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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K
 
Mark One
     
þ   Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2008
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:
NONE
Securities Registered Pursuant to Section 12(g) of the Act:
     
Title of each class   Name of each exchange on which registered
     
Common Units representing limited
partnership interests
  NASDAQ
          Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes o      No þ
          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 þ
          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 þ      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. o
     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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
             
Large accelerated filer o   Accelerated filer þ   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 þ
     As of June 30, 2008, 12,837,480 common units were outstanding. The aggregate market value of the common units held by non-affiliates of the registrant as of such date approximated $306,811,495. There were 13,688,152 of the registrant’s common units and 850,674 of the registrant’s subordinated units outstanding as of March 4, 2009.
DOCUMENTS INCORPORATED BY REFERENCE:      None.
 
 

 


 

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Table of Contents

PART I
Item 1. Business
Overview
          We are a publicly traded limited partnership with a diverse set of operations focused primarily in the United States Gulf Coast region. Our four primary business lines include:
    Terminalling and storage services for petroleum products and by-products;
 
    Natural gas services;
 
    Marine transportation services for petroleum products and by-products; and
 
    Sulfur and sulfur-based products processing, manufacturing, marketing and distribution.
          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 Gulf Coast region of the United States. 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 Corporation (“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 hydrocarbon products and by-products and other bulk liquids. Martin Resource Management owns an approximate 34.9% limited partnership interest in us. Furthermore, it owns and controls our general partner, which owns a 2.0% general partner interest and incentive distribution rights in us.
          Martin Resource Management operated our business segments for several years. 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 terminalling and storage businesses in the early 1990s. In recent years, Martin Resource Management has increased the size of our asset base through expansions and strategic acquisitions.
Primary Business Segments
Our primary business segments can be generally described as follows:
    Terminalling and Storage. We own or operate 17 marine terminal facilities and six inland terminal facilities located in the United States Gulf Coast region that provide storage and handling services for producers and suppliers of petroleum products and by-products, lubricants and other liquids. We also provide land rental to oil and gas companies along with storage and handling services for lubricants and fuel oil. We provide these terminalling and storage services on a fee basis primarily under long-term contracts.
 
    Natural Gas Services. Through our acquisitions of Prism Gas Systems I, L.P. (“Prism Gas”) and Woodlawn Pipeline Co., Inc. (“Woodlawn”), we have ownership interests in over 669 miles of gathering and transmission pipelines located in the natural gas producing regions of Central and East Texas, Northwest Louisiana, the Texas Gulf Coast and offshore Texas and federal waters in the Gulf of Mexico as well as a 265 MMcfd capacity natural gas processing plant located in East Texas. In addition to our natural gas gathering and processing business, we distribute natural gas liquids (“NGLs”). We purchase NGLs primarily from natural gas processors. We store NGLs in our supply and storage facilities for resale to propane retailers, refineries and industrial NGL users in Texas and the Southeastern United States. We own an NGL pipeline which spans approximately 200 miles running from Kilgore to Beaumont, Texas. We own three NGL supply and storage facilities with an aggregate above ground storage capacity of approximately 3,000 barrels and we lease approximately 2.2 million barrels of underground storage capacity for NGLs.

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    Marine Transportation. We own a fleet of 40 inland marine tank barges, 17 inland push boats and four offshore tug barge units that transport petroleum products and by-products primarily in the United States Gulf Coast region. We provide these transportation services on a fee basis primarily under annual contracts. In addition, our marine segment manages our sulfur segment’s marine assets.
 
    Sulfur Services. We process and distribute sulfur predominately produced by oil refineries primarily located in the United States Gulf Coast region. We own one offshore tug barge unit and two inland barges and an inland tug that transports sulfur primarily in the United States Gulf Coast region. We process molten sulfur into prilled, or pelletized, sulfur under both fee-based volume contracts and buy/sell contracts at our facilities in Port of Stockton, California and Beaumont, Texas. We own and operate six sulfur-based fertilizer production plants and one emulsified sulfur blending plant that manufacture primarily sulfur-based fertilizer products for wholesale distributors and industrial users. These plants are located in Illinois, Texas and Utah. In October 2007, we completed the construction of a sulfuric acid production plant in Plainview, Texas which processes molten sulfur into sulfuric acid.
          2008 Developments and Subsequent Events
          Recent Acquisitions
          Acquisition of Martin Resource Management Stanolind Assets. In January 2008, we acquired 7.8 acres of land, a deep water dock and two sulfuric acid tanks at our Stanolind terminal in Beaumont, from Martin Resource Management. In connection with this acquisition, we entered into a lease agreement with Martin Resource Management for use of the sulfuric acid tanks.
          Other Developments
          Quarterly Distribution. We declared a quarterly cash distribution for the fourth quarter of 2008 of $0.75 per common and subordinated unit on January 27, 2009, reflecting no change over the quarterly distribution paid in respect of the third quarter of 2008.
          Conversion of Subordinated Units. On November 14, 2008, 850,672 of our 1,701,346 outstanding subordinated units owned by Martin Resource Management through a subsidiary converted into common units on a one-for-one basis following our quarterly cash distribution on such date. Additional conversions of our outstanding subordinated units may occur in the future provided that certain distribution thresholds contained in our partnership agreement are met by us.
Business Strategy
The key components of our business strategy are to:
    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, increase the distributable cash flow from our existing assets through improved utilization and efficiency, and leverage our existing customer base.
 
    Pursue Internal Organic Growth by Attracting New Customers and Expanding Services Provided to Existing Customers. We seek to identify and pursue opportunities to expand our customer base across all of our business segments. We generally begin a relationship with a customer by transporting or marketing a limited range of products and services. We believe expanding our customer base and our service and product offerings to existing customers is the most efficient and cost effective method of achieving organic growth in revenues and cash flow. We believe significant opportunities exist to expand our customer base and provide additional services and products to existing customers.
    Pursue Strategic Acquisitions. We 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 will 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.

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      We believe that our diversified base of operations provides multiple platforms for strategic growth through acquisitions. While we continue to monitor the marketplace for potential acquisitions, we anticipate that our activities in this area will be limited in 2009 due to general economic conditions and capital constraints.
 
    Pursue Strategic Alliances. Many of our larger customers are establishing strategic alliances with midstream service providers such as us to address logistical and transportation problems or achieve operational synergies. These strategic alliances are typically structured differently than our regular commercial relationships, with the goal that such alliances would expand our business relationships with our customers and suppliers. We intend to pursue strategic alliances with customers in the future.
 
    Expand Geographically. We work to identify and assess other attractive geographic markets for our services and products based on the market dynamics and the cost associated with penetration of such markets. We typically enter a new market through an acquisition or by securing at least one major customer or supplier and then dedicating or purchasing assets for operation in the new market. Once in a new territory, we seek to expand our operations within this new territory both by targeting new customers and by selling additional services and products to our original customers in the territory.
Competitive Strengths
          We believe we are well positioned to execute our business strategy because of the following competitive strengths:
    Asset Base and Integrated Distribution Network. We operate a diversified asset base that, together with the services provided by Martin Resource Management, enables us to offer our customers an integrated distribution network consisting of transportation, terminalling 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 a complementary portfolio of transportation, terminalling, distribution and other midstream services for petroleum products and by-products.
 
    Strategically Located Assets. We believe we are one of the largest providers of shore bases and one of the largest lubricant distributors and marketers in the United States Gulf Coast region. In addition, we are one of the largest operators of marine service terminals in the United States Gulf Coast region providing broad geographic coverage and distribution capability of our products and services to our customers. Our natural gas gathering and processing assets are focused in areas that have continued to experience high levels of drilling activity and natural gas production.
 
    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, such as molten sulfur and asphalt. For example, we own facilities and resources to transport molten sulfur and asphalt, which must be maintained at temperatures between approximately 275 and 350 degrees Fahrenheit to remain in liquid form. We believe these capabilities help us enhance relationships with our customers by offering them services to handle their unique product requirements.
 
    Ability to Grow Our Natural Gas Gathering and Processing Services. We believe that, with our Prism Gas assets, we have opportunities for organic growth in our natural gas gathering and processing operations through increasing fractionation capacity, pipeline expansions, new pipeline construction and bolt-on acquisitions. We believe Prism’s assets are well situated in the Haynesville Shale which is one of the four largest U.S. shale deposits. Chesapeake Energy, the largest lease holder in the Haynesville Shale, estimates that the Haynesville Shale will ultimately produce over 500 TCF of natural gas and that this field will be among the top 10 natural gas fields in the world. As the development of the Haynesville Shale is in its early stages, it is too early to estimate the ultimate impact on Prism.
 
    Experienced Management Team and Operational Expertise. Members of our executive management team and the heads of our principal business lines have, on average, more than 29 years of experience in the industries in which we operate. Further, these individuals have been employed by Martin Resource Management, on average, for more than 17 years. Our management team has a successful track record of creating internal growth and completing acquisitions. We believe our management team’s experience and familiarity with our industry and businesses are important assets that assist us in implementing our business strategies.

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    Strong Industry Reputation and Established Relationships with Suppliers and Customers. We believe 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 believe we benefit from our management’s reputation and track record, and from these long-term relationships.
Terminalling and Storage Segment
          Industry Overview. The United States petroleum distribution system moves petroleum products and by-products from oil refinery and natural gas processing facilities to end users. This distribution system is comprised of a network of terminals, storage facilities, pipelines, tankers, barges, rail cars and trucks. Terminals play a key role in moving these products throughout the distribution system by providing storage, blending and other ancillary services.
          In the 1990s, the petroleum industry entered a period of consolidation. Refiners and marketers developed large-scale, cost-efficient operations resulting in several refinery acquisitions, combinations, alliances and joint ventures. This consolidation resulted in major oil companies integrating the various components of their businesses, including terminalling and storage. However, major integrated oil companies later concentrated their focus and resources on their core competencies of exploration, production, refining and retail marketing and examined ways to lower their distribution costs. Additionally, the Federal Trade Commission required some divestitures of terminal assets in markets in which merged companies, alliances and joint ventures were regarded as having excessive market power. As a result of these factors, oil and gas companies began to increasingly rely on third parties such as us to perform many terminalling and storage 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 two-thirds of United States refining capacity expansion in the 1990s occurred 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.
          Marine Terminals. We own or operate 17 marine terminals along the Gulf Coast from Tampa, Florida to Corpus Christi, Texas. Our terminal assets are located at strategic distribution points for the products we handle and are in close proximity to our customers. Further, the location and composition of our terminals are structured to complement our other businesses and reflect our strategy to provide a broad range of integrated services in the handling and transportation of petroleum products and by-products. We developed our terminalling and storage assets by acquiring existing terminalling and storage facilities and then customizing and upgrading these facilities as needed to integrate the facilities into our petroleum product and by-product transportation network and to more effectively service customers. We expect to continue to acquire facilities, streamline their operations and customize and upgrade them as part of our growth strategy. We also continually evaluate opportunities to add services and increase access to our terminals to attract more customers and create additional revenues.
          We are one of the largest operators of marine service terminals in the Gulf Coast region. These terminals are used to distribute and market lubricants and the 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.

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Shore bases typically provide logistical support including the storing and handling of tubular goods, loading and unloading bulk materials, providing facilities from which major and independent oil companies can communicate with and control offshore operations and leasing dockside facilities to companies which provide complementary products and services such as drilling fluids and cementing services. We generate revenues from our terminals that have shore bases by fees that we charge our customers under land rental contracts for the use of our terminal facility for these shore bases. These contracts generally provide us a fixed land rental fee and additional rental fees that are determined based on a percentage of the sales value of the products and services delivered from the shore base. We also generate revenues through the distribution and marketing of lubricants. Lubricants are used in the operation of offshore drilling rigs, offshore production and transmission platforms, and various ships and equipment engaged in marine transportation. In addition, Martin Resource Management, through contractual arrangements, pays us for terminalling and storage of fuel oil at these terminal facilities.
          Our 17 marine terminals are divided generally into three classes of terminals: (i) full service terminals, (ii) fuel and lubricant terminals and (iii) specialty petroleum terminals.
          Full Service Terminals. We own or operate eight full service terminals. These terminal facilities provide logistical support services, distribute and market lubricants and provide storage and handling services for fuel oil. 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 are primarily oil and gas exploration and production companies, and oilfield service companies such as drilling fluids companies, marine transportation companies, and offshore construction companies.
          The following is a summary description of our eight full service terminals:
                         
Terminal   Location   Acres   Tanks   Aggregate Capacity
Pelican Island
  Galveston, Texas     51.3       16     87,200 Bbls.
Harbor Island(1)
  Harbor Island, Texas     25.5       12     32,500 Bbls.
Freeport
  Freeport, Texas     17.8       1     8,300 Bbls.
Port O’Connor(2)
  Port O’Connor, Texas     22.8       8     7,000 Bbls.
Sabine Pass(3)
  Sabine Pass, Texas     23.1       11     17,000 Bbls.
Cameron “East”(4)
  Cameron, Louisiana     34.3       12     34,000 Bbls.
Cameron “West”(5)
  Cameron, Louisiana     16.9       5     16,500 Bbls.
Venice (6)
  Venice, Louisiana     2.8       2     15,000 Bbls.
 
(1)   A portion of this terminal is located on land owned by a third party and leased under a lease that expires in January 2010 and can be extended by us through January 2015.
 
(2)   This terminal is located on land owned by a third party and leased under a lease that expires in March 2014.
 
(3)   A portion of this terminal is located on land owned by a third party and leased under a lease that expires in September 2036.
 
(4)   This terminal is located on land owned by third parties and leased under a lease that expires in March 2012 and can be extended by us through March 2022.
 
(5)   This terminal is located on land owned by a third party and leased under a lease that expires in February 2013.
 
(6)   This terminal is located on land owned by a third party and leased under a sublease agreement that expires in August 2009 and can be extended by us through August 2024.
          Fuel and Lubricant Terminals. We own or operate four lubricant and fuel oil terminals located in the Gulf Coast region that provide storage and handling service for lubricants and fuel oil. We also distribute and market lubricants at these terminals.
          The following is a summary description of our fuel and lubricant terminals:
                 
Terminal   Location   Tanks   Aggregate Capacity
Amelia
  Amelia, Louisiana     17     14,900 Bbls.
Berwick(1)
  Berwick, Louisiana     2     25,000 Bbls.
Intracoastal City(2)(3)
  Intracoastal City, Louisiana     16     39,000 Bbls.
Fourchon(4)
  Fourchon, Louisiana     11     80,000 Bbls.

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(1)   This terminal is located on land owned by third parties and leased under a lease that expires in September 2012 and can be extended by us through September 2017.
 
(2)   A portion of this terminal is located on land owned by a third party at which we throughput fuel oil pursuant to an agreement that expires in January 2010.
 
(3)   A portion of this terminal is located on land owned by third parties and leased under a lease that expires in April 2014.
 
(4)   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 January 2017.
          Specialty Petroleum Terminals. We own or operate five terminal facilities providing storage and handling services for some or all of the following: anhydrous ammonia, asphalt, sulfur, sulfuric acid, fuel oil, crude oil and other petroleum products and by-products. Our specialty terminals have an aggregate storage capacity of approximately 1.90 million barrels. Each of these terminals has storage capacity for petroleum products and by-products and has assets to handle products transported by vessel, barge and truck. Our 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 with two five year options. Our Stanolind terminal is located on approximately 11 acres of land owned by us located on the Neches River in Beaumont. Our Neches terminal is a deep water marine terminal located near Beaumont, Texas on approximately 50 acres of land owned by us. Our Ouachita County terminal is located on approximately six acres of land owned by us on the Ouachita River in southern Arkansas. Our Corpus Christi 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.
          At our Tampa, Neches, Stanolind and Corpus Christi terminals, our customers are primarily large oil refining and natural gas processing 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. At our Ouachita County terminal, Cross Oil Refining & Marketing, Inc., a related party owned by Martin Resource Management, operates the terminal under a long-term terminalling agreement whereby we receive a throughput fee. We also continually evaluate opportunities to add services and increase access to our terminals to attract more customers and create additional revenues. The following is a summary description of our specialty marine terminals:
                         
                Aggregate        
Terminal   Location   Tanks   Capacity   Products   Description
Tampa(1)
  Tampa, Florida     8     779,000 Bbls.   Asphalt, sulfur and fuel oil   Marine terminal, loading/unloading for vessels, barges and trucks
Stanolind
  Beaumont, Texas     8     555,000 Bbls.   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     7     500,400 Bbls.   Ammonia, asphalt, fuel oil, crude oil and sulfur-based fertilizer   Marine terminal, loading/unloading for vessels, barges, railcars and trucks
Ouachita County
  Ouachita County,
Arkansas
    2     77,500 Bbls.   Crude oil   Marine terminal, loading/unloading for barges and trucks
Corpus Christi
  Corpus Christi,
Texas
    4     330,000 Bbls.   Fuel oil and diesel   Marine Terminal, loading/unloading barges and vessels and unloading trucks
 
(1)   This terminal is located on land owned by the Tampa Port Authority that was leased to us under a 10-year lease that expires in December 2016 with two five year extension options.

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          Inland Terminals. We own or operate six inland terminals.
          At Mont Belvieu, Texas, we own a rail unloading terminal where we unload and measure NGLs and transport these products via a half-mile pipeline to Enterprise Products Texas Operating L.P.’s NGL fractionator facility. Our fees for the use of this facility are based on the number of gallons unloaded at the terminal.
          In Beaumont, Texas we own Spindletop Terminal where we receive natural gasoline via pipeline and then ship the product to our customers via other pipelines to which the facility is connected. Our fees for the use of this facility are based on the number of barrels shipped from the terminal.
          In Channelview, Texas, we operate an inland terminal used for lubricant storage, packaging and distribution. This terminal is used as our central hub for lubricant distribution where we receive, package, and ship our lubricants to our terminals or directly to customers.
          In 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.
          The following is a summary description our inland terminals:
                 
Terminal   Location   Aggregate Capacity   Products   Description
Channelview
  Houston, Texas   34,000 sq. ft. Warehouse/29,000 Bbls   Lubricants   Lubricants blending and truck loading/unloading
Mont Belvieu
  Mont Belvieu, Texas   20 rail car spaces   Propane-propylene mix   Rail car unloading
South Houston
Asphalt
  Houston, Texas   71,000 Bbls   Asphalt   Asphalt Processing and storage
Port Neches Asphalt
  Port Neches, Texas   31,250 Bbls   Asphalt   Asphalt Processing and storage
Omaha Asphalt
  Omaha, Nebraska   114,225 Bbls   Asphalt   Asphalt Processing and storage
Spindletop
  Beaumont, Texas   90,000 Bbls   Natural Gasoline   Pipeline receipts and shipments
          Competition. We compete with independent terminal operators and major energy and chemical companies that own their own terminalling and storage facilities. We believe 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 believe 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.

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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 sulfuric acid. As a result, our facilities typically command higher terminal fees when compared to fees charged for terminalling and storage of other petroleum products.
          The principal competitive factors affecting our terminals which provide lubricant 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 lubricant supply sources.
Natural Gas Services Segment
          NGL Industry Overview. NGLs are produced through natural gas processing. They are also a by-product of crude oil refining. NGL consists of hydrocarbons that are vapors at atmospheric temperatures and pressures but change to liquid phase under pressure. NGLs include ethane, propane, normal butane, iso butane and natural gasoline.
          Ethane is almost entirely used as a petrochemical feedstock in the production of ethylene and propylene. Propane is used as a petrochemical feedstock in the production of ethylene and propylene, as a fuel for heating, for industrial applications, as motor fuel and as a refrigerant. Normal butane is used as a petrochemical feedstock, as a blend stock for motor gasoline and as a component in aerosol propellants. Normal butane can also be made into iso butane through isomerization. Iso butane is used in the production of motor gasoline, petrochemical feedstock and as a component in aerosol propellants. Natural gasoline is used as a component of motor gasoline and as a petrochemical feedstock.
          NGL Facilities. We purchase NGLs primarily from natural gas processors and, to a lesser extent, major domestic oil refiners. 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. We believe 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.
          The following is a summary description of our owned and leased NGL facilities:
             
NGL Facility   Location   Capacity   Description
Wholesale terminals
  Arcadia, Louisiana(1)   2,000,000 barrels   Underground storage
 
  Hattiesburg, Mississippi(2)   100,000 barrels   Underground storage
 
  Mt. Belvieu, Texas(3)(2)   40,000 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 Arcadia, Louisiana from Martin Resource Management under a three-year product storage agreement, which is renewable on a yearly basis thereafter subject to a re-determination of the lease rate for each subsequent year.
 
(2)   We lease our underground storage at Hattiesburg, Mississippi and Mont Belvieu, Texas from third parties under one-year lease agreements, which have been renewed annually for more than 20 years.
 
(3)   In addition, under a throughput agreement, we are entitled to the sole access to and use of a truck loading and unloading and pipeline distribution terminal owned by Martin Resource Management and located at Mont Belvieu, Texas. 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 30 days prior to the expiration of the then-applicable term. This terminal facility has a storage capacity of 8,000 barrels.

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          Our NGL customers that utilize these assets consist of retail propane distributors, industrial processors and refiners. For the year ended December 31, 2008, we sold approximately 34% of our NGL volume to independent retail propane distributors located in Texas and the southeastern United States and approximately 66% of our NGL volume to refiners and industrial processors.
          NGL Competition. We compete with large integrated NGL producers and marketers, as well as small local independent marketers. NGLs compete primarily with natural gas, electricity and fuel oil as an energy source, principally on the basis of price, availability and portability.
          NGL 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 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 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.
          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.
          Prism Gas. Prism Gas is operated and reported as part of our natural gas services business segment, which has been expanded to include natural gas gathering and processing as well as the NGL services business described herein.
          Prism Gas has ownership interests in over 669 miles of gathering pipelines located in the natural gas producing regions of North Central Texas and East Texas, Northwest Louisiana, the Texas Gulf Coast and offshore Texas and federal waters in the Gulf of Mexico as well as a 265 MMcfd natural gas processing plant located in East Texas. The underlying assets are in two operating areas:
          North Central Texas and East Texas
The North Central Texas and East Texas area assets consist of the Waskom Processing Plant, Woodlawn Pipeline Co., the McLeod Gathering System, the Hallsville Gathering System, the Marshall Line, Bosque County Pipeline (“BCP”), the East Texas Gathering System and the Prism Liquids Pipeline.
    Waskom Processing Plant — The Waskom Processing Plant, located in Harrison County in East Texas, currently has 265 MMcfd of processing capacity with full fractionation facilities. Expansions to the processing plant were completed in March and June of 2007, and July of 2008 increasing the capacity from 150 MMcfd to 265 MMcfd. In January 2007, the Waskom fractionator was expanded to a capacity of 12,500 barrels per day (“bpd”). In addition, an increase in the processing capacity of the plant to 285 MMcfd and fractionation capacity to 14,500 bpd is expected to be completed by the end of the second quarter of 2009. For the years ended December 31, 2008 and 2007, inlet throughput and NGL fractionation averaged approximately 257 and 229 MMcfd and 10,542 and 8,725 bpd, respectively. Prism Gas owns an unconsolidated 50% operating interest in the Waskom Processing Plant with CenterPoint Energy Gas Processing, Inc. owning the remaining 50% non-operating interest. We reflect the results of operations from this facility using the equity method of accounting
 
    Woodlawn Plant and Gathering System — On May 2, 2007, we, through our subsidiary Prism Gas acquired 100% of the outstanding stock of Woodlawn. The results of Woodlawn’s operations have been included in our consolidated financial statements beginning May 2, 2007. Woodlawn is a natural gas gathering and processing company which owns integrated gathering and processing assets in East Texas. Woodlawn’s system consists of approximately 135 miles of natural gas gathering pipe, approximately 36 miles of condensate transport pipe and a 30 MMcfd processing plant. Prism Gas acquired a nine-mile pipeline, from a Woodlawn related party, that delivers residue gas from the Woodlawn plant to the Texas Eastern Transmission pipeline system.

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    McLeod Gathering System — The McLeod Gathering System, located in East Texas and Northwest Louisiana, is a low pressure gathering system connected to the Waskom Processing Plant, providing processing and blending services for natural gas with high nitrogen and high liquids content gathered by the system. For both years ended December 31, 2008 and 2007, the McLeod Gathering System gathered approximately 5 MMcfd of natural gas. Prism Gas owns a consolidated 100% interest in this system.
 
    Hallsville Gathering System — The Hallsville Gathering System, which Prism Gas constructed in 2006 in Harrison County, Texas, provides gathering and centralized compression for producers in the Oak Hill Field of East Texas. The system operates at low pressure and redelivers gas to two interstate and three intrastate markets via the Oakhill Gathering System. For the years ended December 31, 2008 and 2007, the Hallsville Gathering System gathered approximately 21 and 17 MMcfd of natural gas, respectively. Prism Gas owns a consolidated 100% interest in this system.
 
    The Marshall Line — The Marshall Line is a 10” gathering line that Prism Gas began leasing from Kinder Morgan Texas in 2006. It is located in Harrison County, Texas. The Marshall Line gathers gas at intermediate pressure and feeds the Waskom Processing Plant. Prism Gas owns a consolidated 100% interest in the lease.
 
    Bosque County Pipeline — The Bosque County Pipeline, gathers gas in four North Central Texas counties centered around Bosque County. Prism Gas owns an unconsolidated 20% non-operating interest in a partnership that owns the lease rights to the assets of the Bosque County Pipeline, with Panther Pipeline Ltd. owning a 42.5% operating interest and two unrelated parties owning the remaining 37.5% interest. The lease contract provides for termination in June 2009 and an extension of the lease is not currently contemplated.
 
    East Texas Gathering System — The East Texas Gathering System, located in Panola County, Texas, is comprised of gathering systems built to gather gas produced in this area to market outlets. Prism Gas owns a consolidated 100% interest in these systems.
          The natural gas supply for the Waskom Processing Plant, the Woodlawn Plant and Gathering System, the McLeod Gathering System, the Hallsville Gathering System, the Marshall Line and the East Texas Gathering System is derived primarily from natural gas wells located in the Cotton Valley formation of East Texas and Northwest Louisiana. The Cotton Valley formation is one of the largest tight gas plays in the U.S. and extends over fourteen counties in East Texas and into Northwest Louisiana. Prism Gas’ East Texas Operating Area includes assets that provide gathering and processing services to producers in Cass, Gregg, Harrison, Panola, and Rusk Counties, Texas and Caddo Parish, Louisiana. The total number of wells permitted in Prism Gas’ East Texas Operating Area was 2,323 and 2,290 in calendar years 2008 and 2007, respectively. These annual permit numbers include 261 permits for horizontal wells in 2008 and 83 permits for horizontal wells in 2007. Improved technology and drilling applications have enhanced the economics of drilling in the Cotton Valley formation. This increase in drilling activity has provided us with access to newly developed natural gas supplies. However, we anticipate that drilling activity in 2009 will be negatively impacted by low commodity prices and capital constraints. In addition, emphasis in the area will shift from predominantly Cotton Valley drilling to a blend of Cotton Valley and Haynesville formation drilling.
          Our primary suppliers of natural gas to the Waskom Processing Plant include BP America Production Company, Centerpoint Energy Gas Transmission Company and Devon Energy Corporation, which collectively represented approximately 72% of the 229 MMcfd of natural gas supplied in 2007 and approximately 70% of the 257 MMcfd of natural gas supplied for the year ended December 31, 2008. A substantial portion (approximately 27%) of the Waskom Processing Plant’s inlet volumes are derived from production at BP’s Blocker, East Mountain, Carthage and Woodlawn fields in East Texas. Production from these fields is dedicated to the Waskom Processing Plant under a contract with BP for the life of the Waskom partnership. We receive natural gas at the Waskom Processing Plant from our McLeod Gathering System. We also receive a significant amount of trucked-in NGLs that are fractionated, treated and stabilized at the Waskom Processing Plant. The tightening of pipeline dew point specifications and access to local markets with high NGL demand has resulted in increased trucked-in NGL volumes at the Waskom Processing Plant. 

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In October 2006, we began construction to expand the fractionator to 12,500 bpd to provide additional capacity for both the increase in NGL volumes from the plant expansions that were underway and this increase in trucked-in NGL volumes. This expansion was completed in late January 2007. The processing plant was expanded to 265 MMcfd in three phases with the first expansion of 30 MMcfd being completed in March 2007, the second expansion of 70 MMcfd being completed in June 2007 and the third phase of 15 Mmcfd being completed in July 2008.
          There are currently six processing plants that compete with Waskom for natural gas supplies. Drilling activity in the Cotton Valley trend is moving north from the Panola-Harrison County line further into Harrison County. Our plant is the preferred gas plant for much of this new production due to its proximity to the increased drilling activity. In addition, the Waskom Processing Plant is the only plant in this area that has full fractionation capability with access to strong local markets for NGLs. Purchasers of NGLs fractionated at Waskom include various chemical companies and other industrial distributors.
          The processing contracts for the Waskom Processing Plant are primarily percent-of-liquids (“POL”) contracts, in which we retain a portion of the NGLs recovered as a processing fee, percent-of-proceeds (“POP”) contracts in which we retain a portion of both the residue gas and the NGLs as payment for services and straight fee contracts in which we receive a fee for every Mcf of gas delivered to the plant. Currently, approximately 50% of the contracts are POL, 30% of the contracts are fee and 20% of the contracts are POP. In addition, there is one minor contract for processing on a keep-whole basis.
          Woodlawn provides gathering and processing services. The Woodlawn gathering system provides both low and intermediate pressure gathering services. The gas is gathered to a 30 MMcfd refrigerated gas processing plant. The NGL’s that are recovered at Woodlawn are trucked to the Waskom Processing Plant for fractionation. In 2007, after acquiring Woodlawn, the system gathered and processed 21 MMcfd and recovered 223 bpd of NGL’s. For the year ended December 31, 2008, the system gathered and processed 24 MMcfd and recovered 247 bpd of NGL’s. The contracts on the Woodlawn system are primarily wellhead purchase with some POP contracts.
          The McLeod Gathering System is a low-pressure gathering system that provides an outlet for high nitrogen and high liquids content gas. In June 2003, Prism Gas constructed a pipeline to tie the McLeod Gathering System to the Waskom Processing Plant to provide an outlet for high nitrogen gas. As a result, the majority of gas gathered on the McLeod Gathering System is transported to the Waskom Processing Plant for processing and blending. Revenue from the McLeod Gathering System is earned through gathering and compression fees and processing revenue. The processing revenue results from the difference in the processing agreements with the producers and the agreement that we have with the Waskom partnership.  The processing contracts in the McLeod Gathering System are predominately POP contracts. Natural gas gathered in the region surrounding the McLeod Gathering System has two primary outlets, including the Waskom Processing Plant.
          Cotton Valley wells are now being drilled in the southern area served by the McLeod Gathering System. The new Cotton Valley wells that have recently been tied into the system are POL contracts with a small gathering fee. These contracts are typically lower margin, higher volume contracts. In this area, competition is geographic based with the McLeod Gathering System capturing wells that are located near the system and the competitor capturing wells that are near its system.
          The Hallsville Gathering System was constructed in 2005 and 2006 to gather low pressure gas. The wells tied into the system are fee based gathering contracts.
          The Marshall Line was leased from Kinder Morgan to provide additional sources of gas for the Waskom Processing Plant. The gas on the system is from Cotton Valley production and is tied into the system under percent of index based contracts.
          The BCP is an approximate 67 mile pipeline located in the Barnett Shale extension. 
          The East Texas Gathering System was constructed in 2004 to tie producers into DCP Midstream’s gathering system in Panola County, Texas. These lines are sized to handle volumes that are expected to increase as producers continue to develop Cotton Valley sands in areas that were traditionally marginal. The existing East Texas Gathering System contracts are all fee-for-service contracts dependent on volumes gathered.

