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, 2009

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

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)

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

Yes o           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 definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o		Accelerated filer 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, 2009, 13,688,152 common units were outstanding. The aggregate market value of the common units held by non-affiliates of the registrant as of such date approximated $190,489,698 based on the closing sale price on that date. There were 17,707,832 of the registrant’s common units and 889,444 of the registrant’s subordinated units outstanding as of March 4, 2010.

     DOCUMENTS INCORPORATED BY REFERENCE:       None.

 

 

TABLE OF CONTENTS

				Page
		PART I
Item 1.		Business			1
Item 1A.		Risk Factors			26
Item 1B.		Unresolved Staff Comments			46
Item 2.		Properties			46
Item 3.		Legal Proceedings			46
Item 4.		Reserved			46
		PART II
Item 5.		Market for Our Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities			46
Item 6.		Selected Financial Data			49
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			51
Item 7A.		Quantitative and Qualitative Disclosures about Market Risk			74
Item 8.		Financial Statements and Supplementary Data			77
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			118
Item 9A.		Controls and Procedures			118
Item 9B.		Other Information			118
		PART III
Item 10.		Directors, Executive Officers and Corporate Governance			120
Item 11.		Executive Compensation			125
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			132
Item 13.		Certain Relationships and Related Transactions, and Director Independence			136
Item 14.		Principal Accounting Fees and Services			144
		PART IV
Item 15.		Exhibits and Financial Statement Schedules			145
EX-21.1
EX-23.1
EX-23.2
EX-23.3
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-99.1

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;
	•		Sulfur and sulfur-based products processing, manufacturing, marketing and distribution; and
	•		Marine transportation services for petroleum products and by-products.

     The petroleum products and by-products we gather, process, 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 generate the majority of our cash flow from fee-based contracts with these customers. Our location in the Gulf Coast region of the United States provides us strategic access to 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. As of March 4, 2010, Martin Resource Management owns an approximate 40.0% 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.

     The historical operation of our business segments by Martin Resource Management provides us with several decades of experience and a demonstrated track record of customer service across our operations. Our current lines of business have been developed and systematically integrated over this period of more than 50 years, including natural gas services (1950s); sulfur (1960s); marine transportation (late 1980s) and terminalling and storage (early 1990s). This development of a diversified and integrated set of assets and operations has produced a complementary portfolio of midstream services that facilitates the maintenance of long-term customer relationships and encourages the development of new customer relationships.

Primary Business Segments

     Our primary business segments can be generally described as follows:

	•		Terminalling and Storage. We own or operate 12 marine shore based terminal facilities and 11 specialty terminal facilities located in the United States Gulf Coast region that provide storage, processing and handling services for producers and suppliers of petroleum products and by-products, lubricants and other liquids, including the refining of various grades and quantities of naphthenic lubricants and related products. Our facilities and resources provide us with the ability to handle various products that require specialized treatment, such as molten sulfur and asphalt. We also provide land rental to oil and gas companies along with storage and handling services for lubricants and fuel oil. We provide these terminalling and storage services on a fee basis primarily under long-term contracts. A significant portion of the contracts in this segment provide for minimum fee arrangements that are not based on the volumes handled.
	•		Natural Gas Services. Through our acquisitions of Prism Gas Systems I, L.P. (“Prism Gas”) and Woodlawn Pipeline Co., Inc. (“Woodlawn”), we have ownership interests in over 615 miles of gathering and transmission pipelines located in the natural gas producing regions of East Texas, Northwest Louisiana, the Texas Gulf Coast and offshore Texas and federal waters in the Gulf of Mexico, as well as a 285 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 or, “NGLs”. We purchase NGLs primarily from natural gas processors. We store NGLs in our supply and storage facilities for wholesale deliveries 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. We believe we have a natural gas processing competitive advantage in East Texas with the only full fractionation facilities serving this area. The recent acquisition of natural gas gathering and processing assets from Crosstex Energy, L.P. and Crosstex Energy, Inc. by our Waskom Gas Processing Company (a joint venture in which we participate with Center Point Energy Gas Processing Company, an indirect, wholly-owned subsidiary of CenterPoint Energy, Inc.) further strengthens our East Texas infrastructure.
	•		Sulfur Services. We have developed an integrated system of transportation assets and facilities relating to sulfur services over the last 30 years. We process and distribute sulfur predominantly produced by oil refineries primarily located in the United States Gulf Coast region. We handle molten sulfur on contracts that are tied to sulfur indices and tend to provide stable margins. We process molten sulfur into prilled or pelletized sulfur on take or pay fee contracts at our facilities in Port of Stockton, California and Beaumont, Texas. The sulfur we process and handle is primarily used in the production of fertilizers and industrial chemicals. We own and operate six sulfur-based fertilizer production plants and one emulsified sulfur blending plant that 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. Demand for our sulfur products exists in both the domestic and foreign markets, and we believe our asset base provides us with additional opportunities to handle increases in U.S. supply and access to foreign demand.
	•		Marine Transportation. We 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 largely in the United States Gulf Coast region. We provide these transportation services on a fee basis primarily under annual contracts and many of our customers have long standing contractual relationships with us. Over the past several years, we have focused on modernizing our fleet. As a result, the average age of our vessels has decreased from 33 years in 2006 to 22 years as of March 4, 2010 and we anticipate that the average age will be 19 years at the end of 2010. This modernized asset base is attractive both to our existing customers as well as potential new customers. In addition, our fleet contains several vessels that reflect our focus on specialty products. For example, we are one of a very limited number of companies that can transport molten sulfur.

2009 Developments and Subsequent Events

     Recent Acquisitions

     Acquisition of Cross Assets. On November 25, 2009, we closed a transaction with Martin Resource Management and Cross Refining & Marketing, Inc. (“Cross”), a wholly owned subsidiary of Martin Resource Management, in which we acquired certain specialty lubricants processing assets (“Assets”) from Cross for total consideration of $44.9 million (the “Contribution”). As consideration for the Contribution, we issued 804,721 of our common units and 889,444 subordinated units to Martin Resource Management at a price of $27.96 and $25.16 per limited partner unit, respectively. The common units will be entitled to receive distributions beginning in February 2010, while the subordinated units will have no distribution rights until the second anniversary of closing of the Contribution. At the end of such second anniversary, the subordinated units will automatically convert to common units, having the same distribution rights as existing common units. In connection with the Contribution, our general partner made a capital contribution of $0.9 million to us in order to maintain its 2% general partner interest in us.

     In connection with the closing of the Contribution, we and Martin Resource Management entered into a long-term, fee for services-based Tolling Agreement whereby Martin Resource Management agreed to pay us for the processing of its crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts. Under the Tolling Agreement, Martin Resource Management generally agreed to refine a minimum of 6,500 barrels per day of crude oil at the refinery at a price of $4.00 per barrel. Any additional barrels will be refined at a price of $4.28 per barrel. In addition, Martin Resource Management agreed to pay a monthly reservation fee of $1.3 million and a periodic fuel surcharge fee based on certain parameters specified in the Tolling Agreement. All of these fees (other than the fuel surcharge) are subject to escalation annually based upon the greater of 3% or the increase in the

Consumer Price Index for a specified annual period. In addition, every three years, the parties can negotiate an upward or downward adjustment in the fees subject to their mutual agreement. The Tolling Agreement has a 12-year term, subject to certain termination rights specified therein. Martin Resource Management will continue to market and distribute all finished products under the Cross brand name. In addition, Martin Resource Management will continue to own and operate the Cross packaging business.

     The acquisition of the Cross assets was considered a transfer of net assets between entities under common control. Accordingly, we are required to revise our financial statements to include activities of the Cross assets as of the date of common control. Our historical financial statements have been recast to reflect the results attributable to the Cross assets as if we owned the Cross assets for all periods presented.

     Acquisition of the East Harrison Pipeline System. In December 2009, we acquired, through Prism Gas, from Woodward Partners, Ltd., 6.45 miles of gathering pipeline referred to as the East Harrison Pipeline System for approximately $0.3 million. The system currently transports approximately 500 Mcfd of natural gas under various transport contracts which provide for a minimum monthly fee.

