximately 80 railcars or 250 tanker trucks. Pipelines generally provide a less expensive form of transportation than marine transportation. However, pipelines are not able to transport most of the products we transport and are generally a less flexible form of transportation because they are limited to the fixed point-to-point distribution of commodities in high volumes over extended periods of time.

Our Relationship with Martin Resource Management
 
Martin Resource Management is engaged in the following principal business activities:
 
providing land transportation of various liquids using a fleet of trucks and road vehicles and road trailers;

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

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

operating a crude oil gathering business in Stephens, Arkansas;

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providing crude oil gathering, refining, and marketing services of base oils, asphalt, and distillate products in Smackover, Arkansas;
    
providing crude oil marketing and transportation from the well head to the end market;

operating an environmental consulting company;

operating an engineering services company;

supplying employees and services for the operation of our business;

operating a natural gas optimization business; and

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

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

Ownership

Martin Resource Management owns approximately 17.7% of the outstanding limited partner units. In addition, Martin Resource Management controls MMGP, our general partner, by virtue of its 51% voting interest in Holdings, the sole member of MMGP. MMGP owns a 2.0% general partner interest in us and all of our incentive distribution rights.

Management

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

Related Party Agreements

The Omnibus Agreement with Martin Resource Management requires us to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes on our behalf or in connection with the operation of our business.  We reimbursed Martin Resource Management for $183.2 million, $177.1 million and $157.8 million of direct costs and expenses for the years ended December 31, 2014, 2013 and 2012, respectively.  There is no monetary limitation on the amount we are required to reimburse Martin Resource Management for direct expenses.

In addition to the direct expenses, under the Omnibus Agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses.  For the years ended December 31, 2014, 2013, and 2012, the conflicts committee of our general partner (“Conflicts Committee”) approved reimbursement amounts of $12.5 million, $10.6 million and $7.6 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.  These indirect expenses covered the centralized corporate functions Martin Resource Management provides for us, such as accounting, treasury, clerical, engineering, legal, billing, information technology, administration of insurance, general office expenses and employee benefit plans and other general corporate overhead functions we share with Martin Resource Management’s retained businesses.  The Omnibus Agreement also contains significant non-compete provisions and indemnity obligations.  Martin Resource Management also licenses certain of its trademarks and trade names to us under the Omnibus Agreement.
 
Other agreements include, but are not limited to, a motor carrier agreement, marine transportation agreements, terminal services agreements, a tolling agreement, and a sulfuric acid sales agency agreement.  Pursuant to the terms of the Omnibus Agreement, we are prohibited from entering into certain material agreements with Martin Resource Management without the approval of the Conflicts Committee.


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For a more comprehensive discussion concerning the Omnibus Agreement and the other agreements that we have entered into with Martin Resource Management, please see “Item 13. Certain Relationships and Related Transactions, and Director Independence.”
 
Commercial
 
We have been and anticipate that we will continue to be both a significant customer and supplier of products and services offered by Martin Resource Management. Our motor carrier agreement with Martin Resource Management provides us with access to Martin Resource Management’s fleet of road vehicles and road trailers to provide land transportation in the areas served by Martin Resource Management. Our ability to utilize Martin Resource Management’s land transportation operations is currently a key component of our integrated distribution network.
  
In the aggregate, our purchases from Martin Resource Management accounted for approximately 7% of our total cost of products sold during for the year ended December 31, 2014 and 8% of our total cost of products sold for the years ended December 31, 2013, and 2012. We also purchase marine fuel from Martin Resource Management, which we account for as an operating expense.
 
Correspondingly, Martin Resource Management is one of our significant customers. Our sales to Martin Resource Management accounted for approximately 6% of our total revenues for each of the years ended December 31, 2014, 2013 and 2012. We have entered into certain agreements with Martin Resource Management pursuant to which we provide terminalling and storage and marine transportation services to its subsidiary, Martin Energy Services, LLC ("MES"), and MES provides terminal services to us to handle lubricants, greases and drilling fluids.  Additionally, we have entered into a long-term, fee for services-based tolling agreement with Martin Resource Management where Martin Resource Management agrees to pay us for the processing of its crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts.

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

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

Insurance

Our deductible for onshore physical damage resulting from named windstorms is 5% of the total value located at an individual location subject to an overall minimum deductible of $4.0 million for damage caused by the named windstorm at all locations. Our onshore program currently provides $40.0 million per occurrence for named windstorm events. For non-windstorm events, our deductible applicable to onshore physical damage is $1.25 million per occurrence. Business interruption coverage in connection with a windstorm event is subject to the same $40.0 million per occurrence and aggregate limit as the property damage coverage and a waiting period of 45 days. For non-windstorm events, our waiting period applicable to business interruption is 30 days.

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

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

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

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

The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and, thus, any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and financial position. Moreover, there is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum products and by-products, chemical substances, and wastes as well as the accidental release or spill of such materials into the environment. Consequently, we cannot provide assurance that we will not incur significant costs and liabilities as result of such handling practices, releases or spills, including those relating to claims for damage to property and persons. In the event of future increases in costs, we may be unable to pass on those increases to our customers. While we believe that we are in substantial compliance with current environmental laws and regulations and that continued compliance with existing requirements would not have a material adverse impact on us, we cannot provide any assurance that our environmental compliance expenditures will not have a material adverse effect on us in the future.
 
Superfund
 
The Federal Comprehensive Environmental Response, Compensation and Liability Act, as amended, (“CERCLA”), also known as the “Superfund” law, and similar state laws, impose liability without regard to fault or the legality of the original conduct, on certain classes of “responsible persons,” including the owner or operator of a site where regulated hazardous substances have been released into the environment and companies that disposed or arranged for the disposal of the hazardous substances found at such site. Under CERCLA, these responsible persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances into the environment. Although certain hydrocarbons are not subject to CERCLA’s reach because “petroleum” is excluded from

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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.” We are not subject to any notification that we may be potentially responsible for cleanup costs under CERCLA.
 
Solid Waste
 
We generate both hazardous and nonhazardous solid wastes, which are subject to requirements of the federal Resource Conservation and Recovery Act, as amended (“RCRA”) and comparable state statutes. From time to time, the U.S. Environmental Protection Agency (“EPA”) has considered making changes in nonhazardous waste standards that would result in stricter disposal requirements for these wastes. Furthermore, it is possible some wastes generated by us that are currently classified as nonhazardous may in the future be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly disposal requirements. Changes in applicable regulations may result in an increase in our capital expenditures or operating expenses.
 
