Edgar Filing: MARTIN MIDSTREAM PARTNERS LP

e424b2

Filed Pursuant to Rule 424(b)(2)

Registration No. 333-117023

PROSPECTUS SUPPLEMENT

(To Prospectus dated July 19, 2004)

3,000,000 Common Units

Representing Limited Partner Interests

$29.12 Per Common Unit

We are selling 3,000,000 common units representing limited partner interests. We have granted the underwriters an option to purchase up to 450,000 additional common units to cover over-allotments.

Our common units are quoted on the Nasdaq National Market under the symbol “MMLP.” The last reported sale price of our common units on the Nasdaq National Market on January 10, 2006 was $29.12 per common unit.

Investing in our common units involves risks. See “Risk Factors” beginning on page S-13 of this prospectus supplement and page 2 of the accompanying prospectus.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus supplement or the accompanying prospectus is truthful or complete. Any representation to the contrary is a criminal offense.


	Per Common Unit		Total

Public Offering Price	$	29.120	$	87,360,000
Underwriting Discount	$	1.310	$	3,931,200
Proceeds to Martin Midstream Partners L.P. (before expenses)	$	27.810	$	83,428,800

The underwriters expect to deliver the common units to purchasers on or about January 17, 2006.

Sole Book-Running Manager

Citigroup


Raymond James	RBC Capital Markets	A.G. Edwards

KeyBanc Capital Markets

January 10, 2006

You should rely only on the information contained or incorporated by reference in this prospectus supplement or the accompanying prospectus. We have not, and the underwriters have not, authorized any other person to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should not assume that the information appearing in this prospectus supplement or the accompanying prospectus is accurate as of any date other than the date on the front cover of this prospectus supplement. Our business, financial condition, results of operations and prospects may have changed since that date.

TABLE OF CONTENTS


	Page

Prospectus Supplement
Forward-Looking Statements		S-ii
About this Prospectus Supplement		S-ii
Summary		S-1
Risk Factors		S-13
Use Of Proceeds		S-32
Capitalization		S-33
Price Range Of Common Units And Distributions		S-34
Selected Historical And Pro Forma Financial Data		S-35
Management’s Discussion And Analysis Of Financial Condition And Results Of Operations		S-38
Business		S-71
Management		S-92
Material Tax Considerations		S-95
Investment In Martin Midstream Partners L.P. By Employee Benefit Plans		S-110
Underwriting		S-111
Validity Of The Common Units		S-113
Experts		S-113
Where You Can Find More Information		S-113
Incorporation Of Documents By Reference		S-115
Index To Unaudited Pro Forma Financial Statements		F-1
Prospectus dated July 19, 2004
About This Prospectus		i
Martin Midstream Partners L.P.		1
The Guarantors		1
Risk Factors		2
Forward-Looking Statements		17
Use of Proceeds		18
Ratio of Earnings to Fixed Charges		18
Description of the Debt Securities		18
Description of the Common Units		27
Cash Distribution Policy		30
The Partnership Agreement		38
Material Tax Considerations		50
Investment In Us By Employee Benefit Plans		63
Plan of Distribution		64
Legal Matters		65
Experts		65
Where You Can Find More Information		66
Incorporation By Reference		66
Glossary of Terms		A-1

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FORWARD-LOOKING STATEMENTS

Statements included in this prospectus supplement or the accompanying prospectus 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 under “Risk Factors” and elsewhere in this prospectus supplement or the accompanying prospectus.

ABOUT THIS PROSPECTUS SUPPLEMENT

This document consists of two parts. The first part is this prospectus supplement, which describes the specific terms of this offering and certain other matters relating to us. The second part, the accompanying prospectus, gives more general information about securities we may offer from time to time, some of which does not apply to this offering. If the information in this prospectus supplement differs from the information in the accompanying prospectus, the information in this prospectus supplement supersedes the information in the accompanying prospectus.

Martin Midstream Partners L.P. is the issuer of securities in this offering. References in this prospectus supplement to “Martin Midstream Partners L.P.,” “we,” “ours,” “us” or like terms when used in the present tense or prospectively or for historical periods since November 2002 refer to Martin Midstream Partners L.P. and its consolidated subsidiaries. References to “Martin Midstream Partners Predecessor,” “we,” “ours,” “us” or like terms when used in a historical context for periods prior to November 2002 refer to the assets, liabilities and operations of Martin Resource Management’s businesses that were contributed to us in connection with the closing of our initial public offering in November 2002. References in this prospectus supplement to “Martin Resource Management” refer to Martin Resource Management Corporation and its direct and indirect consolidated subsidiaries. References in this prospectus supplement to “CF Martin Sulphur” refer to CF Martin Sulphur, L.P., in which we acquired all of the remaining interests not previously owned by us on July 15, 2005. References in this prospectus supplement to “Prism Gas” refer to Prism Gas Systems I, L.P., which we acquired on November 10, 2005. For the reasons stated elsewhere herein, we refer to the term EBITDA. EBITDA is a non-GAAP financial measure, which is explained in greater detail below under “Summary — Summary Historical and Pro Forma Financial Data — Non-GAAP Financial Measure.” In this prospectus supplement, we refer to liquefied petroleum gas as “LPG,” barrels per day as “bpd,” natural gas liquid as “NGL,” a British thermal unit as a “btu” and millions of cubic feet per day as “MMcfd.”

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SUMMARY

This summary highlights information contained elsewhere in this prospectus supplement and the accompanying prospectus. You should read the entire prospectus supplement, the accompanying prospectus, the information incorporated by reference and the other information to which we refer for a more complete understanding of this offering. The information presented in this prospectus supplement assumes that the underwriters’ option to purchase additional common units is not exercised. Financial information, other than pro forma financial information, presented in this prospectus supplement and the accompanying prospectus does not include financial results from any acquisition prior to its closing date. Pro forma financial information presented in this prospectus supplement gives pro forma effect to the acquisitions of Prism Gas and CF Martin Sulphur, assuming that such acquisitions occurred on January 1, 2004, the related borrowings under our credit facility and this offering. For a more detailed description of the pro forma adjustments and the assumptions used in preparing the pro forma financial information, you should read the pro forma financial statements and the accompanying notes included elsewhere in this prospectus supplement. You should read “Risk Factors” beginning on page S-13 of this prospectus supplement and on page 2 of the accompanying prospectus for information about important factors you should consider before buying our common units.