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          The Prism Liquids Pipeline condensate system was formed from the condensate pipeline system obtained in the Woodlawn acquisition. The system was subsequently extended approximately 10 miles using lateral lines to gather condensate from additional locations. The pipeline is a common carrier under the Rules and Regulations of the Railroad Commission of Texas, Oil and Gas Division and, as such, operates under a tariff filed with the Railroad Commission of Texas. The system gathers and transports condensate for producers along the main line which extends south from the Woodlawn Plant to the Carthage Plant operated by DCP Midstream.
          Gulf Coast
          The Gulf Coast area assets consist of the Fishhook Gathering System and the Matagorda Offshore Gathering System (“Matagorda”) located offshore and onshore of the Texas Gulf Coast.
    Fishhook Gathering System — The Fishhook Gathering System, located in Jefferson County, Texas and offshore federal waters, gathers and transports gas in both offshore and onshore areas. For the year ended December 31, 2007, the Fishhook Gathering System gathered and transported approximately 32 MMcfd of natural gas. In September 2008, Hurricane Ike caused extensive damage to an offshore platform on the system. Repairs were completed in February 2009. Prior to the hurricane damage approximately 15 MMcfd of natural gas was gathered and transported for the year ended December 31, 2008. Prism Gas owns an unconsolidated 50% non-operating interest in Panther Interstate Pipeline Energy, LLC (“PIPE”), the owner of the Fishhook Gathering System, with Panther Pipeline Ltd owning the remaining 50% operating interest. We reflect the results of operations from this system using the equity method of accounting.
 
    Matagorda Offshore Gathering System — The Matagorda Offshore Gathering System, located in Matagorda County, Texas and offshore Texas State waters, gathers gas in both the offshore and onshore areas. For the years ended December 31, 2008 and 2007, the Matagorda Offshore Gathering System gathered approximately 15 and 7 MMcfd of natural gas, respectively. Prism Gas owns an unconsolidated 50% non-operating interest in the Matagorda Offshore Gathering System, with Panther Pipeline Ltd. owning the remaining 50% operating interest. We reflect the results of operations from this system using the equity method of accounting.
          The Fishhook Gathering System and the Matagorda Offshore Gathering System gather and transport natural gas from Texas and federal waters of the Gulf of Mexico to onshore pipelines. The Fishhook Pipeline gathers and transports natural gas principally from the eastern portion of the High Island Area which is further offshore. The offshore natural gas supply for the Matagorda Offshore Gathering System is produced primarily from the Brazos Area blocks, which are near shore in the Texas State waters. Additionally, the Matagorda Offshore Gathering System includes onshore gathering in Matagorda, Wharton and Brazoria Counties.
          The Fishhook Gathering System is located in federal waters offshore from Beaumont, Texas and gathers gas from producers. This area is characterized by strong drilling activity with traditionally high volume, high decline wells. Typically, two to four of these traditional wells are drilled near the Fishhook Gathering System each year. Contracts on this system are 100% fee-for-service contracts with both the gathering fee and the maximum transmission fee stated in PIPE’s FERC Gas Tariff, on file with the Federal Energy Regulatory Commission. There are currently two competing pipelines in the area which limit our ability to increase margins on this system. However, we believe that our existing relationships with active producers will enable us to capture additional volumes from new production in this area.
          The Matagorda Offshore Gathering System gathers gas from producers. Contracts for the offshore portion of the Matagorda Offshore Gathering System are a combination of fixed transportation fees plus a fixed margin. The contracts for the onshore portion of the Matagorda Offshore Gathering System are under either a fixed margin or a fixed transportation fee. There is limited competition for the offshore portion of the pipeline. There are currently two pipelines situated in the offshore area but they primarily gather natural gas from wells further offshore than the Matagorda Offshore Gathering System. There are several pipelines that compete with the onshore portion of the system. These competing pipelines result in lower margins for the onshore portion of this system.
Marine Transportation Segment
          Industry Overview. The United States 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.

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          The Gulf Coast region is a major hub for petroleum refining. Approximately two-thirds of United States refining capacity expansion in the 1990s occurred in this region. The hydrocarbon 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 United States refineries and petrochemical facilities. Recent growth in refining and natural gas processing capacity has increased the volume of petroleum products and by-products transported within the Gulf Coast region, which consequently has increased the need for transportation, storage and distribution facilities.
          The marine transportation industry uses push boats and tugboats as power sources and tank barges for freight capacity. The combination of the power source and tank barge freight capacity is called a tow.
          Marine Fleet. We own 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 system operates coastwise along the Gulf of Mexico and on the United States inland waterway system, primarily between domestic ports along the Gulf of Mexico Intracoastal Waterway, the Mississippi River system and the Tennessee-Tombigbee Waterway system. Our inland tows generally consist of one push boat and one to three tank barges, depending upon the horsepower of the push boat, the river or canal capacity and conditions, and customer requirements. 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
    14     20,000 bbl and under   Asphalt, crude oil, fuel oil, gasoline and sulfur(1)
Inland tank barges
    26     20,000 — 30,000 bbl   Asphalt, crude oil, fuel oil and gasoline(1)
Inland push boats
    17     800 — 3,800 horsepower   N/A
Offshore tank barges
    4     40,000 bbl and 95,000 bbl   Asphalt, fuel oil and NGLs
Offshore tugboats
    4     3,200 — 7,200 horsepower   N/A
 
(1)   One of our 14 inland tank barges with capacity of up to 20,000 bbl, and 13 of our 26 inland tank barges with capacity of 20,000 to 30,000 bbl, are specialized and equipped to transport asphalt.
          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 under spot contracts and under term contracts that typically range from one to 12 months in length.
          In order to maintain a balance of pricing flexibility and stable cash flow, we strive to maintain an appropriate mix of spot versus term contracts, based on current market conditions.
          We are a party to a marine transportation agreement effective January 1, 2006 under which we provide marine transportation services to Martin Resource Management on a spot contract basis at applicable market rates. This agreement replaced a prior agreement between us and Martin Resource Management covering marine transportation services which expired in November 2005. Effective each January 1, this agreement automatically renews for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at least 60 days prior to the expiration of the then-applicable term. The fees we charge Martin Resource Management are based on applicable market rates.
          Competition. We compete primarily with other marine transportation companies. The marine barging industry has experienced significant consolidation in the past few years. The total number of tank barges and push boats that operate in the inland waters of the United States declined from approximately 4,200 in 1982 to approximately 2,900 in 1993 and has reduced to approximately 2,800 since 1993. We believe the earlier decrease primarily resulted from:

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    the increasing age of the domestic tank barge fleet, resulting in retirements;
 
    a reduction in tax incentives, which previously encouraged speculative construction of new equipment;
 
    stringent operating standards to adequately address safety and environmental risks;
 
    the elimination of government programs supporting small refineries;
 
    an increase in environmental regulations mandating expensive equipment modification; and
 
    more restrictive and expensive insurance.
          There are several barriers to entry into the marine transportation industry that discourage the emergence of new competitors. Examples of these barriers to entry include:
    significant start-up capital requirements;
 
    the costs and operational difficulties of complying with stringent safety and environmental regulations;
 
    the cost and difficulty in obtaining insurance; and
 
    the number and expertise of personnel required to support marine fleet operations.
          We believe the reduction of the number of tank barges, the consolidation among barging companies and the significant barriers to entry in the industry have resulted in a more stabilized and favorable pricing environment for our marine transportation services.
          We believe we compete favorably with many of our competitors. Historically, competition within the marine transportation business was based primarily on price. However, we believe customers are placing an increased emphasis on safety, environmental compliance, quality of service and the availability of a single source of supply of a diversified package of services. In particular, we believe customers are increasingly seeking transportation vendors that can offer marine, land, rail and terminal distribution services, as well as provide operational flexibility, safety, environmental and financial responsibility, adequate insurance and quality of service consistent with the customer’s own operations and policies. We operate a diversified asset base that, together with the services provided by Martin Resource Management, enables us to offer our customers an integrated distribution network consisting of transportation, terminalling, distribution and midstream logistical services for petroleum products and by-products.
          In addition to competitors that provide marine transportation services, we also compete with providers of other modes of transportation, such as rail tank cars, tractor-trailer tank trucks and, to a limited extent, pipelines. We believe we offer a competitive advantage over rail tank cars and tractor-trailer tank trucks because marine transportation is a more efficient, and generally less expensive, mode of transporting petroleum products and by-products. For example, a typical two inland barge unit carries a volume of product equal to approximately 80 rail cars 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.
          Seasonality. The demand for our marine transportation business is subject to some seasonality factors. Our asphalt shipments are generally higher during April through November when weather allows for efficient road construction. However, demand for marine transportation of sulfur, fuel oil and gasoline is directly related to production of these products in the oil refining and natural gas processing business, which is fairly stable.
Sulfur Services Segment
          Industry Overview. Sulfur is a natural element and is required to produce a variety of industrial products. In the United States, approximately 11 million tons of sulfur is consumed annually, with the Tampa, Florida area being the largest single market. Currently, all sulfur produced in the United States is “recovered sulfur,” or sulfur that is a by-product from oil refineries and natural gas processing plants. Sulfur production in the United States is principally located along the Gulf Coast, along major inland waterways and in some areas of the western United States.

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          Sulfur is an important plant nutrient and is used in the manufacture of phosphate fertilizers. Approximately 53% of worldwide sulfur consumption is currently used for 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. The Fertilizer Institute has estimated that the earth’s soil contains less than 20% of organic plant nutrients needed to meet worldwide food production needs. As a result, we believe mineral fertilizer production will continue to be an important industrial market.
          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. The largest consumers of industrial sulfur products are power plants, paper mills and rubber products manufacturers.
          Our Operations and Products. We gather molten sulfur from refiners, primarily located on the Gulf Coast, and from natural gas processing plants, primarily located in the southwestern United States. We transport sulfur by inland and offshore barges, rail cars and trucks. In 2008, we handled approximately 1.7 million long tons of molten sulfur. 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 transportation and storage assets and expertise to handle the unique requirements for transportation and storage of molten sulfur for domestic customers.
          The terms of our commercial sulfur contracts typically range from one to five years in length. 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 to large integrated oil companies that produce sulfur and fertilizer manufacturers that consume sulfur under transportation and storage contracts with remaining lives from one to two years in duration.
          The sulfur prilling assets we acquired from the acquisition of Bay Sulfur in April 2005 are located at the Port of Stockton in California and are used to process molten sulfur into pellets. These dry, bulk pellets are stored and loaded at our facility at the Port of Stockton. The sulfur pellets are sold into certain U.S. and international agricultural markets. Our facility at the Port of Stockton can process approximately 1,000 metric tons of molten sulfur per day. In January 2007, we completed the construction of a sulfur priller at our Neches facility in Beaumont, Texas. In January 2009, we completed the construction of a second sulfur priller at our Neches facility in Beaumont, Texas. The two Beaumont prillers have the capacity to process approximately 4,000 metric tons of molten sulfur per day. Our sulfur prilling facilities provide refiners with an alternative market for the sale of their residual sulfur.
          In late September 2007, we completed construction of a sulfuric acid production facility at our Plainview, Texas location. This facility processes molten sulfur to produce approximately 500 short tons of sulfuric acid per day. Our sulfuric acid facility provides our Plainview fertilizer plant with an economical supply of sulfuric acid and it uses approximately one third of the sulfuric acid produced by the Plainview facility. The remaining sulfuric acid production is sold to Martin Resource Management which markets the product to third parties.
          We entered the sulfur based fertilizer manufacturing business in 1990 through an acquisition. We acquired two additional fertilizer manufacturing companies in 1998. Over the next two years we expended significant resources to replace and update facilities and other assets and to integrate each of the businesses into our business. These acquisitions have subsequently increased the profitability of our fertilizer business. In December 2005, sulfur fertilizer production capacity was added with the purchase of the net operating assets of A & A Fertilizer, Ltd. (“A & A Fertilizer”). This production capacity is located at our Neches deep-water marine terminal near Beaumont, Texas.
          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 from approximately 62,000 tons in 1997 to approximately 255,000 tons in 2008 as a result of acquisitions and internal growth.

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          In the United States, fertilizer is generally sold to farmers through local dealers. These dealers are typically owned and supplied by much larger wholesale distributors. We sell primarily to these wholesale distributors, as well as to a small number of independent dealers throughout the United States. Our industrial sulfur products are marketed primarily in the eastern United States, 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 two facilities in Odessa, Texas. We also produce plant nutrient sulfur at our facility in Seneca, Illinois. Our plant nutrient sulfur product is a 90% degradable sulfur product marketed under the Disper-Sul® trade name and sold throughout the United States to direct application agricultural markets. Our agricultural ground sulfur products are used primarily in the western United States on grapes and vegetable crops.
 
    Ammonium sulfate products, NPK products and related blended products. We produce various grades of ammonium sulfate including coarse and standard grades, a 40% ammonium sulfate solution and a Kosher-approved food grade material. We also produce nitrogen-phosphorus-potassium products (commonly referred to as NPK products). Our NPK products are an ammoniated phosphate fertilizer containing nitrogen, phosphorus and potash that we manufacture so all particles have a uniform composition. These products primarily serve direct application agricultural markets within a 400-mile radius of our manufacturing plant in Plainview, Texas. 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 emulsified sulfur, elemental pastille sulfur, and industrial ground sulfur products. 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. We produce elemental pastille sulfur at our two Odessa, Texas facilities and at our Seneca, Illinois facility. 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.
 
    Liquid sulfur products. We produce ammonium thiosulfate at our Neches terminal location 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 NPK liquids or suspensions as well. Our market is predominantly the Mid South and Coastal Bend area of Texas.
          Our Sulfur Services Facilities.
          We own 60 railcars and lease approximately 105 railcars equipped to transport molten sulfur. We own the following major marine assets and use them to ship molten sulfur from our Beaumont, Texas terminal to our Tampa, Florida terminal:
             
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 prilling facilities as part of our sulfur services business:
                 
Terminal   Location   Daily Production Capacity       Products Stored
Stockton
  Stockton, California   1,000 metric tons per day     Molten and prilled sulfur
Neches
  Beaumont, Texas   4,000 metric tons per day     Molten and prilled sulfur

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          We lease approximately 40 railcars to transport ammonium thiosulfate. We own the following manufacturing plants as part of our sulfur services business:
             
Facility   Location   Capacity   Description
Fertilizer plants (two)
  Odessa, Texas   70,000 tons/year   Dry sulfur fertilizer production
Fertilizer plant
  Seneca, Illinois   36,000 tons/year   Dry sulfur fertilizer production
Fertilizer plant
  Plainview Texas   180,000 tons/year   Fertilizer production
Fertilizer plant
  Salt Lake City, Utah   25,000 tons/year   Blending and packaging
Fertilizer plant
  Beaumont, Texas   70,000 tons/year   Liquid sulfur fertilizer production
Industrial sulfur plant
  Texarkana, Texas   18,000 tons/year   Emulsified sulfur production
Sulfuric acid plant
  Plainview Texas   150,000 tons/year   Sulfuric acid production
          Competition. Seven phosphate fertilizer manufacturers together consume a vast majority of the total United States production of sulfur. These companies buy from resellers as well as directly from producers. We own one of the four vessels currently used to transport molten sulfur between United States ports on the Gulf of Mexico and Tampa, Florida. Our primary competition consists of producers that sell their production directly to a fertilizer manufacturer that has its own transportation assets or foreign suppliers from Mexico or Venezuela that may sell into the Florida market. Our sulfuric acid products compete with regional producers and importers in the South and Southwest portion of the U.S. from Louisiana to California. 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.
          Seasonality. Sales of our agricultural fertilizer products are partly seasonal as a result of increased demand during the growing season.
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, Mississippi and Texas;
 
    operating a small crude oil gathering business in Stephens, Arkansas;
 
    operating a lube oil processing facility in Smackover, Arkansas;
 
    operating an underground NGL storage facility in Arcadia, Louisiana
 
    building and marketing sulfur prillers;
 
    developing an underground natural gas storage facility in Arcadia, Louisiana;
 
    supplying employees and services for the operation of our business;
 
    operating, for its account and our account, the docks, roads, loading and unloading facilities and other common use facilities or access routes at our Stanolind terminal;
 
    operating, solely for our account, an NGL truck loading and unloading and pipeline distribution terminal in Mont Belvieu, Texas; and
 
    operating, solely for our account, the asphalt facilities in Omaha, Nebraska.

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          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 an approximate 34.9% limited partnership interest and a 2% general partnership interest in us and all of our incentive distribution rights.
          Management
          Martin Resource Management directs our business operations through its ownership 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
          We are a party to an omnibus agreement with Martin Resource Management. The omnibus agreement requires us to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes on our behalf or in connection with the operation of our business. We reimbursed Martin Resource Management for $67.5 million of direct costs and expenses for the twelve months ended December 31, 2008, compared to $53.9 million for the twelve months ended December 31, 2007. 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. The amount of this reimbursement was capped at $2.0 million through November 1, 2007 when the cap expired. For the years ended December 31, 2008, 2007, and 2006, the Conflicts Committee of our general partner approved reimbursement amounts of $2.9, $1.5 and $1.5 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually. These indirect expenses covered the centralized corporate functions Martin Resource Management provides for us, such as accounting, treasury, clerical billing, information technology, administration of insurance, general office expenses and employee benefit plans and other general corporate overhead functions we share with Martin Resource Management retained businesses. The 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.
          In addition to the omnibus agreement, we and Martin Resource Management have entered into various other agreements that are not the result of arm’s-length negotiations and consequently may not be as favorable to us as they might have been if we had negotiated them with unaffiliated third parties. The agreements include, but are not limited to, a motor carrier agreement, a terminal services agreement, a marine transportation agreement, a product storage agreement, a product supply agreement, a throughput agreement, and a Purchaser Use Easement, Ingress-Egress Easement and Utility Facilities Easement. 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 of our general partner’s board of directors.
          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 – Agreements.”
          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.
          We also use the underground storage facilities owned by Martin Resource Management in our natural gas services operations. We lease an underground storage facility from Martin Resource Management in Arcadia, Louisiana with a storage capacity of 2.0 million barrels. Our use of this storage facility gives us greater flexibility in our operations by allowing us to store a sufficient supply of product during times of decreased demand for use when demand increases.

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          In the aggregate, our purchases of land transportation services, NGL storage services, and lube oil product purchases and sulfur services payroll reimbursements from Martin Resource Management accounted for approximately 10%, 12% and 14% of our total cost of products sold during the years ended December 31, 2008, 2007, and 2006, respectively. We also purchase marine fuel from Martin Resource Management, which we account for as an operating expense.
          Correspondingly, Martin Resource Management is one of our significant customers. It primarily uses our terminalling, marine transportation and NGL distribution services for its operations. We provide terminalling and storage services under a terminal services agreement. We provide marine transportation services to Martin Resource Management under a charter agreement on a spot-contract basis at applicable market rates. Our sales to Martin Resource Management accounted for approximately 6%, 6% and 4% of our total revenues for the years ended December 31, 2008, 2007, and 2006, respectively. In connection with the closing of the Tesoro Marine asset acquisition in 2003, we entered into certain agreements with Martin Resource Management pursuant to which we provide terminalling and storage and marine transportation services to Midstream Fuel and Midstream Fuel provides terminal services to us to handle lubricants, greases and drilling fluids.
          For a more comprehensive discussion concerning these commercial agreements that we have entered into with Martin Resource Management, please see “Item 13. Certain Relationships and Related Transactions – Agreements.”
          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 of our general partner’s board of directors, as constituted under our limited partnership agreement. If a matter is referred to the Conflicts Committee, it obtains information regarding the proposed transaction from management and determines whether to engage independent legal counsel or an independent financial advisor to advise the members of the committee regarding the transaction. If the Conflicts Committee retains such counsel or financial advisor, it considers such advice and, in the case of a financial advisor, such advisor’s opinion as to whether the transaction is fair and reasonable to us and to our unitholders.
Insurance
          Loss of, or damage to, our vessels and cargo is insured through hull and cargo insurance policies. Vessel operating liabilities such as collision, cargo, environmental and personal injury are insured primarily through our participation in mutual insurance associations and other reinsurance arrangements, pursuant to which we are potentially exposed to assessments in the event claims by us or other members exceed available funds and reinsurance. Protection and indemnity, (“P&I”), insurance coverage is provided by P&I associations and other insurance underwriters. Our vessels are entered in P&I associations that are parties to a pooling agreement, known as the International Group Pooling Agreement, (“Pooling Agreement”), through which approximately 95% of the world’s commercial shipping 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 pre-determined amount, beyond which we are covered by catastrophe insurance coverage.
          For marine pollution claims, our insurance covers up to $1.0 billion of liability per accident or occurrence and for non-pollution incidents, our insurance covers up to $2.0 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 and that we maintain appropriate levels of environmental damage and pollution insurance coverage. However, there can be no assurance that all risks are adequately insured against, that any particular claim will be paid by the insurer, or that we will be able to procure adequate insurance coverage at commercially reasonable rates in the future.

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Environmental and Regulatory Matters
          Our activities are subject to various federal, state and local laws and regulations, as well as orders of regulatory bodies, governing a wide variety of matters, including marketing, production, pricing, community right-to-know, protection of the environment, safety and other matters.
          Environmental
          We are subject to complex federal, state, and local environmental laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of human health, natural resources and the environment. These laws and regulations can impair our operations that affect the environment in many ways, such as requiring the acquisition of permits to conduct regulated activities; restricting the manner in which we can release materials into the environment; requiring remedial activities or capital expenditures to mitigate pollution from former or current operations; and imposing substantial liabilities on us for pollution resulting from our operations. Many environmental laws and regulations can impose joint and several, strict liability, and any failure to comply with environmental laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial obligations, and, in some circumstances, the issuance of injunctions that can limit or prohibit our operations.
          The 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 hydrocarbons, chemical substances, and wastes as well as the accidental release or spill of such materials into the environment. Consequently, we cannot assure you 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 impact on us in the future.
          Superfund
          The Federal Comprehensive Environmental Response, Compensation and Liability Act, as amended, (“CERCLA”), also known as the “Superfund” law, and similar state laws, impose liability without regard to fault or the legality of the original conduct, on certain classes of “responsible persons,” including the owner or operator of a site where regulated hazardous substances have been released into the environment and companies that disposed or arranged for the disposal of the hazardous substances found at such site. Under CERCLA, these responsible persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances into the environment. Although certain hydrocarbons are not subject to CERCLA’s reach because “petroleum” is excluded from CERCLA’s definition of a “hazardous substance,” in the course of our ordinary operations we will generate wastes that may fall within the definition of a “hazardous substance.” We have not received 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.

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Nevertheless, a possibility exists that hydrocarbons 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 hydrocarbons, hydrocarbon 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, as amended, and comparable state statutes. Amendments to the Clean Air Act 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 Mont Belvieu terminal we use is located in an EPA-designated ozone non-attainment area, referred to as the Houston-Galveston non-attainment area, which is now subject to a new, EPA-adopted 8-hour standard for complying with the national standard for ozone. Categorized as being in “moderate” non-attainment for ozone, the Houston-Galveston non-attainment area has until 2010 to achieve compliance with this new standard, which almost certainly will require the adoption of more restrictive regulations in this non- attainment area for the issuance of air permits for new or modified facilities. In addition, existing sources of air emissions in the Houston-Galveston 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 Clean Air Act 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 is actively considering 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 must consider whether 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 Clean Air Act’s definition of “air pollutant” may also result in future regulation of greenhouse gas emissions from stationary sources under various Clean Air Act programs. New legislation or regulatory programs that restrict emissions of greenhouse gases in areas in which we conduct business could adversely affect our operations and demand for our services.
          Clean Water Act
          The Federal Water Pollution Control Act, 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 EPA in 2002. We believe that compliance with the conditions of such permits and plans will not have a material effect on our operations.

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          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 United States 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 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 United States 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 United States 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 these oil spill-related and financial responsibility requirements.
          Safety Regulation
          The Company’s marine transportation operations are subject to regulation by the United States 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 United States Coast Guard and to meet operational and safety standards presently established by the United States 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. In May 2001, Martin Resource Management paid a small fine in relation to the settlement of alleged OSHA violations at our facility in Plainview, Texas. Although we believe the amount of this fine and the nature of these violations were not, as an individual event, material to our business or operations, this violation may result in increased fines and other sanctions if we are cited for similar violations in the future. Our marine vessel operations are also subject to safety and operational standards established and monitored by the United States 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 United States to vessels built and registered in the United States and owned and manned by United States citizens. Since we engage in maritime transportation between locations in the United States, 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 insure that no violation of the Jones Act ownership restrictions occurs. The Jones Act also requires that all United States-flagged vessels be manned by United States citizens. Foreign-flagged seamen generally receive lower wages and benefits than those received by United States citizen seamen. This requirement significantly increases operating costs of United States-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 United States-flagged vessel owners. The United States 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 United States-flagged operators than for owners of vessels registered under foreign flags of convenience. Following Hurricane Katrina, and again after Hurricane Rita, emergency suspensions of the Jones Act were effectuated by the United States government. The last suspension ended on October 24, 2005. Future suspensions of the Jones Act or other similar actions could adversely affect our cash flow and ability to make distributions to our unitholders.

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          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 United States of a national emergency or a threat to the national security, the United States Secretary of Transportation may requisition or purchase any vessel or other watercraft owned by United States’ citizens (including us, provided that we are considered a United States citizen for this purpose). If one of our push boats, tugboats or tank barges were purchased or requisitioned by the United States 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.
          Regulations Affecting Natural Gas Transmission, Processing and Gathering
          We own a 50% non-operating interest in PIPE. PIPE’s Fishhook Gathering System transports natural gas in interstate commerce and is thus subject to FERC regulations and FERC-approved tariffs as a natural gas company under the National Gas Act of 1938 (“NGA”). Under the NGA, FERC has issued orders requiring pipelines to provide open- access transportation on a basis that is equal for all shippers. In addition, FERC has the authority to regulate natural gas companies with respect to: rates, terms and conditions of service; the types of services PIPE may provide to its customers; the construction of new facilities; the acquisition, extension, expansion or abandonment of services or facilities; the maintenance and retention of accounts and records; and relationships of affiliated companies involved in all aspects of the natural gas and energy business.
          On August 8, 2005, President Bush signed into law the Domenici-Barton Energy Policy Act of 2005 (“EP Act”). The EP Act is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. With respect to regulation of natural gas transportation, the EP Act amends the NGA and the Natural Gas Policy Act of 1978 by increasing the criminal penalties available for violations of each act. The EP Act also adds a new section to the NGA which provides FERC with the power to assess civil penalties of up to $1,000,000 per day per violation of the NGA.
          Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. However, we do not believe that we will be disproportionately affected as compared to other natural gas producers and marketers by any action taken. We believe that our natural gas gathering operations meet the tests FERC uses to establish a pipeline’s status as a gatherer exempt from FERC regulation under the NGA, but FERC regulation still affects these businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of its oil and natural gas regulatory activities, including, for example, its policies on open access transportation, ratemaking, capacity release and market center promotion, indirectly affect intrastate markets. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate oil and natural gas pipelines. However, we cannot assure our unitholders that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to oil and natural gas transportation capacity. In addition, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of regular litigation, so, in such a circumstance, the classification and regulation of some of our gathering facilities and intrastate transportation pipelines may be subject to change based on future determinations by FERC and the courts.
          Other state and local regulations also affect our natural gas processing and gathering business. Our gathering lines are subject to ratable take and common purchaser statutes in Louisiana and Texas. Ratable take statutes generally require gatherers to take, without undue discrimination, oil or natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or transport oil or natural gas. Federal law leaves any economic regulation of natural gas gathering to the states. The states in which we operate have adopted complaint-based regulation of oil and natural gas gathering activities, which allows oil and natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to oil and natural gas gathering access and rate discrimination. Other state regulations may not directly regulate our business, but may nonetheless affect the availability of natural gas for purchase, processing and sale, including state regulation of production rates and maximum daily production allowable from gas wells. While our gathering lines currently are subject to limited state regulation, there is a risk that state laws will be changed, which may give producers a stronger basis to challenge proprietary status of a line, or the rates, terms and conditions of a gathering line providing transportation service.

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          Pursuant to the Pipeline Safety Improvement Act of 2002, the United States Department of Transportation (“DOT”) has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in “high consequence areas.” The regulations require operators to:
    perform ongoing assessments of pipeline integrity;
 
    identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
 
    improve data collection, integration and analysis;
 
    repair and remediate the pipeline as necessary; and
 
    implement preventive and mitigating actions.
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 601 individuals who provide direct support to our operations as of March 2, 2009. None of these employees are represented by labor unions.
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 Securities and Exchange Commission (“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. 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. If any events occur that give rise to the following risks, our business, financial condition, or results of operations could be materially and adversely affected, and as a result, the trading price of our common units could be materially and adversely impacted. Many of such factors are beyond our ability to control or predict. Unitholders are cautioned not to put undue reliance on forward-looking statements.

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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 distribution 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 may 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 an event of default or if the payment of a distribution would cause 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.
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.
We may not be able to obtain funding on acceptable terms or at all because of the deterioration of the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.
          Global financial markets and economic conditions have been, and continue to be, volatile due to a variety of factors, including significant write-offs in the financial services sector and the current weak economic conditions. As a result of the disruption in the financial markets, the availability of funds from those markets has diminished significantly and the cost of raising money in the debt and equity capital markets has increased substantially.

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In particular, as a result of concerns about the stability of financial markets generally and the solvency of lending counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt on similar terms or at all and reduced, or in some cases ceased, to provide funding to borrowers. In addition, lending counterparties under existing revolving credit facilities and other debt instruments may be unwilling or unable to meet their funding obligations. Due to the disruption in the financial markets and the current weak economic conditions, we cannot be certain that new debt or equity financing will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due, complete future acquisitions or expansion and maintenance capital projects.
We are exposed to counterparty risk in our credit facility and related interest rate protection agreements.
          We have 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. There is considerable turmoil in the world economy and banking markets 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 current economic crisis may significantly affect our customers and their ability to make payments to us.
          The current economic crisis is having profound effects on all areas of the world economy. Our customers’ abilities to make payments to us when due may be adversely affected in this environment. As such, we could see an increase in delayed or uncollected receivables that may have an adverse effect on our results of operations, cash flow and ability to make distributions to our unitholders.
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.