     Other Developments

     Fourth Amendment to Credit Agreement. On December 21, 2009, we entered into a Fourth Amendment (the “Fourth Amendment”) to the Second Amended and Restated Credit Agreement (the “Credit Agreement”), among Martin Operating Partnership L.P., a wholly-owned subsidiary of ours (the “Operating Partnership”), as borrower, the Partnership and certain of our subsidiaries, as guarantors, the financial institutions parties thereto, as lenders, Royal Bank of Canada, as administrative agent and collateral agent, and the various other agents and parties thereto. The Fourth Amendment modified our existing Credit Agreement to, among other things, (1) increase the total commitments of the lenders thereunder from $325.0 million to approximately $335.7 million, (2) provide that the term loans thereunder will automatically convert to revolving loans on November 10, 2010, such that after giving effect to such conversion the aggregate revolving loan commitments will be approximately $335.7 million, (3) extend the maturity date of amounts outstanding under the Credit Agreement from November 10, 2010 to November 9, 2012, (4) increase the applicable interest rate margin and fees payable to the lenders under the Credit Agreement, (5) amend the financial covenants and certain other covenants under the Credit Agreement, (6) include 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 $375.0 million for all term loan and revolving loan commitments under the Credit Agreement, (7) eliminate the requirement that we make annual prepayments of the term loans outstanding under the Credit Agreement with excess cash flow, (8) eliminate the swing line facility under the Credit Agreement and (9) limit asset dispositions to $25 million per fiscal year.

     Conversion of Subordinated Units Issued at Formation of Partnership. On November 14, 2009, all of our remaining 850,674 outstanding subordinated units, which were issued at the formation of the partnership and 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. All of the 4,253,362 original subordinated units issued to Martin Resource Management have been converted into common units on a one-for-one basis since the formation of the Partnership.

     Investment by Martin Resource Management. On November 25, 2009, we closed a private equity sale with Martin Resource Management, under which Martin Resource Management invested $20.0 million in cash in the Partnership in exchange for 714,285 of our common units (the “Investment”). In connection with the Investment, our general partner made a capital contribution to us of $0.4 million in order to maintain its 2% general partner interest in us. Proceeds from the Investment were used to repay borrowings under our credit facility.

     Subsequent Events

     Fifth Amendment to Credit Agreement. On January 14, 2010, we entered into a Fifth Amendment (the “Fifth Amendment”) to the Credit Agreement. The Fifth Amendment modified the Credit Agreement to, among other things, (1) permit us to invest up to $25 million in our joint ventures and (2) limit our ability to make capital expenditures.

     Increase Joinder. On February 25, 2010, we entered into a Commitment Increase and Joinder Agreement (the “Increase Joinder”) with respect to the Credit Agreement. The Increase Joinder increased the maximum amount of borrowings and letters of credit under our credit facility from approximately $335.7 million to $350.0 million.

     Acquisition by Waskom of the Harrison Pipeline System. On January 15, 2010, we, through Prism Gas, as 50% owner and the operator of Waskom Gas Processing Company (“WGPC”), through WGPC’s wholly owned subsidiaries Waskom Midstream LLC and Olin Gathering LLC, acquired from Crosstex North Texas Gathering, L.P., a 100% interest in approximately 62 miles of gathering pipeline, two 35 MMcfd dew point control plants and equipment

referred to as the Harrison Pipeline System. The Partnership’s share of the acquisition cost is approximately $20.0 million.

     Quarterly Distribution. On January 21, 2010, we declared a quarterly cash distribution of $0.75 per common unit for the fourth quarter of 2009, or $3.00 per common unit on an annualized basis, to be paid on February 12, 2010 to unitholders of record as of February 5, 2010, reflecting no change over the quarterly distribution paid in respect to the third quarter of 2009.

     Public Offering. On February 8, 2010, we completed a public offering of 1,650,000 common units, resulting in net proceeds of $50.6 million, after payment of underwriters’ discounts, commissions and offering expenses. Our general partner contributed $1.1 million in cash to us in conjunction with the issuance 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.

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. This ability to pursue organic growth opportunities which can be seen in the construction of our Beaumont, Texas sulfur prilling facility, which provides our customers with access to foreign markets.
	•		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 product and service offerings to existing customers is the most efficient and cost-effective method of achieving organic growth. 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. Our acquisitions have tended to focus on targets with which we are familiar through historical business relations (as suppliers or customers). This allows us to seek out operations that we believe will be strengthened by our management team and existing operations. An example of our strategy is the acquisition of our Prism subsidiary in 2005 which complemented and expanded our NGL distribution capabilities. We believe that our diversified base of operations provides multiple platforms for strategic growth through acquisitions.
	•		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. Due to our diversified portfolio of assets and the comprehensive solutions provided thereby, we believe we are an attractive partner for the pursuit of strategic alliances and 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. Our focus on geographic expansion can be seen in the 2005 acquisition of our Bay Sulfur assets in Stockton, California which allowed for us to establish our presence in the West Coast sulfur markets.

•

Maintain Financial Strength and Flexibility. We continue to seek additional long-term, fee-based contracts to further minimize our exposure to commodity price fluctuations and sustain our long-term customer relationships. We continue to hedge a significant portion of our remaining exposure to commodity price fluctuations. In addition, we intend to continue to maintain a strong balance sheet by financing growth through a combination of long-term debt and equity, with the goal of having flexibility to fund future organic growth and strategic acquisitions through opportunistically accessing the capital markets.

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 storage and midstream logistical services while minimizing our dependence on the availability and pricing of services provided by third parties. Our integrated distribution network enables us to provide customers with a complementary portfolio of transportation, terminalling, distribution and other midstream services for petroleum products and by-products. We believe our customers value the efficiency of using this complementary portfolio as opposed to contracting with a varying number of other service providers to obtain the same services.
	•		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 comprehensive 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. In addition, our natural gas services business is well positioned in the East Texas area with the only full fractionation facilities serving this area.
	•		Specialized Transportation Equipment and Storage Facilities. We have the assets and expertise to handle and transport certain petroleum products and by-products with unique requirements for transportation and storage. For example, we own facilities and resources to transport 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 allow us to enhance relationships with our customers by offering them services to handle their unique product requirements. These specialized assets, and the comprehensive solutions provided thereby, provide us with the flexibility to require minimum fee contracts with certain of our customers that require these specialized services.
	•		Ability for Growth Across Multiple Segments. Our distinct lines of business allow us to allocate capital to the most promising growth opportunities based on current and anticipated market conditions. 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 Gas’ assets are well situated in the Haynesville Shale, which is one of the four largest U.S. shale deposits, and anticipate growth opportunities as these deposits are further developed. Additionally, we believe we could significantly increase our sulfur processing capacity with minimal capital investment.
	•		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 30 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 18 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.
	•		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.
	•		Financial Strength and Flexibility. We have historically financed our operations with a combination of debt and equity while maintaining a modest leverage profile, even in challenging business environments. Since our initial public offering, we have accessed the public equity markets 4 times for $241.0 million in total net proceeds, including capital contributions from our general partner. We have also occasionally issued units to Martin Resource Management in exchange for cash or assets.
	•		Fee-Based Contracts and Active Commodity Risk Management. We generate a majority of our cash flow from fee-based contracts with our customers. In addition, a significant portion of these fee-based contracts consist of reservation charges or minimum fee arrangements, which reduce the volatility of a portion of cash flows to volume fluctuations. We seek to further minimize our exposure to commodity price fluctuations through swaps for crude oil, natural gas and natural gasoline. As of December 31, 2009, Prism Gas has hedged approximately 50% of its commodity risk by volume for 2010.

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 Shore Based Terminals. We own or operate 12 marine shore based terminals along the Gulf Coast from Venice, Louisiana 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.

     We are one of the largest operators of marine shore based terminals in the Gulf Coast region. These terminals are used to distribute and market 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. Shore bases typically provide logistical support, including the storing and handling of tubular goods, loading and unloading bulk materials, providing facilities from which major and independent oil

companies can communicate with and control offshore operations and leasing dockside facilities to companies which provide complementary products and services such as drilling fluids and cementing services. We generate revenues from our terminals that have shore bases by fees that we charge our customers under land rental contracts for the use of our terminal facility for these shore bases. These contracts generally provide us a fixed land rental fee and additional rental fees that are determined based on a percentage of the sales value of the products and services delivered from the shore base. In addition, Martin Resource Management, through contractual arrangements, pays us for terminalling and storage of fuel oil and lubricants at these terminal facilities.