Martin Midstream Partners L.P.

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


	•	Terminalling and storage services for petroleum products and by-products

	•	Natural gas gathering, processing and LPG distribution

	•	Marine transportation services for petroleum products and by-products

	•	Sulfur gathering, processing and distribution

	•	Fertilizer manufacturing and distribution

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

On November 10, 2005, we acquired Prism Gas, a natural gas gathering and processing company with operations in East Texas, Northwest Louisiana and the Texas Gulf Coast, for approximately $97.4 million. The operations of Prism Gas are focused in areas that continue to experience high levels of drilling activity and natural gas production. Through acquisitions and internal growth projects, Prism Gas has increased its total average daily gathering and processing system volume from 145 MMcfd in 2002 to 210 MMcfd in 2004. For the nine months ended September 30, 2005, Prism Gas had total average daily gathering and processing system volume of 220 MMcfd. Prism Gas’ net income before taxes increased from $(0.5) million in 2002 to $4.9 million in 2004. For the nine months ended September 30, 2005, Prism Gas had net income before taxes of $3.4 million.

Primary Business Segments

Our primary business segments can be generally described as follows:


	•	Terminalling and Storage. We own or operate 16 marine terminal facilities and two inland terminal facilities located in the United States Gulf Coast region that provide storage and handling services for producers and suppliers of petroleum products and by-products, lubricants and other

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		liquids. We also provide land rental to oil and gas companies along with storage and handling services for lubricants and fuel oil.

	•	Natural Gas Gathering, Processing and LPG Distribution. Through our acquisition of Prism Gas, we have ownership interests in over 330 miles of natural gas gathering pipelines located in the natural gas producing regions of East Texas, Northwest Louisiana and the Texas Gulf Coast and in offshore Texas and federal waters in the Gulf of Mexico as well as a 150 MMcfd capacity processing plant located in East Texas. In addition to our newly acquired natural gas gathering and processing business, we distribute LPGs. We purchase LPGs primarily from oil refiners and natural gas processors. We store LPGs in our supply and storage facilities for resale to propane retailers, refineries and industrial LPG users in Texas and the Southeastern United States. We own three LPG supply and storage facilities with an aggregate above ground storage capacity of approximately 132,000 gallons and we lease approximately 72 million gallons of underground storage capacity for LPGs.

	•	Marine Transportation. We own a fleet of 36 inland marine tank barges, 17 inland pushboats and two offshore tug barge units that transport petroleum products and by-products primarily in the United States Gulf Coast region. We provide these transportation services on a fee basis primarily under annual contracts.

	•	Sulfur. We gather, process and distribute sulfur predominately produced by oil refineries primarily located in the United States Gulf Coast region. We process molten sulfur into prilled, or pelletized, sulfur under fee-based volume contracts at our facility in Port of Stockton, California. We are currently constructing an additional sulfur priller at our Neches facility in Beaumont, Texas. In July 2005, we acquired the remaining interests in CF Martin Sulphur not previously owned by us. CF Martin Sulphur gathers, transports and stores molten sulfur supplied by oil refineries.

	•	Fertilizer. We own and operate six 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.

The following table provides a summary of the revenue and operating income of our business segments, pro forma for the November 2005 acquisition of Prism Gas and the July 2005 acquisition of CF Martin Sulphur as if they occurred on January 1, 2004:


		Year Ended							Nine Months Ended
		December 31, 2004							September 30, 2005

							Equity in							Equity in
				Operating			Earnings of				Operating			Earnings of
				Income			Unconsolidated				Income			Unconsolidated
		Revenue		(loss)			Entities		Revenue		(loss)			Entities

		(Dollars in thousands)
Terminalling and Storage		$	26,113	$	6,705		$	—	$	23,970	$	6,272		$	—
Natural Gas Gathering, Processing and LPG Distribution(1)			265,676		82			7,112		257,621		2,756			4,896
Marine Transportation(2)			28,991		38			—		23,323		(846	)		—
Sulfur(2)			63,999		7,027			—		51,376		5,563			—
Fertilizer			29,464		2,210			—		25,793		1,995			—

	Total Before Indirect Expenses		414,243		16,062			7,112		382,083		15,740			4,896

Indirect Expenses			—		(2,766	)		—		—		(2,524	)		—

Total		$	414,243	$	13,296		$	7,112	$	382,083	$	13,216		$	4,896


(1)	Through our acquisition of Prism Gas in November 2005, we acquired an unconsolidated 50% interest in each of the Waskom Gas Processing Company, the owner of the Waskom Processing Plant, Panther Interstate Pipeline Energy, LLC, the owner of the Fishhook Gathering System, and the

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	Matagorda Gathering System. As a result, these interests are accounted for using the equity method of accounting, and we do not include any portion of their net income in our operating income.

(2)	As a result of our July 2005 acquisition of the remaining interests in CF Martin Sulphur not previously owned by us, we have reclassified our consolidated financial statements to eliminate previously reported intersegment sales from our marine transportation segment to our sulfur segment. This elimination reduced marine transportation revenue and marine transportation operating income by $5.8 million for the year ended December 31, 2004 and by $4.5 million for the nine months ended September 30, 2005. Correspondingly, our sulfur segment operating expenses have been reduced, and operating income has been increased, by $5.8 million for the year ended December 31, 2004 and $4.5 million for the nine months ended September 30, 2005.

Our principal executive offices are located at 4200 Stone Road, Kilgore, Texas 75662, our phone number is (903) 983-6200, and our web site is www.martinmidstream.com.

Recent Developments

Recent Acquisitions

Prism Gas Acquisition. On November 10, 2005, we acquired Prism Gas. The selling parties in this transaction were Natural Gas Partners V, L.P. and certain members of the Prism Gas management team. The final purchase price was approximately $97.4 million (including the assumption of approximately $4.2 million in working capital obligations, $0.3 million of assumed long-term liabilities and $0.5 million in acquisition expenses), subject to post-closing reconciliations. The purchase price was funded through a combination of the following:


	•	$62.8 million in revolving and term borrowings under our credit facility;

	•	$5.0 million in a previously funded escrow account;

	•	$15.0 million in new equity capital provided by Martin Resource Management, the owner of our general partner, in exchange for 460,971 common units;

	•	$9.6 million in seller financing through the issuance of 295,509 common units to certain members of the Prism Gas management team, most of whom have remained with the acquired business; and

	•	$0.5 million in capital provided by Martin Resource Management to continue its 2% general partnership interest in us.