We currently own or lease, and have in the past owned or leased, properties that have been used for the manufacturing, processing, transportation and storage of petroleum products and by-products. Solid waste disposal practices within oil and gas related industries have improved over the years with the passage and implementation of various environmental laws and regulations. Nevertheless, a possibility exists that petroleum and other solid wastes may have been disposed of on or under various properties owned or leased by us during the operating history of those facilities. In addition, a number of these properties have been operated by third parties over whom we had no control as to such entities’ handling of petroleum, petroleum by-products or other wastes and the manner in which such substances may have been disposed of or released. State and federal laws and regulations applicable to oil and natural gas wastes and properties have gradually become more strict and, under such laws and regulations, we could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination, even under circumstances where such contamination resulted from past operations of third parties.

Clean Air Act
 
Our operations are subject to the federal Clean Air Act (“CAA”), as amended, and comparable state statutes. Amendments to the CAA adopted in 1990 contain provisions that may result in the imposition of increasingly stringent pollution control requirements with respect to air emissions from the operations of our terminal facilities, processing and storage facilities and fertilizer and related products manufacturing and processing facilities. Such air pollution control requirements may include specific equipment or technologies to control emissions, permits with emissions and operational limitations, pre-approval of new or modified projects or facilities producing air emissions, and similar measures. For example, the Neches Terminal is located in an EPA-designated ozone non-attainment area, referred to as the Beaumont/Port Arthur non-attainment area, which is subject to a EPA-adopted 8-hour standard for complying with the national standard for ozone.  In addition, existing sources of air emissions in the Beaumont/Port Arthur area are already subject to stringent emission reduction requirements.  Failure to comply with applicable air statutes or regulations may lead to the assessment of administrative, civil or criminal penalties, and/or result in the limitation or cessation of construction or operation of certain air emission sources. We believe our operations, including our manufacturing, processing and storage facilities and terminals, are in substantial compliance with applicable requirements of the CAA and analogous state laws.
 
Global Warming and Climate Change.  Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere.  In response to such studies, the U.S. Congress has from time to time considered climate change-related legislation to restrict greenhouse gas emissions.  At least 17 states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs.  Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007, in Massachusetts, et al. v. EPA, the EPA eventually concluded that it is required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases.  The Court's holding in Massachusetts that greenhouse gases fall under the federal CAA's definition of air pollutant has also led the EPA to determine that regulation of greenhouse gas emissions from stationary sources under various Clean Air Act programs is required.  To that end, EPA promulgated regulations, referred to as the Tailoring Rule, 75 Fed. Red. 31514, to begin gradually subjecting stationary greenhouse gas emission sources to various Clean Air Act programs, including permitting programs applicable to new and existing major sources of greenhouse gas emissions.  To date, such requirements have not had a substantial effect upon our operations.  Still, new legislation or regulatory programs that restrict emissions of greenhouse gases in areas in which we conduct business could adversely affect our operations and demand for our services.
 
Clean Water Act

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The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and controls on the discharge of pollutants into federal and state waters. Regulations promulgated under these laws require entities that discharge into federal and state waters obtain National Pollutant Discharge Elimination System (“NPDES”) and/or state permits authorizing these discharges. The Clean Water Act and analogous state laws assess penalties for releases of unauthorized pollutants into the water and impose substantial liability for the costs of removing spills from such waters. In addition, the Clean Water Act and analogous state laws require that individual permits or coverage under general permits be obtained by covered facilities for discharges of storm water runoff and that applicable facilities develop and implement plans for the management of storm water runoff (referred to as storm water pollution prevention plans (“SWPPPs”)) as well as for the prevention and control of oil spills (referred to as spill prevention, control and countermeasure (“SPCC”) plans). As part of the regular overall evaluation of our on-going operations, we are reviewing and, as necessary, updating SWPPPs for certain of our facilities, including facilities recently acquired.  In addition, we have reviewed our SPCC plans and, where necessary, amended such plans to comply with applicable regulations adopted by the EPA.  We believe that compliance with the conditions of such permits and plans will not have a material effect on our 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 and all existing single hull tank barges be retrofitted with double hulls or phased out by 2015. We believe we are in substantial compliance with all of the oil spill-related and financial responsibility requirements. Nonetheless, in the aftermath of the Deepwater Horizon incident in 2010, Congress has from time to time considered oil spill related legislation that could have the effect of substantially increasing financial responsibility requirements and potential fines and damages for violations and discharges subject to the OPA, and similar legislation.  Any such changes in law affecting areas where we conduct business could materially affect our operations.

Safety Regulation
 
The Company’s marine transportation operations are subject to regulation by the U.S. Coast Guard, federal laws, state laws and certain international treaties. Tank ships, push boats, tugboats and barges are required to meet construction and repair standards established by the American Bureau of Shipping, a private organization, and the U.S. Coast Guard and to meet operational and safety standards presently established by the U.S. Coast Guard. We believe our marine operations and our terminals are in substantial compliance with current applicable safety requirements.
 
Occupational Health Regulations
 
The workplaces associated with our manufacturing, processing, terminal and storage facilities are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. We believe we have conducted our operations in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances.  Our marine vessel operations are also subject to safety and operational standards established and monitored by the U.S. Coast Guard.
 
In general, we expect to increase our expenditures relating to compliance with likely higher industry and regulatory safety standards such as those described above. These expenditures cannot be accurately estimated at this time, but we do not expect them to have a material adverse effect on our business.
 
Jones Act
 
The Jones Act is a federal law that restricts maritime transportation between locations in the U.S. to vessels built and registered in the U.S. and owned and manned by U.S. citizens. Since we engage in maritime transportation between locations in the U.S., we are subject to the provisions of the law. As a result, we are responsible for monitoring the ownership of our subsidiaries that engage in maritime transportation and for taking any remedial action necessary to ensure that no violation of the Jones Act ownership restrictions occurs. The Jones Act also requires that all U.S.-flagged vessels be manned by U.S.

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citizens. Foreign-flagged seamen generally receive lower wages and benefits than those received by U.S. citizen seamen. This requirement significantly increases operating costs of U.S.-flagged vessel operations compared to foreign-flagged vessel operations. Certain foreign governments subsidize their nations’ shipyards. This results in lower shipyard costs both for new vessels and repairs than those paid by U.S.-flagged vessel owners. The U.S. Coast Guard and American Bureau of Shipping maintain the most stringent regimen of vessel inspection in the world, which tends to result in higher regulatory compliance costs for U.S.-flagged operators than for owners of vessels registered under foreign flags of convenience.
 
Merchant Marine Act of 1936
 
The Merchant Marine Act of 1936 is a federal law that provides that, upon proclamation by the President of the U.S. of a national emergency or a threat to the national security, the U.S. Secretary of Transportation may requisition or purchase any vessel or other watercraft owned by U.S. citizens (including us, provided that we are considered a U.S. citizen for this purpose). If one of our push boats, tugboats or tank barges were purchased or requisitioned by the U.S. government under this law, we would be entitled to be paid the fair market value of the vessel in the case of a purchase or, in the case of a requisition, the fair market value of charter hire. However, if one of our push boats or tugboats is requisitioned or purchased and its associated tank barge is left idle, we would not be entitled to receive any compensation for the lost revenues resulting from the idled barge. We also would not be entitled to be compensated for any consequential damages we suffer as a result of the requisition or purchase of any of our push boats, tugboats or tank barges.