     Our 12 marine shore based terminals are divided into two classes of terminals: (i) full service terminals and (ii) fuel and lubricant terminals.

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

     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 services for lubricants and fuel oil.

     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.

     Specialty Petroleum Terminals. We own or operate 11 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 2.24 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. 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.

     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. In addition, a significant portion of the contracts for our specialty terminals provide for minimum fee arrangements that are not based on the volume handled. 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.

     In Channelview, Texas, we operate an inland terminal used for lubricant blending, 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 Smackover, Arkansas, we own a refining terminal where we process crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts. This process is dedicated to an affiliate of Martin Resource Management through a long-term tolling agreement based upon throughput rates and a monthly reservation fee.

     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.

     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.

     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 railcars 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

Terminal		Location		Aggregate Capacity		Products		Description
Channelview		Houston, Texas		34,000 sq. ft. Warehouse/29,000 Bbls		Lubricants		Lubricants blending and truck loading/unloading
Cross Refining		Smackover, Arkansas		7,500 Bbls per day		Naphthenic lubricants, Distillates, Asphalt		Crude refining facility
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. 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, anhydrous ammonia 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, alkylation or MTBE 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

     Our NGL customers that utilize these assets consist of retail propane distributors, industrial processors and refiners. For the year ended December 31, 2009, we sold approximately 32% of our NGL volume to independent retail propane distributors located in Texas and the southeastern United States and approximately 68% 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 615 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 285 MMcfd natural gas processing plant located in East Texas. The underlying assets are in two operating areas:

East Texas and North Central Texas

The East Texas and North Central Texas area assets consist of the Waskom Processing Plant, Woodlawn, 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 285 MMcfd of processing capacity with full fractionation facilities. Expansions to the processing plant were completed in March and June of 2007, July of 2008 and June of 2009 increasing the capacity from 150 MMcfd to 285 MMcfd. In June 2009, the Waskom fractionator was expanded to a capacity of 14,500 barrels per day (“bpd”). For the years ended December 31, 2009 and 2008, inlet throughput and NGL fractionation averaged approximately 243 and 257 MMcfd and 10,034 and 10,542 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.
	•		Harrison Pipeline System – In January of 2010, as 50% owner and operator of Waskom Gas Processing Company, through Waskom Gas Processing Company’s wholly owned subsidiaries Waskom Midstream LLC and Olin Gathering LLC, we acquired the Harrison Pipeline System, located in Harrison County in East Texas. The system consists of approximately 62 miles of gathering pipeline, two 35 MMcfd dew point control plants and various equipment. We will reflect the results of operations from this system 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 142 miles of natural gas gathering pipe, approximately 33 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.
	•		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 the years ended December 31, 2009 and 2008, the McLeod Gathering System gathered approximately 4 and 5 MMcfd of natural gas, respectively. Prism Gas owns a consolidated 100% interest in this system.
	•		East Harrison Gathering System – In December of 2009, we acquired 6.45 miles of gathering pipeline referred to as the East Harrison Pipeline System. For December 2009, the system transported 514 Mcfd. 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, 2009 and 2008, the Hallsville Gathering System gathered approximately 18 and 21 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 owned an unconsolidated 20% non-operating interest in a partnership that owned 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 terminated in June 2009.
	•		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 and Haynesville formations 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 419 and 2,323 in calendar years 2009 and 2008, respectively. These annual permit numbers include 200 and 261 permits for horizontal wells in 2009 and 2008, respectively. Improved technology and drilling applications have enhanced the economics of drilling in the Cotton Valley formation; however, in 2009 the economic benefit was more than offset by lower prices and as a result drilling activity declined. We anticipate that drilling activity in 2010 will begin to recover from the low levels of 2009.

     In 2008 and 2009, development of the Haynesville Shale began. The Haynesville Shale is one of the four largest U.S. shale deposits. One of the largest producers in the Haynesville Shale estimates the formation will ultimately produce over 500 TCF of natural gas and will be among the top 10 natural gas fields in the world. Haynesville gas contains less natural gas liquids than Cotton Valley gas and as a result, in 2009, the inlet stream to Waskom Processing Plant contained less natural gas liquids than the historical average.

     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 70% of the 257 MMcfd of natural gas supplied in 2008 and approximately 64% of the 243 MMcfd of natural gas supplied for the year ended December 31, 2009. A substantial portion (approximately 26%) 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. In June 2009, we completed construction to expand the fractionator to 14,500 bpd to provide additional capacity for the increase in NGL volumes from the plant expansion that was underway and trucked-in NGL volumes. In 2009, trucked-in NGL volumes decreased along with the decline in drilling activity. The processing plant was expanded to 285 MMcfd in four phases with the first expansion of 30 MMcfd being completed in March 2007, the second expansion of 70 MMcfd being completed in June 2007, the third phase of 15 MMcfd being completed in July 2008 and the fourth phase of 20 MMcfd being completed in June 2009.

     There are currently five cryogenic processing plants that compete with Waskom for natural gas supplies. Drilling activity in the Cotton Valley formation 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, 34% of the contracts are fee and 16% 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. For both years ended December 31, 2009 and 2008, the system gathered and processed 24 MMcfd. 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 and Haynesville 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. The Haynesville wells are typically fee based gathering. 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 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.

     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 offshore federal waters, gathers and transports gas in both offshore and onshore areas. 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. For the year ended December 31, 2009 approximately 26 MMcfd of natural gas was gathered and transported on the system. 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, 2009 and 2008, the Matagorda Offshore Gathering System gathered approximately 10 and 15 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 Jefferson County, Texas offshore federal waters 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.

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 10 million tons of sulfur are 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.

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

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

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

     Our Operations and Products. We have an integrated system of transportation assets and facilities relating to our sulfur services. We gather molten sulfur from refiners, primarily located on the Gulf Coast, 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 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. We handle molten sulfur on margin-based contracts. 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. We process molten sulfur into prilled sulfur on take-or-pay fee contracts. Our sulfur prilling facilities provide refiners access to the export 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 the remaining sulfuric 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 238,000 tons in 2009 as a result of acquisitions and internal growth.

     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 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 59 railcars and lease approximately 150 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

     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 strial sulfur 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.

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.

     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		12		20,000 bbl and under		Asphalt, crude oil, fuel oil,
						gasoline and sulfur(1)
Inland tank barges		28		20,000 - 30,000 bbl		Asphalt, crude oil, fuel oil
						and gasoline(1)
Inland push boats		17		800 - 3,800		N/A
				horsepower
Offshore tank barges		4		40,000 bbl and 95,000		Asphalt, fuel oil and NGLs
				bbl
Offshore tugboats		4		3,200 - 7,200		N/A
				horsepower

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

     The average age of our vessels is 22 years as of March 4, 2010 and we anticipate that the average age of our vessels will be 19 years by the end of 2010.

     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:

	•		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.

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 packaging 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; and
	•		operating, solely for our account, the asphalt facilities in Omaha, Nebraska.

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

     Ownership

     As of March 4, 2010, Martin Resource Management owned an approximate 40.0% 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’s 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 $63.1 million of direct costs and expenses for the twelve months ended December 31, 2009, compared to $67.5 million for the twelve months ended December 31, 2008. 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, 2009, 2008, and 2007, the Conflicts Committee of our general partner approved reimbursement amounts of $3.5, $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. 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’s retained businesses. The omnibus agreement also contains significant non-compete provisions and indemnity obligations. Martin Resource Management also licenses certain of its trademarks and trade names to us under the omnibus agreement.

     In addition to the omnibus agreement, we and Martin Resource Management have entered into various other agreements that may not be 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, and Director Independence – 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.