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          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, fuel oil and gasoline. 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 and other petroleum products and by-products;
 
    fires and explosions;
 
    damage to transportation, terminalling and storage facilities, and surrounding properties caused by natural disasters; and
 
    terrorist attacks or sabotage.
          Our insurance coverage may not be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage, including various legal proceedings and litigation resulting from these hazards and risks. If we incur material liabilities that are not covered by insurance, our operating results, cash flow and ability to make distributions to our unitholders could be adversely affected.
          Changes in the insurance markets attributable to the September 11, 2001, terrorist attacks, and their aftermath, may make some types of insurance more difficult or expensive for us to obtain. In addition, changes in the insurance markets attributable to the effects of Hurricanes Katrina and Rita, 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 can reduce our liquidity and results of operations and ability to make distributions to our unitholders.
          We purchase hydrocarbon products and by-products such as molten sulfur, sulfur derivatives, fuel oils, LPGs, lubricants, asphalt 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 hydrocarbon products and by-products can 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 hydrocarbon 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, such as those experienced in the past couple of years, 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.

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Demand for our terminalling and storage services is substantially dependent on the level of offshore oil and gas exploration, development and production activity.
          The level of offshore oil and gas exploration, development and production activity historically has been volatile and is likely to continue to be so in the future. The level of activity is subject to large fluctuations in response to relatively minor changes in a variety of factors that are beyond our control, including:
    prevailing oil and natural gas prices and expectations about future prices and price volatility;
 
    the cost of offshore exploration for, and production and transportation of, oil and natural gas;
 
    worldwide demand for oil and natural gas;
 
    consolidation of oil and gas and oil service companies operating offshore;
 
    availability and rate of discovery of new oil and natural gas reserves in offshore areas;
 
    local and international political and economic conditions and policies;
 
    technological advances affecting energy production and consumption;
 
    weather conditions;
 
    environmental regulation; and
 
    the ability of oil and gas companies to generate or otherwise obtain funds for exploration and production.
          We expect levels of offshore oil and gas exploration, development and production activity to continue to be volatile and affect demand for our terminalling and storage services.
Our NGL and sulfur-based fertilizer products are subject to seasonal demand and could cause our revenues to vary.
          The demand for NGL 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 may 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.

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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. Additionally, if neither Ruben Martin nor Scott Martin is the chief executive officer of our general partner, amounts we owe under our credit facility may become immediately due and payable.
          Our success is largely dependent upon the continued services of members of the senior management team of Martin Resource Management. Those senior executive 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. Additionally, if neither Ruben Martin nor Scott Martin is the chief executive officer of our general partner, the lender under our credit facility could declare amounts outstanding thereunder immediately due and payable. If such event occurs, our results of operations and our ability to make distribution to our unitholders could be negatively impacted.
          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 operation 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 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 would be adversely affected if operations at our transportation, terminalling and storage and distribution facilities experienced significant interruptions. Our business would 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.

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          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 affect on our results of operations, cash flow and ability to make distributions to our unitholders.
Political, regulatory and economic factors may 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 Presidential election in the United States, 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.
Our marine transportation business would 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 United States to vessels built and registered in the United States. Furthermore, the Jones Act requires that the vessels be manned and owned by United States citizens. If we fail to comply with these requirements, our vessels lose their eligibility to engage in coastwise trade within United States domestic waters.
          The requirements that our vessels be United States built and manned by United States citizens, the crewing requirements and material requirements of the Coast Guard and the application of United States labor and tax laws significantly increase the costs of United States 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 United States 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 United States 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. Following Hurricane Katrina and again after Hurricane Rita, emergency suspensions of the Jones Act were effectuated by the United States government. The last suspension ended on October 24, 2005. Future suspensions of the Jones Act or other similar actions could result in similar consequences.
Our marine transportation business would be adversely affected if the United States 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 United States of a national emergency or a threat to the national security, the United States Secretary of Transportation may requisition or purchase any vessel or other watercraft owned by United States citizens (including us, provided that we are considered a United States citizen for this purpose). If one of our push boats, tugboats or tank barges were purchased or requisitioned by the United States 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 United States government, such transactions could have a material adverse affect on our results of operations, cash flow and ability to make distributions to our unitholders.
Regulations affecting the domestic tank vessel industry may limit our ability to do business, increase our costs and adversely impact our results of operations and ability to make distributions to our unitholders.
          The OPA 90, provides for the phase out of single-hull vessels and the phase-in of the exclusive operation of double-hull tank vessels in U.S. waters for barges that carry petroleum products that are regulated under OPA. Under OPA, substantially all tank vessels that do not have double hulls will be phased out by 2015 and will not be permitted to enter U.S. ports or trade in U.S. waters. The phase out dates vary based on the age of the vessel and other factors. All but one of our offshore tank barges are double-hull vessels which have no phase out date.

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We have 13 single-hull barges that will be phased out of the petroleum product trade by the year 2015. The phase out of these single-hull vessels in accordance with OPA may require us to make substantial capital expenditures, which could adversely affect our operations and market position and reduce our cash available for distribution.
A decline in the volume of natural gas and NGLs delivered to our facilities could adversely affect our results of operations, cash flows and financial condition.
          Our profitability could be materially impacted by a decline in the volume of natural gas and NGLs transported, gathered or processed at our facilities. A material decrease in natural gas production, as a result of depressed commodity prices, a decrease in exploration and development activities or otherwise, could result in a decline in the volume of natural gas and NGLs handled by our facilities.
          The natural gas and NGLs available to our facilities will be derived from reserves produced from existing wells. These reserves naturally decline over time. To offset this natural decline, our facilities will need access to additional reserves.
Our profitability is dependent upon prices and market demand for natural gas and NGLs, which are beyond our control and have been volatile.
          We are subject to significant risks due to fluctuations in commodity prices. These risks relate primarily to: (1) the purchase of certain volumes of natural gas at a price that is a percentage of a relevant index; and (2) certain processing contracts for Prism Gas whereby we are exposed to natural gas and NGL commodity price risks.
          The margins we realize from purchasing and selling a portion of the natural gas that we transport through our pipeline systems decrease in periods of low natural gas prices because our gross margins are based on a percentage of the index price. For the years ended December 31, 2008, and 2007, Prism Gas purchased approximately 22% and 14%, respectively, of our gas at a percentage of relevant index. Accordingly, a decline in the price of natural gas could have an adverse impact on our results of operations.
          In the past, the prices of natural gas and NGLs have been extremely volatile and we expect this volatility to continue. For example, in 2007, the spot price of Henry Hub natural gas ranged from a high of $9.10 per MMBtu to a low of $5.29 per MMBtu. From January 1, 2008, through December 31, 2008, the same price ranged from $13.31 per MMBtu to $5.38 per MMBtu. On December 31, 2008, the spot price was $5.63 per MMBtu.
          We may not be successful in balancing our purchases and sales. In addition, a producer could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a consumer could purchase less than contracted volumes. Any of these actions could cause our purchases and sales not to be balanced. If our purchases and sales are not balanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income.
          The markets and prices for residue gas and NGLs depend upon factors beyond our control. These factors include demand for oil, natural gas and NGLs, which fluctuate with changes in market and economic conditions and other factors, including:
    the impact of weather on the demand for oil and natural gas;
 
    the level of domestic oil and natural gas production;
 
    the level of domestic industrial and manufacturing activity;
 
    the availability of imported oil and natural gas;
 
    actions taken by foreign oil and gas producing nations;
 
    the availability of local, intrastate and interstate transportation systems;
 
    the availability and marketing of competitive fuels;
 
    the impact of energy conservation efforts; and

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    the extent of governmental regulation and taxation.
Our hedging activities may have a material adverse effect on our earnings, profitability, liquidity, cash flows and financial condition.
          As of December 31, 2008, Prism Gas has hedged approximately 47% and 21% of its commodity risk by volume for 2009 and 2010, respectively. These hedging arrangements are in the form of swaps for crude oil, natural gas and natural gasoline. We anticipate entering into additional hedges in 2009 and beyond to further reduce our exposure to commodity price movements. The intent of these arrangements is to reduce the volatility in our cash flows resulting from fluctuations in commodity prices.
          We entered into these derivative transactions with an investment grade subsidiary of a major oil company and investment grade banks. While we anticipate that future derivative transactions will be entered into with investment grade counterparties, and that we will actively monitor the credit rating of such counterparties, it is nevertheless possible that losses will result from counterparty credit risk in the future. Such risks may be more likely due to the worldwide financial and credit crisis.
          Management will continue to evaluate whether to enter into any new hedging arrangements, but there can be no assurance that we will enter into any new hedging arrangements or that our future hedging arrangements will be on terms similar to our existing hedging arrangements. Also, we may seek in the future to further limit our exposure to changes in natural gas, NGL and condensate commodity prices and we may seek to limit our exposure to changes in interest rates by using financial derivative instruments and other hedging mechanisms from time to time. To the extent we hedge our commodity price and interest rate risk, we may forego the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor.
          Despite our hedging program, we remain exposed to risks associated with fluctuations in commodity prices. The extent of our commodity price risk is related largely to the effectiveness and scope of our hedging activities. For example, the derivative instruments we utilize are based on posted market prices, which may differ significantly from the actual natural gas, NGL and condensate prices that we realize in our operations. Furthermore, we have entered into derivative transactions related to only a portion of the volume of our expected natural gas supply and production of NGLs and condensate from our processing plants; as a result, we will continue to have direct commodity price risk to the unhedged portion. Our actual future production may be significantly higher or lower than we estimated at the time we entered into the derivative transactions for that period. If the actual amount is higher than we estimated, we will have greater commodity price risk than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a reduction of our liquidity.
          As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, even though our management monitors our hedging activities, these activities can result in substantial losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the applicable hedging arrangement, the hedging arrangement is imperfect or ineffective, or our hedging policies and procedures are not properly followed or do not perform as planned. We cannot assure our unitholders that the steps we take to monitor our hedging activities will detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved. For additional information regarding our hedging activities, please see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.”
We typically do not obtain independent evaluations of natural gas reserves dedicated to our gathering and pipeline systems; therefore, volumes of natural gas on our systems in the future could be less than we anticipate.
          We make internal evaluations of natural gas reserves based on publicly available information. However, we typically do not obtain independent evaluations of natural gas reserves connected to our systems due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations to verify publicly available information. Accordingly, we do not have independent estimates of total reserves dedicated to our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering systems are less than we anticipate and we are unable to secure additional sources of natural gas, then the volumes of natural gas on our systems in the future could be less than we anticipate. A decline in the volumes of natural gas on our systems could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

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We depend on certain natural gas producer customers for a significant portion of our supply of natural gas and NGLs. The loss of any of these customers could result in a decline in our volumes, revenues and cash available for distribution.
          We rely on certain natural gas producer customers for a significant portion of our natural gas and NGL supply. While some of these customers are subject to long-term contracts, we may be unable to negotiate extensions or replacements of these contracts on favorable terms, if at all. The loss of all or even a portion of the natural gas volumes supplied by these customers, as a result of competition or otherwise, could have a material adverse effect on our business, results of operations and financial condition, unless we were able to acquire comparable volumes from other sources.
We may not successfully balance our purchases and sales of natural gas, which would increase our exposure to commodity price risks.
          We purchase from producers and other customers a significant amount of the natural gas that flows through our natural gas gathering, processing and transportation systems for resale to third parties, including natural gas marketers and end-users. We may not be successful in balancing our purchases and sales. A producer or supplier could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause our purchases and sales to be unbalanced. While we attempt to balance our purchases and sales, if our purchases and sales are unbalanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income and cash flows.
If third party pipelines and other facilities interconnected to our natural gas and NGL pipelines and facilities become unavailable to transport or produce natural gas and NGLs, our revenues and cash available for distribution could be adversely affected.
          We depend upon third party pipelines and other facilities that provide delivery options to and from our pipelines and facilities for the benefit of our customers. Since we do not own or operate any of these pipelines or other facilities, their continuing operation is not within our control. If any of these third party pipelines and other facilities become unavailable to transport or produce natural gas and NGLs, our revenues and cash available for distribution could 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 natural gas and NGLs than we do. Some of these competitors may expand or construct gathering, processing and transportation systems that would create additional competition for the services we provide to our customers. 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.
A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.
          We believe that our natural gas gathering operations meet the tests the FERC, uses to establish a pipeline’s status as a gatherer exempt from FERC regulation under the NGA, but FERC regulation still affects these businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of its oil and natural gas regulatory activities, including, for example, its policies on open access transportation, ratemaking, capacity release and market center promotion, indirectly affect intrastate markets. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate oil and natural gas pipelines. However, we cannot assure our unitholders that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to oil and natural gas transportation capacity. In addition, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of regular litigation, so, in such a circumstance, the classification and regulation of some of our gathering facilities and intrastate transportation pipelines may be subject to change based on future determinations by FERC and the courts.

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          Other state and local regulations also affect our business. Our gathering lines are subject to ratable take and common purchaser statutes in Louisiana and Texas. Ratable take statutes generally require gatherers to take, without undue discrimination, oil or natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or transport oil or natural gas. Federal law leaves any economic regulation of natural gas gathering to the states. The states in which we operate have adopted complaint-based regulation of oil and natural gas gathering activities, which allows oil and natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to oil and natural gas gathering access and rate discrimination. Other state regulations may not directly regulate our business, but may nonetheless affect the availability of natural gas for purchase, processing and sale, including state regulation of production rates and maximum daily production allowable from gas wells. While our gathering lines currently are subject to limited state regulation, there is a risk that state laws will be changed, which may give producers a stronger basis to challenge the rates, terms and conditions of a gathering line providing transportation service.
Panther Interstate Pipeline Energy, LLC is also subject to regulation by FERC with respect to issues other than ratemaking.
          Under the NGA, FERC has the authority to regulate natural gas companies, such as Panther Interstate Pipeline Energy, LLC with respect to: rates, terms and conditions of service; the types of services Panther Interstate Pipeline Energy, LLC may provide to its customers; the construction of new facilities; the acquisition, extension, expansion or abandonment of services or facilities; the maintenance and retention of accounts and records; and relationships of affiliated companies involved in all aspects of the natural gas and energy business. FERC’s actions in any of these areas or modifications to its current regulations could impair Panther Interstate Pipeline Energy, LLC’s ability to compete for business, the costs it incurs to operate, or the acquisition or construction of new facilities.
We may incur significant costs and liabilities resulting from pipeline integrity programs and related repairs.
          Pursuant to the Pipeline Safety Improvement Act of 2002, the DOT has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in “high consequence areas.” The regulations require operators to:
    perform ongoing assessments of pipeline integrity;
 
    identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
 
    improve data collection, integration and analysis;
 
    repair and remediate the pipeline as necessary; and
 
    implement preventive and mitigating actions.
          We currently estimate that we will incur costs of less than $1.0 million between 2008 and 2010 to implement pipeline integrity management program testing along certain segments of our natural gas and NGL pipelines. This does not include the costs, if any, of any repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which costs could be substantial.
We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.
          We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights of way or if such rights of way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions to our unitholders.

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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.
          Martin Resource Management through a subsidiary currently hold 850,674 subordinated units and 4,334,143 common units. The remaining subordinated units may convert into common units in accordance with the terms of our Partnership Agreement at the end of the subordination period on November 14, 2009 if certain distribution thresholds are met by us.
          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, after the subordination period, we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders. During the subordination period, our general partner, without the approval of our unitholders, may cause us to issue up to 1,500,000 additional common units. Our general partner may also cause us to issue an unlimited number of additional common units or other equity securities of equal rank with the common units, without unitholder approval, in a number of circumstances such as:
    the issuance of common units in additional public offerings or in connection with acquisitions that increase cash flow from operations on a pro forma, per unit basis;
 
    the conversion of subordinated units into common units;
 
    the conversion of units of equal rank with the common units into common units under some circumstances; or
 
    the conversion of our general partner’s general partner interest in us and its incentive distribution rights into common units as a result of the withdrawal of our general partner.
          Our partnership agreement does not restrict our ability to issue equity securities ranking junior to the common units at any time. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding.
          Under our partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow the general partner and its affiliates or their assignees holding any units to require registration of any of these units and to include any of these units in a registration by us of other units, including units offered by us or by any unitholder. Our general partner will continue to have these registration rights for two years following its withdrawal or removal as a general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. Except as described below, the general partner and its affiliates may sell their units in private transactions at any time, subject to compliance with applicable laws. Our general partner and its affiliates, with our concurrence, have granted comparable registration rights to their bank group to which their partnership units have been pledged.
          The sale of any common or subordinated units could have an adverse impact on the price of the common units or on any trading market that may develop.
Unitholders have less power to elect or remove management of our general partner than holders of common stock in a corporation. Common unitholders will not have sufficient voting power to elect or remove our general partner without the consent of Martin Resource Management.

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          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. Because our general partner and its affiliates, including Martin Resource Management, control 35.7% of our outstanding limited partnership units, our general partner initially cannot be removed without the consent of it and its affiliates.
          If our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. A removal under these circumstances would adversely affect the common units by prematurely eliminating their contractual right to distributions and liquidation preference over the subordinated units, which preferences would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud, gross negligence or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of our business, so the removal of our general partner because of the unitholders’ dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period.
          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 it determines in its reasonable discretion to be necessary to fund our future operating expenditures. In addition, our partnership agreement permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available for distribution to our unitholders.
Unitholders may not have limited liability if a court finds that we have not complied with applicable statutes or that unitholder action constitutes control of our business.
          The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some states. The holder of one of our common units could be held liable in some circumstances for our obligations to the same extent as a general partner if a court were to determine that:
    we had been conducting business in any state without compliance with the applicable limited partnership statute; or
 
    the right or the exercise of the right by our unitholders as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted participation in the “control” of our business.

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          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.
          During the subordination period, our general partner, without the approval of our unitholders, may cause us to issue up to 1,500,000 additional common units. 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.
          After the subordination period, 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.
          On November 14, 2008, 850,672 of 1,701,346 outstanding subordinated units owned by Martin Resource Management through a subsidiary converted into common units on a one for one basis following our distribution of available cash on such date. Additional conversion of our outstanding subordinated units will occur following our quarterly distributions of available cash provided that certain distribution thresholds are met by us.

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          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. Additionally, if Martin Resource Management no longer controls our general partner, amounts we owe under our credit facility may become immediately due and payable.
          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. Martin Resource Management and its affiliates have pledged their interests in our general partner and us to their bank group. If, at any time, Martin Resource Management no longer controls our general partner, the lenders under our credit facility may declare all amounts outstanding thereunder immediately due and payable. If such event occurs, we may be required to refinance our debt on unfavorable terms, which could negatively impact our results of operations and our ability to make distribution to our unitholders.
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 National Market (“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 and a report by our independent auditors addressing these assessments. During the course of our testing we may identify deficiencies which we may not be able to address in time to meet the deadline imposed by the Sarbanes-Oxley Act for compliance with the requirements of Section 404. In addition, if we fail to maintain the adequacy of our internal controls, as such standards are modified, supplemented or amended from time to time, we may not be able to ensure that we can conclude on an ongoing basis that we have effective internal controls over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act. Failure to achieve and maintain an effective internal control environment could have a material adverse effect on the price of our common units.

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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.
          Martin Resource Management owns an approximate 34.9% limited partnership interest in us. Furthermore, it owns and controls our general partner, which owns a 2.0% general partner interest and incentive distribution rights in us. Conflicts of interest may arise between Martin Resource Management and our general partner, on the one hand, and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of Martin Resource Management over the interests of our unitholders. Potential conflicts of interest between us, Martin Resource Management and our general partner could occur in many of our day-to-day operations including, among others, the following situations:
    Officers of Martin Resource Management who provide services to us also devote significant time to the businesses of Martin Resource Management and are compensated by Martin Resource Management for that time.
 
    Neither our partnership agreement nor any other agreement requires Martin Resource Management to pursue a business strategy that favors us or utilizes our assets or services. Martin Resource Management’s directors and officers have a fiduciary duty to make these decisions in the best interests of the shareholders of Martin Resource Management without regard to the best interests of the unitholders.
 
    Martin Resource Management may engage in limited competition with us.
 
    Our general partner is allowed to take into account the interests of parties other than us, such as Martin Resource Management, in resolving conflicts of interest, which has the effect of reducing its fiduciary duty to our unitholders.
 
    Under our partnership agreement, our general partner may limit its liability and reduce its fiduciary duties, while also restricting the remedies available to our unitholders for actions that, without the limitations and reductions, might constitute breaches of fiduciary duty. As a result of purchasing units, our unitholders will be treated as having consented to some actions and conflicts of interest that, without such consent, might otherwise constitute a breach of fiduciary or other duties under applicable state law.
 
    Our general partner determines which costs incurred by Martin Resource Management are reimbursable by us.
 
    Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or from entering into additional contractual arrangements with any of these entities on our behalf.
 
    Our general partner controls the enforcement of obligations owed to us by Martin Resource Management.
 
    Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

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    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 a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.
 
    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. Our general partner may establish reserves for distribution on the subordinated units, but only if those reserves will not prevent us from distributing the full minimum quarterly distribution, plus any arrearages, on the common units for the following four quarters.
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 — Agreements — Omnibus Agreement.” 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, a bankruptcy filing by or against Martin Resource Management could independently result in an event of default under our credit facility if it could reasonably be expected to have a material adverse effect on us. If our lenders do declare us in default and accelerate repayment, we may be required to refinance our debt on unfavorable terms, which could negatively impact our results of operations and our ability to make distributions to our unitholders. A bankruptcy filing by or against Martin Resource Management could also result in the termination or material breach of some or all of the various commercial contracts between us and Martin Resource Management, which could have a material adverse impact on our results of operations, cash flow and ability to make distributions to our unitholders.
Tax Risks
The IRS could treat us as a corporation for tax purposes, which would substantially reduce the cash available for distribution to unitholders.
          The anticipated after-tax economic benefit of an investment in us depends largely on our classification as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.
          If we were treated as a corporation for federal income tax purposes, we would pay tax on our income at corporate rates, which is currently a maximum of 35%, and would likely pay state income tax at various rates. Distributions to unitholders would generally be taxed again to them as corporate distributions, and no income, gains, losses or deductions would flow through to unitholders. Because a tax would be imposed upon us as a corporation, the cash available for distribution to unitholders would be substantially reduced. Treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders and therefore would likely result in a substantial reduction in the value of the common units.
          Current law may change so as to cause us to be taxable as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. 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.

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A successful IRS contest of the federal income tax positions we take may adversely affect the market for our common units and the costs of any contest will be borne by our unitholders and our general partner.
          We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from 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 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 foreign 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 individual retirement accounts (known as IRAs), 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 individual retirement accounts 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 effective tax rate applicable to individuals, and non-U.S. persons will be required to file federal income tax returns and pay tax on their share of our taxable income.
We treat a purchaser of our common units as having the same tax benefits without regard to the seller’s identity. The IRS may challenge this treatment, which could adversely affect the value of the common units.
          Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation positions that may not conform to all aspects of the Treasury regulations. 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 unit holders’ 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 conduct business in Alabama, Arkansas, California, Georgia, Florida, Illinois, Louisiana, Mississippi, Nebraska, Texas and Utah. 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.

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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 United States 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 United States 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 United States 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, in response to certain recent developments, members of Congress are considering substantive changes to the definition of qualifying income under Internal Revenue Code Section 7704(d) 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 United States 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 twelve-month period will result in the termination of our partnership for federal income tax purposes.
          We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-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 (and unitholders receiving two Schedule K-1’s) 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 twelve 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.
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, 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.
          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.
          In addition to the foregoing, as a result of a routine inspection by the U.S. Coast Guard of our tug Martin Explorer at the Freeport Sulfur Dock Terminal in Tampa, Florida, we have been informed that an investigation has been commenced concerning a possible violation of the Act to Prevent Pollution from Ships, 33 USC 1901, et. seq., and the MARPOL Protocol 73/78. In connection with this matter, two of our employees were served with grand jury subpoenas during the fourth quarter of 2007. We are cooperating with the investigation and, as of the date of this report, no formal charges, fines and/or penalties have been asserted against us.
Item 4. Submission of Matters to a Vote of Security Holders
          None.
PART II
Item 5. Market for Our Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
          Our common units are traded on the NASDAQ under the symbol “MMLP.” As of March 2, 2009 there were approximately 24 holders of record and approximately 10,371 beneficial owners of our common units. In addition, as of that date there were 850,674 subordinated units representing limited partner interests outstanding. All of the subordinated units are held by Martin Resource Management through a subsidiary. There is no established public trading market for our subordinated units. The following table sets forth the high and low closing sale prices of our common units for the periods indicated, based on the daily composite listing of stock transactions for the NASDAQ and cash distributions declared per common and subordinated units during those periods:

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Fiscal 2008:
                                 
    Common Units   Distributions Declared per Unit
Quarters Ended   High   Low   Common   Subordinated
March 31, 2008
  $ 37.20     $ 30.50     $ 0.720     $ 0.720  
June 30, 2008
  $ 36.24     $ 31.50     $ 0.740     $ 0.740  
September 30, 2008
  $ 32.76     $ 19.23     $ 0.750     $ 0.750  
December 31, 2008
  $ 26.99     $ 13.60     $ 0.750     $ 0.750  
Fiscal 2007:
                                 
    Common Units   Distributions Declared per Unit
Quarters Ended   High   Low   Common   Subordinated
March 31, 2007
  $ 39.17     $ 32.96     $ 0.640     $ 0.640  
June 30, 2007
  $ 42.66     $ 39.48     $ 0.660     $ 0.660  
September 30, 2007
  $ 42.65     $ 34.62     $ 0.680     $ 0.680  
December 31, 2007
  $ 38.61     $ 35.33     $ 0.700     $ 0.700  
          On March 2, 2009, the last reported sales price of our common units as reported on the NASDAQ was $16.22 per unit.
          In connection with our formation in June 2002, we issued to our general partner a 2% general partner interest in us in exchange for a capital contribution in the amount of $20 and issued to Martin Resources LLC a 98% limited partner interest in the partnership in exchange for a capital contribution in the amount of $980 in an offering exempt from registration under Section 4(2) of the Securities Act of 1933, as amended. On November 1, 2002, in offerings exempt from registration under Section 4(2) of the Securities Act of 1933, as amended, we (i) issued 1,543,797 subordinated units representing limited partner interests in us (“Subordinated Units”) to Martin Product Sales LLC, in connection with the contribution to us of Martin Gas Sales LLC’s limited partner interests in Martin Operating Partnership L.P. (“Operating Partnership”) which holds our operating assets; (ii) issued 620,644 Subordinated Units to Midstream Fuel Service LLC, in connection with the contribution to us of Midstream Fuel Service LLC’s limited partner interests in the Operating Partnership; (iii) issued 2,088,921 Subordinated Units to Martin Gas Marine LLC in connection with the contribution of Martin Gas Marine LLC’s limited partner interests in the Operating Partnership; and (iv) converted a portion of the existing interest in us owned by Martin Midstream GP LLC into a portion of its 2% general partner interest and the incentive distribution rights in us.
          In connection with our public offering of 1,322,500 common units in February 2004, our general partner contributed $0.8 million in cash to us in order to maintain its 2% general partner interest in us.
          In connection with our acquisition of Prism Gas in November 2005, 756,480 common units were issued to certain members of the Prism Gas management team and Martin Resource Management. In addition our general partner contributed $0.5 million in cash to us in order to maintain its 2% general partner interest in us.
          In connection with our public offering of 3,450,000 common units in January 2006, our general partner contributed $2.1 million in cash to us in order to maintain its 2% general partner interest in us.
          In connection with our public offering of 1,380,000 common units in May 2007, our general partner contributed $1.2 million in cash to us in order to maintain its 2% general partner interest in us.
          In December 2006, we issued 470,484 common units to Martin Product Sales LLC, an affiliate of Martin Resource Management, for approximately $15.3 million, including a capital contribution of approximately $0.3 million made by our general partner in order to maintain its 2% general partner interest in us. This transaction was exempt from registration pursuant to either Regulation D or Section 4(2) of the Securities Act of 1933, as amended.
          A total of 3,402,688 of our original 4,253,362 outstanding subordinated units owned by Martin Resource Management and its subsidiaries were converted into common units on a one-for-one basis following our quarterly cash distribution, 850,672 each on November 14, 2008, 2007, 2006 and 2005. The common units into which the subordinated units were converted were issued in reliance on Section 3(a)(9) of the Securities Act of 1933, as amended. The remaining 850,674 outstanding subordinated units will convert into common units at the end of the subordination period on November 14, 2009.
          Within 45 days after the end of each quarter, we will distribute all of our available cash, as defined in our partnership agreement, to unitholders of record on the applicable record date. During the subordination period (as described below), the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.50 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. Our available cash consists generally of all cash on hand at the end of the fiscal quarter, less reserves that our general partner determines are necessary to:
    provide for the proper conduct of our business;

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    comply with applicable law, any of our debt instruments, or other agreements; or
 
    provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;
plus all cash on hand for the quarter resulting from working capital borrowings made after the end of the quarter on the date of determination of available cash.
          Our general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct our business. These can include cash reserves for future capital and maintenance expenditures, reserves to stabilize distributions of cash to the unitholders and our general partner, reserves to reduce debt, or, as necessary, reserves to comply with the terms of any of our agreements or obligations. Our distributions are effectively made 98% to unitholders and 2% to our general partner, subject to the payment of incentive distributions to our general partner if certain target cash distribution levels to common unitholders are achieved. Distributions to our general partner increase to 15%, 25% and 50% based on incremental distribution thresholds as set forth in our partnership agreement.
          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 an event of default, or an event of default is existing, under our credit facility. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Description of Our Credit Facility.”
          The subordination period will extend until the first day of any quarter beginning after September 30, 2009, in which each of the following tests are met:
    distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
 
    the “adjusted operating surplus” as defined in the partnership agreement generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and
 
    there are no arrearages in payment of the minimum quarterly distribution on the common units.
          Upon expiration of the subordination period, each outstanding subordinated unit will convert into one common unit and will participate pro rata with the other common units in distributions of available cash.
Item 6. Selected Financial Data
          The following table sets forth selected financial data and other operating data of Martin Midstream Partners L.P. for the years ended December 31, 2008, 2007, 2006, 2005 and 2004 are derived from the audited consolidated financial statements of Martin Midstream Partners L.P.