We intend to use a portion of the net proceeds from this offering to repay $48.3 million in revolving credit facility indebtedness incurred in connection with the Prism Gas acquisition.

This acquisition provides us with an attractive opportunity to enter into another significant segment of the midstream energy industry, the natural gas gathering and processing business. Through its natural gas gathering and processing operations, Prism Gas facilitates the transportation of natural gas from wells in East Texas, Northern Louisiana and offshore Texas and federal waters in the Gulf of Mexico to connections with intrastate and interstate pipelines that transport natural gas to other regions of the United States. The operations of Prism Gas are focused in areas that continue to experience high levels of drilling activity and increasing natural gas production. Prism Gas has capitalized on these trends by acquiring and constructing additional gathering lines and interests in the Waskom Processing Plant, a natural gas processing plant located in East Texas. Through these initiatives, Prism Gas has increased its natural gas gathering and processing volumes significantly since 2002. We believe the strategically located Prism Gas assets, combined with our access to capital and our existing infrastructure, will enhance our ability to offer additional gathering and processing services to customers through internal growth projects including natural gas processing, fractionation and pipeline expansions as well as new pipeline construction.

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Texas and federal waters in the Gulf of Mexico as well as a 150 MMcfd capacity natural gas processing plant located in East Texas. The underlying assets are in two operating areas:


	•	The East Texas area assets consist of the Waskom Processing Plant, the McLeod Gathering System and other related gathering systems (collectively known as the East Texas Gathering System).


	-	Waskom Processing Plant — The Waskom Processing Plant, located in Harrison County in East Texas, currently has 150 MMcfd of processing capacity with full fractionation facilities. For the nine months ended September 30, 2005, inlet throughput and NGL fractionation averaged approximately 157 MMcfd and 7,300 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.

	-	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 nine months ended September 30, 2005, the McLeod Gathering System gathered approximately 7 MMcfd of natural gas. Prism Gas owns a consolidated 100% interest in this system.

	-	East Texas Gathering Systems — The East Texas Gathering Systems, located in Panola and Harrison Counties, Texas, are gathering systems built to deliver gas produced in these areas to market outlets. Prism Gas owns a consolidated 100% interest in this system.


	•	The Gulf Coast area assets consist of the Fishhook Gathering System and the Matagorda Gathering System located offshore and onshore in the Texas Gulf Coast.


	-	Fishhook Gathering System — The Fishhook Gathering System, located in Jefferson County, Texas and offshore federal waters, gathers and transports gas in both offshore and onshore areas. For the nine months ended September 30, 2005, the Fishhook Pipeline gathered and transported approximately 37 MMcfd of natural gas. Prism Gas owns an unconsolidated 50% non-operating interest in Panther Interstate Pipeline Energy, LLC, 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 Gathering System — The Matagorda Gathering System, located in Matagorda County, Texas and offshore Texas state waters, gathers gas in both the offshore and onshore areas. For the nine months ended September 30, 2005, the Matagorda Gathering System gathered approximately 16 MMcfd of natural gas. Prism Gas owns an unconsolidated 50% non-operating interest in the Matagorda 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.

Prism Gas’ gathering and processing revenues are earned under various contractual arrangements with gas producers. Gathering revenues are generated through a combination of fee for service and percent-of-proceeds (POP) contracts. Processing revenues are generated primarily through contracts which provide for processing on a percent-of-liquids (POL) and a POP basis. As of December 31, 2005, Prism Gas had hedged approximately 63% of its commodity risk by volume for 2006. We anticipate entering into additional hedges in 2006 and beyond to further reduce our exposure to commodity price movements, although there can be no assurance that we will enter into any new hedging arrangements or that the terms thereof will be similar to our existing arrangements. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk” for additional information concerning these hedging arrangements.

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A&A Fertilizer. On December 13, 2005, we acquired the operating assets of A&A Fertilizer from an unrelated third party for $6.0 million. We use these assets, which are located in Beaumont, Texas, to manufacture fertilizer products, and these assets are included in our fertilizer segment. We intend to use a portion of the net proceeds from this offering to repay $6.0 million borrowed under our revolving credit facility to complete this acquisition.

CF Martin Sulphur Acquisition. On July 15, 2005, we acquired the remaining interests in CF Martin Sulphur not previously owned by us from CF Industries, Inc. and certain subsidiaries of Martin Resource Management for $18.9 million. In connection with the acquisition, we assumed $11.5 million in debt, of which we promptly repaid $2.1 million. We intend to use a portion of the net proceeds from this offering to repay the remaining assumed indebtedness and the related pre-payment premium. Prior to this transaction, we owned an unconsolidated non-controlling 49.5% limited partnership interest in CF Martin Sulphur, which was accounted for using the equity method of accounting. Subsequent to the acquisition, CF Martin Sulphur is consolidated within our sulfur segment. CF Martin aggregates, transports, stores and distributes molten sulfur supplied primarily by oil refineries.

Bay Sulfur Asset Acquisition. On April 20, 2005, we acquired the operating assets and sulfur inventories of Bay Sulfur Company located at the Port of Stockton, California for $5.9 million. We use the assets acquired to process molten sulfur into pellets. These assets are included in our sulfur segment.

LPG Pipeline Purchase. On January 3, 2005, we acquired an LPG pipeline located in East Texas from an unrelated third party for $3.8 million. We use the pipeline, which spans approximately 200 miles, from Kilgore to Beaumont, Texas, to transport LPGs for third parties and our own account. These assets are included in our natural gas processing, gathering and LPG distribution segment.

Other Developments

New Credit Facility. In connection with the Prism Gas acquisition, we entered into a $225.0 million multi-bank credit facility. The credit facility is comprised of a $130.0 million term loan facility and a $95.0 million revolving credit facility. The revolving credit facility is used for ongoing working capital needs and general partnership purposes and to finance permitted investments, acquisitions and capital expenditures. On November 10, 2005, we borrowed $130.0 million under the term loan facility and $52.2 million under the revolving credit facility to repay preexisting indebtedness under our prior credit facility and to fund a portion of the purchase price paid in the Prism Gas acquisition as described above. On December 13, 2005, we borrowed $6.0 million under the revolving credit facility to fund the purchase price paid in the A&A Fertilizer acquisition as described above. We intend to use a portion of the net proceeds from this offering to repay $54.3 million in revolving credit facility indebtedness incurred in connection with the Prism Gas and the A&A Fertilizer acquisitions.