     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

15%, 10% and 12% of our total cost of products sold during the years ended December 31, 2009, 2008, and 2007, 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 7%, 6% and 5% of our total revenues for the years ended December 31, 2009, 2008, and 2007, 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. Additionally, we have entered into a long-term, fee for services-based Tolling Agreement with Martin Resource Management where Martin Resource Management agrees to pay us for the processing of its crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts.

     For a more comprehensive discussion concerning the omnibus agreement and the other agreements that we have entered into with Martin Resource Management, please see “Item 13. Certain Relationships and Related Transactions, and Director Independence – 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 90% of the world’s ocean-going tonnage is reinsured through a group reinsurance policy. With regard to collision coverage, the first $1.0 million of coverage is insured by our hull policy and any excess is insured by a P&I association. We insure our owned cargo through a domestic insurance company. We insure cargo owned by third parties through our P&I coverage. As a member of P&I associations that are parties to the Pooling Agreement, we are subject to supplemental calls payable to the associations of which we are a member, based on our claims record and the other members of the other P&I associations that are parties to the Pooling Agreement. Except for our marine operations, we self-insure against liability exposure up to a 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.

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. 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 Neches Terminal we use is located in an EPA-designated ozone non-attainment area, referred to as the Beaumont/Port Arthur 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 Beaumont/Port Arthur 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 Beaumont/Port Arthur area are already subject to stringent emission reduction requirements. Failure to comply with applicable air statutes or regulations may lead to the assessment of administrative, civil or criminal penalties, and/or result in the limitation or cessation of construction or operation of certain air emission sources. We believe our operations, including our manufacturing, processing and storage facilities and terminals, are in substantial compliance with applicable requirements of the 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.

     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.

     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 George W. 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.

     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 642 individuals who provide direct support to our operations as of March 2, 2010. 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 19 to our consolidated financial statements included in this annual report on Form 10-K.

Access to Public Filings

     We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to these reports filed with the 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.

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 a default or an event of default under our credit facility, or if the payment of a distribution would cause a default or an event of default thereunder. Our leverage and various limitations in our credit facility may reduce our ability to incur additional debt, engage in certain transactions and capitalize on acquisition or other business opportunities that could increase cash flows and distributions to our unitholders.

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, disrupted and 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 these conditions, the availability of funds from the credit and capital markets has diminished significantly and the cost of raising money in the debt and equity capital markets has increased substantially. 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 our existing revolving credit facility and other debt instruments may be unwilling or unable to meet their funding obligations. These conditions, have made, and may continue to make, it difficult to obtain funding for our capital needs. Due to these conditions, we cannot be certain that new debt or equity financing will be available on acceptable terms or at all. 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, which could have a material adverse effect on our revenues and results of operations.

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

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

	•		one or more of our lenders may be unable or otherwise fail to meet its funding obligations;
	•		the lenders do not have to provide funding if there is a default under the credit facility or if any of the representations or warranties included in the credit facility are false in any material respect; and
	•		if any lender refuses to fund its commitment for any reason, whether or not valid, the other lenders are not required to provide additional funding to make up for the unfunded portion.

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

     In addition, we have 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.

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

     Currently, there are numerous international, federal and state-level initiatives and proposals addressing domestic and global climate issues. Within the U.S., most of these proposals would regulate and/or tax, in one fashion or another, the production of carbon dioxide and other “greenhouse gases” to facilitate the reduction of carbon compound emissions to the atmosphere, and provide tax and other incentives to produce and use more “clean energy.” For example, in 2009 the U.S. House of Representatives passed the Markey-Waxman bill (HR 2454), which would establish a so-called “cap and trade” regime and new permitting requirements to regulate greenhouse gas generation, as well as provide an incentive for the production and use of clean energy. To date, the U.S. Senate has not passed any comparable legislation. In sum, we believe that the potential for climate change legislation on the federal level is unknown. In addition, in late 2009, the U.S. EPA issued an “endangerment finding” under the Clear Air Act (“CAA”) with respect to carbon dioxide, which could lead to the regulation of carbon dioxide as a criteria pollutant under the CAA and have significant ramifications for us and the industry in general. On the international front, the United Nations

Climate Change Conference in Copenhagen, which took place in December 2009, did not result in any significant progress toward a binding agreement to replace the Kyoto Protocol, which expires in 2012.

     Overall, it is possible that future legislative and regulatory activity in this area will in some way impact us, but it is unclear at this time whether such impact will be, in the aggregate, positive or negative, or material. We continue to monitor political and regulatory developments in this area, but their overall impact on us, from a cost, benefit and financial performance standpoint, is uncertain at this time.

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

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

	•		post-closing discovery of material undisclosed liabilities of the acquired business or assets;
	•		the unexpected loss of key employees or customers from the acquired businesses;
	•		difficulties resulting from our integration of the operations, systems and management of the acquired business; and
	•		an unexpected diversion of our management’s attention from other operations.

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

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

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

     National weather conditions have a substantial impact on the demand for our products. Unusually warm weather during the winter months can cause a significant decrease in the demand for NGL products, 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, Rita and Ike, and their aftermath, may make some types of insurance more difficult or expensive for us to obtain. As a result, we may be unable to secure the levels and types of insurance we would otherwise have secured prior to such events. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage.

The price volatility of petroleum products and by-products 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.

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. 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 lenders 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, processing and marine transportation services to Martin Resource Management to support its businesses under various commercial contracts. The loss of Martin Resource Management as a customer could have a material adverse impact on our results of operations, cash flow and ability to make distributions to our unitholders.

Our business 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.

     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. We have 11 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, 2009, and 2008, Prism Gas purchased approximately 19% and 22%,

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 2008, the spot price of Henry Hub natural gas ranged from a high of $13.31 per MMBtu to a low of $5.38 per MMBtu. From January 1, 2009, through December 31, 2009, the same price ranged from $6.10 per MMBtu to $1.84 per MMBtu. On December 31, 2009, the spot price was $5.79 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
	•		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, 2009, Prism Gas has hedged approximately 50% of its commodity risk by volume for 2010. These hedging arrangements are in the form of swaps for crude oil, natural gas and natural gasoline. We anticipate entering into additional hedges in 2010 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.

We depend on certain natural gas producers 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 producers for a significant portion of our natural gas and NGL supply. While some of these producers 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 producers, 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.

     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 $0.5 million between 2010 and 2012 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.

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 its subsidiaries currently holds 889,444 subordinated units and 6,703,823 common units. The subordinated units will have no distribution rights until February, 2012. At the end of such second anniversary, the subordinated units will automatically convert to common units, having the same distribution rights as existing common units.

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

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

	•		the issuance of common units in additional public offerings or in connection with acquisitions that increase cash flow from operations on a pro forma, per unit basis;
	•		the conversion of subordinated units into common units;
	•		the conversion of units of equal rank with the common units into common units under some circumstances; or
	•		the conversion of our general partner’s general partner interest in us and its incentive distribution rights into common units as a result of the withdrawal of our general partner.

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

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

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

Unitholders have less power to elect or remove management of our general partner than holders of common stock in a corporation. Common unitholders will not have sufficient voting power to elect or remove our general partner without the consent of Martin Resource Management.

     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 40.8% of our outstanding limited partnership units as of March 4, 2010, our general partner initially cannot be removed without the consent of it and its affiliates.

     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.

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

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

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

	•		permits our general partner to make a number of decisions in its “sole discretion.” This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner;
	•		provides that our general partner is entitled to make other decisions in its “reasonable discretion” which may reduce the obligations to which our general partner would otherwise be held;
	•		generally provides that affiliated transactions and resolutions of conflicts of interest not involving a required vote of unitholders must be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the interests of all parties involved, including its own; and
	•		provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for errors of judgment or for any acts or omissions if our general partner and those other persons acted in good faith.

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

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

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

	•		the issuance of common units in additional public offerings or in connection with acquisitions that increase cash flow from operations on a pro forma, per unit basis;
	•		the conversion of subordinated units into common units;
	•		the conversion of units of equal rank with the common units into common units under some circumstances; or

•

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

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

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

	•		our unitholders’ proportionate ownership interest in us will decrease;
	•		the amount of cash available for distribution on a per unit basis may decrease;
	•		because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
	•		the relative voting strength of each previously outstanding unit will diminish;
	•		the market price of the common units may decline; and
	•		the ratio of taxable income to distributions may increase.