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          The following selected financial data are qualified by reference to and should be read in conjunction with our Consolidated and Combined Financial Statements and Notes thereto and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this document.
                                         
    2008     2007     2006     2005     2004  
Income Statement Data:
                                       
Revenues
  $ 1,213,958     $ 765,822     $ 576,384     $ 438,443     $ 294,144  
 
                                       
Cost of product sold
    1,013,525       618,689       459,170       351,820       229,976  
Operating expenses
    102,894       83,533       65,387       46,888       34,475  
Selling, general, and administrative
    16,939       11,985       10,977       8,133       6,198  
Depreciation and amortization
    31,218       23,442       17,597       12,642       8,766  
 
                             
Total costs and expenses
    1,164,576       737,649       553,131       419,483       279,415  
Other operating income
    209       703       3,356              
 
                             
Operating Income
    49,591       28,876       26,609       18,960       14,729  
Equity in earnings of unconsolidated entities
    13,224       10,941       8,547       1,591       912  
Interest expense
    (19,777 )     (14,533 )     (12,466 )     (6,909 )     (3,326 )
Debt prepayment premium
                (1,160 )            
Other, net
    483       299       713       238       11  
 
                             
Income before income taxes
    43,521       25,583       22,243       13,880       12,326  
Income taxes
    711       644                    
 
                             
Net Income
  $ 42,810     $ 24,939     $ 22,243     $ 13,880     $ 12,326  
 
                             
 
                                       
Net income per limited partner unit
  $ 2.72     $ 1.67     $ 1.69     $ 1.58     $ 1.45  
Weighted average limited partner units
    14,529,826       14,018,799       12,602,000       8,583,634       8,349,551  
 
                                       
Balance Sheet Data (at Period End):
                                       
 
                                       
Total assets
  $ 668,916     $ 623,577     $ 457,461     $ 389,044     $ 188,332  
Due to affiliates
    13,420       7,543       10,474       3,492       429  
Long-term debt
    295,000       225,000       174,021       192,200       73,000  
Partner’s capital (owner’s equity)
    234,714       235,848       198,525       95,565       75,534  
 
                                       
Cash Flow Data:
                                       
 
                                       
Net cash flow provided by (used in):
                                       
Operating activities
    79,903       58,017       39,317       32,334       12,812  
Investing activities
    (100,184 )     (127,103 )     (95,098 )     (138,742 )     (34,322 )
Financing activities
    24,151       69,896       52,991       109,689       22,424  
 
                                       
Other Financial Data:
                                       
 
                                       
Maintenance capital expenditures
    16,528       10,342       12,391       5,100       5,182  
Expansion capital expenditures
    84,424       107,892       78,267       74,110       30,234  
 
                             
Total capital expenditures
  $ 100,952     $ 118,234     $ 90,658     $ 79,210     $ 35,416  
 
                             
 
                                       
Cash dividends per common unit (in dollars)
  $ 2.91     $ 2.60     $ 2.44     $ 2.19     $ 2.10  
 
                             
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
          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” refers to Martin Resource Management Corporation and its subsidiaries, unless the context 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.

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          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 above 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 Gulf Coast region. Our four primary business lines include:
    Terminalling and storage services for petroleum products and by-products;
 
    Natural gas services;
 
    Marine transportation services for petroleum products and by-products; and
 
    Sulfur and sulfur-based products processing, manufacturing, marketing and distribution.
          The petroleum products and by-products we collect, transport, store and distribute 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 Gulf Coast region of the United States. This region is a major hub for petroleum refining, natural gas gathering and processing and support services to the exploration and production industry.
          2008 Developments and Subsequent Events
          Recent Acquisitions
          Acquisition of Martin Resource Management Stanolind Assets. In January 2008, we acquired 7.8 acres of land, a deep water dock and two sulfuric acid tanks at our Stanolind terminal in Beaumont, from Martin Resource Management. In connection with this acquisition, we entered into a lease agreement with Martin Resource Management for use of the sulfuric acid tanks.
          Other Developments
          Quarterly Distribution. We declared a quarterly cash distribution for the fourth quarter of 2008 of $0.75 per common and subordinated unit on January 27, 2009, reflecting no change over the quarterly distribution paid in respect of the third quarter of 2008.
          Conversion of Subordinated Units. On November 14, 2008, 850,672 of our 1,701,346 outstanding subordinated units owned by Martin Resource Management through a subsidiary converted into common units on a one-for-one basis following our quarterly cash distribution on such date. Additional conversions of our outstanding subordinated units may occur in the future provided that certain distribution thresholds contained in our partnership agreement are met by us.
          Critical Accounting Policies
          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 generally accepted accounting principles. 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. Our results may differ from these estimates. Currently, we believe that our accounting policies do not require us to make estimates using assumptions about matters that are highly uncertain. However, we have described below the critical accounting policies that we believe could impact our consolidated financial statements most significantly.
          You should also read Note 2, “Significant Accounting Policies” in Notes to Consolidated Financial Statements contained in this annual report on Form 10-K. Some of the more significant estimates in these financial statements include the amount of the allowance for doubtful accounts receivable and the determination of the fair value of our reporting units under the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS 142”), Goodwill and Other Intangible Assets.

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          Derivatives
          In accordance with Statement of Financial Accounting Standards No. 133 (“SFAS 133”), Accounting for Derivative Instruments and Hedging Activities, all derivatives and hedging instruments are included on the balance sheet as an asset or liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings. In early 2006, we adopted a hedging policy that allows us to use hedge accounting for financial transactions that are designated as hedges. Derivative instruments not designated as hedges are being marked to market with all market value adjustments being recorded in the consolidated statements of operations. As of December 31, 2008, we had designated a portion of our derivative instruments as qualifying cash flow hedges. Fair value changes for these hedges have been recorded in other comprehensive income as a component of equity.
          Product Exchanges
          We enter into product exchange agreements with third parties whereby we agree to exchange NGLs and sulfur with third parties. We record the balance of NGLs and sulfur due to other companies under these agreements at quoted market product prices and the balance of NGLs and sulfur due from other companies at the lower of cost or market. Cost is determined using the first-in, first-out method.
          Revenue Recognition
          Revenue for our four operating segments is recognized as follows:
          Terminalling and storage — Revenue is recognized for storage contracts based on the contracted monthly tank fixed fee. For throughput contracts, revenue is recognized based on the volume moved through our terminals at the contracted rate. When lubricants and drilling fluids are sold by truck, revenue is recognized upon delivering product to the customers as title to the product transfers when the customer physically receives the product.
          Natural gas services — Natural gas gathering and processing revenues are recognized when title passes or service is performed. NGL distribution revenue is recognized when product is delivered by truck to our NGL customers, which occurs when the customer physically receives the product. When product is sold in storage, or by pipeline, we recognize NGL distribution revenue when the customer receives the product from either the storage facility or pipeline.
          Marine transportation — Revenue is recognized for contracted trips upon completion of the particular trip. For time charters, revenue is recognized based on a per day rate.
          Sulfur Services — Revenue is recognized when the customer takes title to the product, either at our plant or the customer facility.
          Equity Method Investments
          We use the equity method of accounting for investments in unconsolidated entities where the ability to exercise significant influence over such entities exists. Investments in unconsolidated entities consist of capital contributions and advances plus our share of accumulated earnings as of the entities’ latest fiscal year-ends, less capital withdrawals and distributions. Investments in excess of the underlying net assets of equity method investees, specifically identifiable to property, plant and equipment, are amortized over the useful life of the related assets. Excess investment representing equity method goodwill is not amortized but is evaluated for impairment, annually. Under the provisions of SFAS 142, this goodwill is not subject to amortization and is accounted for as a component of the investment. Equity method investments are subject to impairment under the provisions of Accounting Principles Board (“APB”) Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock. No portion of the net income from these entities is included in our operating income.
          Following our acquisition of Prism Gas in November 2005, we own an unconsolidated 50% interest in Waskom, Matagorda, and PIPE. As a result, these assets are accounted for by the equity method and we do not include any portion of their net income in operating income.

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          On June 30, 2006, we, through Prism Gas, acquired a 20% ownership interest in a partnership which owns the lease rights to the assets of the BCP. This interest is accounted for by the equity method of accounting. The lease contract expires in June 2009 and an extension is not currently contemplated.
          Goodwill
          Goodwill is subject to a fair-value based impairment test on an annual basis, or more often if events or circumstances indicate there may be impairment. We are required to identify our reporting units and determine the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets. Goodwill is assigned to reporting units at the date the goodwill is initially recorded. Once goodwill has been assigned to reporting units, it no longer retains its association with a particular acquisition, and all of the activities within a reporting unit, whether acquired or organically grown, are available to support value of the goodwill.
          We performed the annual impairment tests as of September 30, 2008, September 30, 2007 and September 30, 2006, respectively. In performing such tests, we determined we had four “reporting units” which contained goodwill. These reporting units were in each of our four reporting segments: terminalling, natural gas services, marine transportation, and sulfur services. The estimated fair value of our reporting units with goodwill were developed using the guideline public company method, the guideline transaction method, and the discounted cash flow (“DCF”) method using observable market data where available. To the extent the carrying amount of a reporting unit exceeds the fair value of the reporting unit, we would be required to perform the second step of the impairment test, as this is an indication that the reporting unit goodwill may be impaired. At September 30, 2008, 2007 and 2006 the estimated fair value of each of our four reporting units was in excess of its carrying value resulting in no impairment.
          As a result of the deterioration in the overall stock market subsequent to September 30, 2008 and the decline in our unit price, we reviewed specific factors, as outlined in Statement of Financial Accounting Standards No. 142, to determine if we had a trigging event that required us to test our goodwill for impairment as of December 31, 2008.
          These factors included whether there have been any significant fundamental changes since our annual impairment test to (i) our business as a whole or to the reporting units, including regulatory changes, (ii) our level of operating cash flows, (iii) our expectation of future levels of operating cash flows, (iv) our executive management team, and (v) the carrying value of our other long-lived assets. While these factors did not indicate a triggering event occurred, our unit price fell to a point by December 31, 2008, that resulted in our total market capitalization being less than our partner’s equity. We determined this to be a triggering event requiring us to perform an impairment test as of December 31, 2008. As a result of our goodwill impairment test for each of the four reporting units as of December 31, 2008, no impairment was determined to exist.
          Environmental Liabilities
          We have historically not experienced circumstances requiring us to account for environmental remediation obligations. If such circumstances arise, we would estimate remediation obligations utilizing a remediation feasibility study and any other related environmental studies that we may elect to perform. We would record changes to our estimated environmental liability as circumstances change or events occur, such as the issuance of revised orders by governmental bodies or court or other judicial orders and our evaluation of the likelihood and amount of the related eventual liability.
          Allowance for Doubtful Accounts
     In evaluating the collectability of our accounts receivable, we assess a number of factors, including a specific customer’s ability to meet its financial obligations to us, the length of time the receivable has been past due and historical collection experience. Based on these assessments, we record both specific and general reserves for bad debts to reduce the related receivable to the amount we ultimately expect to collect from customers.
          Asset Retirement Obligation
     In accordance with Statement of Financial Accounting Standards No. 143 (“SFAS 143”), Accounting for Asset Retirement Obligations and FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”), an interpretation of SFAS 143, we recognize and measure our asset retirement obligations and the associated asset retirement cost upon acquisition of the related asset. Subsequent measurement and accounting provisions are in accordance with SFAS 143. We have recognized asset retirement obligations, where appropriate.

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          Reclassifications
          As previously reported in our Quarterly Report on Form 10-Q for the three months ended September 30, 2005, which was filed with the SEC on November 9, 2005, we converted to a new accounting system in August 2005. In connection with the system conversion, we closely examined expense classifications under the new system. Upon review, it was determined that certain payroll, property insurance and property tax expenses that were previously categorized as selling, general and administrative expenses would be more appropriately classified as operating expenses or costs of products sold. As a result, those expenses were set up in the new system with the new classification. Accordingly, it is necessary for us to reclassify the related expense items for fiscal year 2004. Since the reclassifications, as indicated in the tables set forth below, had no impact on the prior periods’ revenues, operating income, cash flows from operations or net income, we have determined that the reclassifications are not material to our audited financial statements for the prior periods. Nonetheless, we are effecting the reclassifications for prior periods in order to provide comparative clarity and consistency for the 2004 annual period when compared to our financial reporting for our current 2008 fiscal year.
          The following table sets forth the effects of the reclassifications on certain line items within our previously reported consolidated statements of income for the year ended December 31, 2004 (dollars in thousands), which statements of income and certain relevant footnotes thereto as well as the relevant portions of Management’s Discussion and Analysis of Financial Condition and Results of Operations for those periods have been updated.
Year Ended December 31, 2004
(In Thousands)
                                         
    Terminalling                
    and Storage   NGL   Marine   Sulfur   Total
Cost of products sold (as previously reported)
  $ 6,775     $ 197,859     $     $ 25,207     $ 229,841  
Cost of products sold (as reclassified)
    6,775       197,859             25,342       229,976  
Operating expenses (as previously reported)
    6,699       928       24,796             32,423  
 
Operating expenses (as reclassified)
    8,494       1,185       24,796             34,475  
Selling, general and administrative (as previously reported)
    2,194       1,457       175       4,599       8,425  
Selling, general and administrative (as reclassified)
    399       1,200       175       4,424       6,198  
Our Relationship with Martin Resource Management
          Martin Resource Management directs our business operations through its ownership and control of our general partner and under an 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. The amount of this reimbursement was capped at $2.0 million through November 1, 2007, when the cap expired. For the years ended December 31, 2008, 2007 and 2006, the Conflicts Committee of our general partner approved reimbursement amounts of $2.9, $1.5 and $1.5 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.
          We are required to reimburse Martin Resource Management for all direct expenses it incurs or payments it makes on our behalf or in connection with the operation of our business. Martin Resource Management also licenses certain of its trademarks and trade names to us under this 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, underground storage services, sulfuric acid and marine fuel from Martin Resource Management. Additionally, we have exclusive access to and use of a truck loading and unloading terminal and pipeline distribution system owned by Martin Resource Management at Mont Belvieu, Texas. 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 — Agreements.”

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Results of Operations
          The results of operations for the twelve months ended December 31, 2008, 2007 and 2006 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 twelve months ended December 31, 2008, 2007 and 2006.
                                                 
                    Operating             Operating     Operating  
            Revenues     Revenues     Operating     Income     Income (loss)  
    Operating     Intersegment     after     Income     Intersegment     after  
    Revenues     Eliminations     Eliminations     (loss)     Eliminations     Eliminations  
    (In thousands)  
Year ended December 31, 2008:
                                               
Terminalling and storage
  $ 90,474     $ (4,189 )   $ 86,285     $ 12,261     $ (3,635 )   $ 8,626  
Natural gas services
    679,375             679,375       2,780       945       3,725  
Marine transportation
    80,059       (3,710 )     76,349       8,104       (2,534 )     5,570  
Sulfur services
    372,987       (1,038 )     371,949       31,956       5,224       37,180  
Indirect selling, general and administrative
                      (5,510 )           (5,510 )
 
                                   
 
                                               
Total
  $ 1,222,895     $ (8,937 )   $ 1,213,958     $ 49,591     $     $ 49,591  
 
                                   
 
                                               
Year ended December 31, 2007:
                                               
Terminalling and storage
  $ 59,790     $ (865 )   $ 58,925     $ 10,745     $ (472 )   $ 10,273  
Natural gas services
    515,992             515,992       4,159       333       4,492  
Marine transportation
    63,533       (3,954 )     59,579       7,949       (3,679 )     4,270  
Sulfur services
    131,602       (276 )     131,326       9,222       3,818       13,040  
Indirect selling, general and administrative
                      (3,199 )           (3,199 )
 
                                   
 
                                               
Total
  $ 770,917     $ (5,095 )   $ 765,822     $ 28,876     $     $ 28,876  
 
                                   
 
Year ended December 31, 2006:
                                               
Terminalling and storage
  $ 36,606     $ (389 )   $ 36,217     $ 12,646     $ (142 )   $ 12,504  
Natural gas services
    389,735             389,735       4,239             4,239  
Marine transportation
    50,174       (2,339 )     47,835       8,258       (1,847 )     6,411  
Sulfur services
    102,646       (49 )     102,597       4,719       1,989       6,708  
Indirect selling, general and administrative
                      (3,253 )           (3,253 )
 
                                   
 
                                               
Total
  $ 579,161     $ (2,777 )   $ 576,384     $ 26,609     $     $ 26,609  
 
                                   
          Our results of operations are discussed 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.
Year Ended December 31, 2008 Compared to the Year Ended December 31, 2007
          Our total revenues before eliminations were $1,222.9 million for the year ended December 31, 2008 compared to $770.9 million for the year ended December 31, 2007, an increase of $452.0 million, or 59%. Our operating income before eliminations was $49.6 million for the year ended December 31, 2008 compared to $28.9 million for the year ended December 31, 2007, an increase of $20.7 million, or 72%.

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          The results of operations are described in greater detail on a segment basis below.
          Terminalling and Storage Segment
          The following table summarizes our results of operations in our terminalling and storage segment.
                 
    Years Ended December 31,  
    2008     2007  
    (In thousands)  
Revenues:
               
Services
  $ 40,118     $ 29,400  
Products
    50,356       30,390  
 
           
Total Revenues
    90,474       59,790  
Cost of products sold
    42,721       26,298  
Operating expenses
    26,086       16,238  
Selling, general and administrative expenses
    120       139  
Depreciation and amortization
    9,272       6,358  
 
           
 
    12,275       10,757  
 
           
Other operating income (loss)
    (14 )     (12 )
 
           
Operating income
  $ 12,261     $ 10,745  
 
           
          Revenues. Our terminalling and storage revenues increased $30.7 million, or 51%, for the year ended December 31, 2008 compared to the year ended December 31, 2007. Service revenue accounted for $10.7 million of this increase. The service revenue increase was primarily a result of recent acquisitions and capital projects being placed into service during the end of 2007 and throughout 2008 and increased service revenue. Product revenue, which is lubricant sales, increased $20.0 million primarily due to our acquisition of the operations assets of Mega Lubricants Inc. (“Mega Lube”) in June 2007.
          Cost of products sold. Our cost of products sold increased $16.4 million, or 62% for the year ended December 31, 2008 compared to the year ended December 31, 2007. This increase was primarily a result of the Mega Lube acquisition.
          Operating expenses. Operating expenses increased $9.8 million, or 61%, for the year ended December 31, 2008 compared to the year ended December 31, 2007. The increase was result of our recent acquisitions and capital projects placed into service during the end of 2007 and throughout 2008. The increase was also a result of increased operating activities and an increase in costs of those activities at our terminals, including increased salaries and related burden and utility costs. Hurricane expenses also accounted for $1.1 million of this increase.
          Selling, general and administrative expenses. Selling, general & administrative expenses were approximately the same for the years ended December 31, 2008 and 2007.
          Depreciation and amortization. Depreciation and amortization increased $2.9 million, or 46%, for the year ended December 31, 2008 compared to the year ended December 31, 2007. This increase was primarily a result of our recent acquisitions and capital expenditures.
          Other operating income (loss). Other operating income was approximately the same for the year ended December 31, 2008 compared to the year ended December 31, 2007. This consisted solely of a loss related to the sale of equipment for both periods.
          In summary, terminalling and storage operating income increased $1.5 million, or 14%, for the years ended December 31, 2008 and 2007.

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     Natural Gas Services Segment
          The following table summarizes our results of operations in our natural gas services segment.
                 
    Years Ended December 31,  
    2008     2007  
    (In thousands)  
Revenues:
               
NGLs
  $ 615,966     $ 481,018  
Natural gas
    59,346       35,983  
Non-cash mark to market and impairment adjustments of commodity derivatives
    4,930       (3,104 )
Loss on cash settlements of commodity derivatives
    (3,932 )     (611 )
Other operating fees
    3,065       2,706  
 
           
Total revenues
    679,375       515,992  
 
Cost of products sold:
               
NGLs
    599,835       461,489  
Natural gas
    58,771       34,485  
 
           
Total cost of products sold
    658,606       495,974  
 
               
Operating expenses
    8,633       7,082  
Selling, general and administrative expenses
    5,292       5,524  
Depreciation and amortization
    4,067       3,252  
 
           
 
    2,777       4,160  
 
           
Other operating income
    3       (1 )
 
           
Operating income
  $ 2,780     $ 4,159  
 
           
 
               
NGLs Volumes (Bbls)
    8,794       8,266  
 
           
Natural Gas Volumes (Mmbtu)
    7,267       5,550  
 
           
 
*   Information above does not include activities relating to Waskom, PIPE, Matagorda and BCP investments
                 
Equity in Earnings of Unconsolidated Entities
  $ 13,224     $ 10,941  
 
           
 
               
Waskom:
               
Plant Inlet Volumes (Mmcf/d)
    257       229  
 
           
Frac Volumes (Bbls/d)
    10,542       8,725  
 
           
          Revenues. Our natural gas services revenues increased $163.4 million, or 32% for the year ended December 31, 2008 compared to the year ended December 31, 2007 due to higher commodity prices, in addition to increased natural gas and NGL volumes.
          For the year ended December 31, 2008, NGL revenues increased $134.9 million, or 28% and natural gas revenues increased $23.4 million, or 65%. During 2008, our NGL average sales price per barrel increased $11.85 or 20% and our natural gas average sales price per Mmbtu increased $1.68, or 26% compared to the same period in 2007. NGL sales volumes for the year increased 6% and natural gas volumes increased 31% compared to the same period of 2007. The increase in NGL volumes is primarily due to increased industrial demand experienced during 2008 and the increase in natural gas volumes is primarily due to receiving a full year’s benefit of the Woodlawn acquisition.
          Our natural gas services segment utilizes derivative instruments to manage the risk of fluctuations in market prices for its anticipated sales of natural gas, condensate and NGLs. This activity is referred to as price risk management. For the year ended December 31, 2008, 58% of our total natural gas volumes and 33% of our total NGL volumes were hedged as compared to 46% and 53%, respectively in 2007. The impact of price risk management and marketing activities increased total natural gas and NGL revenues $1.0 million for 2008 compared to a decrease of $3.7 million in the same period of 2007.
          Costs of product sold. Our cost of products increased $162.6 million, or 33%, for the year ended December 31, 2008 compared to the same period in 2007. Of the increase, $138.3 million relates to NGLs and $24.3 million relates to natural gas. The percentage increase in NGL cost of products sold is greater than our percentage increase in NGL revenues as our NGL per barrel margins decreased $0.53, or 22%, primarily due to a sharp decline in commodity prices experienced in the fourth quarter of 2008. The percentage increase relating to natural gas cost of products sold is greater than the percentage increase in natural gas revenues which caused our Mmbtu margins to decrease by 70%, primarily as a result of the terms of Woodlawn’s producer contracts compared to our historical producer contracts.
          Operating expenses. Operating expenses increased $1.6 million, or 22%, for the year ended December 31, 2008 compared to the same period of 2007. This increase is primarily due to a full year of operations of the Woodlawn acquisition.
          Selling, general and administrative expenses. Selling, general and administrative expenses remained consistent for the years ended December 31, 2008 and 2007.

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          Depreciation and amortization. Depreciation and amortization increased $0.8 million, or 25%, for the year ended December 31, 2008 compared to the same period of 2007. This increase was primarily a result of the Woodlawn acquisition.
          In summary, our natural gas services operating income decreased $1.4 million, or 33%, for the year ended December 31, 2008 compared to the year ended December 31, 2007.
          Equity in earnings of unconsolidated entities. Equity in earnings of unconsolidated entities was $13.2 million and $10.9 million for the year ended December 31, 2008 and 2007, respectively, an increase of 21%. This increase is primarily a result of receiving full benefit of the expansion to the Waskom plant and the Waskom fractionator in 2008 as the plant was shut down for a portion of 2007. As a result, our inlet volumes increased 12% and our fractionation volumes increased 21% for the year ended December 31, 2008 compared to the same period of 2007.
          Marine Transportation Segment
          The following table summarizes our results of operations in our marine transportation segment.
                 
    Years Ended December 31,  
    2008     2007  
    (In thousands)  
Revenues
  $ 80,059     $ 63,533  
Operating expenses
    57,346       46,946  
Selling, general and administrative expenses
    2,635       535  
Depreciation and amortization
    12,128       8,819  
 
           
 
    7,950       7,233  
 
           
Other operating income
    154       716  
 
           
Operating income
  $ 8,104     $ 7,949  
 
           
          Revenues. Our marine transportation revenues increased $16.5 million, or 26%, for the year ended December 31, 2008 compared to the year ended December 31, 2007. Our inland marine assets generated an additional $16.8 million in revenue from expansion of our inland fleet and increased contract rates. This increase was offset by a slight decrease in our offshore revenues of $0.3 million resulting primarily from downtime associated with capital expenditures of offshore vessels.
          Operating expenses. Operating expenses increased $10.4 million, or 22%, for the year ended December 31, 2008 compared to the year ended December 31, 2007 due to increases in fuel, salaries and wages, property and liability premiums and repair and maintenance expenses.
          Selling, general and administrative expenses. Selling, general & administrative expenses increased $2.1 million, or 393% for the year ended December 31, 2008 compared to the year ended December 31, 2007. This increase was a result of the bankruptcy of a contractor to which we had made advance payments for the construction of vessels and other expenses associated with the expansion of our fleet.
          Depreciation and amortization. Depreciation and amortization increased $3.3 million, or 38%, for the year ended December 31, 2008 compared to the year ended December 31, 2007. This increase was the result of capital expenditures made in the last 12 months.
          Other operating income. Other operating income decreased $0.5 million, or 78%, for the year ended December 31, 2008 compared to the year ended December 31, 2007. In 2008, there were less gains recorded on the sale of property and equipment than in 2007.
          In summary, our marine transportation operating income increased $0.2 million, or 2%, for the year ended December 31, 2008 compared to the year ended December 31, 2007.

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     Sulfur Services Segment
     The following table summarizes our results of operations in our sulfur services segment.
                 
    Years Ended December 31,  
    2008     2007  
    (In thousands)  
Revenues
  $ 372,987     $ 131,602  
Cost of products sold
    314,001       97,747  
Operating expenses
    17,963       17,033  
Selling, general and administrative expenses
    3,382       2,587  
Depreciation and amortization
    5,751       5,013  
 
           
 
    31,890       9,222  
 
           
Other operating income
    66        
 
           
Operating income
  $ 31,956     $ 9,222  
 
           
 
               
Sulfur (long tons)
    1,094.3       1,169.8  
Fertilizer (long tons)
    227.6       251.1  
 
           
Sulfur Services Volumes (long tons)
    1,321.9       1,420.9  
 
           
          Revenues. Our sulfur services revenues increased $241.4 million, or 183%, for the year ended December 31, 2008 compared to the year ended December 31, 2007. This increase was primarily a result of the significant escalation in market prices during 2008, primarily driven by higher costs of sulfur and raw materials, which generated higher revenues on decreased volumes. Margins were positively impacted due to a contract pricing provision with a significant customer which allowed us to invoice them at prices greater than the prevailing market prices in the fourth quarter of 2008.
          Cost of products sold. Our cost of products sold increased $216.3 million, or 221%, for the year ended December 31, 2008 compared to the year ended December 31, 2007. This increase was primarily a result of significant escalation in market prices during 2008 which generated higher cost of products sold on decreased volumes, particularly with respect to prilled sulfur.
          Operating expenses. Our operating expenses increased $0.9 million, or 5%, for the year ended December 31, 2008 compared to the year ended December 31, 2007. This increase was a result of increased costs relating to fuel prices for marine transportation and increased gas utilities pricing.
          Selling, general, and administrative expenses. Our selling, general, and administrative expenses increased $0.8 million, or 31%, for the year ended December 31, 2008 compared to the year ended December 31, 2007. This increase is a result of increased compensation expense.
          Depreciation and amortization. Depreciation and amortization increased $0.7 million, or 15%, for the year ended December 31, 2008 compared to the year ended December 31, 2007. This is attributable to full year of operations at our sulfuric acid facility.
          In summary, our sulfur services operating income increased $22.7 million, or 247%, for the year ended December 31, 2008 compared to the year ended December 31, 2007.
          Statement of Operations Items as a Percentage of Revenues
          In the aggregate, our cost of products sold, operating expenses, selling, general and administrative expenses, and depreciation and amortization have remained relatively constant as a percentage of revenues for the years ended December 31, 2008 and December 31, 2007. The following table summarizes, on a comparative basis, these items of our statement of operations as a percentage of our revenues.
                 
    Years Ended December 31,
    2008   2007
    (In thousands)
Revenues
    100 %     100 %
Cost of products sold
    83 %     81 %
Operating expenses
    8 %     11 %
Selling, general and administrative expenses
    1 %     2 %
Depreciation and amortization
    3 %     3 %

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          Equity in Earnings of Unconsolidated Entities
          For the years ended December 31, 2008 and 2007, equity in earnings of unconsolidated entities relates to our unconsolidated interests in Waskom Gas Processing Company (“Waskom”), Matagorda, PIPE and BCP.
          Equity in earnings of unconsolidated entities was $13.2 million for the year ended December 31, 2008, compared to $10.9 million for the year ended December 31, 2007, an increase of $2.3 million. This increase related to earnings received from Waskom, Matagorda, PIPE and BCP.
          Interest Expense
          Our interest expense for all operations was $19.8 million for 2008 compared to $14.5 million for 2007, an increase of $5.3 million, or 37%. This increase was primarily due to an increase in average debt outstanding offset by a decrease in interest rates throughout 2008 compared to 2007. Also, we had interest swap cash settlements of $2.7 million and non-cash mark-to-market charges of $0.7 million which increased interest expense in 2008.
          Indirect Selling, General and Administrative Expenses
          Indirect selling, general and administrative expenses were $5.5 million for 2008 compared to $3.2 million for 2007, an increase of $2.3 million or 72%.
          Martin Resource Management allocated to us a portion of its indirect selling, general and administrative expenses for services such as accounting, treasury, clerical billing, information technology, administration of insurance, engineering, general office expense and employee benefit plans and other general corporate overhead functions we share with Martin Resource Management retained businesses. This allocation is based on the percentage of time spent by Martin Resource Management personnel that provide such centralized services. Generally accepted accounting principles also permit other methods for allocation of these expenses, such as basing the allocation on the percentage of revenues contributed by a segment. The allocation of these expenses between Martin Resource Management and us is subject to a number of judgments and estimates, regardless of the method used. We can provide no assurances that our method of allocation, in the past or in the future, is or will be the most accurate or appropriate method of allocation these expenses. Other methods could result in a higher allocation of selling, general and administrative expense to us, which would reduce our net income.
          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. The amount of this reimbursement was capped at $2.0 million through November 1, 2007, when the cap expired. For the years ended December 31, 2008 and 2007, the Conflicts Committee of our general partner approved reimbursement amounts of $2.9 and $1.5 million, respectively, reflecting our allocable share of such expenses. The Conflicts Committee will review and approve future adjustments in the reimbursement amount for indirect expenses, if any, annually.
Year Ended December 31, 2007 Compared to the Year Ended December 31, 2006
          Our total revenues before eliminations were $770.9 million for the year ended December 31, 2007, compared to $579.2 million for the year ended December 31, 2006, an increase of $191.7 million, or 33%. Our operating income before eliminations was $28.9 million for the year ended December 31, 2007, compared to $26.6 million for the year ended December 31, 2006, an increase of $2.3 million, or 9%.