Hurricanes. During the third quarter of 2005, several of our facilities in the United States Gulf Coast region were in the path of Hurricanes Katrina and Rita. We experienced damage to minor buildings and tanks at our Sabine Pass, Venice, Intracoastal City, Port Fourchon, Galveston, Cameron West, Neches and Stanolind facilities, which resulted in an accrual of a non-cash impairment charge of $1.2 million equal to the net-book value of the damaged assets and a corresponding receivable for the expected recovery under our applicable insurance polices. We also recognized a loss of $0.6 million during the third quarter of 2005 equal to the applicable deductible under these insurance policies. The damage from the hurricanes did not have a material impact on our business.

Increased Quarterly Distribution. We declared a quarterly cash distribution for the fourth quarter of 2005 of $0.61 per common and subordinated unit on January 5, 2006, reflecting an increase of $0.04 per unit over the quarterly distribution paid in respect of the third quarter of 2005. The distribution represents our third distribution increase since the distribution paid in respect of the fourth quarter of 2004. The new distribution represents a 14% increase when compared to the distribution paid in respect of the fourth quarter of 2004.

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Conversion of Subordinated Units. On November 14, 2005, 850,672 of our 4,253,362 outstanding subordinated units owned by Martin Resource Management, the owner of our general partner, converted into common units on a one-for-one basis following our quarterly cash distribution on such date. Additional conversions of our outstanding subordinated units may occur in the future provided that certain distribution thresholds contained in our partnership agreement are met by us.

Business Strategy

The key components of our business strategy are to:


	•	Pursue 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. We believe that our diversified base of operations provides multiple platforms for strategic growth through acquisitions.

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

	•	Pursue Organic Growth by Attracting New Customers and Expanding Services Provided to Existing Customers. We seek to identify and pursue opportunities to expand our customer base across all of our business segments. We generally begin a relationship with a customer by transporting or marketing a limited range of products and services. We believe expanding our customer base and our service and product offerings to existing customers is the most efficient and cost effective method of achieving organic growth in revenues and cash flow. We believe significant opportunities exist to expand our customer base and provide additional services and products to existing customers.

	•	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.

	•	Pursue Strategic Alliances. Many of our larger customers are establishing strategic alliances with midstream service providers such as us to address logistical and transportation problems or achieve operational synergies. These strategic alliances are typically structured differently than our regular commercial relationships, with the goal that such alliances would expand our business relationships with our customers and suppliers. We intend to pursue strategic alliances with customers in the future.

Competitive Strengths

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


	•	Asset Base and Integrated Distribution Network. We operate a diversified asset base that, together with the services provided by Martin Resource Management, enables us to offer our customers an integrated distribution network consisting of transportation, terminalling and midstream logistical services while minimizing our dependence on the availability and pricing of services provided by third parties. Our integrated distribution network enables us to provide customers a complementary

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		portfolio of transportation, terminalling, distribution and other midstream services for petroleum products and by-products.

	•	Strategically Located Assets. We believe we are one of the largest providers of shore bases and one of the largest lubricant distributors and marketers in the United States Gulf Coast region. In addition, we are one of the largest operators of marine service terminals in the United States Gulf Coast region providing broad geographic coverage and distribution capability of our products and services to our customers. Our natural gas gathering and processing assets are focused in areas that have continued to experience high levels of drilling activity and natural gas production.

	•	Specialized Transportation Equipment and Storage Facilities. We have the assets and expertise to handle and transport certain petroleum products and by-products with unique requirements for transportation and storage, such as molten sulfur and asphalt. For example, we own facilities and resources to transport molten sulfur and asphalt, which must be maintained at temperatures between approximately 275 and 350 degrees Fahrenheit to remain in liquid form. We believe these capabilities help us enhance relationships with our customers by offering them services to handle their unique product requirements.

	•	Ability to Grow Our Natural Gas Gathering and Processing Services. We believe that, with our recent acquisition of Prism Gas, we have opportunities for organic growth in our natural gas gathering and processing operations through increasing fractionation capacity, pipeline expansions, as well as new pipeline construction.

	•	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 25 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 22 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 Flexibility. We believe the borrowings available under our credit facility and our ability to issue additional partnership units provide us with the financial flexibility necessary to enable us to pursue expansion and acquisition opportunities.

Our Relationship with Martin Resource Management

We were formed by Martin Resource Management, a privately held company whose initial predecessor was incorporated in 1951. We are and will continue to be closely affiliated with Martin Resource Management, who will own, upon completion of this offering, an approximate 37.8% limited partnership interest in us, a 2% general partnership interest in us and all of our incentive distribution rights. Martin Resource Management directs our business operations through its ownership and control of our general partner. In addition, under the terms of an omnibus agreement with Martin Resource Management, the employees of Martin Resource Management are responsible for conducting our business and operating our assets. Martin Resource Management is also an important supplier and customer of ours. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our Relationship with Martin Resource Management.”

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Martin Midstream Partners L.P. Structure and Ownership

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The Offering


Common units offered to the public		3,000,000 common units.

		3,450,000 common units if the underwriters exercise their option to purchase additional common units in full.

Exchange listing		Our common units are quoted on the Nasdaq National Market under the symbol “MMLP.”

Units outstanding after this offering		8,829,652 common units and 3,402,690 subordinated units, representing a 70.7% and 27.3% limited partner interest in us, respectively.

Use of proceeds		We intend to use a portion of the net proceeds from this offering to repay approximately $72.2 million of indebtedness and to fund approximately $12.5 million in pending acquisitions and expansion capital expenditures. Please read “Use of Proceeds.”

Timing of next quarterly distribution		The first distribution paid to purchasers of the units offered by this prospectus supplement was declared on January 5, 2006 and will be paid in mid-February 2006. Our current quarterly cash distribution rate is $0.61 per common unit, or $2.44 per common unit on an annualized basis.

Subordination period		Our partnership agreement provides that our 3,402,690 subordinated units may periodically convert into common units prior to September 30, 2009 if we meet certain quarterly financial tests. The subordination period for our subordinated units will end if we meet the financial tests in our partnership agreement, but it generally cannot end before September 30, 2009. When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages. Please read “Cash Distribution Policy — Subordination Period — Early Conversion of Subordinated Units” in the accompanying prospectus.