The control of our general partner may be transferred to a third party, and that party could replace our current management team, without unitholder consent. 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 Global Select 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 addressing these assessments. During the course of our testing we may identify deficiencies which we may not be able to address in time to meet the deadline imposed by the Sarbanes-Oxley Act for compliance with the requirements of Section 404. In addition, if we fail to maintain the adequacy of our internal controls, as such standards are modified, supplemented or amended from time to time, we may not be able to ensure that we can conclude on an ongoing basis that we have effective internal controls over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act. Failure to achieve and maintain an effective internal control environment could have a material adverse effect on the price of our common units.

Risks Relating to Our Relationship with Martin Resource Management

Existing litigation between Ruben Martin and Scott Martin and related parties concerning the ownership, management and operation of Martin Resource Management, the owner of our General Partner, could adversely effect us.

     There are several pending lawsuits between Ruben Martin, the President, Chief Executive Officer and member of the board of directors of our General Partner, and Scott Martin, who is Ruben Martin’s brother, and related parties concerning the ownership, management and operation of Martin Resource Management, the owner of our General Partner. We are not a party to any of those lawsuits and they do not assert any claims (i) against us, (ii) concerning our governance or operations or (iii) against our directors, officers or employees with respect to their service to us. The existence of those lawsuits, however, including any ultimate outcomes that might be deemed negative to us or our existing management team, could adversely effect our ability to access capital markets or obtain additional credit or negatively impact our business, results of operations and/or ability to make distributions to our unitholders. Any similar effects from such litigation on Martin Resource Management or its existing management team could also adversely affect us.

     In addition, such litigation, depending on its ultimate outcome, could also result in changes in the existing boards of directors and management teams of Martin Resource Management and us. To the extent that any such adverse circumstances occur, they could be deemed by our lenders to have a “material adverse effect” on us, thereby providing such lenders with an opportunity to prohibit further borrowings by us under our credit facility and, depending on the circumstances, assert that an event of default exists thereunder. If any such event of default exists and is continuing, then, upon the election of our lenders, all outstanding amounts due under our credit facility could be accelerated and could become immediately due and payable. Similarly, a negative outcome in such litigation could result in a similar result under the credit facility maintained by Martin Resource Management. While any such litigation remains pending, there can be no assurance that the litigation parties adverse to our existing management team or the existing management team of Martin Resource Management will not seek to disrupt, delay or postpone any future attempts by us to access the capital markets.

     For a more detailed discussion of these pending litigation matters, please see “Item 9B. Other Information —Existing Litigation at Martin Resource Management.”

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

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

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

     As of March 4, 2010, Martin Resource Management owns an approximate 40.0% 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.
	•		The audit committee of our general partner retains our independent auditors.
	•		In some instances, our general partner may cause us to borrow funds to permit us to pay cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions.
	•		Our general partner has broad discretion to establish financial reserves for the proper conduct of our business. These reserves also will affect the amount of cash available for distribution.

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

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

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

     If Martin Resource Management were ever to commence or consent to the commencement of a bankruptcy proceeding or otherwise defaults on its obligations under its credit facility, its lenders could foreclose on its pledge of the interests in our general partner and take control of our general partner. If Martin Resources Management no longer

controls our general partner, the lenders under our credit facility may declare all amounts outstanding thereunder immediately due and payable. In addition, either a judgment against Martin Resource Management or a bankruptcy filing by or against Martin Resource Management could independently result in an event of default under our credit facility if it could reasonably be expected to have a material adverse effect on us. If our lenders do declare us in default and accelerate repayment, we may be required to refinance our debt on unfavorable terms, which could negatively impact our results of operations and our ability to make distributions to our unitholders. A bankruptcy filing by or against Martin Resource Management could also result in the termination or material breach of some or all of the various commercial contracts between us and Martin Resource Management, which could have a material adverse impact on our results of operations, cash flow and ability to make distributions to our unitholders.

Tax Risks

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

     The anticipated after-tax economic benefit of an investment in us depends largely on our classification as a partnership for federal income tax purposes. In order for us to be classified as a partnership for U.S. federal income tax purposes, more than 90% of our gross income each year must be “qualifying income” under Section 7704 of the U.S. Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”). “Qualifying income” includes income and gains derived from the transportation, storage, processing and marketing of crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. Thus, “qualifying income” includes income from providing marine transportation services to customers with respect to crude oil, natural gas and certain products thereof but does not include rental income from leasing vessels to customers. The recent decision of the United States Court of Appeals for the Fifth Circuit in Tidewater Inc. v. United States, 565 F.3d 299 (5th Cir. April 13, 2009) held that marine time charter agreements are “leases” that generate rental income for purposes of a foreign sales corporation provision of the Code.

     After the Tidewater decision, there is some uncertainty regarding the status of a significant portion of our income as “qualifying income” and, thus, whether we are classified as a partnership for federal income tax purposes. As a result of this uncertainty, our counsel, Baker Botts L.L.P., has previously rendered an opinion that we should (as opposed to will) be classified as a partnership for U.S. federal income tax purposes. Additionally, as a result of the Tidewater decision, we have requested a private letter ruling from the U.S. Internal Revenue Service to confirm that gross income from our marine time charter agreements constitutes “qualifying income” under Section 7704 of the Internal Revenue Code. There can be no assurance that the U.S. Internal Revenue Service (the “IRS”) will issue a favorable private letter ruling to us.

     If the income from our marine time charters were not considered “qualifying income,” then we would not have satisfied the “qualifying income” requirement of Section 7704 for any year of our existence and, accordingly, we would be classified as a corporation for federal income tax purposes. If we were treated as a corporation for federal income tax purposes, we would owe federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%, and would likely owe state income tax at varying rates, for 2006 through the current tax year. Distributions would generally be taxed again to unitholders as corporate distributions and no income, gains, losses, or deductions would flow through to unitholders. Because a tax would be imposed upon us as an entity for a period of several years, cash available for distribution to unitholders would be reduced. Treatment of us as a corporation would result in a reduction in the anticipated cash flow and after-tax return to unitholders and therefore would likely result in a reduction in the value of the common units.

     Moreover, current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. At the federal level, members of Congress have considered substantive changes to the existing U.S. tax laws that would have affected certain publicly traded partnerships. Although the legislation considered would not have appeared to affect our tax treatment, we are unable to predict whether any such change or other proposals will ultimately be enacted. Moreover, any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Any such changes could negatively impact the value of an investment in our common units. At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay Texas franchise tax at a maximum effective rate of 0.7% of our gross income apportioned to Texas in the prior year. Imposition of any such tax on us by any other state will reduce the cash available for distribution to you.

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

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

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

Unitholders may be required to pay taxes on income from us even if they do not receive any cash distributions from us.

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

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

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

Tax-exempt entities and 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 unitholders’ tax returns.

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

     In addition to federal income taxes, unitholders may be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. Unitholders may be required to file state, local and foreign income

tax returns and pay state and local income taxes in some or all of the various jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. We own property and 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.

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.

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. Reserved

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, 2010 there were approximately 24 holders of record and approximately 10,934 beneficial owners of our common units. In addition, as of that date there were 889,444 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:

Fiscal 2009:

		Common Units								Distributions Declared per Unit
Quarters Ended		High				Low				Common				Subordinated1
March 31, 2009		$	21.00			$	14.89			$	0.750			$	0.750
June 30, 2009		$	21.96			$	17.33			$	0.750			$	0.750
September 30, 2009		$	28.50			$	20.70			$	0.750			$	0.750
December 31, 2009		$	31.69			$	26.02			$	0.750			$	0.750

Fiscal 2008:

		Common Units								Distributions Declared per Unit
Quarters Ended		High				Low				Common				Subordinated1
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

     On March 3, 2010, the last reported sales price of our common units as reported on the NASDAQ was $31.91 per unit.