Employees
 
We do not have any employees.  Under our Omnibus Agreement with Martin Resource Management, Martin Resource Management provides us with corporate staff and support services.  These services include centralized corporate functions, such as accounting, treasury, engineering, information technology, insurance, administration of employee benefit plans and other corporate services.  Martin Resource Management employs approximately 921 individuals, including 62 employees represented by labor unions, who provide direct support to our operations as of December 31, 2014.

Financial Information about Segments
 
Information regarding our operating revenues and identifiable assets attributable to each of our segments is presented in Note 20 to our consolidated financial statements included in this annual report on Form 10-K.
 
Access to Public Filings
 
We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to these reports filed with the SEC under the Securities and Exchange Act of 1934.  These documents may be accessed free of charge on our website at the following address: www.martinmidstream.com.  These documents are provided as soon as is reasonably practicable after their filing with the SEC.  This website address is intended to be an inactive, textual reference only, and none of the material on this website is part of this report.  These documents may also be found at the SEC’s website at www.sec.gov.

Item 1A.
Risk Factors
    
Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a business similar to ours. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In this case, we might not be able to pay distributions on our common units, the trading price of our common units could decline and unitholders could lose all or part of their investment. These risk factors should be read in conjunction with the other detailed information concerning us set forth herein.

Risks Relating to Our Business

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


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

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

the costs of acquisitions, if any;

the prices of petroleum products and by-products;

fluctuations in our working capital;

the level of capital expenditures we make;

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

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

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

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

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

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

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

                Our indebtedness could have important consequences, including the following:

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

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

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

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

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control.  If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital

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expenditures, selling assets or seeking additional equity capital.  We may not be able to effect any of these actions on satisfactory terms or at all.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

fires and explosions;


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

terrorist attacks or sabotage.

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

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

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

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

Increasing energy prices could adversely affect our results of operations.

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

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

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

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

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

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

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

worldwide demand for oil and natural gas;

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

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

local and international political and economic conditions and policies;

technological advances affecting energy production and consumption;

weather conditions;

environmental regulation; and

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

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

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

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

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

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

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

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

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

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


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

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

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

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

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

catastrophic events, including hurricanes;

environmental remediation;

labor difficulties; and

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

                We are reliant on technology to improve efficiency in our business.  Information technology systems are critical to our operations.  These systems could be a potential target for a cyber security attack as they are used to store and process

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sensitive information regarding our operations, financial position, and information pertaining to our customers and vendors.  While we take the utmost precautions, we cannot guarantee safety from all threats and attacks.  Any successful breach of security could result in the spread of inaccurate or confidential information, disruption of operations, environmental harm, endangerment of employees, damage to our assets, and increased costs to respond.  Any of these instances could have a negative impact on cash flows, litigation status and/or our reputation, which could have a material adverse affect on our business, financial conditions and operations. 

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

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

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

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

Risks Relating to an Investment in the Common Units

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

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

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

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

the conversion of subordinated units into common units;

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

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

Our partnership agreement does not restrict our ability to issue equity securities ranking junior to the common units at any time. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the

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proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding.

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

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

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

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and therefore limited ability to influence management's decisions regarding our business. Unitholders did not elect our general partner or its directors and will have no right to elect our general partner or its directors on an annual or other continuing basis. Martin Resource Management elects the directors of our general partner. Although our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders, the directors of our general partner also have a fiduciary duty to manage our general partner in a manner beneficial to Martin Resource Management and its shareholders.

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, 2014, Martin Resource Management owned 17.7% of our total outstanding common limited partner units.

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

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

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

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


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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

the conversion of subordinated units into common units;

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


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

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

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

our unitholders' proportionate ownership interest in us will decrease;

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

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

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

the market price of the common units may decline; and

the ratio of taxable income to distributions may increase.

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

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

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

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

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

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

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

In order to comply with Section 404 of the Sarbanes-Oxley Act, we periodically document and test our internal control procedures. Section 404 of the Sarbanes-Oxley Act requires annual management assessments of the effectiveness of our internal controls over financial reporting addressing these assessments. During the course of our testing we may identify deficiencies, which we may not be able to address in time to meet the deadline imposed by the Sarbanes-Oxley Act for compliance with the requirements of Section 404. In addition, if we fail to maintain the adequacy of our internal controls, as

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such standards are modified, supplemented or amended from time to time, we may not be able to ensure that we can conclude on an ongoing basis that we have effective internal controls over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act. Failure to achieve and maintain an effective internal control environment could have a material adverse effect on the price of our common units.

Risks Relating to Our Relationship with Martin Resource Management

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

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

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

As of December 31, 2014, Martin Resource Management owned 17.7% of our total outstanding common limited partner units and a 51% voting interest in Holdings, the sole member of MMGP. MMGP owns a 2.0% general partnership interest in us and all of our incentive distribution rights. Conflicts of interest may arise between Martin Resource Management and our general partner, on the one hand, and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of Martin Resource Management over the interests of our unitholders. Potential conflicts of interest between us, Martin Resource Management and our general partner could occur in many of our day-to-day operations including, among others, the following situations:

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

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

Martin Resource Management may engage in limited competition with us;

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

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

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

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

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


34


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

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

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

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

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

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

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

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

Tax Risks

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

The anticipated after-tax economic benefit of an investment in us depends largely on our classification as a partnership for federal income tax purposes. 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 “Internal Revenue Code”). “Qualifying income” includes income and gains derived from the transportation, storage, processing and marketing of 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 U.S. Internal Revenue Service (“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. Moreover, current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. At the federal level, members of Congress have considered substantive changes to the existing U.S. tax laws that would have affected certain publicly traded partnerships. Although the legislation considered would not have appeared to affect our tax treatment, we are unable to predict whether any such change or other proposals will ultimately be

35


enacted. Moreover, any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Any such changes could negatively impact the value of an investment in our common units. At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay a Texas margin tax at a maximum effective rate of 0.7% of our gross income apportioned to Texas in the prior year. Imposition of any such tax on us by any other state will reduce the cash available for distribution to you.

If we were treated as a corporation for federal income tax purposes, we would owe federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%, and would likely owe state income tax at varying rates. Distributions would generally be taxed again to unitholders as corporate distributions and no income, gains, losses, or deductions would flow through to unitholders. Because a tax would be imposed upon us as an entity, cash available for distribution to unitholders would be reduced. Treatment of us as a corporation would result in a reduction in the anticipated cash flow and after-tax return to unitholders and therefore would likely result in a reduction in the value of the common units.

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

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.