Issuance of additional units		In general, during the subordination period we can issue up to 1,500,000 additional common units without obtaining unitholder approval. We can also issue an unlimited number of common units for acquisitions, capital improvements or repayments of certain debt that increase cash flow from operations per unit on a pro forma basis and upon conversion of our subordinated units. Please read “The Partnership Agreement — Issuance of Additional Securities” in the accompanying prospectus.

Estimated ratio of taxable income to distributions		We estimate that if you hold the common units you purchase in this offering through December 31, 2008, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be approximately 20% or less of the cash distributed to you with respect to that period. Please read “Material Tax Considerations — Tax Consequences of Unit Ownership — Ratio of Taxable Income to Distributions” for the basis of this estimate.

Material tax considerations		For a discussion of other material federal income tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Tax Considerations.”

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Summary Historical and Pro Forma Financial Data

The following table shows summary historical and pro forma financial data for Martin Midstream Partners Predecessor and Martin Midstream Partners L.P. for the periods and as of the dates indicated. Martin Midstream Partners Predecessor is the term used to describe certain assets, liabilities and operations owned by Martin Resource Management that were transferred to us upon completion of our initial public offering in November 2002. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The summary historical financial data as of and for the periods presented below is derived from the audited or unaudited combined or consolidated statements of either Martin Midstream Partners Predecessor or Martin Midstream Partners included in our filings with the Securities and Exchange Commission, or “SEC”, which are incorporated by reference herein.

The summary pro forma financial data is derived from the unaudited pro forma financial statements included elsewhere in this prospectus supplement. For income statement items, the summary pro forma financial data assumes that the Prism Gas acquisition, the CF Martin Sulphur acquisition and the related borrowings under our credit facility occurred on January 1, 2004. For balance sheet items, the summary pro forma financial data assumes that this offering occurred on September 30, 2005. For a description of all of the assumptions used in preparing the summary pro forma financial data, you should read the notes to the pro forma financial statements included elsewhere in this prospectus supplement. The pro forma financial data should not be considered as indicative of the historical results we would have had or the future results that we will have after the offering.

Prior to July 15, 2005, we owned an unconsolidated non-controlling 49.5% limited partner interest in CF Martin Sulphur. We accounted for this interest in CF Martin Sulphur using the equity method of accounting. As a result, we did not include any portion of the net income attributable to CF Martin Sulphur in our operating income or in the operating income of any of our segments. Rather, we included only our share of its net income in our statement of operations. On July 15, 2005, we acquired the remaining interests in CF Martin Sulphur not previously owned by us from CF Industries, Inc. and certain affiliates of Martin Resource Management. Subsequent to the acquisition, CF Martin Sulphur is included in the consolidated financial presentation of our sulfur segment.

In connection with our acquisition of Prism Gas, we acquired an unconsolidated 50% interest in each of the Waskom Gas Processing Company, the owner of the Waskom Processing Plant, and the Matagorda Gathering System. We also acquired a 50% interest in Panther Interstate Pipeline Energy LLC, the owner of the Fishhook Gathering System. As a result, these interests are accounted for using the equity method of accounting and we do not include any portion of their net income in our operating income.

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The following table also shows our EBITDA which is described below under “— Non-GAAP Financial Measure.”


		Martin			Martin Midstream Partners
		Midstream
		Predecessor

					Period From															Pro Forma As Adjusted
		Period From			November 6,
		January 1,			2002			Years Ended						Nine Months Ended									Nine Months
		2002 Through			Through			December 31,						September 30,						Year Ended			Ended
		November 5,			December 31,															December 31,			September 30,
		2002			2002			2003			2004			2004			2005			2004			2005

														(Unaudited)
		(In thousands)
Income Statement Data:
Revenues		$	116,160		$	33,746		$	192,731		$	294,144		$	202,511		$	293,816		$	414,243		$	382,083
Cost of products sold			84,442			26,504			150,892			229,976			156,892			232,141			331,245			308,622
Operating expenses			17,389			3,189			21,590			34,475			24,995			32,778			46,297			39,953
Selling, general, and administrative expenses			4,662			656			4,986			6,198			4,672			5,420			10,482			9,041
Depreciation and amortization			3,741			747			4,765			8,766			6,276			8,672			12,923			11,251

	Total costs and expenses		110,234			31,096			182,233			279,415			192,835			279,011			400,947			368,867
Other Operating income			—			—			589			—			—			—			—			—

Operating income			5,926			2,650			11,087			14,729			9,676			14,805			13,296			13,216
Equity in earnings (losses) of unconsolidated entities			2,565			599			2,801			912			532			222			7,112			4,896
Interest expense			(3,283	)		(345	)		(2,001	)		(3,326	)		(2,338	)		(3,834	)		(7,204	)		(6,327	)
Other, net			42			5			94			11			52			127			237			108

Income before income taxes			5,250			2,909			11,981			12,326			7,922			11,320			13,441			11,893
Income taxes			1,959			—			—			—			—			—			—			—

Net income		$	3,291		$	2,909		$	11,981		$	12,326		$	7,922		$	11,320		$	13,441		$	11,893

Balance Sheet Data (at Period End):
Total assets					$	100,455		$	139,685		$	188,332		$	175,594		$	255,234					$	404,009
Due to affiliates						—			560			429			210			1,216						6,960
Long-term debt (including current portion)						35,000			67,000			73,000			69,000			121,004						139,104
Owner’s equity (partners’ capital)						47,106			45,892			75,534			75,671			72,843						182,672
Cash Flow Data:
Net cash flow provided by (used in):
	Operating activities	$	316		$	4,824		$	10,273		$	12,812		$	7,889		$	24,276
	Investing activities		(1,962	)		(2,116	)		(27,621	)		(34,322	)		(31,789	)		(46,445	)
	Financing activities		6,897			(6,287	)		17,884			22,424			23,857			22,101
Other Financial Data:
Maintenance capital expenditures(1)		$	394		$	157		$	2,773		$	5,182		$	5,396		$	3,179
Expansion capital expenditures(1)			1,909			2,850			29,159			30,234			30,019			33,142

	Total capital expenditures	$	2,303		$	3,007		$	31,932		$	35,416		$	35,415		$	36,321

EBITDA(2)(3)		$	12,274		$	4,001		$	18,747		$	24,418		$	16,536		$	23,826		$	33,568		$	29,471


(1)	Maintenance capital expenditures represent capital expenditures to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and extend their useful lives. Expansion capital expenditures represent capital expenditures to expand the existing operating capacity of our assets, whether through construction or acquisition. Repair and maintenance expenditures associated with existing assets that are minor in nature and do not extend the useful life of existing assets are treated as operating expenses as incurred.