     On November 25, 2009, we closed a transaction with Martin Resource Management and Cross, in which we acquired certain specialty lubricants processing assets from Cross for total consideration of $44.9 million. As consideration for the Contribution, we issued 804,721 of our common units and 889,444 subordinated units to Martin Resource Management at a price of $27.96 and $25.16 per limited partner unit, respectively. The common units will be entitled to receive distributions beginning in February 2010, while the subordinated units will have no distribution rights until the second anniversary of closing of the Contribution. At the end of such second anniversary, in November 2011, the subordinated units will automatically convert to common units, having the same distribution rights as existing common units. In connection with the Contribution, our general partner made a capital contribution of $0.9 million to us in order to maintain its 2% general partner interest in us. The units were issued in reliance on the exemption from registration provided by Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”). We accounted for the Cross acquisition as a transfer of net assets between entities under common control. The Cross assets were recorded at $33.0 million, which represents the amounts reflected in Martin Resource Management’s historical consolidated financial statements. The difference between the purchase price and Martin Resource Management’s carrying value of the combined net assets acquired and liabilities assumed was recorded as an adjustment to partners’ capital.

     On November 25, 2009, we closed a private equity sale with Martin Resource Management, under which Martin Resource Management invested $20.0 million in cash in us in exchange for 714,285 of our common units. In connection with the Investment, our general partner made a capital contribution to us of $0.4 million in order to maintain its 2% general partner interest in us. Proceeds from the Investment were used to repay borrowings under our credit facility. In issuing the common units, we relied on the exemption from registration provided by Section 4(2) of the Securities Act.

     All of our original 4,253,362 outstanding subordinated units owned by Martin Resource Management and its subsidiaries, which were issued at the formation of the Partnership, converted into common units on a one-for-one basis following our quarterly cash distributions in November 2009. The subordinated units converted as follows: 850,674 on November 14, 2009 and 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.

     Within 45 days after the end of each quarter, we distribute all of our available cash, as defined in our partnership agreement, to unitholders of record on the applicable record date. Until our current subordinated units convert into common units in November 2011, the subordinated units will not have the right to receive distributions of available cash from operating surplus .

     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 a default or an event of

default, or a 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.”

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, 2009, 2008, 2007, 2006 and 2005 is derived from the audited consolidated financial statements of Martin Midstream Partners L.P.

     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.

		20091				20081				20071				2006				2005
Income Statement Data:
Revenues		$	662,385			$	1,246,444			$	804,327			$	576,384			$	438,443
Cost of product sold			457,259				1,013,526				618,689				459,170				351,820
Operating expenses			117,438				126,808				104,165				65,387				46,888
Selling, general, and administrative			19,775				19,062				13,918				10,977				8,133
Depreciation and amortization			39,506				34,893				26,323				17,597				12,642
Total costs and expenses			633,978				1,194,289				763,095				553,131				419,483
Other operating income			6,013				209				703				3,356				—
Operating income			34,420				52,364				41,935				26,609				18,960
Equity in earnings of unconsolidated entities			7,044				13,224				10,941				8,547				1,591
Interest expense			(18,995	)			(21,433	)			(15,125	)			(12,466	)			(6,909	)
Debt prepayment premium			—				—				—				(1,160	)			—
Other, net			326				801				405				713				238
Income before income taxes			22,795				44,956				38,156				22,243				13,880
Income taxes			592				1,398				5,595				—				—
Net income		$	22,203			$	43,558			$	32,561			$	22,243			$	13,880
Net income per limited partner unit		$	1.17			$	2.72			$	1.67			$	1.69			$	1.58
Weighted average limited partner units			14,680,807				14,529,826				14,018,799				12,602,000				8,583,634
Balance Sheet Data (at Period End):
Total assets		$	685,939			$	706,322			$	656,604			$	457,461			$	389,044
Due to affiliates			13,810				23,085				17,119				10,474				3,492
Long-term debt			304,372				295,000				225,000				174,021				192,200
Partner’s capital (owner’s equity)			264,951				246,379				246,765				198,525				95,565
Cash Flow Data:
Net cash flow provided by (used in):
Operating activities			47,592				86,340				61,209				39,317				32,334
Investing activities			(14,675	)			(106,621	)			(130,295	)			(95,098	)			(138,742	)
Financing activities			(34,944	)			24,151				69,896				52,991				109,689
Other Financial Data:
Maintenance capital expenditures			7,601				17,998				11,955				12,391				5,100
Expansion capital expenditures			28,572				89,435				109,474				78,267				74,110
Total capital expenditures		$	36,173			$	107,433			$	121,429			$	90,658			$	79,210
Cash dividends per common unit (in dollars)		$	3.00			$	2.91			$	2.60			$	2.44			$	2.19

     The following tables present our historical results of operations, the effect of including the results of the Cross assets which are included in our terminalling and storage segment and the revised total amounts included in our consolidated financial statements:

		Year Ended December 31, 2009
		Historical
		Martin Midstream
		Partners LP				Cross Assets Results				Revised Total
		(Dollars in thousands, except per unit amounts)
Revenues		$	633,776			$	28,609			$	662,385
Costs and expenses:
Cost of products sold (excluding depreciation and amortization)			457,259				—				457,259
Operating expenses			98,677				18,761				117,438
Selling, general and administrative			18,090				1,685				19,775
Depreciation and amortization			35,143				4,363				39,506
Total costs and expenses			609,169				24,809				633,978
Other operating income			6,160				(147	)			6,013
Operating income			30,767				3,653				34,420
Equity in earnings of unconsolidated entities			7,044				—				7,044
Interest expense			(18,124	)			(871	)			(18,995	)
Other, net			303				23				326
Net income before taxes			19,990				2,805				22,795
Income tax benefit (expense)			549				( 1,141	)			( 592	)
Net income		$	20,539			$	1,664			$	22,203

		Year Ended December 31, 2008
		Historical
		Martin Midstream
		Partners LP				Cross Assets Results				Revised Total
		(Dollars in thousands, except per unit amounts)
Revenues		$	1,213,958			$	32,486			$	1,246,444
Costs and expenses:
Cost of products sold (excluding depreciation and amortization)			1,013,526				—				1,013,526
Operating expenses			102,894				23,914				126,808
Selling, general and administrative			16,939				2,123				19,062
Depreciation and amortization			31,218				3,675				34,893
Total costs and expenses			1,164,576				29,712				1,194289
Other operating income			209				—				209
Operating income			49,591				2,773				52,364
Equity in earnings of unconsolidated entities			13,224				—				13,224
Interest expense			(19,777	)			(1,656	)			(21,433	)
Other, net			483				318				801
Net income before taxes			43,521				1,435				44,956
Income tax benefit (expense)			( 711	)			( 687	)			(1,398	)
Net income		$	42,810			$	748			$	43,558

		Year Ended December 31, 2007
		Historical
		Martin Midstream
		Partners LP				Cross Assets Results				Revised Total
		(Dollars in thousands, except per unit amounts)
Revenues		$	765,822			$	38,505			$	804,327
Costs and expenses:
Cost of products sold (excluding depreciation and amortization)			618,689				—				618,689
Operating expenses			83,533				20,632				104,165
Selling, general and administrative			11,985				1,933				13,918
Depreciation and amortization			23,442				2,881				26,323
Total costs and expenses			737,649				25,446				763,095
Other operating income			703				—				703
Operating income			28,876				13,059				41,935
Equity in earnings of unconsolidated entities			10,941				—				10,941
Interest expense			(14,533	)			(592	)			(15,125	)
Other, net			299				106				405
Net income before taxes			25,583				12,573				38,156
Income tax benefit (expense)			( 644	)			( 4,951	)			(5,595	)
Net income		$	24,939			$	7,622			$	32,561

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.

     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 and by-products;
	•		Natural gas services;
	•		Sulfur and sulfur-based products gathering, processing, marketing, manufacturing and distribution; and
	•		Marine transportation services for petroleum products and by-products.

     The petroleum products and by-products we gather, process, 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 generate the majority of our cash flow from fee-based contracts with these customers. Our location in the Gulf Coast region of the United States provides us strategic access to a major hub for petroleum refining, natural gas gathering and processing and support services for the exploration and production industry.