The IRS may adopt positions that differ from 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.

Unitholders may be required to pay taxes on income from us 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.

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

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

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

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


36


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 U.S Department of the Treasury's regulations (“Treasury regulations”). Any position we take that is inconsistent with applicable Treasury regulations may have to be disclosed on our federal income tax return. This disclosure increases the likelihood that the IRS will challenge our positions and propose adjustments to some or all of our unitholders. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders' tax returns.

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

In addition to federal income taxes, unitholders may be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. Unitholders may be required to file state, local and foreign income tax returns and pay state and local income taxes in some or all of the various jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. We own property and/or conduct business in Alabama, Arizona, Arkansas, California, Florida, Georgia, Illinois, Indiana, Kansas, Louisiana, Minnesota, Mississippi, Missouri, Nebraska, Nevada, New Mexico, Oklahoma, Pennsylvania, Tennessee, Texas, Utah, and West Virginia. We may do business or own property in other states or foreign countries in the future. It is the unitholder's responsibility to file all federal, state, local and foreign tax returns. Our counsel has not rendered an opinion on the state, local or foreign tax consequences of an investment in our common units.

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

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

The 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. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes that is not taxable as a corporation (referred to as the “Qualifying Income Exception”), 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. For example, the Obama administration's budget proposal for fiscal year 2016 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. Also, from time to time, members of Congress have considered substantive changes to the existing U.S. tax laws including the definition of qualifying income under Section 7704(d) of the Internal Revenue Code and the treatment of certain types of income earned from profits interests in partnerships. It is possible that these efforts could result in changes to the existing U.S. tax laws that affect publicly traded partnerships, including us. 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.

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


37


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

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. 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. The use of this proration method may not be permitted under existing Treasury regulations. The U.S. Department of the Treasury issued proposed Treasury regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed Treasury regulations do not specifically authorize the use of the proration method we have adopted. Therefore, the use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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

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

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Item 1B.
Unresolved Staff Comments

None. 

Item 2.
Properties
    
A description of our properties is contained in “Item 1.  Business” and is incorporated herein by reference. 

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

Item 3.
Legal Proceedings

From time to time, we are subject to certain legal proceedings, claims and disputes that arise in the ordinary course of our business. Although we cannot predict the outcomes of these legal proceedings, we do not believe these actions, in the aggregate, will have a material adverse impact on our financial position, results of operations or liquidity. A description of our legal proceedings is included in “Item 8. Financial Statements and Supplementary Data, Note 22. Commitments and Contingencies”, and is incorporated herein by reference.

Item 4.
Mine Safety Disclosures

Not applicable.


39


PART II

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

Our common units are traded on the NASDAQ under the symbol “MMLP.” As of March 2, 2015 there were approximately 292 holders of record and approximately 28,326 beneficial owners of our common units.  The following table sets forth the high and low sale prices of our common units for the periods indicated, based on the daily composite listing of stock transactions for NASDAQ during those periods:
 
 
Year Ended December 31, 2014
 
Year Ended December 31, 2013
 
 
 
High
 
Low
 
High
 
Low
 
First Quarter
 
$
44.36

 
$
40.28

 
$
38.52

 
$
31.93

 
Second Quarter
 
$
43.48

 
$
39.22

 
$
46.20

 
$
37.73

 
Third Quarter
 
$
41.64

 
$
35.75

 
$
47.02

 
$
42.28

 
Fourth Quarter
 
$
37.40

 
$
25.80

 
$
48.53

 
$
40.90

 

Cash Distributions

The following table sets forth the quarterly cash distribution declared and paid for our common units during the periods indicated:
Declared for Quarter Ending
 
Distribution Per Common Unit
 
Date Declared
 
Date Paid
December 31, 2014
 
$
0.8125

 
January 22, 2015
 
February 13, 2015
September 30, 2014
 
$
0.8125

 
October 23, 2014
 
November 14, 2014
June 30, 2014
 
$
0.7925

 
July 24, 2014
 
August 14, 2014
March 31, 2014
 
$
0.7875

 
April 23, 2014
 
May 15, 2014
December 31, 2013
 
$
0.7850

 
January 23, 2014
 
February 14, 2014
September 30, 2013
 
$
0.7825

 
October 24, 2013
 
November 14, 2013
June 30, 2013
 
$
0.7800

 
July 25, 2013
 
August 14, 2013
March 31, 2013
 
$
0.7750

 
April 25, 2013
 
May 15, 2013

Cash Distribution Policy
  
Within 45 days after the end of each quarter, we distribute all of our available cash, as defined in our partnership agreement, to unitholders of record on the applicable record date.  Our general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct our business.  These can include cash reserves for future capital and maintenance expenditures, reserves to stabilize distributions of cash to the unitholders and our general partner, reserves to reduce debt, or, as necessary, reserves to comply with the terms of any of our agreements or obligations.  Our distributions are effectively made 98% to unitholders and 2.0% to our general partner, subject to the payment of incentive distributions to our general partner if certain target cash distribution levels to common unitholders are achieved.  Distributions to our general partner increase to 15%, 25% and 50% based on incremental distribution thresholds as set forth in our partnership agreement. On October 2, 2012, our general partner executed Amendment No. 3 to the Second Amended and Restated Agreement of Limited Partnership of the Partnership (“the Partnership Agreement Amendment”). The Partnership Agreement Amendment provides that our general partner, currently the holder of the incentive distribution rights, shall forego the next $18.0 million in incentive distributions that it would otherwise be entitled to receive. Additionally, on May 5, 2014, the owner of our general partner agreed to forego an additional $3.0 million in incentive distributions. As of March 2, 2015, the amount of incentive distributions the general partner has foregone is $21.0 million, and incentive distributions were paid in conjunction with the fourth quarter 2014 cash distribution paid on February 13, 2015.
 
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

40


credit facility.  Please read “Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Description of Our Credit Facility.”

Item 6.
Selected Financial Data

The following table sets forth selected financial data and other operating data of the Partnership for the years ended December 31, 2014, 2013, 2012, 2011 and 2010 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.
 