(2)	See “Non-GAAP Financial Measure” below.

(3)	For the nine months ended September 30, 2005, pro forma as adjusted EBITDA includes an approximately $0.9 million charge in connection with the settlement of an outstanding Prism Gas lawsuit.

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	*Non-GAAP Financial Measure*

We define EBITDA as net income plus interest expense, income taxes and depreciation and amortization expense. We use EBITDA as a supplemental financial measure to assess:


	•	the ability of our assets to generate cash sufficient for us to pay interest costs and to make cash distributions to our unitholders;

	•	the financial performance of our assets;

	•	our performance over time and in relation to other companies that own similar assets and that we believe calculate EBITDA in a manner similar to us; and

	•	in certain situations, the appropriateness of the purchase price of assets or companies we might consider acquiring.

We also understand that such data is used by investors to assess our historical ability to service our indebtedness and make cash distributions to unitholders. However, the term EBITDA is not defined under generally accepted accounting principles and EBITDA is not a measure of operating income or operating performance presented in accordance with generally accepted accounting principles. When assessing our operating performance, you should not consider this data in isolation or as a substitute for our net income, cash flow from operating activities or other cash flow data calculated in accordance with generally accepted accounting principles. In addition, our EBITDA may not be comparable to EBITDA or similarly titled measures utilized by other companies since such other companies may not calculate EBITDA in the same manner as we do.

You should note that our EBITDA and our net income through July 14, 2005, included our equity in the earnings of CF Martin Sulphur, in which we owned an unconsolidated non-controlling 49.5% limited partnership interest. Under the equity method of accounting, we included in our earnings our proportionate share of CF Martin Sulphur’s income or losses. On July 15, 2005, we acquired the remaining interests in CF Martin Sulphur not previously owned by us. As a result, since that date our consolidated financial results reflect the operations of CF Martin Sulphur. In connection with our acquisition of Prism Gas, we acquired an unconsolidated 50% interest in each of the Waskom Gas Processing Company, the owner of the Waskom Processing Plant, and the Matagorda Gathering System. We also acquired a 50% interest in Panther Interstate Pipeline Energy LLC, the owner of the Fishhook Gathering System. As a result, these interests are accounted for using the equity method of accounting and we do not include any portion of their net income in our operating income.

The following table reconciles our historical EBITDA to our historical net income and on a pro forma basis as described elsewhere herein:


		Martin
		Midstream
		Predecessor		Martin Midstream Partners

		Period From		Period From										Pro Forma As Adjusted
		January 1,		November 6,
		2002		2002		Years Ended				Nine Months Ended						Nine Months
		Through		Through		December 31,				September 30,				Year Ended		Ended
		November 5,		December 31,										December 31,		September 30,
		2002		2002		2003		2004		2004		2005		2004		2005

										(Unaudited)
		(In thousands)
EBITDA Reconciliation:
	Net Income	$	3,291	$	2,909	$	11,981	$	12,326	$	7,922	$	11,320	$	13,441	$	11,893
Plus:
	Depreciation and amortization		3,741		747		4,765		8,766		6,276		8,672		12,923		11,251
	Interest Expense		3,283		345		2,001		3,326		2,338		3,834		7,204		6,327
	Income Taxes		1,959		—		—		—		—		—		—		—

EBITDA		$	12,274	$	4,001	$	18,747	$	24,418	$	16,536	$	23,826	$	33,568	$	29,471

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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. You should carefully consider the following risk factors together with all of the other information included in this prospectus supplement and in the accompanying prospectus in evaluating an investment in our common units. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline and you could lose all or part of your investment.

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. Investors 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.

You 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.


	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.

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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 terminalling and storage and 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 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 LPG 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 LPGs 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. As a result of the September 11 attacks and the risk of future terrorist attacks, we may be unable to secure the levels and types of insurance we would otherwise have secured prior to September 11. 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 results of operations and ability to make distributions to our unitholders.*

We purchase petroleum products and by-products such as molten sulfur, sulfur derivatives and LPGs, and sell these products to wholesale and bulk customers and to other end users. Since the closing of the Tesoro Marine asset acquisition, we and our affiliates also distribute and market lubricants. We also generate revenues through the terminalling of certain products for third parties. The price and market value of petroleum products and by-products can be volatile. Our revenues have been adversely affected by

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this volatility during periods of decreasing prices because of the reduction in the value and resale price of our inventory. Future price volatility could have an adverse impact on our results of operations, cash flow and ability to make distributions to our unitholders.


	*Increasing energy prices could adversely affect our results of operations.*

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


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

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


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

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


	*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, including Prism Gas, 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.

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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.


	*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 LPG and fertilizer businesses are seasonal and could cause our revenues to vary.*

The demand for LPG and natural gas is highest in the winter. Therefore, revenue from our natural gas gathering, processing and LPG distribution business is higher in the winter than in other seasons. Our fertilizer business experiences 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 business lines 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;

S-16

restricting the manner in which we can release materials into the environment; requiring remedial activities or capital expenditures to mitigate pollution from former of 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 lender under our credit facility could declare amounts outstanding thereunder immediately due and payable. If such event occurs, our results of operations and our ability to make distribution to our unitholders could be negatively impacted.

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


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

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


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

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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 remediations;

	•	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.


	*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 flag vessels when compared with foreign flag 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 flag 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.

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	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 U.S. Oil Pollution Act of 1990, or 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. Under OPA 90, substantially all tank vessels that do not have double hulls will be phased out by 2015 and will not be permitted to come to 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 of our offshore tank barges are double-hull vessels and have no phase out date. We have 13 inland single-hull barges that will be phased out in the year 2015. The phase out of these single-hull vessels in accordance with OPA 90 may require us to make substantial capital expenditures, which could adversely affect our operations and market position and reduce our cash available for distribution.