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          The results of operations are described in greater detail on a segment basis below.
          Terminalling and Storage Segment
          The following table summarizes our results of operations in our terminalling and storage segment.
                 
    Years Ended December 31,  
    2007     2006  
    (In thousands)  
Revenues:
               
Services
  $ 29,400     $ 24,182  
Products
    30,390       12,424  
 
           
Total Revenues
    59,790       36,606  
Cost of products sold
    26,298       9,999  
Operating expenses
    16,238       12,276  
Selling, general and administrative expenses
    139       112  
Depreciation and amortization
    6,358       4,700  
 
           
 
    10,757       9,519  
 
           
Other operating income (loss)
    (12 )     3,127  
 
           
Operating income
  $ 10,745     $ 12,646  
 
           
          Revenues. Our terminalling and storage revenues increased $23.2 million, or 63%, for the year ended December 31, 2007 compared to the year ended December 31, 2006. Service revenue accounted for $5.2 million of this increase. The service revenue increase was primarily a result of recent acquisitions and capital projects being placed into service during the end of 2006 and throughout 2007. Product revenue increased $18.0 million primarily due to the Mega Lube acquisition, and, exclusive of Mega Lube, a 29% increase in product cost that was passed through to our customers. There was also a 22% increase in sales volumes.
          Cost of products sold. Our cost of products sold increased $16.3 million, or 163% for the year ended December 31, 2007, compared to the year ended December 31, 2006. This increase was primarily a result of the Mega Lube acquisition, an increase in product cost and an increase in sales volumes.
          Operating expenses. Operating expenses increased $4.0 million, or 32%, for the year ended December 31, 2007, compared to the year ended December 31, 2006. The increase was result of our recent acquisitions and capital projects placed into service during the end of 2006 and throughout 2007. The increase was also a result of increased operating activities and an increase in costs of those activities at our terminals.
          Selling, general and administrative expenses. Selling, general & administrative expenses were approximately the same for the year ended December 31, 2007, compared to the year ended December 31, 2006.
          Depreciation and amortization. Depreciation and amortization increased $1.7 million, or 35%, for the year ended December 31, 2007, compared to the year ended December 31, 2006. This increase was primarily a result of our recent acquisitions and capital expenditures.
          Other operating income (loss). Other operating income for the year ended December 31, 2007, consisted solely of a loss related to the sale of equipment. Other operating income for the year ended December 31, 2006 consisted primarily of a gain of $3.1 million related to an involuntary conversion of assets. This gain resulted from insurance proceeds which were greater than the impairment of assets destroyed by hurricanes Katrina and Rita.
          In summary, terminalling and storage operating income decreased $1.9 million, or 15%, for the year ended December 31, 2007, compared to the year ended December 31, 2006.

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     Natural Gas Services Segment
          The following table summarizes our results of operations in our natural gas services segment.
                 
    Years Ended December 31,  
    2007     2006  
    (In thousands)  
Revenues:
               
NGLs
  $ 481,018     $ 372,997  
Natural gas
    35,983       13,773  
Non-cash mark to market adjustment of commodity derivatives
    (3,104 )     221  
Gain (loss) on cash settlements of commodity derivatives
    (611 )     894  
Other operating fees
    2,706       1,850  
 
           
Total revenues
    515,992       389,735  
 
Cost of products sold:
               
NGLs
    461,489       361,941  
Natural gas
    34,485       12,277  
 
           
Total cost of products sold
    495,974       374,218  
 
               
Operating expenses
    7,082       5,240  
Selling, general and administrative expenses
    5,524       4,373  
Depreciation and amortization
    3,252       1,667  
 
           
 
    4,160       4,237  
 
           
Other operating income
    (1 )     2  
 
           
Operating income
  $ 4,159     $ 4,239  
 
           
 
               
NGLs Volumes (Bbls)
    8,266       7,688  
 
           
Natural Gas Volumes (Mmbtu)
    5,550       2,107  
 
           
 
*   Information above does not include activities relating to Waskom, PIPE, Matagorda and BCP investments which are reflected in Equity in Earnings of Unconsolidated Entities detailed below.
                 
Equity in Earnings of Unconsolidated Entities
  $ 10,941     $ 8,547  
 
           
 
               
Waskom:
               
Plant Inlet Volumes (Mmcf/d)
    229       183  
 
           
Frac Volumes (Bbls/d)
    8,725       7,677  
 
           
          Revenues. Our natural gas services revenues increased $126.3 million, or 32% for the year ended December 31, 2007 compared to the year ended December 31, 2006 due to increased natural gas and NGL volumes, in addition to higher commodity prices.
          For the year ended December 31, 2007, NGL revenues increased $108.0 million, or 29% and natural gas revenues increased $22.2 million, or 161% compared to the year ended December 31, 2006. NGL sales volumes for the year increased 8% and natural gas volumes increased 163% compared to the same period of 2006. During 2007, our NGL average sales price per barrel increased $9.68 or 20% and our natural gas average sales price per Mmbtu decreased $0.05, or 1% compared to the same period of 2006. The increase in NGL volumes is primarily due to increased industrial demand experienced during 2007 and the increase in natural gas volumes is primarily due to the Woodlawn acquisition, completed in the second quarter of 2007.
          Our natural gas services segment utilizes derivative instruments to manage the risk of fluctuations in market prices for its anticipated sales of natural gas, condensate and NGLs. This activity is referred to as price risk management. For the year ended December 31, 2007, 46% of our total natural gas volumes and 53% of our total NGL volumes were hedged as compared to 53% and 64%, respectively for the year ended December 31, 2006. The impact of price risk management and marketing activities decreased total natural gas and NGL revenues $3.7 million for 2007 compared to an increase of $1.1 million in the same period of 2006.
          Costs of product sold. Our cost of products increased $121.8 million, or 33%, for the year ended December 31, 2007 compared to the same period of 2006. Of the increase, $99.6 million relates to NGLs and $22.2 million relates to natural gas. The percentage increase in NGL cost of products sold is less than our percentage increase in NGL revenues as our NGL per barrel margins increased $0.92, or 64%, primarily due to continued rising NGL prices in 2007. The percentage increase relating to natural gas cost of products sold is greater than the percentage increase in natural gas revenues, which caused our Mmbtu margins to decrease by 62%, as a result of the terms of Woodlawn’s producer contracts compared to our historical producer contracts.
          Operating expenses. Operating expenses increased $1.8 million, or 35%, for the year ended December 31, 2007 compared to the same period of 2006. This increase is primarily due to the Woodlawn acquisition.
          Selling, general and administrative expenses. Selling, general and administrative expenses increased $1.2 million, or 26%, for the year ended December 31, 2007 compared to the same period of 2006. This increase primarily is primarily due to the Woodlawn acquisition.

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          Depreciation and amortization. Depreciation and amortization increased $1.6 million, or 95%, for the year ended December 31, 2007 compared to the same period of 2006. This increase was primarily a result of the Woodlawn acquisition
          In summary, our natural gas services operating income decreased $0.1 million, or 2%, for the year ended December 31, 2007 compared to the year ended December 31, 2006.
          Equity in earnings of unconsolidated entities. Equity in earnings of unconsolidated entities was $10.9 million and $8.5 million for the year ended December 31, 2007 and 2006, respectively, an increase of 28%. This increase is primarily a result of completing the expansions to the Waskom plant and the Waskom fractionator in the first half of 2007, resulting in our inlet volumes and fractionation volumes increasing 25% and 14%, respectively.
          Marine Transportation Segment
          The following table summarizes our results of operations in our marine transportation segment.
                 
    Years Ended December 31,  
    2007     2006  
    (In thousands)  
Revenues
  $ 63,533     $ 50,174  
Operating expenses
    46,946       34,946  
Selling, general and administrative expenses
    535       587  
Depreciation and amortization
    8,819       6,609  
 
           
 
    7,233       8,032  
 
           
Other operating income
    716       226  
 
           
Operating income
  $ 7,949     $ 8,258  
 
           
          Revenues. Our marine transportation revenues increased $13.4 million, or 27%, for the year ended December 31, 2007 compared to the year ended December 31, 2006. Our inland marine assets generated an additional $12.4 million in revenue from increased utilization of our fleet as a result of a geographical redistribution of our assets on the Gulf Coast. We also had increased contract rates and operated an additional number of leased vessels. Our offshore revenues increased $1.0 million primarily from the acquisition of an integrated tug barge unit in the fourth quarter of 2006.
          Operating expenses. Operating expenses increased $12.0 million, or 34%, for the year ended December 31, 2007 compared to the year ended December 31, 2006. We experienced increases in salaries and wages, repair and maintenance expenses, increased shipyard costs and outside towing expenses.
          Selling, general and administrative expenses. Selling, general & administrative expenses were approximately the same for the year ended December 31, 2007 compared to the year ended December 31, 2006.
          Depreciation and amortization. Depreciation and amortization increased $2.2 million, or 33%, for the year ended December 31, 2007 compared to the year ended December 31, 2006. This increase was the result of capital expenditures made in the last 12 months.
          Other operating income. Other operating income increased $0.5 million, or 217%, for the year ended December 31, 2007 compared to the year ended December 31, 2006. This increase consisted of gains on the sale of property and equipment.
          In summary, our marine transportation operating income decreased $0.3 million, or 4%, for the year ended December 31, 2007 compared to the year ended December 31, 2006.

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          Sulfur Services Segment
          The following table summarizes our results of operations in our sulfur services segment.
                 
    Years Ended December 31,  
    2007     2006  
    (In thousands)  
Revenues
  $ 131,602     $ 102,646  
Cost of products sold
    97,747       76,372  
Operating expenses
    17,033       14,283  
Selling, general and administrative expenses
    2,587       2,651  
Depreciation and amortization
    5,013       4,621  
 
           
Operating income
  $ 9,222     $ 4,719  
 
           
 
               
Sulfur (long tons)
    1,169.8       836.3  
Fertilizer (long tons)
    251.1       188.9  
 
           
Sulfur Services Volumes (long tons)
    1,420.9       1,025.2  
 
           
          Revenues. Our sulfur services revenues increased $29.0 million, or 28%, for the year ended December 31, 2007 compared to the year ended December 31, 2006. This increase was primarily a result of a 39% increase in sales volume. The sales volume increase was due to a new molten sulfur sales contract negotiated in 2007 and increased demand for our sulfur-based products, driven by higher agricultural commodity prices.
          Cost of products sold. Our cost of products sold increased $21.4 million, or 28%, for the year ended December 31, 2007 compared to the year ended December 31, 2006. This percentage increase was the same as our percentage increase in sales, as our margin per ton was approximately the same for both years.
          Operating expenses. Our operating expenses increased $2.8 million, or 19%, for the year ended December 31, 2007 compared to the year ended December 31, 2006. This increase was a result of increased marine transportation costs relating to increased crew wages, outside towing expense incurred for leased vessels due to down time of vessels owned by the sulfur services segment and repairs and maintenance on vessels owned by the sulfur services segment to bring them up to higher quality standards adopted by our marine transportation group.
          Selling, general, and administrative expenses. Our selling, general, and administrative expenses decreased $0.1 million, or 2%, for the year ended December 31, 2007 compared to the year ended December 31, 2006.
          Depreciation and amortization. Depreciation and amortization increased $0.4 million, or 8%, for the year ended December 31, 2007 compared to the year ended December 31, 2006. This is attributable to our sulfuric acid facility coming online in the fourth quarter of 2007.
          In summary, our sulfur services operating income increased $4.5 million, or 95%, for the year ended December 31, 2007 compared to the year ended December 31, 2006
          Statement of Operations Items as a Percentage of Revenues
          In the aggregate, our cost of products sold, operating expenses, selling, general and administrative expenses, and depreciation and amortization have remained relatively constant as a percentage of revenues for the years ended December 31, 2007 and December 31, 2006. The following table summarizes, on a comparative basis, these items of our statement of operations as a percentage of our revenues.
                 
    Years Ended December 31,
    2007   2006
    (In thousands)
Revenues
    100 %     100 %
Cost of products sold
    81 %     80 %
Operating expenses
    11 %     11 %
Selling, general and administrative expenses
    2 %     2 %
Depreciation and amortization
    3 %     3 %
          Equity in Earnings of Unconsolidated Entities
          For the years ended December 31, 2007 and 2006, equity in earnings of unconsolidated entities relates to our unconsolidated interest in BCP subsequent to its acquisition on June 30, 2006 and the unconsolidated interests in Waskom, Matagorda and PIPE.

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          Interest Expense
          Our interest expense for all operations was $14.5 million for 2007 compared to $13.6 million for 2006, an increase of $0.9 million, or 7%. This increase was primarily due to an increase in average debt outstanding offset by a decrease in interest rates throughout 2007 compared to 2006 which also included a debt prepayment premium of $1.2 million. Also, we had non-cash mark-to-market charges of $0.8 million which increased interest expense in 2007.
          Indirect Selling, General and Administrative Expenses
          Indirect selling, general and administrative expenses were $3.2 million for 2007 compared to $3.3 million for 2006, a decrease of $0.1 million or 2%.
          Martin Resource Management allocated to us a portion of its indirect selling, general and administrative expenses for services such as accounting, treasury, clerical billing, information technology, administration of insurance, engineering, general office expense and employee benefit plans and other general corporate overhead functions we share with Martin Resource Management retained businesses. This allocation is based on the percentage of time spent by Martin Resource Management personnel that provide such centralized services. Generally accepted accounting principles also permit other methods for allocation of these expenses, such as basing the allocation on the percentage of revenues contributed by a segment. The allocation of these expenses between Martin Resource Management and us is subject to a number of judgments and estimates, regardless of the method used. We can provide no assurances that our method of allocation, in the past or in the future, is or will be the most accurate or appropriate method of allocation these expenses. Other methods could result in a higher allocation of selling, general and administrative expense to us, which would reduce our net income.
          Under the omnibus agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. The amount of this reimbursement was capped at $2.0 million through November 1, 2007 when the cap expired. For both the years ended December 31, 2007 and 2006, the Conflicts Committee of our general partner approved reimbursement amounts of $1.5 million 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.
Liquidity and Capital Resources
          Impact of Current Economic Crisis
          We believe that cash generated from operations and our borrowing capacity under our credit facility will be sufficient to meet our working capital requirements, anticipated maintenance capital expenditures and scheduled debt payments in 2009. However, current economic conditions, including wide fluctuations in commodity prices and deteriorating credit markets, have created constraints on liquidity within the capital markets and the ability to obtain credit in the markets. Due to restrictions on liquidity within the capital markets and existing litigation at Martin Resource Managment (See “Item 9B. Other Information”) we expect our ability to access the capital markets to remain constrained over the next twelve months. Our near-term focus is to ensure we have sufficient liquidity to fund our growth programs, while continuing the present distribution rate to our unitholders. The current economic crisis has created a challenging operating environment for us to maintain our liquidity and operating cash flows at levels consistent with the recent past while maintaining the present distribution rate to our unitholders. We continue to evaluate our liquidity and capital resources and may consider sales of non-performing or non-core assets for additional liquidity.
          We intend to move forward with our commercially supported internal growth projects. Our ability to access the capital markets to fund new projects in the future at prices that make the proposed projects accretive is likely to be limited. We may revise the timing and scope of other projects as necessary to adapt to existing economic conditions and the incremental benefits expected to accrue to our unitholders from our expansion activities are likely to be decreased by substantial cost of capital increases during this period.
          In addition, if there is need to access the credit markets and the credit markets do not improve, we cannot assure you that we would be able to secure additional financing if needed, and, if such funds were available, whether the terms or conditions would be acceptable to us.
          Finally, our ability to satisfy our working capital requirements, to fund planned capital expenditures and to satisfy our debt service obligations will depend upon our future operating performance, which is subject to certain risks. For example, the impact of the current economic crisis may significantly affect our customers, including their ability to satisfy receivables owed to us on a timely basis. Please read “Item 1A. Risk Factors — Risks Related to Our Business” for a discussion of such risks.

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          General
          In 2008, cash increased $3.9 million as a result of $79.9 million provided by operating activities, $100.2 million used in investing activities and $24.2 million provided by financing activities. In 2007, cash increased $0.8 million as a result of $58.0 million provided by operating activities, $127.1 million used in investing activities and $69.9 million provided by financing activities. In 2006, cash decreased $2.8 million as a result of $39.3 million provided by operating activities, $95.1 million used in investing activities and $53.0 million provided by financing activities.
          For 2008, our investing activities of $100.2 million consisted primarily of capital expenditures, acquisitions, proceeds from sale of property, insurance proceeds from involuntary conversion of property, plant and equipment, and investments in and returns of investments from unconsolidated partnerships. Our investment in unconsolidated partnerships helped to fund $0.9 million and $5.2 million in expansion capital expenditures made by these unconsolidated entities for the fourth quarter and year ended December 31, 2008, respectively. For 2007, our investing activities of $127.1 million consisted primarily of capital expenditures, acquisitions, proceeds from sale of property, and investments in and returns of investments from unconsolidated partnerships. Our investment in unconsolidated partnerships helped to fund $1.2 million and $8.2 million in expansion capital expenditures made by these unconsolidated entities for the fourth quarter and year ended December 31, 2007, respectively. For 2006, our investing activities of $95.1 million consisted primarily of capital expenditures, acquisitions, proceeds from sale of property, insurance proceeds from involuntary conversion of property, plant and equipment, and investments in and returns of investments from unconsolidated partnerships.
          For 2008, 2007 and 2006 our capital expenditures for property and equipment were $101.0 million, $118.2 million, and $90.7 million, respectively.
          As to each period:
    In 2008, we spent $84.4 million for expansion and $16.5 million for maintenance (including $6.6 million for maintenance in the fourth quarter of 2008). Our expansion capital expenditures were made in connection with marine vessel purchases and conversions, construction projects associated with our terminalling business. Our maintenance capital expenditures were primarily made in our marine transportation segment for routine dry dockings of our vessels pursuant to the United States Coast Guard requirements and in our terminalling and sulfur services at our Neches facility, where $1.5 million in maintenance capital expenditures was spent in connection with restoration of assets destroyed in Hurricanes Gustav and Ike.
 
    In 2007, we spent $107.9 million for expansion and $10.3 million for maintenance (including $3.7 million for maintenance in the fourth quarter of 2007). Our expansion capital expenditures were made in connection with the Woodlawn and Mega Lube acquisitions, marine vessel purchases and conversions, construction projects associated with our terminalling business, and the sulfuric acid plant construction project at our facility in Plainview, Texas. Our maintenance capital expenditures were primarily made in our marine transportation segment for routine dry dockings of our vessels pursuant to the United States Coast Guard requirements and include $0.3 million spent in connection with the restoration of assets destroyed in hurricanes Rita and Katrina.
 
    In 2006, we spent $78.3 million for expansion and $12.4 million for maintenance. Our expansion capital expenditures were made in connection with our marine vessel purchases, acquiring assets relating to the South Houston and Prime Asphalt terminal acquisitions, the Corpus Christi barge terminal, the sulfur priller construction project at our Neches facility in Beaumont, Texas, and the sulfuric acid plant construction project at our facility in Plainview, Texas. Our maintenance capital expenditures were primarily made in our marine transportation segment for routine dry dockings of our vessels pursuant to the United States Coast Guard requirements and in our terminal segment for terminal facilities where $4.7 million in maintenance capital expenditures was spent in connection with restoration of assets destroyed in Hurricanes Rita and Katrina.
          In 2008, our financing activities consisted of cash distributions paid to common and subordinated unitholders of $45.7 million, purchase of treasury stock of $0.1 million, payments of long-term debt under our current and predecessor credit facilities of $257.2 million and borrowings of long-term debt under our current and predecessor credit facilities of $327.2 million and payments of debt issuance costs of $18k.
          In 2007, our financing activities consisted of cash distributions paid to common and subordinated unitholders of $37.9 million, net proceeds from a follow-on public equity offering of $55.9 million, contributions of $1.2 million from our general partner to maintain its 2% general partner interest, payments of long-term debt under our current and predecessor credit facilities of $169.0 million and borrowings of long-term debt under our current and predecessor credit facilities of $220.0 million and payments of debt issuance costs of $0.3 million.

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          In 2006, our financing activities consisted of cash distributions paid to common and subordinated unitholders of $32.1 million, net proceeds from a follow-on public equity offering of $95.3 million, net proceeds from the issuance of common units of $15.0 million, contributions of $2.4 million from our general partner to maintain its 2% general partner interest, payments of long-term debt under our current and predecessor credit facilities of $163.0 million and borrowings of long-term debt under our current and predecessor credit facilities of $135.8 million and payments of debt issuance costs of $0.4 million.
          Capital Resources
     Historically, we have generally satisfied our working capital requirements and funded our capital expenditures with cash generated from operations and borrowings. We expect our primary sources of funds for short-term liquidity needs will be cash flows from operations and borrowings under our credit facility.
     As of December 31, 2008, we had $295.0 million of outstanding indebtedness, consisting of outstanding borrowings of $165.0 million under our revolving credit facility and $130.0 million under our term loan facility.
     On January 22, 2008, we financed the Stanolind asset acquisition through approximately $6.0 million in borrowings under our revolving credit facility.
     On October 2, 2007, we financed the Monarch acquisition through approximately $3.9 million in borrowings under our revolving credit facility.
     On June 13, 2007, we financed the Mega Lube acquisition through approximately $4.6 million in borrowings under our revolving credit facility.
     On May 2, 2007, we financed the Woodlawn acquisition through approximately $33.0 million in borrowings under our revolving credit facility.
     In May 2007, we completed a follow-on public offering of 1,380,000 common units, resulting in proceeds of $56.0 million, after payment of underwriters’ discounts, commissions, and offering expenses. Our general partner contributed $1.2 million in cash to us in conjunction with the offering in order to maintain its 2% general partner interest in us. The net proceeds were used to pay down revolving debt under our credit facility and to provide working capital.
     Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of December 31, 2008 is as follows (dollars in thousands):
                                         
    Payment due by period  
    Total     Less than     1-3     3-5        
Type of Obligation   Obligation     One Year     Years     Years     Due Thereafter  
Long-Term Debt
                                       
Revolving credit facility
  $ 165,000     $     $ 165,000     $     $  
Term loan facility
    130,000             130,000              
Other
                             
Non-competition agreements
    500       250       100       100       50  
Operating leases
    26,361       3,814       10,297       4,782       7,468  
Interest expense(1)
                                       
Revolving Credit Facility
    17,096       9,145       7,951              
Term loan facility
    15,898       8,504       7,394              
Other
                             
 
                             
 
                                       
Total contractual cash obligations
  $ 354,855     $ 21,713     $ 320,742     $ 4,882     $ 7,518  
 
                             
 
(1)   Interest commitments are estimated using our current interest rates for the respective credit agreements over their remaining terms.

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     Letter of Credit At December 31, 2008, we had an outstanding irrevocable letter of credit in the amount of $0.1 million which was issued under our revolving credit facility. This letter of credit was issued to the Texas Commission on Environmental Quality to provide financial assurance for our used oil handling program.
     Off Balance Sheet Arrangements. We do not have any off-balance sheet financing arrangements.
          Description of Our Credit Facility
          On November 10, 2005, we entered into a new $225.0 million multi-bank credit facility comprised of a $130.0 million term loan facility and a $95.0 million revolving credit facility, which includes a $20.0 million letter of credit sub-limit. Our credit facility also includes procedures for additional financial institutions to become revolving lenders, or for any existing revolving lender to increase its revolving commitment, subject to a maximum of $100.0 million for all such increases in revolving commitments of new or existing revolving lenders. Effective June 30, 2006, we increased our revolving credit facility $25.0 million resulting in a committed $120.0 million revolving credit facility. Effective December 28, 2007, we increased our revolving credit facility $75.0 million resulting in a committed $195.0 million revolving credit facility. The revolving credit facility is used for ongoing working capital needs and general partnership purposes, and to finance permitted investments, acquisitions and capital expenditures. Under the amended and restated credit facility, as of December 31, 2008, we had $165.0 million outstanding under the revolving credit facility and $130.0 million outstanding under the term loan facility. As of December 31, 2008, we had $29.9 million available under our revolving credit facility.
          On July 14, 2005, we issued a $0.1 million irrevocable letter of credit to the Texas Commission on Environmental Quality to provide financial assurance for its used oil handling program.
          Draws made under our credit facility are normally made to fund acquisitions and for working capital requirements. During the current fiscal year, draws on our credit facilities have ranged from a low of $225.0 million to a high of $319.1 million. As of December 31, 2008, we had $29.9 million available for working capital, internal expansion and acquisition activities under our credit facility.
          Our obligations under the credit facility are secured by substantially all of our assets, including, without limitation, inventory, accounts receivable, marine vessels, equipment, fixed assets and the interests in our operating subsidiaries and equity method investees. We may prepay all amounts outstanding under this facility at any time without penalty.
          Indebtedness under the credit facility bears interest at either LIBOR plus an applicable margin or the base prime rate plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 1.50% to 3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 0.50% to 2.00%. The applicable margin for term loans that are LIBOR loans ranges from 2.00% to 3.00% and the applicable margin for term loans that are base prime rate loans ranges from 1.00% to 2.00%. The applicable margin for existing LIBOR borrowings is 2.50%. Effective January 1, 2009, the applicable margin for existing LIBOR borrowings will decrease to 2.00%. As a result of our leverage ratio test, effective April 1, 2009, the applicable margin for existing LIBOR borrowings will remain at 2.00%. We incur a commitment fee on the unused portions of the credit facility.
          Effective October 2008, we entered into an interest rate swap that swaps $40.0 million of floating rate to fixed rate. The fixed rate cost is 2.820% plus our applicable LIBOR borrowing spread. This interest rate swap which matures in October 2010 is accounted for using hedge accounting.
          Effective January 2008, we entered into an interest rate swap that swaps $25.0 million of floating rate to fixed rate. The fixed rate cost is 3.400% plus our applicable LIBOR borrowing spread. This interest rate swap which matures in January 2010 is accounted for using hedge accounting.
          Effective September 2007, we entered into a cash flow hedge that swaps $25,000 of floating rate to fixed rate. The fixed rate cost is 4.605% plus our applicable LIBOR borrowing spread. The cash flow hedge matures in September 2010 is accounted for using hedge accounting.

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          Effective November 2006, we entered into an interest rate swap that swaps $40.0 million of floating rate to fixed rate. The fixed rate cost is 4.82% plus our applicable LIBOR borrowing spread. This interest rate swap which matures in December 2009 is accounted for using hedge accounting.
          Effective November 2006, we entered into an interest rate swap that swaps $30.0 million of floating rate to fixed rate. The fixed rate cost is 4.765% plus our applicable LIBOR borrowing spread. This interest rate swap, which matures in March 2010, is not accounted for using hedge accounting.
          Effective March 2006, we entered into an interest rate swap that swaps $75.0 million of floating rate to fixed rate. The fixed rate cost is 5.25% plus our applicable LIBOR borrowing spread. This interest rate swap which matures in November 2010 is accounted for using hedge accounting.
          In addition, the credit facility contains various covenants, which, among other things, limit our ability to: (i) incur indebtedness; (ii) grant certain liens; (iii) merge or consolidate unless we are the survivor; (iv) sell all or substantially all of our assets; (v) make certain acquisitions; (vi) make certain investments; (vii) make certain capital expenditures; (viii) make distributions other than from available cash; (ix) create obligations for some lease payments; (x) engage in transactions with affiliates; (xi) engage in other types of business; and (xii) our joint ventures to incur indebtedness or grant certain liens.
          The credit facility also contains covenants, which, among other things, require us to maintain specified ratios of: (i) minimum net worth (as defined in the credit facility) of $75.0 million plus 50% of net proceeds from equity issuances after November 10, 2005; (ii) EBITDA (as defined in the credit facility) to interest expense of not less than 3.0 to 1.0 at the end of each fiscal quarter; (iii) total funded debt to EBITDA of not more than 4.75 to 1.00 for each fiscal quarter; and (iv) total secured funded debt to EBITDA of not more than 4.00 to 1.00 for each fiscal quarter. We are in compliance with the debt covenants contained in the credit facility for the years ended December 31, 2008 and 2007.
          The credit facility also contains certain default provisions relating to Martin Resource Management. If Martin Resource Management no longer controls our general partner, the lenders under our credit facility may declare all amounts outstanding thereunder immediately due and payable. In addition, an event of default by Martin Resource Management under its credit facility could independently result in an event of default under our credit facility if it is deemed to have a material adverse effect on us. Any event of default and corresponding acceleration of outstanding balances under our credit facility could require us to refinance such indebtedness on unfavorable terms and would have a material adverse effect on our financial condition and results of operations as well as our ability to make distributions to unitholders.
          On November 10 of each year, commencing with November 10, 2006, we must prepay the term loans under the credit facility with 75% of Excess Cash Flow (as defined in the credit facility), unless its ratio of total funded debt to EBITDA is less than 3.00 to 1.00. No prepayments under the term loan were required to be made in 2008 and 2007. If we receive greater than $15.0 million from the incurrence of indebtedness other than under the credit facility, we must prepay indebtedness under the credit facility with all such proceeds in excess of $15.0 million. Any such prepayments are first applied to the term loans under the credit facility. We must prepay revolving loans under the credit facility with the net cash proceeds from any issuance of its equity. We must also prepay indebtedness under the credit facility with the proceeds of certain asset dispositions. Other than these mandatory prepayments, the credit facility requires interest only payments on a quarterly basis until maturity. All outstanding principal and unpaid interest must be paid by November 10, 2010. The credit facility contains customary events of default, including, without limitation, payment defaults, cross-defaults to other material indebtedness, bankruptcy-related defaults, change of control defaults and litigation-related defaults.
          As of March 3, 2009, our outstanding indebtedness includes $310.0 million under our credit facility.
Seasonality
          A substantial portion of our revenues are dependent on sales prices of products, particularly NGLs and sulfur-based fertilizer products, which fluctuate in part based on winter and spring weather conditions. The demand for NGLs is strongest during the winter heating season. The demand for fertilizers is strongest during the early spring planting season. However, our terminalling and storage and marine transportation businesses and the molten sulfur business are typically not impacted by seasonal fluctuations. We expect to derive approximately half of our net income from our terminalling and storage, marine transportation, natural gas and sulfur businesses. Therefore, we do not expect that our overall net income will be impacted by seasonality factors. However, extraordinary weather events, such as hurricanes, have in the past, and could in the future, impact our terminalling and storage and marine transportation businesses. For example, Hurricanes Gustav and Ike in the third quarter of 2008 and Hurricanes Katrina and Rita in the third quarter of 2005 adversely impacted our operating expenses and adversely impacted our terminalling and storage and marine transportation business’s revenues.