     We were formed in 2002 by Martin Resource Management, a privately-held company whose initial predecessor was incorporated in 1951 as a supplier of products and services to drilling rig contractors. Since then, Martin Resource Management has expanded its operations through acquisitions and internal expansion initiatives as its management identified and capitalized on the needs of producers and purchasers of hydrocarbon products and by-products and other bulk liquids. As of March 4, 2010, Martin Resource Management owns an approximate 40.0% 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.

     The historical operation of our business segments by Martin Resource Management provides us with several decades of experience and a demonstrated track record of customer service across our operations. Our current lines of business have been developed and systematically integrated over this period of more than 50 years, including natural gas services (1950s); sulfur (1960s); marine transportation (late 1980s) and terminalling and storage (early 1990s). This development of a diversified and integrated set of assets and operations has produced a complementary portfolio of midstream services that facilitates the maintenance of long-term customer relationships and encourages the development of new customer relationships.

2009 Developments and Subsequent Events

     Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. Numerous events have restricted current liquidity in the capital markets throughout the United States and around the world. The ability to raise money in the debt and equity markets has diminished and, if available, the cost of funds has increased. One of the features driving investments in master limited partnerships, including us, over the past few years has been the distribution growth offered by master limited partnerships due to liquidity in the financial markets for capital investments to grow distributable cash flow through development projects and acquisitions. Growth opportunities have been and are expected to continue to be constrained by the lack of liquidity in the financial markets.

     Conditions in our industry continued to be challenging in 2009. For example:

	•		Market prices of oil, natural gas, NGLs, and sulfur remained below the market prices realized throughout most of 2008.
	•		The decline in drilling activity by gas producers in our areas of operations that began during the fourth quarter of 2008 as a result of the global economic crisis has continued. Several gas producers in our areas of operation substantially reduced drilling activity during 2009 as compared to their drilling levels during 2008.
	•		The decline in the demand for marine transportation services based on decreased refinery production resulting in an oversupply of equipment.
	•		A modest shift in marine transportation contracts from term contracts to spot contracts.

Despite the weaker commodity price environment and reduced drilling activity, we are positioning ourselves to benefit from a recovering economy. In particular:

	•		We adjusted our business strategy for 2009 to focus on maximizing our liquidity, maintaining a stable asset base and improving the profitability of our assets by increasing their utilization while controlling costs. We also reduced our capital expenditures.
	•		We continue to evaluate opportunities to enter into commodity hedging transactions to further reduce our commodity price risk.
	•		We completed the disposition of certain non-strategic assets including the April 2009 sale of the Mont Belvieu Railcar Unloading Facility for $19.6 million, and we may consider marketing certain other non-strategic assets in the future.
	•		We extended the maturity date of our existing credit facility and increased the aggregate commitments of the lenders thereunder through an amendment in order to have sufficient liquidity to fund our growth programs, while continuing the present distribution rate to our unitholders. The current economic crisis and the existing litigation at Martin Resource Management 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 acquired certain assets of a subsidiary of Martin Resource Management in exchange for the issuance of new common and subordinated units to maintain appropriate financial ratios satisfactory to our lenders. See “Recent Acquisitions — Acquisition of Cross Assets”.

     Recent Acquisitions

     Acquisition of Cross Assets. On November 25, 2009, we closed a transaction with Martin Resource Management and Cross Refining & Marketing, Inc. (“Cross”), a wholly owned subsidiary of Martin Resource Management, in which we acquired certain specialty lubricants processing assets (“Assets”) from Cross for total consideration of $44.9 million (the “Contribution”). As consideration for the Contribution, we issued 804,721 of our common units and 889,444 subordinated units to Martin Resource Management at a price of $27.96 and $25.16 per limited partner unit, respectively. The common units will be entitled to receive distributions beginning in February 2010, while the subordinated units will have no distribution rights until the second anniversary of closing of the Contribution. At the end of such second anniversary, the subordinated units will automatically convert to common units, having the same distribution rights as existing common units. In connection with the Contribution, our general partner made a capital contribution of $0.9 million to us in order to maintain its 2% general partner interest in us.

     In connection with the closing of the Contribution, we and Martin Resource Management entered into a long-term, fee for services-based Tolling Agreement whereby Martin Resource Management agreed to pay us for the processing of its crude oil into finished products, including naphthenic lubricants, distillates, asphalt and other intermediate cuts. Under the Tolling Agreement, Martin Resource Management has generally agreed to refine a minimum of 6,500 barrels per day of crude oil at the refinery at a price of $4.00 per barrel. Any additional barrels will be refined at a price of $4.28 per barrel. In addition, Martin Resource Management has agreed to pay a monthly reservation fee of $1.3 million and a periodic fuel surcharge fee based on certain parameters specified in the Tolling Agreement. All of these fees (other than the fuel surcharge) are subject to escalation annually based upon the greater of 3% or the increase in the Consumer Price Index for a specified annual period. In addition, every three years, the parties can negotiate an upward or downward adjustment in the fees subject to their mutual agreement. The Tolling Agreement has a 12 year term, subject to certain termination rights specified therein. Martin Resource Management will continue to market and distribute all finished products under the Cross brand name. In addition, Martin Resource Management will continue to own and operate the Cross packaging business.

     The acquisition of the Cross assets was considered a transfer of net assets between entities under common control. Accordingly, we are required to revise our financial statements to include activities of the Cross assets as of the date of common control. Our historical financial statements have been recast to reflect the results attributable to the Cross assets as if we owned the Cross assets for all periods presented.

     Acquisition of the East Harrison Pipeline System. In December 2009, we acquired, through Prism Gas, from Woodward Partners, Ltd. 6.45 miles of gathering pipeline referred to as the East Harrison Pipeline System for approximately $0.3 million. The system currently transports approximately 500 Mcfd of natural gas under various transport contracts which provide for a minimum monthly fee.

     Other Developments

     Fourth Amendment to Credit Agreement. On December 21, 2009, we entered into a Fourth Amendment (the “Fourth Amendment”) to the Second Amended and Restated Credit Agreement (the “Credit Agreement”), among Martin Operating Partnership L.P., a wholly-owned subsidiary of ours (the “Operating Partnership”), as borrower, the Partnership and certain of our subsidiaries, as guarantors, the financial institutions parties thereto, as lenders, Royal Bank of Canada, as administrative agent and collateral agent, and the various other agents and parties thereto. The Fourth Amendment modified our existing Credit Agreement to, among other things, (1) increase the total commitments of the lenders thereunder from $325.0 million to approximately $335.7 million, (2) provide that the term loans thereunder will automatically convert to revolving loans on November 10, 2010, such that after giving effect to such conversion the aggregate revolving loan commitments will be approximately $335.7 million, (3) extend the maturity date of amounts outstanding under the Credit Agreement from November 10, 2010 to November 9, 2012, (4) increase the applicable interest rate margin and fees payable to the lenders under the Credit Agreement, (5) amend the financial covenants and certain other covenants under the Credit Agreement, (6) include 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 $375.0 million for all term loan and revolving loan commitments under the Credit Agreement, (7) eliminate the requirement that we make annual prepayments of the term loans outstanding under the Credit Agreement with excess cash flow, (8) eliminate the swing line facility under the Credit Agreement and (9) limit asset dispositions to $25 million per fiscal year.

     Conversion of Subordinated Units Issued at Formation of Partnership. On November 14, 2009, all of our remaining 850,674 outstanding subordinated units issued at the formation of the partnership and 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. All of the 4,253,362 original subordinated units issued to Martin Resource Management have been converted into common units on a one-for-one basis since the formation of the Partnership.

     Investment by Martin Resource Management. On November 25, 2009, we closed a private equity sale with Martin Resource Management, under which Martin Resource Management invested $20.0 million in cash in the Partnership in exchange for 714,285 of our common units (the “Investment”). In connection with the Investment, our general partner made a capital contribution to us of $0.4 million in order to maintain its 2% general partner interest in us. Proceeds from the Investment were used to repay borrowings under our credit facility.

     Subsequent Events

     Fifth Amendment to Credit Agreement. On January 14, 2010, we entered into a Fifth Amendment (the “Fifth Amendment”) to the Credit Agreement. The Fifth Amendment modified the Credit Agreement to, among other things, (1) permit us to invest up to $25 million in our joint ventures and (2) limit our ability to make capital expenditures.