Risks Relating to Our Acquisition of Prism Gas


	*There may be risks or costs resulting from the Prism Gas acquisition that are not known to us.*

We may not be aware of all of the risks associated with the Prism Gas acquisition. Any discovery of adverse information concerning the assets or operations we acquired could be material and, in many cases, would be subject to only limited rights of recovery. In addition, we will likely have to make capital expenditures, which may be significant, but which amount has not been fixed, to enhance or integrate the assets and operations we acquired.


	*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 year ended December 31, 2004 and the nine months ended September 30, 2005, Prism Gas purchased approximately 63% and 55%, 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 2004, the spot price of Henry Hub natural gas ranged from a high of $8.14 per MMBtu to a low of $4.40 per MMBtu. From January 1, 2005 through December 31, 2005, the same price ranged from $15.39 per MMBtu to $5.50 per MMBtu. On December 31, 2005 the spot price was $9.52 per MMBtu.

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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, cash flows and financial condition.*

As of December 31, 2005, Prism Gas has hedged approximately 63% of its commodity risk by volume for 2006. We anticipate entering into additional hedges in 2006 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 an investment grade commercial bank. 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.

For periods after 2006, our management will 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

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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 work as planned. We cannot assure you 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 read “Management’s Discussion and Analysis of Financial Condition and Results of Operation — 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 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 you.


	We depend on certain natural gas producer customers for a significant portion of our supply of natural gas and NGLs. The loss of any of these customers could result in a decline in our volumes, revenues and cash available for distribution.

We rely on certain natural gas producer customers for a significant portion of our natural gas and NGL supply. While some of these customers are subject to long-term contracts, we may be unable to negotiate extensions or replacements of these contracts on favorable terms, if at all. The loss of all or even a portion of the natural gas volumes supplied by these customers, as a result of competition or otherwise, could have a material adverse effect on our business, results of operations and financial condition, unless we were able to acquire comparable volumes from other sources.


	*We may not successfully balance our purchases and sales of natural gas, which would increase our exposure to commodity price risks.*

We purchase from producers and other customers a significant amount of the natural gas that flows through our natural gas gathering, processing and transportation systems for resale to third parties, including natural gas marketers and end-users. We may not be successful in balancing our purchases and sales. A producer or supplier could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause our purchases and sales to be unbalanced. While we attempt to balance our purchases and sales, if our purchases and sales are unbalanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income and cash flows.

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	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 you.


	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 Federal Energy Regulatory Commission, or FERC, uses to establish a pipeline’s status as a gatherer exempt from FERC regulation under the Natural Gas Act of 1938, or 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 you 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

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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 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.

We currently estimate that we will incur costs of less than $1.0 million between 2006 and 2010 to implement pipeline integrity management program testing along certain segments of our natural gas and NGL pipelines. This does not include the costs, if any, of any repair, remediation, preventative or mitigating actions that may be determined to he 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 you.

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Risks Relating to an Investment in the Common Units


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

After the sale of the common units offered by this prospectus supplement, Martin Resource Management will hold 3,402,690 subordinated units and 1,311,643 common units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier.

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

Our partnership agreement provides that, after the subordination period, we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders. During the subordination period, our general partner, without the approval of our unitholders, may cause us to issue up to 1,500,000 additional common units. Our general partner may also cause us to issue an unlimited number of additional common units or other equity securities of equal rank with the common units, without unitholder approval, in a number of circumstances such as:


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

	•	the conversion of subordinated units into common units;

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

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

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

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

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

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	Unitholders have less power to elect or remove management of our general partner than holders of common stock in a corporation. At the closing of this offering, 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 66²/3% of the outstanding units voting together as a single class. Because our general partner and its affiliates, including Martin Resource Management, control, upon completion of this offering, a 37.8% limited partnership interest in us, our general partner initially cannot be removed without the consent of it and its affiliates.

If our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. A removal under these circumstances would adversely affect the common units by prematurely eliminating their contractual right to distributions and liquidation preference over the subordinated units, which preferences would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud, gross negligence or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of our business, so the removal of our general partner because of the unitholders’ dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period.

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

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


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

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

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	*You 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.

If you choose to purchase a common unit, you will be 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 your approval, which would dilute your ownership interests.*

During the subordination period, our general partner, without the approval of our unitholders, may cause us to issue up to 1,500,000 additional common units. Our general partner may also cause us to issue an unlimited number of additional common units or other equity securities of equal rank with the common units, without unitholder approval, in a number of circumstances such as:


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

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	•	the conversion of subordinated units into common units;

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

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

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

On November 14, 2005, 850,672 of our 4,253,362 outstanding subordinated units owned by Martin Resource Management and its subsidiaries converted into common units on a one for one basis following our distribution of available cash on such date. Additional conversion of our outstanding subordinated units will occur following our quarterly distributions of available cash provided that certain distribution thresholds are met by us.

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 to 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 you to sell your common units at an undesirable time or price.*

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units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your 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 your potential tax liability, please read “Risk Factors — Tax Risks — Tax gain or loss on the disposition of our common units could be different than expected” in this prospectus supplement.


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

Our common units are quoted on the Nasdaq National Market under the symbol “MMLP.” However, our common units have a limited trading history and daily trading volumes for our common units are, and may continue to be, relatively small compared to many other securities quoted on the Nasdaq National Market. We cannot assure you that this offering will increase the trading volume for our common units, and the price of our common units may, therefore, be volatile.


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

In order to comply with Section 404 of the Sarbanes-Oxley Act, we periodically document and test our internal control procedures. Section 404 of the Sarbanes-Oxley Act requires annual management assessments of the effectiveness of our internal controls over financial reporting and a report by our independent auditors addressing these assessments. During the course of our testing we may identify deficiencies which we may not be able to address in time to meet the deadline imposed by the Sarbanes-Oxley Act for compliance with the requirements of Section 404. In addition, if we fail to maintain the adequacy of our internal controls, as such standards are modified, supplemented or amended from time to time, we may not be able to ensure that we can conclude on an ongoing basis that we have effective internal controls over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act. Failure to achieve and maintain an effective internal control environment could have a material adverse effect on the price of our common units.

Risks Relating to Our Relationship with Martin Resource Management


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

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


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

Martin Resource Management will own, upon completion of this offering, an approximate 37.8% 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

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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, you 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 a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.

	•	Our general partner has broad discretion to establish financial reserves for the proper conduct of our business. These reserves also will affect the amount of cash available for distribution. Our general partner may establish reserves for distribution on the subordinated units, but only if those reserves will not prevent us from distributing the full minimum quarterly distribution, plus any arrearages, on the common units for the following four quarters.