2014
 
2013
 
2012
 
2011
 
2010
 
(Dollars in thousands, except per unit amounts)
 
 
 
 
 
 
Revenues
$
1,642,141

 
$
1,612,739

 
$
1,490,361

 
$
1,242,490

 
$
880,115

 
 
 
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
(6,367
)
 
$
(14,562
)
 
$
37,122

 
$
13,367

 
$
19,472

Income (loss) from discontinued operations, net of tax
(5,338
)
 
1,208

 
64,865

 
9,392

 
8,061

Net income (loss)
$
(11,705
)
 
$
(13,354
)
 
$
101,987

 
$
22,759

 
$
27,533

Net income (loss) attributable to limited partners
$
(15,176
)
 
$
(13,047
)
 
$
92,617

 
$
17,945

 
$
11,045

 
 
 
 
 
 
 
 
 
 
Net income (loss) per limited partner unit – continuing operations
$
(0.27
)
 
$
(0.54
)
 
$
1.32

 
$
0.57

 
$
0.25

Net income (loss) per limited partner unit – discontinued operations
(0.22
)
 
0.04

 
2.64

 
0.35

 
0.38

Net income (loss) per limited partner unit
$
(0.49
)
 
$
(0.50
)
 
$
3.96

 
$
0.92

 
$
0.63

 
 
 
 
 
 
 
 
 
 
Total assets
$
1,553,919

 
$
1,097,919

 
$
1,012,996

 
$
1,069,108

 
$
864,425

Long-term debt
$
902,005

 
$
658,695

 
$
474,992

 
$
458,941

 
$
372,862

 
 
 
 
 
 
 
 
 
 
Cash dividends per common unit (in dollars)
$
3.18

 
$
3.11

 
$
3.06

 
$
3.05

 
$
3.00




41



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

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

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

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

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

Marine transportation services for petroleum products and by-products.

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

We were formed in 2002 by Martin Resource Management, a privately-held company whose initial predecessor was incorporated in 1951 as a supplier of products and services to drilling rig contractors. Since then, Martin Resource Management has expanded its operations through acquisitions and internal expansion initiatives as its management identified and capitalized on the needs of producers and purchasers of petroleum products and by-products and other bulk liquids. Martin Resource Management is an important supplier and customer of ours. As of December 31, 2014, Martin Resource Management owned 17.7% of our total outstanding common limited partner units. Furthermore, Martin Resource Management controls Martin Midstream GP LLC (“MMGP”), our general partner, by virtue of its 51% voting interest in MMGP Holdings, LLC (“Holdings”), the sole member of MMGP. MMGP owns a 2.0% general partner interest in us and all of our incentive distribution rights. Martin Resource Management directs our business operations through its ownership interests in and control of our general partner.

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

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.

Recent Developments

We believe one of the rationales driving investment in master limited partnerships, including us, is the opportunity for distribution growth offered by the partnerships. Such distribution growth is a function of having access to liquidity in the financial markets used for incremental capital investment (development projects and acquisitions) to grow distributable cash flow.
 
We continually adjust our business strategy to focus on maximizing liquidity, maintaining a stable asset base which generates fee based revenues not sensitive to commodity prices, and improving profitability by increasing asset utilization and controlling costs. Over the past year, we have had access to the capital markets and have appropriate levels of liquidity and operating cash flows to adequately fund our growth.


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Recent Acquisitions
    
Cardinal Gas Storage. On August 29, 2014, Redbird Gas Storage LLC (“Redbird”), a wholly owned subsidiary of the Partnership, completed the previously announced purchase of all of the outstanding membership interests of Cardinal Gas Storage Partners LLC ("Cardinal") from Energy Capital Partners I, LP, Energy Capital Partners I-A, LP, Energy Capital Partners I-B IP, LP and Energy Capital Partners I (Cardinal IP), LP (together, “ECP”) for cash of approximately $121.0 million. Prior to the acquisition, we owned an approximate 42.2% interest in the Category A membership interests in Cardinal. As a result of the acquisition, Redbird owns 100% of the outstanding membership interests in Cardinal. Concurrent with the closing of the transaction, we retired all of the project level financing of various Cardinal subsidiaries. This transaction and repayment of the project financings was funded with borrowings under our revolving credit facility. On October 27, 2014, Cardinal merged with and into Redbird, and Redbird subsequently changed its name to Cardinal.

NGL Storage Assets. On May 31, 2014, we acquired certain natural gas liquids ("NGL") storage assets, located in Arcadia, Louisiana, from Martin Resource Management for $7.4 million. This transaction was funded with borrowings under our revolving credit facility.

West Texas LPG Pipeline Limited Partnership. On May 14, 2014, we acquired from a subsidiary of Atlas Pipeline Partners L.P. ("Atlas"), all of the outstanding membership interests in Atlas Pipeline NGL Holdings, LLC and Atlas Pipeline NGL Holdings II, LLC (collectively, "Atlas Holdings") for cash of approximately $133.9 million. Atlas Holdings owned a 19.8% limited partnership interest and a 0.2% general partnership interest in West Texas LPG Pipeline Limited Partnership ("WTLPG"). WTLPG is currently operated by ONEOK Partners, L.P. ("ONEOK"), which owns the remaining 80.0% interest. WTLPG owns an approximate 2,300 mile common-carrier pipeline system that transports NGLs from New Mexico and Texas to Mont Belvieu, Texas for fractionation. This transaction was funded with borrowings under our revolving credit facility.

Financing Activities

Public Offering. On September 29, 2014, we completed a public offering of 3,450,000 common units at a price of $36.91 per common unit, before the payment of underwriters' discounts, commissions and offering expenses (per unit value is in dollars, not thousands).  Total proceeds from the sale of the 3,450,000 common units, net of underwriters' discounts, commissions and offering expenses, were $122.2 million.  Our general partner contributed $2.6 million in cash to us in conjunction with the issuance in order to maintain its 2.0% general partner interest in us.  All of the net proceeds were used to reduce outstanding indebtedness under our revolving credit facility.

Private Placement of Common Units. On August 29, 2014, we closed a private equity sale with Martin Resource Management, under which Martin Resource Management invested $45.0 million in cash in exchange for 1,171,265 common units (per unit value is in dollars, not thousands). The pricing of $38.42 per common unit was based on the 10-day weighted average price of our common units for the 10 trading days ending August 8, 2014. In connection with the issuance of these common units, our general partner contributed $0.9 million in order to maintain its 2.0% general partner interest in us. All of the net proceeds were used to reduce outstanding indebtedness under our revolving credit facility.

Amendment to Revolving Credit Facility. On June 27, 2014, we increased the maximum amount of borrowings and letters of credit available under our revolving credit facility from $637.5 million to $900.0 million. In addition, we amended certain financial covenants that govern our credit facility.

Public Offering. On May 12, 2014, the Partnership completed a public offering of 3,600,000 common units at a price of $41.51 per common unit, before the payment of underwriters' discounts, commissions and offering expenses (per unit value is in dollars, not thousands).  Total proceeds from the sale of the 3,600,000 common units, net of underwriters' discounts, commissions and offering expenses, were $143.4 million.  Our general partner contributed $3.1 million in cash to us in conjunction with the issuance in order to maintain its 2.0% general partner interest in us.  All of the net proceeds were used to reduce outstanding indebtedness under our revolving credit facility.