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Impact of Inflation
          Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations in 2008, 2007 and 2006. However, inflation remains a factor in the United States economy and could increase our cost to acquire or replace property, plant and equipment as well as our labor and supply costs. We cannot assure our unitholders that we will be able to pass along increased costs to our customers.
          Increasing energy prices could adversely affect our results of operations. Diesel fuel, natural gas, chemicals and other supplies are recorded in operating expenses. An increase in price of these products would increase our operating expenses which could adversely affect net income. We cannot assure our unitholders that we will be able to pass along increased operating expenses to our customers.
Environmental Matters
          Our operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. We incurred no significant environmental costs, liabilities or expenditures to mitigate or eliminate environmental contamination during 2008, 2007 or 2006.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
          Market risk is the risk of loss arising from adverse changes in market rates and prices. We are exposed to market risks associated with commodity prices, counterparty credit and interest rates. Historically, we have not engaged in commodity contract trading or hedging activities. However, in connection with our acquisition of Prism Gas, we have established a hedging policy. For the year ended December 31, 2008, changes in the fair value of our derivative contracts were recorded both in earnings and accumulated other comprehensive income (“AOCI”) since we have designated a portion of our derivative instruments as hedges as of December 31, 2008.
Commodity Price Risk
          We are exposed to market risks associated with commodity prices, counterparty credit and interest rates. Historically, we have not engaged in commodity contract trading or hedging activities. Under our hedging policy, we monitor and manage the commodity market risk associated with our commodity risk exposure. In addition, we are focusing on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction.
          We use derivatives to manage the risk of commodity price fluctuations. Our counterparties to the commodity derivative contracts include Shell Energy North America (US), L.P., Morgan Stanley Capital Group Inc. and Wachovia Bank.
          On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, and have established a maximum credit limit threshold pursuant to our hedging policy and monitor the appropriateness of these limits on an ongoing basis. Currently, we have entered into these derivative transactions with an investment grade subsidiary of a major oil company and investment grade banks. While we anticipate that future derivative transactions will be entered into with investment grade counterparties, and that we will actively monitor the credit rating of such counterparties, it is nevertheless possible that losses will result from counterparty credit risk in the future. Such risks may be more likely due to the worldwide financial and credit crisis.
          We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of gathering, processing and sales activities. Gathering and processing revenues are earned under various contractual arrangements with gas producers. Gathering revenues are generated through a combination of fixed-fee and index-related arrangements. Processing revenues are generated primarily through contracts which provide for processing on POL and POP basis. Prism Gas has entered into hedging transactions through 2010 to protect a portion of its commodity exposure from these contracts. These hedging arrangements are in the form of swaps for crude oil, natural gas, and natural gasoline.

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          In October 2008, we elected to discontinue hedge accounting treatment for certain crude oil derivative contracts. The impact to the Consolidated Statement of Operations was a mark to market gain of $1.8 million for the year ended December 31, 2008.
          In December 2008, we terminated three commodity swap agreements resulting in a cash receipt from the counterparty of $1.9 million. These swap agreements were accounted for as cash flow hedges. As a result of the termination, a gain of $0.4 million was recorded to the Partnership’s Consolidated Statement of Operations for the year ended December 31, 2008.
          As a result of declining commodity prices, we determined that continued reporting of losses in AOCI for certain commodity hedges would lead to recognizing a net loss on the combination of the hedging instrument and the hedge transaction in future periods. Accordingly, the calculated loss of $2.6 million was immediately classified into 2008 earnings. The remaining deferred gains of $1.5 million and deferred losses of $0.1 million pertaining to the above commodity hedges will remain in AOCI and are expected to be reclassified into earnings in the same period that the forecasted hedge transaction is reported in earnings.
          Based on estimated volumes, as of December 31, 2008, Prism Gas had hedged approximately 47% and 21% of its commodity risk by volume for 2009 and 2010, respectively. As of December 31, 2008, commodity derivative assets of $3.6 million were included in current assets and $1.5 million were included in non-current assets on the balance sheet. We anticipate entering into additional commodity derivatives on an ongoing basis to manage risk associated with these market fluctuations, and will consider using various commodity derivatives, including forward contracts, swaps, collars, futures and options, although there is no assurance that we will be able to do so or that the terms thereof will be similar to our existing hedging arrangements. In addition, we will enter into derivative arrangements that include the specific NGL products as well as natural gas and crude oil.
Hedging Arrangements in Place
As of December 31, 2008
                 
Year   Commodity Hedged   Volume   Type of Derivative   Basis Reference
2009
  Natural Gas   30,000 MMBTU/Month   Natural Gas Swap ($9.025)   Columbia Gulf
2009
  Condensate & Natural Gasoline   3,000 BBL/Month   Crude Oil Swap ($69.08)   NYMEX
2009
  Natural Gasoline   3,000 BBL/Month   Crude Oil Swap ($70.90)   NYMEX
2009
  Condensate   1,000 BBL/Month   Crude Oil Swap ($70.45)   NYMEX
2009
  Natural Gasoline   2,000 BBL/Month   Natural Gasoline Swap ($86.42)   Mt. Belvieu (Non-TET)
2010
  Condensate   2,000 BBL/Month   Crude Oil Swap ($69.15)   NYMEX
2010
  Natural Gasoline   3,000 BBL/Month   Crude Oil Swap ($72.25)   NYMEX
2010
  Condensate   1,000 BBL/Month   Crude Oil Swap ($104.80)   NYMEX
2010
  Natural Gasoline   1,000 BBL/Month   Natural Gasoline Swap ($94.14)   Mt. Belvieu (Non-TET)
          Our principal customers with respect to Prism Gas’ natural gas gathering and processing services are large, natural gas marketing services, oil and gas producers and industrial end-users. In addition, substantially all of our natural gas and NGL sales are made at market-based prices. Our standard gas and NGL sales contracts contain adequate assurance provisions which allows for the suspension of deliveries, cancellation of agreements or continuance of deliveries to the buyer after the buyer provides security for payment in a form satisfactory to us. For additional information regarding our hedging activities, please see “Note 16 — Commodity Cash Flow Hedges” in our “Notes to Consolidated Financial Statements” contained herein.
Interest Rate Risk
          We are exposed to changes in interest rates as a result of our credit facility, which had a weighted-average interest rate of 6.48% as of December 31, 2008. We had a total of $295.0 million of indebtedness outstanding under our credit facility as of the date hereof of which $60.0 million was unhedged floating rate debt. Based on the amount of unhedged floating rate debt owed by us on December 31, 2008, the impact of a 1% increase in interest rates on this amount of debt would result in an increase in interest expense and a corresponding decrease in net income of approximately $0.6 million annually. We have 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. There is considerable turmoil in the world economy and banking markets 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.

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          As of March 3, 2009, we had a total of $310.0 million of indebtedness outstanding under our credit facility. The impact of a 1% increase in interest rates on this amount of unhedged floating rate debt would result in an increase in interest expense, and a corresponding decrease in net income of approximately $3.0 million annually.

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Item 8. Financial Statements and Supplementary Data
The following financial statements of Martin Midstream Partners L.P. (Partnership):
         
    Page
    70  
 
       
    71  
 
       
    72  
 
       
    73  
 
       
    74  
 
       
    75  
 
       
    76  
 
       
    77  

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Report of Independent Registered Public Accounting Firm
The Board of Directors
Martin Midstream GP LLC:
          We have audited the accompanying consolidated balance sheets of Martin Midstream Partners L.P. and subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements of operations, changes in capital, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2008. These financial statements are the responsibility of Martin Midstream’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
          We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
          In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Martin Midstream Partners L.P. and subsidiaries and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.
          We also have audited, in accordance with the standards of the Public Accounting Oversight Board (United States), Martin Midstream Partners L.P. and subsidiaries’ internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 4, 2009 expressed an unqualified opinion on the effectiveness of Martin Midstream Partners L.P. and subsidiaries’ internal control over financial reporting.
KPMG LLP
/s/ KPMG LLP
Shreveport, Louisiana
March 4, 2009

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Report of Independent Registered Public Accounting Firm
The Board of Directors
Martin Midstream GP LLC:
          We have audited Martin Midstream Partners L.P. and subsidiaries’ internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Martin Midstream’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting in Item 9A(b). Our responsibility is to express an opinion on Martin Midstream’s internal control over financial reporting based on our audit.
          We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
          A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
          Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
          In our opinion, Martin Midstream Partners L.P. and subsidiaries maintained, in all respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issue by the Committee of Sponsoring Organizations of the Treadway Commission.
          We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Martin Midstream Partners L.P. and subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements of operations, changes in capital, comprehensive income, and cash flows for each of the years in the three year period ended December 31, 2008 and our report dated March 4, 2009 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
KPMG LLP
Shreveport, Louisiana
March 4, 2009

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MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
                 
    December 31,  
    2008     2007  
    (Dollars in thousands)  
Assets
               
 
               
Cash
  $ 7,983     $ 4,113  
Accounts and other receivables, less allowance for doubtful accounts of $481 and $394
    68,117       88,039  
Product exchange receivables
    6,924       10,912  
Inventories
    42,461       51,798  
Due from affiliates
    555       2,325  
Fair value of derivatives
    3,623       235  
Other current assets
    1,079       584  
 
           
Total current assets
    130,742       158,006  
 
           
 
               
Property, plant, and equipment, at cost
    537,381       441,117  
Accumulated depreciation
    (125,256 )     (98,080 )
 
           
Property, plant and equipment, net
    412,125       343,037  
 
           
 
               
Goodwill
    37,405       37,405  
Investment in unconsolidated entities
    79,843       75,690  
Fair value of derivatives
    1,469        
Other assets, net
    7,332       9,439  
 
           
 
  $ 668,916     $ 623,577  
 
           
 
               
Liabilities and Capital
               
 
               
Current installments of long-term debt
  $     $ 21  
Trade and other accounts payable
    87,382       104,598  
Product exchange payables
    10,924       24,554  
Due to affiliates
    13,420       7,543  
Income taxes payable
    414       602  
Fair value of derivatives
    6,478       4,502  
Other accrued liabilities
    6,077       4,752  
 
           
Total current liabilities
    124,695       146,572  
 
               
Long-term debt
    295,000       225,000  
Deferred income taxes
    8,538       8,815  
Fair value of derivatives
    4,302       5,576  
Other long-term obligations
    1,667       1,766  
 
           
Total liabilities
    434,202       387,729  
 
           
 
               
Partners’ capital
    239,649       242,610  
Accumulated other comprehensive income (loss)
    (4,935 )     (6,762 )
 
           
Total partners’ capital
    234,714       235,848  
 
           
Commitments and contingencies
  $ 668,916     $ 623,577  
 
           
See accompanying notes to consolidated financial statements.

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MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
                         
    Year Ended December 31,  
    2008     2007     2006  
    (Dollars in thousands, except per unit  
    amounts)  
Revenues:
                       
Terminalling and storage
  $ 36,067     $ 29,400     $ 24,182  
Marine transportation
    76,349       59,579       47,835  
Product sales:
                       
Natural gas services
    679,375       515,992       389,735  
Sulfur services
    371,949       131,326       102,597  
Terminalling and storage
    50,218       29,525       12,035  
 
                 
 
    1,101,542       676,843       504,367  
 
                 
Total revenues
    1,213,958       765,822       576,384  
 
                 
 
                       
Costs and expenses:
                       
Cost of products sold:
                       
Natural gas services
    657,662       495,641       374,218  
Sulfur services
    313,142       97,577       75,165  
Terminalling and storage
    42,721       25,471       9,787  
 
                 
 
    1,013,525       618,689       459,170  
 
                       
Expenses:
                       
Operating expenses
    102,894       83,533       65,387  
Selling, general and administrative
    16,939       11,985       10,977  
Depreciation and amortization
    31,218       23,442       17,597  
 
                 
Total costs and expenses
    1,164,576       737,649       553,131  
 
                 
Other operating income
    209       703       3,356  
 
                 
Operating income
    49,591       28,876       26,609  
 
                 
 
                       
Other income (expense):
                       
Equity in earnings of unconsolidated entities
    13,224       10,941       8,547  
Interest expense
    (19,777 )     (14,533 )     (12,466 )
Debt prepayment premium
                (1,160 )
Other, net
    483       299       713  
 
                 
Total other income (expense)
    (6,070 )     (3,293 )     (4,366 )
 
                 
Net income before taxes
    43,521       25,583       22,243  
Income taxes
    711       644        
 
                 
Net income
  $ 42,810     $ 24,939     $ 22,243  
 
                 
 
                       
General partner’s interest in net income
  $ 3,301     $ 1,564     $ 949  
Limited partners’ interest in net income
  $ 39,509     $ 23,375     $ 21,294  
 
                       
Net income per limited partner unit — basic and diluted
  $ 2.72     $ 1.67     $ 1.69  
 
                       
Weighted average limited partner units — basic
    14,529,826       14,018,799       12,602,000  
Weighted average limited partner units — diluted
    14,534,722       14,022,545       12,604,425  
See accompanying notes to consolidated financial statements.

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MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CHANGES IN CAPITAL
For the years ended December 31, 2008, 2007 and 2006
                                                         
    Partners’ Capital     Accumulated        
    Limited Partners     General     Comprehensive        
    Common     Subordinated     Partner     Income        
    Units     Amount     Units     Amount     Amount     Amount     Total  
    (Dollars in thousands)  
Balances – December 31, 2005
    5,829,652     $ 100,206       3,402,690     $ (5,642 )   $ 1,001           $ 95,565  
Net income
          16,069             5,225       949             22,243  
Follow-on public offering
    3,450,000       95,272                               95,272  
Issuance of common units
    470,484       15,000                               15,000  
General partner contribution
                            2,358             2,358  
Conversion of subordinated units to common units
    850,672       (2,495 )     (850,672 )     2,495                    
Unit-based compensation
    3,000       24                               24  
Cash distributions ($2.44 per unit)
          (22,650 )           (8,302 )     (1,107 )           (32,059 )
Commodity hedging gains reclassified to earnings
                                  2       2  
Adjustment in fair value of derivatives
                                  120       120  
 
                                         
Balances – December 31, 2006
    10,603,808     $ 201,426       2,552,018     $ (6,224 )   $ 3,201     $ 122     $ 198,525  
Net Income
          19,781             3,594       1,564             24,939  
Follow-on public offering
    1,380,000       55,933                               55,933  
General partner contribution
                            1,192             1,192  
Conversion of subordinated units to common units
    850,672       (3,243 )     (850,672 )     3,243                    
Unit-based compensation
    3,000       46                               46  
Cash distributions ($2.60 per unit)
          (29,423 )           (6,635 )     (1,845 )           (37,903 )
Commodity hedging gains reclassified to earnings
                                  478       478  
Adjustment in fair value of derivatives
                                  (7,362 )     (7,362 )
 
                                         
Balances – December 31, 2007
    12,837,480     $ 244,520       1,701,346     $ (6,022 )   $ 4,112     $ (6,762 )   $ 235,848  
Net Income
          34,978             4,531       3,301             42,810  
Cash distributions ($2.91 per unit)
          (37,357 )           (4,951 )     (3,409 )           (45,717 )
Conversion of subordinated units to common units
    850,672       (2,754 )     (850,672 )     2,754                    
Unit-based compensation
    3,000       39                               39  
Purchase of treasury units
    (3,000 )     (93 )                             (93 )
Adjustment in fair value of derivatives
                                  1,827       1,827  
 
                                         
Balances – December 31, 2008
    13,688,152     $ 239,333       850,674     $ (3,688 )   $ 4,004     $ (4,935 )   $ 234,714  
 
                                         
See accompanying notes to consolidated financial statements.

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MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in thousands)
                         
    Year Ended December 31,  
    2008     2007     2006  
    (Dollars in thousands)  
Net income
  $ 42,810     $ 24,939     $ 22,243  
 
                       
Changes in fair values of commodity cash flow hedges
    4,219       (3,569 )     370  
Cash flow hedging gains reclassified to earnings
    3,043       478       2  
Changes in fair value of interest rate cash flow hedges
    (5,435 )     (3,793 )     (250 )
 
                 
 
                       
Comprehensive income
  $ 44,637     $ 18,055     $ 22,365  
 
                 
     See accompanying notes to consolidated financial statements.

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MARTIN MIDSTREAM PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
                         
    Year Ended December 31,  
    2008     2007     2006  
    (Dollars in thousands)  
Cash flows from operating activities:
                       
Net income
  $ 42,810     $ 24,939     $ 22,243  
 
                       
Adjustments to reconcile net income to net cash provided by operating activities:
                       
Depreciation and amortization
    31,218       23,442       17,597  
Amortization of deferred debt issue costs
    1,120       1,233       1,040  
Deferred income taxes
    (277 )     (149 )      
Gain on disposition or sale of property, plant, and equipment
    (144 )     (703 )     (231 )
Gain on involuntary conversion of property, plant, and equipment
    (65 )           (3,125 )
Equity in earnings of unconsolidated entities
    (13,224 )     (10,941 )     (8,547 )
Distributions from unconsolidated entities
    500       1,523       541  
Distribution in-kind from unconsolidated entities
    9,725       9,337       8,311  
Non-cash mark-to-market on derivatives
    (2,328 )     3,904       (389 )
Other
    39       46       24  
Change in current assets and liabilities, excluding effects of acquisitions and dispositions:
                       
Accounts and other receivables
    19,754       (27,066 )     13,763  
Product exchange receivables
    3,988       (3,836 )     (4,935 )
Inventories
    9,337       (18,297 )     890  
Due from affiliates
    1,770       (995 )     145  
Other current assets
    (495 )     198       115  
Trade and other accounts payable
    (17,216 )     47,535       (13,937 )
Product exchange payables
    (13,630 )     9,817       5,113  
Due to affiliates
    5,877       (2,931 )     6,982  
Income taxes payable
    (188 )     245        
Other accrued liabilities
    1,325       870       (5,912 )
Change in other non-current assets and liabilities
    7       (154 )     (386 )
 
                 
Net cash provided by operating activities
    79,903       58,017       39,302  
 
                 
 
                       
Cash flows from investing activities:
                       
Payments for property, plant, and equipment
    (94,969 )     (82,164 )     (66,352 )
Acquisitions, net of cash acquired
    (5,983 )     (41,271 )     (24,306 )
Proceeds from sale of property, plant, and equipment
    419       1,290       1,825  
Insurance proceeds from involuntary conversion of property, plant and equipment
    1,503             4,812  
Return of investments from unconsolidated entities
    1,225       1,952       433  
Distributions from (contributions to) unconsolidated entities for operations
    (2,379 )     (6,910 )     (11,510 )
 
                 
Net cash used in investing activities
    (100,184 )     (127,103 )     (95,098 )
 
                 
Cash flows from financing activities:
                       
Payments of long-term debt
    (257,191 )     (169,024 )     (163,010 )
Proceeds from long-term debt
    327,170       219,950       135,801  
Net proceeds from follow on public offering
          55,933       95,272  
General partner contribution
          1,192       2,358  
Purchase of treasury units
    (93 )            
Proceeds from issuance of common units
                15,000  
Payments of debt issuance costs
    (18 )     (252 )     (371 )
Cash distributions paid
    (45,717 )     (37,903 )     (32,059 )
 
                 
Net cash provided by financing activities
    24,151       69,896       52,991  
 
                 
 
                       
Net increase(decrease) in cash
    3,870       810       (2,805 )
Cash at beginning of period
    4,113       3,303       6,108  
 
                 
 
                       
Cash at end of period
  $ 7,983     $ 4,113     $ 3,303  
 
                 
          See accompanying notes to consolidated financial statements.

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in Thousands)
(1) ORGANIZATION AND DESCRIPTION OF BUSINESS
          Martin Midstream Partners L.P. (the “Partnership”) is a publicly traded limited partnership with a diverse set of operations focused primarily in the United Stated Gulf Coast region. Its four primary business lines include: terminalling and storage services for petroleum products and by-products, natural gas services, marine transportation services for petroleum products and by products, and sulfur and sulfur based products processing, manufacturing, marketing and distribution.
          The petroleum products and by-products the Partnership collects, transports, stores and distributes are produced primarily by major and independent oil and gas companies who often turn to third parties, such as the Partnership, for the transportation and disposition of these products. In addition to these major and independent oil and gas companies, our primary customers include independent refiners, large chemical companies, fertilizer manufacturers and other wholesale purchasers of these products. The Partnership operates primarily in the Gulf Coast region of the United States, which is a major hub for petroleum refining, natural gas gathering and processing and support services for the oil and gas exploration and production industry.
          The Partnership owns Prism Gas Systems I, L.P. (“Prism Gas”) which is engaged in the gathering, processing and marketing of natural gas and natural gas liquids, predominantly in Texas and northwest Louisiana. Prism Gas owns a 50% ownership interest in Waskom Gas Processing Company (“Waskom”), the Matagorda Offshore Gathering System (“Matagorda”), Panther Interstate Pipeline Energy LLC (“PIPE”), and Bosque County Pipeline (“BCP”) each accounted for under the equity method of accounting.
(2) SIGNIFICANT ACCOUNTING POLICIES
          (a) Principles of Presentation and Consolidation
          The consolidated financial statements include the financial statements of the Partnership and its wholly-owned subsidiaries and equity method investees. In the opinion of the management of the Partnership’s general partner, all adjustments and elimination of significant intercompany balances necessary for a fair presentation of the Partnership’s results of operations, financial position and cash flows for the periods shown have been made. All such adjustments are of a normal recurring nature. In addition, the Partnership evaluates its relationships with other entities to identify whether they are variable interest entities as defined by FASB Interpretation No 46(R) Consolidation of Variable Interest Entities (“FIN 46R”) and to assess whether it is the primary beneficiary of such entities. If the determination is made that the Partnership is the primary beneficiary, then that entity is included in the consolidated financial statements in accordance with FIN 46(R). No such variable interest entities exist as of December 31, 2008 or 2007.
          (b) Product Exchanges
          The Partnership enters into product exchange agreements with third parties whereby the Partnership agrees to exchange NGLs and sulfur with third parties. The Partnership records the balance of exchange products due to other companies under these agreements at quoted market product prices and the balance of exchange products due from other companies at the lower of cost or market. Cost is determined using the first-in, first-out (“FIFO”) method.
          (c) Inventories
          Inventories are stated at the lower of cost or market. Cost is determined by using the first-in, first-out (FIFO) method for all inventories.

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)
          (d) Revenue Recognition
          Terminalling and storage – Revenue is recognized for storage contracts based on the contracted monthly tank fixed fee. For throughput contracts, revenue is recognized based on the volume moved through the Partnership’s terminals at the contracted rate. When lubricants and drilling fluids are sold by truck, revenue is recognized upon delivering product to the customers as title to the product transfers when the customer physically receives the product.
          Natural gas services – Natural gas gathering and processing revenues are recognized when title passes or service is performed. NGL distribution revenue is recognized when product is delivered by truck to our NGL customers, which occurs when the customer physically receives the product. When product is sold in storage, or by pipeline, the Partnership recognizes NGL distribution revenue when the customer receives the product from either the storage facility or pipeline.
          Marine transportation – Revenue is recognized for contracted trips upon completion of the particular trip. For time charters, revenue is recognized based on a per day rate.
          Sulfur services – Revenues are recognized when the products are delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership based on specific contract terms at either the shipping or delivery point.
          (e) Equity Method Investments
          The Partnership uses the equity method of accounting for investments in unconsolidated entities where the ability to exercise significant influence over such entities exists. Investments in unconsolidated entities consist of capital contributions and advances plus the Partnership’s share of accumulated earnings as of the entities’ latest fiscal year-ends, less capital withdrawals and distributions. Investments in excess of the underlying net assets of equity method investees, specifically identifiable to property, plant and equipment, are amortized over the useful life of the related assets. Excess investment representing equity method goodwill is not amortized but is evaluated for impairment, annually. Under the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 142, Goodwill and Other Intangible Assets, this goodwill is not subject to amortization and is accounted for as a component of the investment. Equity method investments are subject to impairment under the provisions of Accounting Principles Board (“APB”) Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock. No portion of the net income from these entities is included in the Partnership’s operating income.
          The Partnership’s Prism Gas subsidiary owns an unconsolidated 50% interest in Waskom, Matagorda, and PIPE. As a result, these assets are accounted for by the equity method.
          On June 30, 2006, the Partnership, through the Partnership’s Prism Gas subsidiary, acquired a 20% ownership interest in a partnership which owns the lease rights to the assets of the Bosque County Pipeline (“BCP”). The lease contract provides for termination in June 2009 and an extension of the lease is not currently contemplated. This interest is accounted for by the equity method of accounting.
          (f) Property, Plant, and Equipment
          Owned property, plant, and equipment is stated at cost, less accumulated depreciation. Owned buildings and equipment are depreciated using straight-line method over the estimated lives of the respective assets.
          Routine maintenance and repairs are charged to operating expense while costs of betterments and renewals are capitalized. When an asset is retired or sold, its cost and related accumulated depreciation are removed from the accounts and the difference between net book value of the asset and proceeds from disposition is recognized as gain or loss.
          (g) Goodwill and Other Intangible Assets
          Goodwill represents the excess of costs over fair value of assets of businesses acquired. Goodwill and intangible assets acquired in a purchase business combination and determined to have an indefinite useful life are not amortized, but instead tested for impairment at least annually in accordance with the provisions of Statement of Financial Accounting Standards No. 142 (“SFAS No. 142”), Goodwill and Other Intangible Assets.

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)
Intangible assets with estimated useful lives are amortized over their respective estimated useful lives to their estimated residual values, and reviewed for impairment in accordance with Statement of Financial Accounting Standards No. 144 (“SFAS No. 144”), Accounting for Impairment or Disposal of Long-Lived Assets. Other intangible assets primarily consist of covenants not-to-compete and contracts obtained through business combinations and are being amortized over the life of the respective agreements.
          Goodwill is subject to a fair-value based impairment test on an annual basis, or more often if events or circumstances indicate there may be impairment. The Partnership is required to identify their reporting units and determine the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets. Goodwill is assigned to reporting units at the date the goodwill is initially recorded. Once goodwill has been assigned to reporting units, it no longer retains its association with a particular acquisition, and all of the activities within a reporting unit, whether acquired or organically grown, are available to support value of the goodwill.
          The Partnership performed the annual impairment tests as of September 30, 2008, September 30, 2007 and September 30, 2006, respectively. In performing such tests, it was determined that there were four “reporting units” which contained goodwill. These reporting units were in each of the four reporting segments: terminalling, natural gas services, marine transportation, and sulfur services. The estimated fair value of the reporting units with goodwill were developed using the guideline public company method, the guideline transaction method, and the discounted cash flow (“DCF”) method using observable market data where available. To the extent the carrying amount of a reporting unit exceeds the fair value of the reporting unit, the Partnership would be required to perform the second step of the impairment test, as this is an indication that the reporting unit goodwill may be impaired. At September 30, 2008, 2007 and 2006 the estimated fair value of each of the four reporting units was in excess of its carrying value resulting in no impairment.
          As a result of the deterioration in the overall stock market subsequent to September 30, 2008 and the decline in the Partnership’s unit price, the Partnership reviewed specific factors, as outlined in SFAS No. 142, to determine if the Partnership had a trigging event that required it to test the goodwill for impairment as of December 31, 2008. These factors included whether there have been any significant fundamental changes since the annual impairment test to (i) the Partnership as a whole or to the reporting units, including regulatory changes, (ii) the level of operating cash flows, (iii) the expectation of future levels of operating cash flows, (iv) the executive management team, and (v) the carrying value of the other long-lived assets. While these factors did not indicate a triggering event occurred, the Partnership’s unit price fell to a point by December 31, 2008 that resulted in the total market capitalization being less than the partner’s equity. The Partnership determined this to be a triggering event requiring the Partnership to perform an impairment test as of December 31, 2008. As a result of the goodwill impairment test for each of the four reporting units as of December 31, 2008, no impairment was determined to exist.
          (h) Debt Issuance Costs
          In connection with the Partnership’s multi-bank credit facility, on November 10, 2005, it incurred debt issuance costs of $3,258. In connection with the amendment and expansion of the Partnership’s multi-bank credit facility on June 30, 2006, it incurred debt issuance costs of $372. In connection with the amendment and expansion of the Partnership’s multi-bank credit facility on December 28, 2007, it incurred debt issuance costs of $252. These debt issuance costs, along with the remaining unamortized deferred issuance costs relating to the line of credit facility as of November 10, 2005 which remain deferred, are amortized over the remainder of the 60 month term of the original debt arrangement.
          Amortization of debt issuance cost, which is included in interest expense for the years ended December 31, 2008, 2007 and 2006, totaled $1,120, $1,233, and $1,040, respectively, and accumulated amortization amounted to $5,445 and $4,324 at December 31, 2008 and 2007, respectively. The unamortized balance of debt issuance costs, classified as other assets amounted to $2,086 and $3,188 at December 31, 2008 and 2007, respectively.
          (i) Impairment of Long-Lived Assets
          In accordance with SFAS No. 144, long-lived assets, such as property, plant and equipment, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset.