     Increase Joinder. On February 25, 2010, we entered into a Commitment Increase and Joinder Agreement (the “Increase Joinder”) with respect to the Credit Agreement. The Increase Joinder increased the maximum amount of borrowings and letters of credit under our credit facility from approximately $335.7 million to $350.0 million.

     Acquisition by Waskom of the Harrison Pipeline System. On January 15, 2010, the Partnership, through Prism Gas, as 50% owner and the operator of Waskom Gas Processing Company (“WGPC”), through WGPC’s wholly owned subsidiaries Waskom Midstream LLC and Olin Gathering LLC, acquired from Crosstex North Texas Gathering, L.P., a 100% interest in approximately 62 miles of gathering pipeline, two 35 MMcfd dew point control plants and equipment referred to as the Harrison Pipeline System. The Partnership’s share of the acquisition cost is approximately $20.0 million.

     Quarterly Distribution. On January 21, 2010, we declared a quarterly cash distribution of $0.75 per common unit for the fourth quarter of 2009, or $3.00 per common unit on an annualized basis, to be paid on February 12, 2010 to unitholders of record as of February 5, 2010, reflecting no change over the quarterly distribution paid in respect to the third quarter of 2009.

     Public Offering. In February 2010, we completed a public offering of 1,650,000 common units, resulting in net proceeds of $50.6 million, after payment of underwriters’ discounts, commissions and offering expenses. Our general partner contributed $1.1 million in cash to us in conjunction with the issuance 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.

Critical Accounting Policies

     Our discussion and analysis of our financial condition and results of operations are based on the historical consolidated and condensed 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 and condensed 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 as it relates to our annual goodwill evaluation.

     Derivatives

     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. Our hedging policy allows us to use hedge accounting for financial transactions that are designated as hedges. Derivative instruments not designated as hedges or hedges that become ineffective are being marked to market with all market value adjustments being recorded in the consolidated statements of operations. As of December 31, 2009, we have 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 partners’ capital.

     Product Exchanges

     We enter into product exchange agreements with third parties whereby we agree to exchange natural gas liquids (“NGLs”) and sulfur with third parties. We record 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 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. For our tolling agreement, revenue is recognized based on the contracted monthly reservation fee and throughput volumes moved through the facility. When lubricants and drilling fluids are sold by truck, 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.

     Sulfur services — Revenue is recognized when the customer takes title to the product at our plant or the customer facility.

     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.

     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. This goodwill is not subject to amortization and is accounted for as a component of the investment. Equity method investments are subject to impairment evaluation. No portion of the net income from these entities is included in our operating income.

     We own an unconsolidated 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.

     Goodwill

     Goodwill is subject to a fair-value based impairment test on an annual basis. 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. We are required to determine the fair value of each reporting unit and compare it to the carrying amount of the reporting unit. To the extent the carrying amount of a reporting unit exceeds the fair value of the reporting unit, 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.

     All four of our “reporting units”, terminalling and storage, marine transportation, natural gas services and sulfur services, contain goodwill.

     We have performed the annual impairment tests as of September 30, 2009, September 30, 2008, and September 30, 2007, and we have determined fair value in each reporting unit based on the weighted average of three

valuation techniques: (i) the discounted cash flow method, (ii) the guideline public company method, and (iii) the guideline transaction method. At September 30, 2009, 2008 and 2007 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 under certain provisions of ASC 350-20, 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.

     No such triggering events occurred that would cause us to perform an impairment test at December 31, 2009.

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

     Environmental Liabilities and Litigation

     We have not historically 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.

     Because the outcomes of both contingent liabilities and litigation are difficult to predict, when accounting for these situations, significant management judgment is required. Amounts paid for contingent liabilities and litigation have not had a materially adverse effect on our operations or financial condition and we do not anticipate they will in the future.

     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 specific and general reserves for bad debts to reduce the related receivables to the amount we ultimately expect to collect from customers.

     Our management closely monitors potentially uncollectible accounts. Estimates of uncollectible amounts are revised each period, and changes are recorded in the period they become known. If there is a deterioration of a major customer’s creditworthiness or actual defaults are higher than the historical experience, management’s estimates of the recoverability of amounts due us could potentially be adversely affected. These charges have not had a materially adverse effect on our operations or financial condition.

     Asset Retirement Obligation

     We recognize and measure our asset and conditional asset retirement obligations and the associated asset retirement cost upon acquisition of the related asset and based upon the estimate of the cost to settle the obligation at its anticipated future date. The obligation is accreted to its estimated future value and the asset retirement cost is depreciated over the estimated life of the asset.

     Estimates of future asset retirement obligations include significant management judgment and are based on projected future retirement costs. Such costs could differ significantly when they are incurred. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates due to surface repair, and labor and

material costs, revisions to estimated inflation rates and changes in the estimated timing of abandonment. For example, the Company does not have access to natural gas reserves information related to our gathering systems to estimate when abandonment will occur.

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, 2009, 2008 and 2007, the Conflicts Committee of our general partner approved reimbursement amounts of $3.5, $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.

     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. All of these services and goods are purchased and sold pursuant to the terms of a number of agreements between us and Martin Resource Management.

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

Results of Operations

     The results of operations for the twelve months ended December 31, 2009, 2008 and 2007 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, 2009, 2008 and 2007.

										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, 2009:
Terminalling and storage		$	109,513			$	(4,219	)		$	105,294			$	20,231			$	(2,332	)		$	17,899
Natural gas services			408,989				(7	)			408,982				4,880				786				5,666
Sulfur services			79,631				(2	)			79,629				9,575				4,201				13,776
Marine transportation			72,103				(3,623	)			68,480				5,811				(2,655	)			3,156
Indirect selling, general and administrative			—				—				—				(6,077	)			—				(6,077	)
Total		$	670,236			$	(7,851	)		$	662,385			$	34,420			$	—			$	34,420
Year ended December 31, 2008:
Terminalling and storage		$	122,960			$	(4,189	)		$	118,771			$	15,034			$	(3,635	)		$	11,399
Natural gas services			679,375				—				679,375				2,780				945				3,725
Sulfur services			372,987				(1,038	)			371,949				31,956				5,224				37,180
Marine transportation			80,059				(3,710	)			76,349				8,104				(2,534	)			5,570
Indirect selling, general and administrative			—				—				—				(5,510	)			—				(5,510	)
Total		$	1,255,381			$	(8,937	)		$	1,246,444			$	52,364			$	—			$	52,364

										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, 2007:
Terminalling and storage		$	98,295			$	(865	)		$	97,430			$	23,804			$	(472	)		$	23,332
Natural gas services			515,992				—				515,992				4,159				333				4,492
Sulfur services			131,602				(276	)			131,326				9,222				3,818				13,040
Marine transportation			63,533				(3,954	)			59,579				7,949				(3,679	)			4,270
Indirect selling, general and administrative			—				—				—				(3,199	)			—				(3,199	)
Total		$	809,422			$	(5,095	)		$	804,327			$	41,935			$	—			$	41,935

     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.

     The acquisition of the Cross assets was considered a transfer of net assets between entities under common control. Accordingly, we are required to revise our financial statements to include activities of the Cross assets as of the date of common control. Our historical financial statements have been recast to reflect the results attributable to the Cross assets as if we owned the Cross assets for all periods presented.

Year Ended December 31, 2009 Compared to the Year Ended December 31, 2008

     Our total revenues before eliminations were $670.2 million for the year ended December 31, 2009 compared to $1,255.4 million for the year ended December 31, 2008, a decrease of $585.2 million, or 47%. Our operating income before eliminations was $34.4 million for the year ended December 31, 2009 compared to $52.4 million for the year ended December 31, 2008, a decrease of $18.0 million, or 34%.

     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,
		2009				2008
		(In thousands)
Revenues:
Services		$	73,885			$	72,604
Products			35,628				50,356
Total Revenues			109,513				122,960
Cost of products sold			31,331				42,721
Operating expenses			45,783				50,001
Selling, general and administrative expenses			1,955				2,243
Depreciation and amortization			15,717				12,947
			14,727				15,048
Other operating income (loss)			5,504				(14	)
Operating income		$	20,231			$	15,034