Equity Distribution Program. In March 2014, we entered into an equity distribution agreement with multiple underwriters (the “Sales Agents”) for the ongoing distribution of our common units. Pursuant to this program, we offered and sold common unit equity through the Sales Agents for aggregate proceeds of $21.1 million for the year ended December 31, 2014. We paid $0.4 million in compensation to the Sales Agents for the year ended December 31, 2014. Under the the program, we issued 522,121 common units during the year ended December 31, 2014. Common units issued were at market prices prevailing at the time of the sale. We also received capital contributions from our general partner of $0.4 million during the year ended December 31, 2014 related to these issuances to maintain its 2.0% general partner interest in us. The net proceeds from the common unit issuances were used to pay down outstanding amounts under our revolving credit facility.

43



Issuance of 7.250% Senior Unsecured Notes Due 2021. On April 1, 2014, we completed a private placement add-on of $150.0 million of the 7.250% senior unsecured notes due 2021.  We filed with the SEC a registration statement on Form S-4 to exchange these notes for substantially identical notes that are registered under the Securities Act and commenced an exchange offer on April 28, 2014. The exchange offer was completed during the second quarter of 2014.

Redemption of 8.875% Senior Unsecured Notes Due 2018. On April 1, 2014, we redeemed all $175.0 million of the 8.875% senior unsecured notes due in 2018 from their holders.  In conjunction with the redemption, the Partnership incurred a debt prepayment premium of $7.8 million and a non-cash charge of $3.9 million for the write-off of unamortized debt issuance costs and unamortized debt discount related to the redemption of the senior unsecured notes.

For a more detailed discussion regarding our financing activities, see “Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

Subsequent Events

Disposition of Floating Storage Assets. On February 12, 2015, we sold six liquefied petroleum gas pressure barges, collectively referred to as the ("Floating Storage Assets") for $41.3 million. These assets were primarily operated under the floating storage component of our NGL distribution business. The proceeds from the disposition were used to reduce outstanding indebtedness under our revolving credit facility.        

Quarterly Distribution.  On January 22, 2015, we declared a quarterly cash distribution of $0.8125 per common unit for the fourth quarter of 2014, or $3.25 per common unit on an annualized basis, which was paid on February 13, 2015 to unitholders of record as of February 6, 2015. Additionally, we paid a distribution to our general partner in the amount of $4.4 million. Of this amount, $0.7 million is related to the base general partner distribution and $3.7 million represents incentive distribution rights paid to our general partner.

Common Unit Grants.   On January 5, 2015, we issued 84,750 restricted common units under our long-term incentive plan to the executive officers of our general partner and certain Martin Resource Management employees who provide services to us. These restricted units vest 100% on January 5, 2018.

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, 2014 and 2013:

Description
 
Judgments and Uncertainties
 
Effect if Actual Results Differ from Estimates and Assumptions
Allowance for Doubtful Accounts
We evaluate our allowance for doubtful accounts on an ongoing basis and record adjustments when, in management's judgment, circumstances warrant it. Reserves are recorded to reduce receivables to the amount ultimately expected to be collected.
 
We evaluate the collectability of our accounts receivable based on factors such as the customer's ability to pay, the age of the receivable and our historical collection experience. A deterioration in any of these factors could result in an increase in the allowance for doubtful accounts balance.
 
If actual collection results are not consistent with our judgments, we may experience an increase in uncollectible receivables. A 10% increase in our allowance for doubtful accounts would result in a decrease in net income of approximately $0.2 million.
Depreciation

44


Depreciation expense is computed using the straight-line method over the useful life of the assets.
 
Determination of depreciation expense requires judgment regarding estimated useful lives and salvage values of property, plant and equipment. As circumstances warrant, estimates are reviewed to determine if any changes in the underlying assumptions are needed.
 
The lives of our fixed assets range from 3 - 50 years. If the depreciable lives of our assets were decreased by 10%, we estimate that annual depreciation expense would increase approximately $7.2 million, resulting in a corresponding reduction in net income.
Impairment of Long-Lived Assets
We periodically evaluate whether the carrying value of long-lived assets has been impaired when circumstances indicate the carrying value of the assets may not be recoverable. These evaluations are based on undiscounted cash flow projections over the remaining useful life of the asset. The carrying value is not recoverable if it exceeds the sum of the undiscounted cash flows. Any impairment loss is measured as the excess of the asset's carrying value over its fair value.
 
Our impairment analyses require management to use judgment in estimating future cash flows and useful lives, as well as assessing the probability of different outcomes.
 
Applying this impairment review methodology, we recorded an impairment charge of $3.4 million in our Marine Transportation segment in 2014. No impairment was recorded in 2013.

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.
 
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.
 
We completed the most recent review of goodwill as of August 31, 2014 and determined there was no impairment. Additionally, management is aware of no change in circumstance which would indicate a need for an interim impairment evaluation.
Purchase Price Allocations
We allocate the purchase price of an acquired business to its identifiable assets (including identifiable intangible assets) and liabilities based on their fair values at the date of acquisition. Any excess of purchase price in excess of amounts allocated to identifiable assets and liabilities is recorded as goodwill. As additional information becomes available, we may adjust the preliminary allocation for a period of up to one year.
 
The determination of fair values of acquired assets and liabilities requires a significant level of management judgment. Fair values are estimated using various methods as deemed appropriate. For significant transactions, third party assessments may be utilized to assist in the valuation process.
 
If subsequent factors indicate that estimates and assumptions used to allocate costs to acquired assets and liabilities differ from actual results, the allocation between goodwill, other intangible assets and fixed assets could significantly differ. Any such differences could impact future earnings through depreciation and amortization expense. Additionally, if estimated results supporting the valuation of goodwill or other intangible assets are not achieved, impairments could result.
Asset Retirement Obligations
Asset retirement obligations (“AROs”) associated with a contractual or regulatory remediation requirement are recorded at fair value in the period in which the obligation can be reasonably estimated and depreciated over the life of the related asset or contractual term. The liability is determined using a credit-adjusted risk-free interest rate and is accreted over time until the obligation is settled.
 
Determining the fair value of AROs requires management judgment to evaluate required remediation activities, estimate the cost of those activities and determine the appropriate interest rate.
 
If actual results differ from judgments and assumptions used in valuing an ARO, we may experience significant changes in ARO balances. The establishment of an ARO has no initial impact on earnings.
Environmental Liabilities

45


We estimate environmental liabilities using both internal and external resources. Activities include feasibility studies and other evaluations management considers appropriate. Environmental liabilities are recorded in the period in which the obligation can be reasonably estimated.
 
Estimating environmental liabilities requires significant management judgment as well as possible use of third party specialists knowledgeable in such matters.
 
Environmental liabilities have not adversely affected our results of operations or financial condition in the past, and we do not anticipate that they will in the future.

Our Relationship with Martin Resource Management
 
Martin Resource Management directs our business operations through its ownership and control of our general partner and under the Omnibus Agreement. In addition to the direct expenses, under the Omnibus Agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. For the years ended December 31, 2014, 2013 and 2012, the conflicts committee of our general partner (“Conflicts Committee”) approved reimbursement amounts of $12.5 million, $10.6 million and $7.6 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.