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)
Assets to be disposed of would be separately presented in the balance sheet and reported at the lower of the carrying amount or fair value less costs to sell, and are no longer depreciated. The assets and liabilities of a disposed group classified as held for sale would be presented separately in the appropriate asset and liability sections of the balance sheet. The Partnership has not identified any triggering events in 2008, 2007 or 2006 that would require an assessment for impairment of long-lived assets.
          (j) Asset Retirement Obligation
          Under SFAS No. 143, Accounting for Asset Retirement Obligations (“Statement No. 143) and Financial Accounting Standards Board Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”), an interpretation of SFAS 143, which provide accounting requirements for costs associated with legal obligations to retire tangible, long-lived assets, the Partnership records an Asset Retirement Obligation (“ARO”) at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted over time towards the ultimate obligation amount and the capitalized costs are depreciated over the useful life of the related asset. The Partnership’s fixed assets include land, buildings, transportation equipment, storage equipment, marine vessels and operating equipment.
          The transportation equipment includes pipeline systems. The Partnership transports NGLs through the pipeline system and gathering system. The Partnership also gathers natural gas from wells owned by producers and delivers natural gas and NGLs on the Partnership’s pipeline systems, primarily in Texas and Louisiana to the fractionation facility of the Partnership’s 50% owned joint venture. The Partnership is obligated by contractual or regulatory requirements to remove certain facilities or perform other remediation upon retirement of the Partnership’s assets. However, the Partnership is not able to reasonably determine the fair value of the asset retirement obligations for the Partnership’s trunk and gathering pipelines and the Partnership’s surface facilities, since future dismantlement and removal dates are indeterminate. In order to determine a removal date of the Partnership’s gathering lines and related surface assets, reserve information regarding the production life of the specific field is required. As a transporter and gatherer of natural gas, the Partnership is not a producer of the field reserves, and the Partnership therefore does not have access to adequate forecasts that predict the timing of expected production for existing reserves on those fields in which the Partnership gathers natural gas. In the absence of such information, the Partnership is not able to make a reasonable estimate of when future dismantlement and removal dates of the Partnership’s gathering assets will occur. With regard to the Partnership’s trunk pipelines and their related surface assets, it is impossible to predict when demand for transportation of the related products will cease. The Partnership’s right-of-way agreements allow us to maintain the right-of-way rather than remove the pipe. In addition, the Partnership can evaluate the Partnership’s trunk pipelines for alternative uses, which can be and have been found. The Partnership will record such asset retirement obligations in the period in which more information becomes available for us to reasonably estimate the settlement dates of the retirement obligations.
          (k) Derivative Instruments and Hedging Activities
          In accordance with Statement of Financial Accounting Standards No. 133 (“SFAS No. 133”), Accounting for Derivative Instruments and Hedging Activities, all derivatives and hedging instruments are included on the balance sheet as an asset or liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings.
          Derivative instruments not designated as hedges are being marked to market with all market value adjustments being recorded in the consolidated statements of operations. As of December 31, 2008, the Partnership has designated a portion of its derivative instruments as qualifying cash flow hedges. Fair value changes for these hedges have been recorded in accumulated other comprehensive income as a component of equity.
          (l) Comprehensive Income
          Comprehensive income includes net income and other comprehensive income. Other comprehensive income for the partnership includes unrealized gains and losses on derivative financial instruments. In accordance with SFAS No. 133, the partnership records deferred hedge gains and losses on its derivative financial instruments that qualify as cash flow hedges as other comprehensive income.

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)
          (m) Unit Grants
          In May 2008, the Partnership issued 1,000 restricted common units to each of its three independent, non-employee directors under its long-term incentive plan from treasury shares purchased by the Partnership in the open market for $93. These units vest in 25% increments beginning in January 2009 and will be fully vested in January 2012.
          In May 2007, the Partnership issued 1,000 restricted common units to each of its three independent, non-employee directors under its long-term incentive plan. These units vest in 25% increments beginning in January 2008 and will be fully vested in January 2011.
          In January 2006, the Partnership issued 1,000 restricted common units to each of its three independent, non-employee directors under its long-term incentive plan. These units vest in 25% increments on the anniversary of the grant date each year and will be fully vested in January 2010.
          The Partnership accounts for the transaction under Emerging Issues Task Force 96-18 “Accounting for Equity Instruments That are Issued to other than Employees For Acquiring, or in Conjunction with Selling, Goods or Services.” The cost resulting from the share-based payment transactions was $39, $46 and $24 for the years ended December 31, 2008, 2007 and 2006, respectively. The Partnership’s general partner contributed cash of $2 in May 2007 and $2 in January 2006 to the Partnership in conjunction with the issuance of these restricted units in order to maintain its 2% general partner interest in the Partnership.
          (n) Incentive Distribution Rights
          The Partnership’s general partner, Martin Midstream GP LLC, holds a 2% general partner interest and certain incentive distribution rights in the Partnership.  Incentive distribution rights represent the right to receive an increasing percentage of cash distributions after the minimum quarterly distribution, any cumulative arrearages on common units, and certain target distribution levels have been achieved.  The Partnership is required to distribute all of its available cash from operating surplus, as defined in the partnership agreement.  The target distribution levels entitle the general partner to receive 15% of quarterly cash distributions in excess of $0.55 per unit until all unit holders have received $0.625 per unit, 25% of quarterly cash distributions in excess of $0.625 per unit until all unit holders have received $0.75 per unit, and 50% of quarterly cash distributions in excess of $0.75 per unit. For the years ended December 31, 2008, 2007 and 2006, the general partner received $2,495, $1,087 and $484 in incentive distributions.
          (o) Net Income per Unit
          Except as discussed in the following paragraph, basic and diluted net income per limited partner unit is determined by dividing net income after deducting the amount allocated to the general partner interest (including its incentive distribution in excess of its 2% interest) by the weighted average number of outstanding limited partner units during the period. Subject to applicability of Emerging Issues Task Force Issue No. 03-06 (“EITF 03-06’’), “Participating Securities and the Two-Class Method under FASB Statement No. 128,’’ as discussed below, Partnership income is first allocated to the general partner based on the amount of incentive distributions. The remainder is then allocated between the limited partners and general partner based on percentage ownership in the Partnership.
          EITF 03-06 addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity when, and if, it declares dividends on its common stock. Essentially, EITF 03-06 provides that in any accounting period where the Partnership’s aggregate net income exceeds the Partnership’s aggregate distribution for such period, the Partnership is required to present earnings per unit as if all of the earnings for the periods were distributed, regardless of the pro forma nature of this allocation and whether those earnings would actually be distributed during a particular period from an economic or practical perspective. EITF 03-06 does not impact the Partnership’s overall net income or other financial results; however, for periods in which aggregate net income exceeds the Partnership’s aggregate distributions for such period, it will have the impact of reducing the earnings per limited partner unit. This result occurs as a larger portion of the Partnership’s aggregate earnings is allocated to the incentive distribution rights held by the Partnership’s general partner, as if distributed, even though the Partnership makes cash distributions on the basis of cash available for distributions, not earnings, in any given accounting period. In accounting periods where aggregate net income does not exceed the Partnership’s aggregate distributions for such period, EITF 03-06 does not have any impact on the Partnership’s earnings per unit calculation.

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)
          The weighted average units outstanding for basic net income per unit were 14,529,826, 14,018,799 and 12,602,000 for years ended December 31, 2008, 2007 and 2006, respectively. For diluted net income per unit, the weighted average units outstanding were increased by 4,896 units, 3,746 units and 2,425 for the years ended December 31, 2008, 2007 and 2006, respectively, due to the dilutive effect of restricted units granted under the Partnership’s long-term incentive plan.
          (p) Indirect Selling, General and Administrative Expenses
          Indirect selling, general and administrative expenses are incurred by Martin Resource Management Corporation (“Martin Resource Management”) and allocated to the Partnership to cover costs of centralized corporate functions such as accounting, treasury, engineering, information technology, risk management and other corporate services. Such expenses are based on the percentage of time spent by Martin Resource Management’s personnel that provide such centralized services. Under the omnibus agreement, we are required to reimburse Martin Resource Management for indirect general and administrative and corporate overhead expenses. The amount of this reimbursement was capped at $2.0 million through November 1, 2007 when the cap expired. For the years ended December 31, 2008, 2007 and 2006, the Conflicts Committee of our general partner approved reimbursement amounts of $2,896, $1,493 and $1,493, 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.
          (q) Environmental Liabilities
          The Partnership’s policy is to accrue for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study. Such accruals are adjusted as further information develops or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable.
          (r) Allowance for Doubtful Accounts.
          Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts is the Partnership’s best estimate of the amount of probable credit losses in the Partnership’s existing accounts receivable.
          (s) Use of Estimates
          Management has made a number of estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ from those estimates.
          (t) Income Taxes
          With respect to our taxable subsidiary (Woodlawn Pipeline Co., Inc.), income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)
(3) FAIR VALUE MEASUREMENTS
          During the first quarter of 2008, the Partnership adopted FASB Statement No. 157, Fair Value Measurements (FAS 157). FAS 157 established a framework for measuring fair value and expanded disclosures about fair value measurements. The adoption of FAS 157 had no impact on the Partnership’s financial position or results of operations.
     FAS 157 applies to all assets and liabilities that are being measured and reported on a fair value basis. This statement enables the reader of the financial statements to assess the inputs used to develop those measurements by establishing a hierarchy for ranking the quality and reliability of the information used to determine fair values. The statement requires that each asset and liability carried at fair value be classified into one of the following categories:
  Level 1: Quoted market prices in active markets for identical assets or liabilities.
  Level 2: Observable market based inputs or unobservable inputs that are corroborated by market data.
  Level 3: Unobservable inputs that are not corroborated by market data.
            The Partnership’s derivative instruments which consist of commodity and interest rate swaps are required to be measured at fair value on a recurring basis. The fair value of the Partnership’s derivative instruments is determined based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. Refer to Notes 13 and 16 for further information on the Partnership’s derivative instruments and hedging activities.
     As prescribed by the FAS 157 levels listed above, the Partnership considers the Partnership’s derivative assets and liabilities as Level 2. The net fair value of the Partnership’s assets and liabilities measured on a recurring basis was a liability of $5,688 and $9,843 at December 31, 2008 and December 31, 2007, respectively.
(4) RECENT ACCOUNTING PRONOUNCEMENTS
          In March 2008, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of SFAS No. 133” (SFAS No. 161). SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities and is effective for the Partnership on January 1, 2009. Since SFAS No. 161 requires enhanced disclosures, without a change to existing standards relative to measurement and recognition, the Partnership’s adoption of SFAS No. 161 will not have any effect on our consolidated financial statements.
          In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51” (SFAS No. 160). SFAS No. 160 establishes new accounting, disclosure and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 is effective for the Partnership on January 1, 2009. The adoption of SFAS No. 160 will not have a material impact on the Partnership’s consolidated financial statements. However, it could impact accounting for future transactions.
          In December 2007, the FASB issued SFAS No. 141(Revised 2007), “Business Combinations” (SFAS No. 141(R)).  SFAS No. 141(R) retains the underlying concepts of SFAS No. 141 in that all business combinations are still required to be accounted for at fair value under the acquisition method of accounting, but SFAS No. 141(R) establishes revised principles and requirements for how entities will recognize and measure assets and liabilities acquired in a business combination, including but not limited to, generally expensing of acquisition costs as incurred and valuing noncontrolling interests (minority interests) at fair value at the acquisition date.   SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the first annual reporting period beginning on or after December 15, 2008.  The Partnership will adopt the provisions of SFAS No. 141(R) to business combinations completed on or after January 1, 2009.
          In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115” (SFAS No. 159). SFAS No. 159 permits the Partnership to choose, at specified election dates, to measure eligible items at fair value (the “fair value option”). The Partnership would report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting period. SFAS No. 159 is effective as of the beginning of the first fiscal year that begins after November 15, 2007 but is not required to be applied. The Partnership adopted SFAS No. 159 on January 1, 2008 but has not elected to apply the fair value option provided under SFAS No. 159 to any eligible assets or liabilities.

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)
          In September 2006, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements” (SFAS No. 157), which is intended to increase consistency and comparability in fair value measurements by defining fair value, establishing a framework for measuring fair value, and expanding disclosures about fair value measurements.  SFAS No. 157 applies to other accounting pronouncements that require or permit fair value measurements and was effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued FASB Staff Position (“FSP”) FAS 157-2, which delayed the effective date of SFAS No. 157 for certain nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statement on a recurring basis, to fiscal years beginning after November 15, 2008. In February 2008, the FASB issued FSP SFAS 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13,” which removes certain leasing transactions from the scope of SFAS No. 157, and FSP SFAS 157-2, “Effective Date of FASB Statement No. 157,” which defers the effective date of SFAS No. 157 for one year for certain nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis.  In October 2008, the FASB also issued FSP SFAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active,” which clarifies the application of SFAS No. 157 in an inactive market and illustrates how an entity would determine fair value when the market for a financial asset is not active.   On January 1, 2008, the Partnership adopted the portion of SFAS No. 157 that was not delayed, and since the Partnership’s existing fair value measurements are consistent with the guidance of SFAS No. 157, the partial adoption of SFAS No. 157 did not have a material impact on the Partnership’s consolidated financial statements. The adoption of the deferred portion of SFAS No. 157 on January 1, 2009 is not expected to have a material impact on the Partnership’s consolidated financial statements. See Note 3 for expanded disclosures about fair value measurements.
(5) ACQUISITIONS
     (a) Stanolind Terminal Assets.
          In January 2008, The Partnership acquired 7.8 acres of land, a deep water dock and two sulfuric acid tanks at its Stanolind terminal in Beaumont, Texas from Martin Resource Management Corporation (“Martin Resource Management”) for $5,983 which was allocated to property, plant and equipment. The Partnership entered into a lease agreement with Martin Resource Management for use of the sulfuric acid tanks. In connection with the acquisition, the Partnership borrowed approximately $6,000 under its credit facility.
     (b) Asphalt Terminal.
          In October 2007, the Partnership acquired the asphalt assets of Monarch Oil, Inc. and related companies (“Monarch Oil”) for $3,927 which was allocated to property, plant and equipment. The results of Monarch Oil’s operations have been included in the consolidated financial statements beginning October 2, 2007. The assets are located in Omaha, Nebraska. The Partnership entered into an agreement with Martin Resource Management, whereby Martin Resource Management will operate the facilities through a terminalling service agreement based upon throughput rates and will bear all additional expenses to operate the facility. In connection with the Partnership’s Monarch Oil acquisition on October 2, 2007, the Partnership borrowed approximately $3,900 under its revolving credit facility.
     (c) Lubricants Terminal
          In June 2007, the Partnership acquired all of the operating assets of Mega Lubricants Inc. (“Mega Lubricants”) located in Channelview, Texas. The results of Mega Lubricant’s operations have been included in the consolidated financial statements beginning June 13, 2007. The excess of the fair value over the carrying value of the assets was allocated to all identifiable assets. After recording all identifiable assets at their fair values, the remaining $1,020 was recorded as goodwill. The goodwill was a result of Mega Lubricant’s strategically located assets combined with the Partnership’s access to capital and existing infrastructure.

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)
This will enhance the Partnership’s ability to offer additional lubricant blending and truck loading and unloading services to customers. In accordance with FAS 142, the goodwill will not be amortized but tested for impairment. The terminal is located on 5.6 acres of land, and consists of 38 tanks with a storage capacity of approximately 15,000 Bbls, pump and piping infrastructure for lubricant blending and truck loading and unloading operations, 34,000 square feet of warehouse space and an administrative office.
          The purchase price of $4,738, including two three-year non-competition agreements totaling $530 and goodwill of $1,020, was allocated as follows:
         
Current assets
  $ 446  
Property, plant and equipment, net
    3,042  
Goodwill
    1,020  
Other assets
    530  
Other liabilities
    (300 )
 
     
Total
  $ 4,738  
 
     
          In connection with the acquisition, the Partnership borrowed approximately $4,600 under its credit facility.
          (d) Woodlawn Pipeline Co., Inc.
          On May 2, 2007, the Partnership, through its subsidiary Prism Gas, acquired 100% of the outstanding stock of Woodlawn. The results of Woodlawn’s operations have been included in the consolidated financial statements beginning May 2, 2007. The excess of the fair value over the carrying value of the assets was allocated to all identifiable assets. After recording all identifiable assets at their fair values, the remaining $8,785 was recorded as goodwill. The goodwill was a result of Woodlawn’s strategically located assets combined with the Partnership’s access to capital and existing infrastructure. This will enhance the Partnership’s ability to offer additional gathering services to customers through internal growth projects including natural gas processing, fractionation and pipeline expansions as well as new pipeline construction. In accordance with FAS 142, the goodwill will not be amortized but tested for impairment.
          Woodlawn is a natural gas gathering and processing company which owns integrated gathering and processing assets in East Texas. Woodlawn’s system consists of approximately 135 miles of natural gas gathering pipe, approximately 36 miles of condensate transport pipe and a 30 MMcfd processing plant. Prism Gas also acquired a nine-mile pipeline, from a Woodlawn related party, that delivers residue gas from Woodlawn to the Texas Eastern Transmission pipeline system.
          The selling parties in this transaction were Lantern Resources, L.P., David P. Deison, and Peak Gas Gathering L.P. The final purchase price, after final adjustments for working capital, was $32,606 and was funded by borrowings under the Partnership’s credit facility.
          The purchase price of $32,606, including four two-year non-competition agreements and other intangibles reflected as other assets, was allocated as follows:
         
Current assets
  $ 4,297  
Property, plant and equipment, net
    29,101  
Goodwill
    8,785  
Other assets
    3,339  
Current liabilities
    (3,889 )
Deferred income taxes
    (8,964 )
Other long-term obligations
    (63 )
 
     
Total
  $ 32,606  
 
     

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)
          The identifiable intangible assets of $3,339 are subject to amortization over a weighted-average useful life of approximately ten years. The intangible assets include four non-competition agreements totaling $40, customer contracts associated with the gathering and processing assets of $3,002, and a transportation contract associated with the residue gas pipeline of $297.
          In connection with the acquisition, the Partnership borrowed approximately $33,000 under its credit facility.
          (e) Asphalt Terminals. In August 2006 and October 2006, respectively, the Partnership acquired the assets of Gulf States Asphalt Company LP and Prime Materials and Supply Corporation (“Prime”), for $4,679 which was allocated to property, plant and equipment. The assets are located in Houston, Texas and Port Neches, Texas. The Partnership entered into an agreement with Martin Resource Management, which Martin Resource Management will operate the facilities through a terminalling service agreement based upon throughput rates and will assume all additional expenses to operate the facility.
          (f) Corpus Christi Barge Terminal. In July 2006, the Partnership acquired a marine terminal located near Corpus Christi, Texas and associated assets from Koch Pipeline Company, LP for $6,200 which was all allocated to property, plant and equipment. The terminal is located on approximately 25 acres of land, and includes three tanks with a combined shell capacity of approximately 240,000 barrels, pump and piping infrastructure for truck unloading and product delivery to two oil docks, and there are several pumps, controls, and an office building on site for administrative use.
          (g) Marine Vessels. In November 2006, the Partnership acquired the La Force, an offshore tug, for $6,001 from a third party. This vessel is a 5,100 horse power offshore tug that was rebuilt in 1999 with new engines installed in 2005.
          In January 2006, the Partnership acquired the Texan, an offshore tug, and the Ponciana, an offshore NGL barge, for $5,850 from Martin Resource Management. The acquisition price was based on a third party appraisal. In March 2006, these vessels went into service under a long term charter with a third party. In February 2006, the Partnership acquired the M450, an offshore barge, for $1,551 from a third party. In March 2006, this vessel went into service under a one-year charter with an affiliate of Martin Resource Management.
(6) PUBLIC OFFERINGS
          In May 2007, the Partnership completed a public offering of 1,380,000 common units at a price of $42.25 per common unit, before the payment of underwriters’ discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Following this offering, the common units represented a 64.3% limited partnership interest in the Partnership. Total proceeds from the sale of the 1,380,000 common units, net of underwriters’ discounts, commissions and offering expenses were $55,933. The Partnership’s general partner contributed $1,190 in cash to the Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the Partnership. The net proceeds were used to pay down revolving debt under the Partnership’s credit facility and to provide working capital.

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)
          A summary of the proceeds received from these transactions and the use of the proceeds received therefrom is as follows (all amounts are in thousands):
         
Proceeds received:
       
Sale of common units
  $ 58,305  
General partner contribution
    1,190  
 
     
Total proceeds received
  $ 59,495  
 
     
 
       
Use of Proceeds:
       
Underwriter’s fees
  $ 2,107  
Professional fees and other costs
    265  
Repayment of debt under revolving credit facility
    55,850  
Working capital
    1,273  
 
     
Total use of proceeds
  $ 59,495  
 
     
          In January 2006, the Partnership completed a public offering of 3,450,000 common units at a price of $29.12 per common unit, before the payment of underwriters’ discounts, commissions and offering expenses (per unit value is in dollars, not thousands). Following this offering, the common units represented a 61.6% limited partnership interest in the Partnership. Total proceeds from the sale of the 3,450,000 common units, net of underwriters’ discounts, commissions and offering expenses were $95,272. The Partnership’s general partner contributed $2,050 in cash to the Partnership in conjunction with the issuance in order to maintain its 2% general partner interest in the Partnership. The net proceeds were used to pay down revolving debt under the Partnership’s credit facility and to provide working capital.
          A summary of the proceeds received from these transactions and the use of the proceeds received therefrom is as follows (all amounts are in thousands):
         
Proceeds received:
       
Sale of common units
  $ 100,464  
General partner contribution
    2,050  
 
     
Total proceeds received
  $ 102,514  
 
     
 
       
Use of Proceeds:
       
Underwriter’s fees
  $ 4,521  
Professional fees and other costs
    671  
Repayment of debt under revolving credit facility
    62,000  
Working capital
    35,322  
 
     
Total use of proceeds
  $ 102,514  
 
     
(7) INVENTORIES
          Components of inventories at December 31, 2008 and 2007 were as follows:
                 
    2008     2007  
Natural gas liquids
  $ 10,530     $ 31,283  
Sulfur
    6,522       7,490  
Sulfur Based Products
    14,879       6,626  
Lubricants
    8,110       5,345  
Other
    2,420       1,054  
 
           
 
  $ 42,461     $ 51,798  
 
           
(8) PROPERTY, PLANT AND EQUIPMENT
          At December 31, 2008 and 2007, property, plant, and equipment consisted of the following:
                         
    Depreciable Lives     2008     2007  
Land
        $ 15,647     $ 14,515  
Improvements to land and buildings
  10-25 years     43,092       34,585  
Transportation equipment
  3-7 years     1,768       616  
Storage equipment
  5-20 years     45,196       38,652  

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)
                         
    Depreciable Lives     2008     2007  
Marine vessels
  4-25 years     200,473       147,627  
Operating equipment
  3-20 years     192,434       172,282  
Furniture, fixtures and other equipment
  3-20 years     1,548       1,542  
Construction in progress
            37,223       31,298  
 
                   
 
          $ 537,381     $ 441,117  
 
                   
Depreciation expense for the year ended December 31, 2008, 2007, and 2006 was $30,319, $22,455, and $16,932 respectively.
(9) GOODWILL AND OTHER INTANGIBLE ASSETS
          At December 31, 2008 and 2007, goodwill balances consisted of the following:
                 
    2008     2007  
Carrying amount of goodwill:
               
Terminalling and storage
  $ 1,020     $ 1,020  
Natural gas services
    29,010       29,010  
Marine transportation
    2,026       2,026  
Sulfur services
    5,349       5,349  
 
           
 
  $ 37,405     $ 37,405  
 
           
          At December 31, 2008 and 2007, covenants not-to-compete balances consisted of the following:
                 
    2008     2007  
Covenants not-to-compete:
               
Terminalling and storage
  $ 1,928     $ 1,928  
Natural gas services 6
    40       640  
Sulfur services
    790       790  
 
           
 
    2,758       3,358  
Less accumulated amortization
    1,539       1,610  
 
           
 
  $ 1,219     $ 1,748  
 
           
          Intangible assets consists of the covenants not-to-compete listed above, customer contracts associated with gathering and processing assets and a transportation contract associated with the residue gas pipeline. The covenants not-to-compete and contracts are presented in the consolidated balance sheets as other assets, net. Aggregate amortization expense for amortizing intangible assets was $899, $987, and $665 for the years ended December 31, 2008, 2007, and 2006, respectively. Estimated amortization expense for the years subsequent to December 31, 2008 are as follows: 2009 — $888; 2010 — $597; 2011 — $513; 2012 — $509; 2013 — $511; subsequent years -$1,731.
(10) LEASES
          The Partnership has numerous non-cancelable operating leases primarily for transportation and other equipment. The leases generally provide that all expenses related to the equipment are to be paid by the lessee. Management expects to renew or enter into similar leasing arrangements for similar equipment upon the expiration of the current lease agreements. The Partnership also has cancelable operating lease land rentals and outside marine vessel charters.
          The future minimum lease payments under non-cancelable operating leases for years subsequent to December 31, 2008 are as follows: 2009 — $3,814; 2010 — $3,652; 2011 — $3,459; 2012 — $3,186; 2013 — $2,488; subsequent years — $9,761.
          Rent expense for operating leases for the years ended December 31, 2008, 2007 and 2006 was $12,527, $12,492 and $8,407, respectively.

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)
(11) INVESTMENT IN UNCONSOLIDATED ENTITIES AND JOINT VENTURES
          The Partnership, through its Prism Gas subsidiary, owns 50% of the ownership interests in Waskom Gas Processing Company (“Waskom”), Matagorda Offshore Gathering System (“Matagorda”), Panther Interstate Pipeline Energy LLC (“PIPE”) and a 20% ownership interest in a partnership which owns the lease rights to Bosque County Pipeline (“BCP”). Each of these interests is accounted for under the equity method of accounting.
          In accounting for the acquisition of the interests in Waskom, Matagorda and PIPE, the carrying amount of these investments exceeded the underlying net assets by approximately $46,176. The difference was attributable to property and equipment of $11,872 and equity method goodwill of $34,304. The excess investment relating to property and equipment is being amortized over an average life of 20 years, which approximates the useful life of the underlying assets. Such amortization amounted to $594 for both the years ended December 31, 2008 and 2007 has been recorded as a reduction of equity in earnings of unconsolidated equity method investees. The remaining unamortized excess investment relating to property and equipment was $10,091 and $10,685 at December 31, 2008 and 2007, respectively. The equity-method goodwill is not amortized in accordance with SFAS 142; however, it is analyzed for impairment annually. No impairment was recognized in 2008, 2007 or 2006.
          As a partner in Waskom, the Partnership receives distributions in kind of natural gas liquids (“NGLs”) that are retained according to Waskom’s contracts with certain producers. The NGLs are valued at prevailing market prices. In addition, cash distributions are received and cash contributions are made to fund operating and capital requirements of Waskom.
          Activity related to these investment accounts is as follows:
                                         
    Waskom     PIPE     Matagorda     BCP     Total  
Investment in unconsolidated entities, December 31, 2006
  $ 64,937     $ 1,718     $ 3,786     $ 210     $ 70,651  
 
                                       
Distributions in kind
    (9,337 )                       (9,337 )
Return on investments
    (884 )     (517 )     (122 )           (1,523 )
Contributions to (distributions from) unconsolidated entities for operations
    6,803                   107       6,910  
Return of investments
    (1,741 )     (118 )     (93 )           (1,952 )
Equity in earnings:
                                       
Equity in earnings from operations
    11,009       514       151       (139 )     11,535  
Amortization of excess investment
    (550 )     (15 )     (29 )           (594 )
 
                             
 
                                       
Investment in unconsolidated entities, December 31, 2007
  $ 70,237     $ 1,582     $ 3,693     $ 178     $ 75,690  
 
                                       
Distributions in kind
    (9,725 )                       (9,725 )
Return on investments
    (500 )                       (500 )
Contributions to (distributions from) unconsolidated entities:
                                       
Cash contributions
    1,250       129             80       1,459  
Contributions to (distributions from) unconsolidated entities for operations
    920                         920  
Return of investments
    (300 )     (180 )     (745 )           (1,225 )
Equity in earnings:
                                       
Equity in earnings from operations
    13,646       (302 )     640       (166 )     13,818  
Amortization of excess investment
    (550 )     (15 )     (29 )           (594 )
 
                             
 
                                       
Investment in unconsolidated entities, December 31, 2008
  $ 74,978     $ 1,214     $ 3,559     $ 92     $ 79,843  
 
                             

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)
          Select financial information for significant unconsolidated equity method investees is as follows:
                                         
    Total     Long-     Partners’              
    Assets     Term Debt     Capital     Revenues     Net Income  
2008
                                       
Waskom
  $ 78,661     $     $ 67,730     $ 115,031     $ 27,292  
 
                             
 
                                       
2007
                                       
Waskom
  $ 66,772     $     $ 57,149     $ 81,797     $ 22,019  
 
                             
 
                                       
2006
                                       
Waskom
  $ 53,260     $     $ 45,450     $ 65,600     $ 17,246  
 
                             
          As of December 31, 2008 and 2007, the Partnership’s interest in cash of the unconsolidated equity method investees is $1,956 and $1,018, respectively.
(12) LONG-TERM DEBT
          At December 31, 2008 and December 31, 2007, long-term debt consisted of the following:
                 
    December 31,     December 31,  
    2008     2007  
**$195,000 Revolving loan facility at variable interest rate (6.04%* weighted average at December 31, 2008), due November 2010 secured by substantially all of our assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in our operating subsidiaries and equity method investees
  $ 165,000     $ 95,000  
***$130,000 Term loan facility at variable interest rate (7.04%* at December 31, 2008), due November 2010, secured by substantially all of our assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in our operating subsidiaries
    130,000       130,000  
 
               
Other secured debt maturing in 2008, 7.25%
          21  
 
           
Total long-term debt
    295,000       225,021  
Less current installments
          21  
 
           
Long-term debt, net of current installments
  $ 295,000     $ 225,000  
 
           
 
*   Interest rate fluctuates based on the LIBOR rate plus an applicable margin set on the date of each advance. The margin above LIBOR is set every three months. Indebtedness under the credit facility bears interest at either LIBOR plus an applicable margin or the base prime rate plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 1.50% to 3.00% and the applicable margin for revolving loans that are base prime rate loans ranges from 0.50% to 2.00%. The applicable margin for term loans that are LIBOR loans ranges from 2.00% to 3.00% and the applicable margin for term loans that are base prime rate loans ranges from 1.00% to 2.00%. The applicable margin for existing LIBOR borrowings is 2.50%. Effective January 1, 2009, the applicable margin for existing LIBOR borrowings will decrease to 2.00%. As a result of our leverage ratio test as of December 31, 2008, effective April 1, 2009, the applicable margin for existing LIBOR borrowings will remain at 2.00%. The Partnership incurs a commitment fee on the unused portions of the credit facility.
 
**   Effective October, 2008, the Partnership entered into a cash flow hedge that swaps $40,000 of floating rate to fixed rate. The fixed rate cost is 2.820% plus the Partnership’s applicable LIBOR borrowing spread. The cash flow hedge matures in October, 2010.
 
**   Effective January, 2008, the Partnership entered into a cash flow hedge that swaps $25,000 of floating rate to fixed rate. The fixed rate cost is 3.400% plus the Partnership’s applicable LIBOR borrowing spread. The cash flow hedge matures in January, 2010.
 
**   Effective September, 2007, the Partnership entered into a cash flow hedge that swaps $25,000 of floating rate to fixed rate. The fixed rate cost is 4.605% plus the Partnership’s applicable LIBOR borrowing spread. The cash flow hedge matures in September, 2010.
 
**   Effective November, 2006, the Partnership entered into a cash flow hedge that swaps $40,000 of floating rate to fixed rate. The fixed rate cost is 4.82% plus the Partnership’s applicable LIBOR borrowing spread. The cash flow hedge matures in December, 2009.