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

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

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

How We Evaluate Our Operations

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

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

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

46


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, 2014, 2013, and 2012, 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,
 
2014
 
2013
 
2012
 
 
 
 
 
 
Net income (loss)
$
(11,705
)
 
$
(13,354
)
 
$
101,987

Less: (Income) loss from discontinued operations, net of income taxes
5,338

 
(1,208
)
 
(64,865
)
Income (loss) from continuing operations
(6,367
)
 
(14,562
)
 
37,122

Adjustments:
 
 
 
 
 
Interest expense
42,203

 
42,495

 
30,665

Income tax expense
1,137

 
753

 
3,557

Depreciation and amortization
68,830

 
50,962

 
42,063

EBITDA
105,803

 
79,648

 
113,407

Adjustments:
 
 
 
 
 
Equity in (income) loss of unconsolidated entities
(5,466
)
 
53,048

 
1,113

(Gain) loss on sale of property, plant and equipment
1,353

 
(217
)
 
795

Gain on sale of equity method investment

 
(750
)
 
(486
)
Gain on involuntary conversion of property, plant and equipment

 
(909
)
 

Impairment of long lived asset
3,445

 

 

Unrealized mark to market on commodity derivatives
818

 

 

Reduction in fair value of investment in Cardinal due to purchase of the controlling interest
30,102

 

 

Debt prepayment premium
7,767

 
272

 
2,470

Distributions from unconsolidated entities
4,323

 
3,476

 
3,961

Mont Belvieu indemnity escrow payment

 

 
(375
)
Unit-based compensation
817

 
911

 
385

Adjusted EBITDA
148,962

 
135,479

 
121,270

Adjustments:
 
 
 
 
 
Interest expense
(42,203
)
 
(42,495
)
 
(30,665
)
Income tax expense
(1,137
)
 
(753
)
 
(3,557
)
Amortization of deferred debt issuance costs
6,263

 
3,700

 
3,290

Amortization of debt discount
1,305

 
306

 
581

Amortization of debt premium
(245
)
 

 

Payments of installment notes payable and capital lease obligations

 
(307
)
 
(279
)
Deferred income taxes

 

 
402

Payments for plant turnaround costs
(3,974
)
 

 
(2,107
)
Maintenance capital expenditures
(14,556
)
 
(11,445
)
 
(8,658
)
Distributable Cash Flow
$
94,415

 
$
84,485

 
$
80,277


Results of Operations


47


The results of operations for the years ended December 31, 2014, 2013, and 2012 have been derived from our consolidated financial statements.

We evaluate segment performance on the basis of operating income, which is derived by subtracting cost of products sold, operating expenses, selling, general and administrative expenses, and depreciation and amortization expense from revenues.  The following table sets forth our operating revenues and operating income by segment for the years ended December 31, 2014, 2013, and 2012.  
 
Our consolidated results of operations are presented on a comparative basis below.  There are certain items of income and expense which we do not allocate on a segment basis.  These items, including equity in earnings (loss) of unconsolidated entities, interest expense, and indirect selling, general and administrative expenses, are discussed after the comparative discussion of our results within each segment.

The Natural Gas Services segment information below excludes the discontinued operations of the Floating Storage Assets disposed of on February 12, 2015 for the years ended December 31, 2014 and 2013 and the natural gas gathering and processing assets for the year ended December 31, 2012. See Item 8, Note 5.
 
Operating Revenues
 
Revenues
Intersegment Eliminations
 
Operating Revenues
 after Eliminations
 
Operating Income (loss)
 
Operating Income Intersegment Eliminations
 
Operating
Income (loss)
 after
Eliminations
 
(In thousands)
Year Ended December 31, 2014:
 

 
 

 
 

 
 

 
 

 
 

Terminalling and storage
$
326,654

 
$
(5,191
)
 
$
321,463

 
$
27,007

 
$
(2,014
)
 
$
24,993

Natural gas services
1,013,835

 

 
1,013,835

 
30,610

 
3,964

 
34,574

Sulfur services
215,471

 

 
215,471

 
25,656

 
(6,191
)
 
19,465

Marine transportation
97,049

 
(5,677
)
 
91,372

 
3,310

 
4,241

 
7,551

Indirect selling, general and administrative

 

 

 
(18,712
)
 

 
(18,712
)
Total
$
1,653,009

 
$
(10,868
)
 
$
1,642,141

 
$
67,871

 
$

 
$
67,871

 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2013:
 

 
 

 
 

 
 

 
 

 
 

Terminalling and storage
$
341,966

 
$
(4,756
)
 
$
337,210

 
$
35,282

 
$
(2,427
)
 
$
32,855

Natural gas services
966,909

 

 
966,909

 
28,003

 
2,521

 
30,524

Sulfur services
213,124

 

 
213,124

 
26,002

 
(4,491
)
 
21,511

Marine transportation
99,511

 
(4,015
)
 
95,496

 
9,014

 
4,397

 
13,411

Indirect selling, general and administrative

 

 

 
(16,837
)
 

 
(16,837
)
Total
$
1,621,510

 
$
(8,771
)
 
$
1,612,739

 
$
81,464

 
$

 
$
81,464

 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2012:
 

 
 

 
 

 
 

 
 

 
 

Terminalling and storage
$
322,175

 
$
(4,652
)
 
$
317,523

 
$
27,944

 
$
(2,541
)
 
$
25,403

Natural gas services
825,506

 

 
825,506

 
13,924

 
1,471

 
15,395

Sulfur services
261,584

 

 
261,584

 
37,262

 
4,647

 
41,909

Marine transportation
88,815

 
(3,067
)
 
85,748

 
6,751

 
(3,577
)
 
3,174

Indirect selling, general and administrative

 

 

 
(12,046
)
 

 
(12,046
)
Total
$
1,498,080

 
$
(7,719
)
 
$
1,490,361

 
$
73,835

 
$

 
$
73,835



48


Terminalling and Storage Segment

Comparative Results of Operations for the Twelve Months Ended December 31, 2014 and 2013
 
Year Ended December 31,
 
Variance
 
Percent Change
 
2014
 
2013
 
 
 
(In thousands)
 
 
Revenues:
 
 
 
 
 
 
 
Services
$
135,697

 
$
120,717

 
$
14,980

 
12%
Products
190,957

 
221,249

 
(30,292
)
 
(14)%
Total revenues
326,654

 
341,966

 
(15,312
)
 
(4)%
 
 
 
 
 
 
 
 
Cost of products sold
175,246

 
197,974

 
(22,728
)
 
(11)%
Operating expenses
83,504

 
74,441

 
9,063

 
12%
Selling, general and administrative expenses
3,565

 
3,238

 
327

 
10%
Depreciation and amortization
37,622

 
31,823

 
5,799

 
18%
 
26,717

 
34,490

 
(7,773
)
 
(23)%
Other operating income
290

 
792

 
(502
)
 
63%
Operating income
$
27,007

 
$
35,282

 
$
(8,275
)
 
(23)%
 
 
 
 
 
 
 
 
Lubricant sales volumes (gallons)
32,418

 
39,342

 
(6,924
)
 
(18)%
Shore-based throughput volumes (gallons)
253,262

 
270,522

 
(17,260
)
 
(6)%
Smackover refinery throughput volumes (barrels per day)
6,159

 
6,912

 
(753
)
 
(11)%
Corpus Christi crude terminal throughput volumes (barrels per day)
164,223

 
108,652

 
55,571

 
51%

Services revenues. Services revenue increased $7.7 million attributable to increased throughput volumes at our crude terminal in Corpus Christi, Texas. In addition, $4.7 million of the increase is due to revenues generated by our Smackover refinery related to increased tolling fees resulting from a new contract effective July 1, 2013. Our new Dunphy terminal in Elko, Nevada, which was placed in service in May 2014, also contributed to $1.2 million of the increase.

Products revenues. A 23% decrease in sales volumes at our blending and packaging facilities resulted in a $36.6 million reduction in product revenues. Product sales volumes from our shore-based terminals decreased 3%, resulting in a $2.2 million reduction in product revenues. The average sales price at our blending and packaging facilities increased 7%, resulting in a $10.2 million increase in product revenues. The average sales price at our shore-based terminals decreased 2%, resulting in a $1.7 million decrease in product revenues.
   
Cost of products sold.  A 23% decrease in sales volumes at our blending and packaging facilities resulted in a $33.2 million decrease in cost of products sold. Product sales volumes from our shore-based terminals decreased 3%, resulting in a
$2.0 million decrease in cost of products sold. Increased average cost at our blending and packaging facilities of 10% resulted in an increase of $13.6 million in cost of products sold. Decreased average cost at our shore-based terminals of 2% resulted in a decrease of $1.1 million in cost of products sold.

Operating expenses. Increased expenses at our specialty terminals accounted for $6.2 million of the total increase, primarily attributable to the Corpus Christi crude terminal. Our shore-based terminal expenses increased $0.4 million primarily due to repair and maintenance cost at the terminals. In addition, $2.5 million of the increase is attributable to the Smackover refining assets, primarily as a result of increased compensation expense.

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

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


49


Other operating income.  Other operating income consists primarily of business interruption recoveries in 2014 and a gain on an involuntary conversion of property, plant and equipment in 2013.

Comparative Results of Operations for the Twelve Months Ended December 31, 2013 and 2012
 
Year Ended December 31,
 
Variance
 
Percent Change
 
2013
 
2012
 
 
 
(In thousands)
 
 
Revenues:
 
 
 
 
 
 
 
Services
$
120,717

 
$
94,895

 
$
25,822

 
27%
Products
221,249

 
227,280

 
(6,031
)
 
(3)%
Total revenues
341,966

 
322,175

 
19,791

 
6%
 
 
 
 
 
 
 
 
Cost of products sold
197,974

 
207,699

 
(9,725
)
 
(5)%
Operating expenses
74,441

 
58,766

 
15,675

 
27%
Selling, general and administrative expenses
3,238

 
4,671

 
(1,433
)
 
(31)%
Depreciation and amortization
31,823

 
22,976

 
8,847

 
39%
 
34,490

 
28,063

 
6,427

 
23%
Other operating income (loss)
792

 
(119
)
 
911

 
766%
Operating income
$
35,282

 
$
27,944

 
$
7,338

 
26%
 
 
 
 
 
 
 
 
Lubricant sales volumes (gallons)
39,342

 
38,107

 
1,235

 
3%
Shore-based throughput volumes (gallons)
270,522

 
218,494

 
52,028

 
24%
Smackover refinery throughput volumes (barrels per day)
6,912

 
5,994

 
918

 
15%
Corpus Christi crude terminal (barrels per day)
108,652

 
55,529

 
53,123

 
96%

Services revenues. Services revenue increased primarily due to $17.7 million attributable to our new crude terminal in Corpus Christi, Texas, which was placed into service in May 2012. In addition, $5.2 million of the increase is due to revenues generated by our Talen's acquisition on December 31, 2012. The remaining increase is primarily due to increased throughput at the Smackover refinery.

Products revenues. An 8% increase in sales volumes at our blending and packaging facilities resulted in a $10.7 million positive impact on product revenues. Product sales volumes from our shore-based terminals decreased 7%, resulting in a $5.6 million reduction in product revenues. The average sales price at our blending and packaging facilities decreased 5%, resulting in a $7.8 million decrease in product revenues. The average sales price at our shore-based terminals decreased 4%, resulting in a $3.3 million decrease in product revenues.
   
Cost of products sold.  An 8% increase in sales volumes at our blending and packaging facilities resulted in a $9.4 million increase in cost of products sold, which was partially offset by a 7% decrease in sales volumes at our shore-based terminals, resulting in a $5.2 million decrease in cost of products sold. Decreased average cost at our blending and packaging facilities of 8% resulted in a decrease of $10.0 million in cost of products sold. Decreased average cost at our shore-based terminals of 5% resulted in a decrease of $3.9 million in cost of products sold.

Operating expenses. Increased expenses at our specialty terminals accounted for $6.9 million of the total increase, primarily attributable to the Corpus Christi crude terminal. Our shore-based terminal expenses increased $1.7 million primarily due to the acquisition of the Talen's terminals. In addition, $7.1 million of the increase is attributable to the Smackover refining assets, primarily as a result of increased utilities and repair and maintenance expense.

Selling, general and administrative expenses.  The decrease in selling, general and administrative expenses is primarily related to decreased advertising expense in our blending and packaging operations.

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


50


Other operating income (loss).  Other operating income in 2013 is primarily attributable to a gain on an involuntary conversion of property, plant and equipment.

Natural Gas Services Segment

Comparative Results of Operations for the Twelve Months Ended December 31, 2014 and 2013
 
Year Ended December 31,
 
Variance
 
Percent Change
 
2014
 
2013
 
 
 
(In thousands)
 
 
Revenues:
 
 
 
 
 
 
 
Services
$
22,991

 
$

 
$
22,991

 
 
Products
990,844

 
966,909

 
23,935

 
2%
Total revenues
1,013,835

 
966,909

 
46,926

 
5%
 
 
 
 
 
 
 
 
Cost of products sold
950,742

 
930,315

 
20,427

 
2%
Operating expenses
10,797

 
3,918

 
6,879

 
176%
Selling, general and administrative expenses
8,596

 
3,731

 
4,865

 
130%
Depreciation and amortization
13,090

 
962