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)
 
***   The $130,000 term loan has $105,000 hedged. Effective March, 2006, the Partnership entered into a cash flow hedge that swaps $75,000 of floating rate to fixed rate. The fixed rate cost is 5.25% plus the Partnership’s applicable LIBOR borrowing spread. The cash flow hedge matures in November, 2010. Effective November 2006, the Partnership entered into an additional interest rate swap that swaps $30,000 of floating rate to fixed rate. The fixed rate cost is 4.765% plus the Partnership’s applicable LIBOR borrowing spread. This cash flow hedge matures in March, 2010.
          On November 10, 2005, the Partnership entered into a new $225,000 multi-bank credit facility comprised of a $130,000 term loan facility and a $95,000 revolving credit facility, which includes a $20,000 letter of credit sub-limit. This credit facility also includes procedures for additional financial institutions to become revolving lenders, or for any existing revolving lender to increase its revolving commitment, subject to a maximum of $100,000 for all such increases in revolving commitments of new or existing revolving lenders. Effective June 30, 2006, the Partnership increased its revolving credit facility $25,000 resulting in a committed $120,000 revolving credit facility. Effective December 28, 2007, the Partnership increased its revolving credit facility $75,000 resulting in a committed $195,000 revolving credit facility. The revolving credit facility is used for ongoing working capital needs and general partnership purposes, and to finance permitted investments, acquisitions and capital expenditures. Under the amended and restated credit facility, as of December 31, 2008, the Partnership had $165,000 outstanding under the revolving credit facility and $130,000 outstanding under the term loan facility. As of December 31, 2008, the Partnership had $29,880 available under its revolving credit facility.
          On July 14, 2005, the Partnership issued a $120 irrevocable letter of credit to the Texas Commission on Environmental Quality to provide financial assurance for its used oil handling program.
          The Partnership’s obligations under the credit facility are secured by substantially all of the Partnership’s assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in its operating subsidiaries and equity method investees. The Partnership may prepay all amounts outstanding under this facility at any time without penalty.
          In addition, the credit facility contains various covenants, which, among other things, limit the Partnership’s ability to: (i) incur indebtedness; (ii) grant certain liens; (iii) merge or consolidate unless it is the survivor; (iv) sell all or substantially all of its assets; (v) make certain acquisitions; (vi) make certain investments; (vii) make certain capital expenditures; (viii) make distributions other than from available cash; (ix) create obligations for some lease payments; (x) engage in transactions with affiliates; (xi) engage in other types of business; and (xii) its joint ventures to incur indebtedness or grant certain liens.
          The credit facility also contains covenants, which, among other things, require the Partnership to maintain specified ratios of: (i) minimum net worth (as defined in the credit facility) of $75,000 plus 50% of net proceeds from equity issuances after November 10, 2005; (ii) EBITDA (as defined in the credit facility) to interest expense of not less than 3.0 to 1.0 at the end of each fiscal quarter; (iii) total funded debt to EBITDA of not more than 4.75 to 1.00 for each fiscal quarter; and (iv) total secured funded debt to EBITDA of not more than  4.00 to 1.00 for each fiscal quarter. The Partnership was in compliance with the debt covenants contained in credit facility for the years ended December 31, 2008 and 2007.
          The credit facility also contains certain default provisions relating to Martin Resource Management. If Martin Resource Management no longer controls the Partnership’s general partner, the lenders under the Partnership’s credit facility may declare all amounts outstanding thereunder immediately due and payable. In addition, an event of default by Martin Resource Management under its credit facility could independently result in an event of default under the Partnership’s credit facility if it is deemed to have a material adverse effect on the Partnership. Any event of default and corresponding acceleration of outstanding balances under the Partnership’s credit facility could require the Partnership to refinance such indebtedness on unfavorable terms and would have a material adverse effect on the Partnership’s financial condition and results of operations as well as its ability to make distributions to unitholders.

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)
          On November 10 of each year, commencing with November 10, 2006, the Partnership must prepay the term loans under the credit facility with 75% of Excess Cash Flow (as defined in the credit facility), unless its ratio of total funded debt to EBITDA is less than 3.00 to 1.00. There were no prepayments made or required under the term loan through December 31, 2008. If the Partnership receives greater than $15,000 from the incurrence of indebtedness other than under the credit facility, it must prepay indebtedness under the credit facility with all such proceeds in excess of $15,000. Any such prepayments are first applied to the term loans under the credit facility. The Partnership must prepay revolving loans under the credit facility with the net cash proceeds from any issuance of its equity. The Partnership must also prepay indebtedness under the credit facility with the proceeds of certain asset dispositions. Other than these mandatory prepayments, the credit facility requires interest only payments on a quarterly basis until maturity. All outstanding principal and unpaid interest must be paid by November 10, 2010. The credit facility contains customary events of default, including, without limitation, payment defaults, cross-defaults to other material indebtedness, bankruptcy-related defaults, change of control defaults and litigation-related defaults.
          Draws made under the Partnership’s credit facility are normally made to fund acquisitions and for working capital requirements. During the current fiscal year, draws on the Partnership’s credit facility have ranged from a low of $225,000 to a high of $319,100. As of December 31, 2008, the Partnership had $29,880 available for working capital, internal expansion and acquisition activities under the Partnership’s credit facility.
          In connection with the Partnership’s Stanolind asset acquisition on January 22, 2008, the Partnership borrowed approximately $6,000 under its revolving credit facility.
          In connection with the Partnership’s Monarch acquisition on October 2, 2007, the Partnership borrowed approximately $3,900 under its revolving credit facility.
          In connection with the Partnership’s Mega Lubricants acquisition on June 13, 2007, the Partnership borrowed approximately $4,600 under its revolving credit facility.
          In connection with the Partnership’s Woodlawn acquisition on May 2, 2007, the Partnership borrowed approximately $33,000 under its revolving credit facility.
          The Partnership paid cash interest in the amount of $18,744, $17,253 and $12,426 for the years ended December 31, 2008, 2007 and 2006 respectively. Capitalized interest was $1,296, $2,483 and $1,546 for the years ended December 31, 2008, 2007 and 2006 respectively.
(13) INTEREST RATE CASH FLOW HEDGES
          The Partnership has entered into several cash flow hedge agreements with an aggregate notional amount of $235,000 to hedge its exposure to increases in the benchmark interest rate underlying its variable rate revolving and term loan credit facilities. The Partnership designated these swap agreements as cash flow hedges. Under these swap agreements, the Partnership pays a fixed rate of interest and receives a floating rate based on a three-month U.S. Dollar LIBOR rate. Because these swaps are designated as a cash flow hedge, the changes in fair value, to the extent the swap is effective, are recognized in other comprehensive income until the hedged interest costs are recognized in earnings. At the inception of these hedges, these swaps were identical to the hypothetical swap as of the trade date, and will continue to be identical as long as the accrual periods and rate resetting dates for the debt and these swaps remain equal. This condition results in a 100% effective swap for the following hedges:
                     
Date of Hedge   Notional Amount   Fixed Rate   Maturity Date
October 2008
  $ 40,000       2.820 %   October 2010
January 2008
  $ 25,000       3.400 %   January 2010
September 2007
  $ 25,000       4.605 %   September 2010
November 2006
  $ 40,000       4.820 %   December 2009
March 2006
  $ 75,000       5.250 %   November 2010
          In December 2006, the Partnership entered into an interest rate swap that swaps $30,000 of floating rate to fixed rate. The fixed rate cost is 4.765% plus the Partnership’s applicable LIBOR borrowing spread. This interest rate swap matures in March 2010. The underlying debt related to this swap was paid prior to December 31, 2006, therefore, hedge accounting was not utilized. The swap has been recorded at fair value at December 31, 2008 with an offset to current operations.

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)
          During the year ended December 31, 2008, the Partnership recognized increases in interest expense of $3,416 related to the difference between the fixed rate and the floating rate of interest on the interest rate swaps. The total fair value of the interest rate swaps agreement was a liability of $10,780 and $4,677 at December 31, 2008 and 2007.
          The fair value of derivative liabilities is as follows:
                 
    December 31,     December 31,  
    2008     2007  
Fair value of derivative liabilities — current
  $ (6,478 )   $ (1,241 )
Fair value of derivative liabilities — long term
    (4,302 )     (3,436 )
 
           
Net fair value of derivatives
  $ (10,780 )   $ (4,677 )
 
           
(14) RELATED PARTY TRANSACTIONS
          Included in the consolidated financial statements are various related party transactions and balances primarily with 1) Martin Resource Management and affiliates, and 2) Waskom.
          Related party transactions include sales and purchases of products and services between the Partnership and these related entities as well as payroll and associated costs and allocation of overhead.
          The impact of these related party transactions is reflected in the consolidated financial statement as follows:
                         
    2008     2007     2006  
Revenues:
                       
Terminalling and storage
  $ 18,362     $ 11,816     $ 8,926  
Marine transportation
    24,956       23,729       15,319  
Product sales:
                       
Natural gas services
    4,024       3,206       1,303  
Sulfur services
    22,631       4,326       24  
Terminalling and storage
    49       45       59  
 
                 
 
    26,704       7,577       1,386  
 
                 
 
  $ 70,022     $ 43,122     $ 25,631  
 
                 
 
                       
Costs and expenses:
                       
Cost of products sold:
                       
Natural gas services
  $ 92,322     $ 62,686     $ 52,030  
Sulfur services
    13,282       13,992       11,913  
Terminalling and storage
    533             1  
 
                 
 
  $ 106,137     $ 76,678     $ 63,944  
 
                 
 
                       
Expenses:
                       
Operating expenses
                       
Marine transportation
  $ 22,586     $ 20,891     $ 20,051  
Natural gas services
    1,625       1,538       1,560  
Sulfur services
    3,737       1,234       928  
Terminalling and storage
    9,713       5,328       3,931  
 
                 
 
  $ 37,661     $ 28,991     $ 26,470  
 
                 
 
                       
Selling, general and administrative:
                       
Natural gas services
    880       927       773  
Sulfur services
    2,508       1,770       1,714  
Terminalling and storage
          41       74  
Indirect overhead allocation, net of reimbursement
    2,896       1,351       1,305  
 
                 
 
  $ 6,284     $ 4,089     $ 3,866  
 
                 

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)
(15) FINANCIAL INSTRUMENTS
          Statement of Financial Accounting Standards No. 107, Disclosures about Fair Value of Financial Instruments, requires that the Partnership disclose estimated fair values for its financial instruments. Fair value estimates are set forth below for the Partnership’s financial instruments. The following methods and assumptions were used to estimate the fair value of each class of financial instrument:
    Accounts and other receivables, trade and other accounts payable, other accrued liabilities, income taxes payable and due from/to affiliates — The carrying amounts approximate fair value because of the short maturity of these instruments.
 
    Long-term debt including current installments — The carrying amount of the revolving and term loan facilities approximates fair value due to the debt having a variable interest rate.
(16) COMMODITY CASH FLOW HEDGES
          The Partnership is exposed to market risks associated with commodity prices, counterparty credit and interest rates. The Partnership has established a hedging policy and monitors and manages the commodity market risk associated with its commodity risk exposure. In addition, the Partnership is focusing on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction.
          The Partnership uses derivatives to manage the risk of commodity price fluctuations. Additionally, the Partnership manages interest rate exposure by targeting a ratio of fixed and floating interest rates it deems prudent and using hedges to attain that ratio.
          In accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133), all derivatives and hedging instruments are included on the balance sheet as an asset or a liability measured at fair value and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in accumulated other comprehensive income until such time as the hedged item is recognized in earnings. The Partnership has adopted a hedging policy that allows it to use hedge accounting for financial transactions that are designated as hedges.
          Derivative instruments not designated as hedges are being marked to market with all market value adjustments being recorded in the consolidated statements of operations. As of December 31, 2008, the Partnership has designated a portion of its derivative instruments as qualifying cash flow hedges. Fair value changes for these hedges have been recorded in other comprehensive income as a component of equity.
          The components of gain/loss on derivatives qualifying for hedge accounting and those that do not qualify for hedge accounting are included in the revenue of the hedged item in the Consolidated Statements of Operations for the year ended December 31, 2008, 2007 and 2006 as follows:
                         
    December 31,  
    2008     2007     2006  
Change in fair value of derivatives that do not qualify for hedge accounting and settlements of maturing hedges
  $ 1,222     $ (3,129 )   $ 1,117  
Ineffective portion of derivatives qualifying for hedge accounting
    (224 )     (586 )     (2 )
 
                 
 
                       
Gain (loss) of derivatives in the Consolidated Statement of Operations
  $ 998     $ (3,715 )   $ 1,115  
 
                 

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)
          The fair value of derivative assets and liabilities are as follows:
                 
    December 31,  
    2008     2007  
Fair value of derivative assets — current
  $ 3,623     $ 235  
Fair value of derivative assets — long term
    1,469        
Fair value of derivative liabilities — current
          (3,261 )
Fair value of derivative liabilities — long term
          (2,140 )
 
           
Net fair value of derivatives
  $ 5,092     $ (5,166 )
 
           
          Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at December 31, 2008 (all gas quantities are expressed in British Thermal Units, crude oil and natural gas liquids are expressed in barrels). As of December 31, 2008, the remaining term of the contracts extend no later than December 2010, with no single contract longer than one year. The Partnership’s counterparties to the derivative contracts include Shell Energy North America (US) L.P., Morgan Stanley Capital Group Inc. and Wachovia Bank. For the period ended December 31, 2008, changes in the fair value of the Partnership’s derivative contracts were recorded in both earnings and in accumulated other comprehensive income as a component of equity since the Partnership has designated a portion of its derivative instruments as hedges as of December 31, 2008.
                     
December 31, 2008
    Total            
    Volume       Remaining Terms    
Transaction Type   Per Month   Pricing Terms   of Contracts   Fair Value
Mark to Market Derivatives::                
 
                   
Crude Oil Swap
  3,000 BBL   Fixed price of $69.08 settled against WTI
NYMEX average monthly closings
  January 2009 to
December 2009
    565  
 
                   
Crude Oil Swap
  3,000 BBL   Fixed price of $70.90 settled against WTI
NYMEX average monthly closings
  January 2009 to
December 2009
    628  
 
                   
Crude Oil Swap
  3,000 BBL   Fixed price of $72.25 settled against WTI
NYMEX average monthly closings
  January 2010 to
December 2010
    300  
 
                   
Crude Oil Swap
  1,000 BBL   Fixed price of $104.80 settled against WTI
NYMEX average monthly closings
  January 2010 to
December 2010
    453  
 
                   
Total swaps not designated as cash flow hedges       $ 1,946  
 
                   
 
                   
Cash Flow Hedges:
                   
 
                   
Natural Gas swap
  30,000 MMBTU   Fixed price of $9.025 settled against
Inside Ferc Columbia Gulf daily average
  January 2009 to
December 2009
    1,033  
 
                   
Crude Oil Swap
  1,000 BBL   Fixed price of $70.45 settled against
WTI NYMEX average monthly closings
  January 2009 to
December 2009
    204  
 
                   
Natural Gasoline Swap
  2,000 BBL   Fixed price of $86.42 settled against Mt. Belvieu Non-TET natural gasoline average monthly postings.   January 2009 to
December 2009
    1,193  
 
                   
Crude Oil Swap
  2,000 BBL   Fixed price of $69.15 settled against WTI NYMEX average monthly closings   January 2010 to
December 2010
    132  
 
                   
Natural Gasoline Swap
  1,000 BBL   Fixed price of $94.14 settled against Mt. Belvieu Non-TET natural gasoline average monthly postings   January 2010 to
December 2010
    584  
 
                   
Total swaps designated as cash flow hedges       $ 3,146  
 
                   
 
                   
Total net fair value of derivatives           $ 5,092  
 
                   

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)
           On all transactions where the Partnership is exposed to counterparty risk, the Partnership analyzes the counterparty’s financial condition prior to entering into an agreement, and has established a maximum credit limit threshold pursuant to its hedging policy, and monitors the appropriateness of these limits on an ongoing basis. The Partnership has incurred no losses associated with the counterparty non-performance on derivative contracts.
           The Partnership is exposed to the impact of market fluctuations in the prices of natural gas, natural gas liquids (“NGLs”) and condensate as a result of gathering, processing and sales activities. The Partnership’s gathering and processing revenues are earned under various contractual arrangements with gas producers. Gathering revenues are generated through a combination of fixed-fee and index-related arrangements. Processing revenues are generated primarily through contracts which provide for processing on percent-of-liquids (“POL”) and percent-of-proceeds (“POP”) basis. The Partnership has entered into hedging transactions through 2010 to protect a portion of its commodity exposure from these contracts. These hedging arrangements are in the form of swaps for crude oil, natural gas, and natural gasoline.
          In October 2008, the Partnership elected to discontinue hedge accounting treatment for certain crude oil derivative contracts. The impact to the Consolidated Statement of Operations was a mark to market gain of $1,790 for the year ended December 31, 2008.
          In December 2008, the Partnership terminated three commodity swap agreements resulting in a cash receipt from the counterparty of $1,935. These swap agreements were accounted for as cash flow hedges. As a result of the termination, a gain of $400 was recorded to the Partnership’s Consolidated Statement of Operations for the year ended December 31, 2008.
          As a result of declining commodity prices, the Partnership determined that continued reporting of losses in accumulated other comprehensive income (“AOCI”) for certain commodity hedges would lead to recognizing a net loss on the combination of the hedging instrument and the hedge transaction in future periods. Accordingly, the calculated loss of $2,608 was immediately classified into 2008 earnings. The remaining deferred gains of $1,534 and deferred losses of $116 pertaining to the above commodity hedges will remain in AOCI and are expected to be reclassified into earnings in the same period that the forecasted hedge transaction is reported in earnings.
          Based on estimated volumes, as of December 31, 2008, the Partnership had hedged approximately 47% and 21% of its commodity risk by volume for 2009, and 2010, respectively. The Partnership anticipates entering into additional commodity derivatives on an ongoing basis to manage its risks associated with these market fluctuations, and will consider using various commodity derivatives, including forward contracts, swaps, collars, futures and options, although there is no assurance that the Partnership will be able to do so or that the terms thereof will be similar to the Partnership’s existing hedging arrangements.
Hedging Arrangements in Place
As of December 31, 2008
                 
Year   Commodity Hedged   Volume   Type of Derivative   Basis Reference
2009
  Natural Gas   30,000 MMBTU/Month   Natural Gas Swap ($9.025)   Columbia Gulf
2009
  Condensate & Natural Gasoline   3,000 BBL/Month   Crude Oil Swap ($69.08)   NYMEX
2009
  Natural Gasoline   3,000 BBL/Month   Crude Oil Swap ($70.90)   NYMEX
2009
  Condensate   1,000 BBL/Month   Crude Oil Swap ($70.45)   NYMEX
2009
  Natural Gasoline   2,000 BBL/Month   Natural Gasoline Swap ($86.42)   Mt. Belvieu (Non-TET)
2010
  Condensate   2,000 BBL/Month   Crude Oil Swap ($69.15)   NYMEX
2010
  Natural Gasoline   3,000 BBL/Month   Crude Oil Swap ($72.25)   NYMEX
2010
  Condensate   1,000 BBL/Month   Crude Oil Swap ($104.80)   NYMEX
2010
  Natural Gasoline   1,000 BBL/Month   Natural Gasoline Swap ($94.14)   Mt. Belvieu (Non-TET)

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)
          The Partnership’s principal customers with respect to Prism Gas’ natural gas gathering and processing are large, natural gas marketing services, oil and gas producers and industrial end-users. In addition, substantially all of the Partnership’s natural gas and NGL sales are made at market-based prices. The Partnership’s standard gas and NGL sales contracts contain adequate assurance provisions which allows for the suspension of deliveries, cancellation of agreements or discontinuance of deliveries to the buyer unless the buyer provides security for payment in a form satisfactory to the Partnership.
Impact of Cash Flow Hedges
Crude Oil
          For the years ended December 31, 2008, 2007 and 2006, net gains and losses on swap hedge contracts increased crude revenue by $1,745, decreased crude revenue by $3,374 and increased crude revenue by $76, respectively. As of December 31, 2008 an unrealized derivative fair value gain of $842, related to current and terminated cash flow hedges of crude oil price risk, was recorded in other comprehensive income (loss). Fair value gains of $197, $22 and $623 are expected to be reclassified into earnings in 2009, 2010 and 2011, respectively. The actual reclassification to earnings for contracts remaining in effect will be based on mark-to-market prices at the contract settlement date or for those terminated contracts based on the recorded values at December 31, 2008 adjusted for any impairment, along with the realization of the gain or loss on the related physical volume, which is not reflected above.
Natural Gas
          For the years ended December 31, 2008, 2007 and 2006, net gains and losses on swap hedge contracts decreased gas revenue by $431 and increased gas revenue by $180 and $1,097, respectively. As of December 31, 2008 an unrealized derivative fair value gain of $1,033 related to cash flow hedges of natural gas was recorded in other comprehensive income (loss). This fair value gain is expected to be reclassified into earnings in 2009. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which is not reflected above.
Natural Gas Liquids
          For the years ended December 31, 2008, 2007 and 2006, net losses on swap hedge contracts decreased liquids revenue by $316, $521 and $58, respectively. As of December 31, 2008, an unrealized derivative fair value gain of $2,669 related to current and terminated cash flow hedges of natural gas liquids price risk was recorded in other comprehensive income (loss). Fair value gains of $1,193, $584 and $892 are expected to be reclassified into earnings in 2009, 2010 and 2011, respectively. The actual reclassification to earnings for contracts remaining in effect will be based on mark-to-market prices at the contract settlement date or for those terminated contracts based on the recorded values at December 31, 2008 adjusted for any impairment, along with the realization of the gain or loss on the related physical volume, which is not reflected above.
(17)        PARTNERS’ CAPITAL
          As of December 31, 2008, partners’ capital consists of 13,688,152 common limited partner units, representing a 92.3% partnership interest, 850,674 subordinated limited partner units, representing a 5.7% partnership interest and a 2% general partner interest. Martin Resource Management through a subsidiary, owned an approximate 34.9% limited partnership interest consisting of 4,334,143 common limited partner units and 850,674 subordinated limited partner units and a 2% general partner interest.
          The Partnership Agreement contains specific provisions for the allocation of net income and losses to each of the partners for purposes of maintaining their respective partner capital accounts.

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)
Distributions of Available Cash
          The Partnership distributes all of its Available Cash (as defined in the Partnership Agreement) within 45 days after the end of each quarter to unitholders of record and to the general partner. Available Cash is generally defined as all cash and cash equivalents of the Partnership on hand at the end of each quarter less the amount of cash reserves its general partner determines in its reasonable discretion is necessary or appropriate to: (i) provide for the proper conduct of the Partnership’s business; (ii) comply with applicable law, any debt instruments or other agreements; or (iii) provide funds for distributions to unitholders and the general partner for any one or more of the next four quarters, plus all cash on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.
Subordination Period
          During the subordination period (defined in the Partnership Agreement), the common units have the right to receive distributions of available cash in an amount equal to the minimum quarterly distribution of $0.50 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units.
          The subordination period ends on the first day of any quarter beginning after September 30, 2009, when certain financial tests (defined in the Partnership Agreement) are met. Additionally, a portion of the subordinated units may convert earlier into common units on a one-for-one basis if additional financial tests (defined in the Partnership Agreement) are met.
          The partnership agreement provides that before the end of the subordination period, a portion of the subordinated units may convert into common units on a one-for-one basis immediately after the distribution of available cash to the partners in respect of any quarter ending on or after:
    September 30, 2005 with respect to 20% of the subordinated units;
 
    September 30, 2006 with respect to 20% of the subordinated units;
 
    September 30, 2007 with respect to 20% of the subordinated units;
 
    September 30, 2008 with respect to 20% of the subordinated units;
          As a result of achieving the defined financial test, 850,672 subordinated units representing 20% of the total originally issued subordinated units were converted into common units on each of November 14, 2008, 2007, 2006 and 2005. A total of 3,402,688 subordinated units representing 80% of the total originally issued subordinated units have been converted into common units as of December 31, 2008. When the subordination period ends, any remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to arrearages.
(18) HURRICANE DAMAGE
          During the third quarter of 2008, several of the Partnership’s facilities in the Gulf of Mexico were in the path of two major hurricanes, Hurricane Gustav and Hurricane Ike. Physical damage to the Partnership’s assets caused by the hurricanes, as well as the related removal and recovery costs, are covered by insurance subject to a deductible. Losses incurred as a result of a single hurricane (an “occurrence”) are limited to a maximum aggregate deductible of $250 for flood damage and $1,000 minimum plus 2% of total insured value at each location for wind damage. The Partnership’s total flood coverage is $15,000 and total wind coverage is $100,000.
          The most significant damage to the Partnership’s assets was sustained at the Neches location. Property damage also occurred at the Partnership’s Galveston, Sabine Pass, Intracoastal City, Cameron East, Cameron West, Freeport, Venice, Port Fourchon, Stanolind, Mont Belvieu, and Spindletop locations. The Partnership performed a damage analysis and has estimated its non-cash charge as $1,269 for all locations which is equal to the net-book value of the damaged assets. A receivable of $4,351 has been recorded for the expected insurance recovery equal to the impairment charge and for all expenditures related to water damage less the fore mentioned deductible. This receivable was reduced by insurance proceeds received of $1,375. These insurance proceeds may exceed net book value of the Partnership’s assets determined to be impaired, which will result in the recognition of a gain equal to the amount of the excess. No net gain or loss has been recognized from the impairment of these damaged assets at December 31, 2008. Any gain or loss will be recognized after the full amount of insurance proceeds are received.

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)
          The Partnership recognized hurricane costs of $1,461 for the year ended December 31, 2008, which approximates the Partnership’s hurricane deductibles under its applicable insurance policies, incurred as a result of Hurricanes Gustav and Ike for the year ended December 31, 2008. The actual hurricane cost payments for the year ended December 31, 2008 were $949.
          Insurance proceeds received as a result of the claims from damages incurred during Hurricanes Katrina and Rita in 2005 exceeded net book value of the Partnership’s assets determined to be impaired. During 2006, the Partnership received insurance proceeds of $4,812 for this involuntary conversion of assets, which resulted in a gain of $3,125 which is reported in other operating income.
(19) INCOME TAXES
          The operations of a partnership are generally not subject to income taxes, except as discussed below, because its income is taxed directly to its partners. The net tax basis in the Partnership’s assets and liabilities is less than the reported amounts on the financial statements by approximately $3.9 million as of December 31, 2008 and more than the reported amounts on the financial statements by approximately $35.4 million as of December 31, 2007. Effective January 1, 2007, the Partnership became subject to the Texas margin tax as described below. Our subsidiary, Woodlawn, is subject to income taxes due to its corporate structure. Current income taxes related to the operations of this subsidiary were $239 and $118 for the years ended December 31, 2008 and 2007, respectively. In connection with the Woodlawn acquisition, the Partnership also established deferred income taxes of $8,964 associated with book and tax basis differences of the acquired assets and liabilities. The basis differences are primarily related to property, plant and equipment. A deferred tax benefit related to these basis differences of $277 and $149 was recorded for the years ended December 31, 2008 and 2007, respectively, and a deferred tax liability of $8,538 and $8,815 related to the basis differences existed at December 31, 2008 and 2007, respectively.
          As a result of its acquisition of Prism Gas, the Partnership assumed a current tax liability of $6.3 million as a result of a tax event triggered by the transfer of the ownership of the assets of Prism Gas in 2005 from a corporate to a partnership structure through the partial liquidation of the corporation. This liability was paid in 2006. The final liquidation of this corporate entity was completed on November 15, 2006. Additional federal and state income taxes of $173 resulting from the liquidation were recorded in income tax expense for the year ended December 31, 2007.
          On May 18, 2006, the Texas Governor signed into law a Texas margin tax (H.B. No. 3) which restructures the state business tax by replacing the taxable capital and earned surplus components of the current franchise tax with a new “taxable margin” component. Since the tax base on the Texas margin tax is derived from an income-based measure, the margin tax is construed as an income tax and, therefore, the provisions of SFAS 109 regarding the recognition of deferred taxes apply to the new margin tax. In accordance with SFAS 109, the effect on deferred tax assets of a change in tax law should be included in tax expense attributable to continuing operations in the period that includes the enactment date. Therefore, the Partnership has calculated its deferred tax assets and liabilities for Texas based on the new margin tax. The cumulative effect of the change was immaterial. The impact of the change in deferred tax assets does not have a material impact on tax expense. State income taxes attributable to the Texas margin tax of $749 and $538 were recorded in income tax expense for the years ended December 31, 2008 and 2007, respectively. The Partnership was not subject to income taxes prior to January 1, 2007.
          In June 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes”. FIN 48 is an interpretation of FASB Statement No. 109, “Accounting for Income Taxes”. FIN 48 prescribes a comprehensive model for recognizing, measuring, presenting and disclosing in the financial statements uncertain tax positions taken or expected to be taken. The Partnership adopted FIN 48 effective January 1, 2007. There was no impact to the Partnership’s financial statements as a result of adopting FIN 48.

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MARTIN MIDSTREAM PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Thousands)
          The components of income tax expense (benefit) from operations recorded for the years ended December 31, 2008 and 2007 are as follows:
                 
    2008     2007  
Current:
               
Federal
  $ 239     $ 274  
State
    749       519  
 
           
 
    988       793  
 
               
Deferred:
               
Federal
    (277 )     (149 )
 
           
 
  $ 711     $ 644  
 
           
(20) BUSINESS SEGMENTS
          The Partnership has four reportable segments: terminalling and storage, natural gas services, marine transportation, and sulfur services. The Partnership’s reportable segments are strategic business units that offer different products and services. The operating income of these segments is reviewed by the chief operating decision maker to assess performance and make business decisions.
          The accounting policies of the operating segments are the same as those described in Note 2 of the notes to consolidated financial statements. The Partnership evaluates the performance of its reportable segments based on operating income. There is no allocation of administrative expenses or interest expense.
                                                 
                    Operating             Operating        
                    Revenues     Depreciation     Income        
    Operating     Intersegment     After     and     (Loss) after     Capital  
    Revenues     Eliminations     Eliminations     Amortization     Eliminations     Expenditures  
Year ended December 31, 2008:
                                               
Terminalling and storage
  $ 90,474     $ (4,189 )   $ 86,285     $ 9,272     $ 8,626     $ 24,958  
Natural gas services
    679,375             679,375       4,067       3,725       9,565  
Marine transportation
    80,059       (3,710 )     76,349       12,128       5,570       53,562  
Sulfur services
    372,987       (1,038 )     371,949       5,751       37,180       6,884  
Indirect selling, general, and administrative
                            (5,510 )      
 
                                   
 
Total
  $ 1,222,895     $ (8,937 )   $ 1,213,958     $ 31,218     $ 49,591     $ 94,969  
 
                                   
 
                                               
Year ended December 31, 2007:
                                               
Terminalling and storage
  $ 59,790     $ (865 )   $ 58,925     $ 6,358     $ 10,273     $ 26,023  
Natural gas services
    515,992             515,992       3,252       4,492       4,090  
Marine transportation
    63,533       (3,954 )     59,579       8,819       4,270       37,562  
Sulfur services
    131,602       (276 )     131,326       5,013       13,040       14,489  
Indirect selling, general, and administrative
                            (3,199 )