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

Martin Resource Management and its affiliates may engage in limited competition with us. For a discussion of the non-competition provisions of the omnibus agreement, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our Relationship with Martin Resource Management — Omnibus Agreement.” If Martin Resource Management does engage in

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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.

Tax Risks

You should read “Material Tax Considerations” for a full discussion of the expected material federal income tax consequences of owning and disposing of common units.


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

The anticipated after-tax economic benefit of an investment in us depends largely on our classification as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.

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

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


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

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from our counsel’s conclusions expressed in this prospectus supplement. 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. To the extent noted in “Material Tax Considerations,” our counsel has not rendered an opinion on certain matters affecting us. Any contest with the IRS may materially and adversely impact the market for our common units and the prices at which they trade. In addition, the costs of any contest with the IRS will be borne directly or indirectly by all of our unitholders and our general partner.


	*You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.*

You may be required to pay federal income taxes and, in some cases, state, local and foreign income taxes on your share of our taxable income even if you receive no cash distributions from us. You may not receive cash distributions from us equal to your 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 you sell your common units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in those common units. Prior distributions in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that common

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unit, will, in effect, become taxable income to you if the common unit is sold at a price greater than your tax basis in that common unit, even if the price you receive is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to you. Should the IRS successfully contest some positions we take, you 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 you sell your units, you may incur a tax liability in excess of the amount of cash you 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. If you are a tax exempt entity or a foreign person, you should consult your tax advisor before investing in our common units.


	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. Please read “Material Tax Considerations — Tax Consequences of Unit Ownership — Section 754 Election.” A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. 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 your tax returns. Please read “Material Tax Considerations — Uniformity of Units” for a further discussion of the effect of, and reasons for, the depreciation and amortization positions we have adopted.


	*You 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. You 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, Texas and Utah. We may do business or own property in other states or foreign countries in the future. It is the unitholder’s responsibility to file all federal, state, local and foreign tax returns. Our counsel has not rendered an opinion on the state, local or foreign tax consequences of an investment in our common units.

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USE OF PROCEEDS

We expect to receive net proceeds of approximately $84.7 million from the sale of the 3,000,000 common units offered by this prospectus supplement, after deducting underwriting discounts and estimated offering expenses. This amount includes a capital contribution from our general partner of approximately $1.8 million to maintain its 2% general partner interest in our partnership. We intend to use the net proceeds from this offering and the capital contribution from our general partner as follows:


	•	to repay approximately $62.0 million in revolving credit facility indebtedness, including approximately $54.3 million in indebtedness incurred in connection with the Prism Gas and the A&A Fertilizer acquisitions, and $7.7 million in indebtedness incurred in connection with additional growth capital expenditures and working capital purposes;

	•	to repay approximately $10.2 million in U.S. Government Guaranteed Ship Financing Bonds (including the associated prepayment premium) we assumed in connection with the acquisition of CF Martin Sulphur;

	•	to pay approximately $1.7 million in connection with our pending acquisition of real property which we lease for use in our fertilizer business in Seneca, Illinois;

	•	to pay approximately $6.5 million to complete the construction of our sulfur priller located at our Beaumont, Texas facility; and

	•	to pay approximately $4.3 million for a portion of the construction of a sulfuric acid plant at our Plainview, Texas facility.

As of the date of this prospectus supplement, total borrowings under our credit facility were approximately $192.0 million, with a weighted-average interest rate of 7.61%. We entered into a new credit facility on November 10, 2005 in connection with the closing of the Prism Gas acquisition. The credit facility includes a $130.0 million term loan and a $95.0 million revolving credit line, which includes a $20.0 million letter of credit sub-limit. The credit facility also provides for procedures for additional financial institutions to become lenders under our revolving credit facility, or for any existing lender to increase its revolving commitment under our revolving credit facility, subject to a maximum of $100.0 million for all such increases. The credit facility matures in 2010. Funds borrowed under our new and predecessor credit facilities between January 2005 and December 31, 2005 (totaling $192.0 million) were used to finance the liquefied petroleum gas pipeline purchase (approximately $3.8 million), the Bay Sulfur asset acquisition (approximately $5.9 million), the CF Martin Sulphur acquisition (approximately $18.9 million), the Prism Gas acquisition (approximately $62.0 million) and the A&A Fertilizer acquisition (approximately $6.0 million). Affiliates of both RBC Capital Markets Corporation and KeyBanc Capital Markets, a division of McDonald Investments Inc., underwriters for this offering, are lenders under our credit facility and will be repaid with a portion of the net proceeds of this offering. See “Underwriting.”

In connection with the acquisition of the remaining interests in CF Martin Sulphur not previously owned by us, we assumed $9.4 million of U.S. Government Guaranteed Ship Financing Bonds maturing in 2021. The outstanding balance of these bonds as of the date of this prospectus supplement was approximately $9.1 million. The effective interest rate on such indebtedness is 7.2%. Pursuant to the terms of our credit facility, we are obligated to repay these bonds (including the associated pre-payment premium) by March 31, 2006.

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CAPITALIZATION

The following table shows our capitalization as of September 30, 2005:


	•	on a historical basis;

	•	pro forma basis to give effect to the Prism Gas and CF Martin Sulphur acquisitions, the related borrowings under our credit facility and our general partner’s proportionate capital contributions; and

	•	a pro forma as adjusted basis to give effect to the common units offered by this prospectus supplement, our general partner’s proportionate capital contribution and the application of the net proceeds from this offering as described in “Use of Proceeds.”

This table should be read together with, and is qualified in its entirety by, reference to our historical and pro forma consolidated and combined financial statements and the accompanying notes included or incorporated by reference in this prospectus supplement and the accompanying prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere herein.


				As of September 30, 2005

										Pro Forma
										As
				Historical			Pro Forma			Adjusted

				(In thousands)
Cash and cash equivalents				$	3,116		$	6,980		$	43,352

Long-term debt (including current portion):(1)
	Term debt			$	9,104		$	139,104		$	139,104
	Revolving credit facility				111,900			48,340			—

		Total long-term debt			121,004			187,444			139,104
Partners’ capital:
	Common unitholders(2)				78,366			102,981			185,910
	Subordinated unitholders(2)				(6,095	)		(6,095	)		(6,095	)
	General partner				572			1,074			2,857

		Total partners’ capital			72,843			97,960			182,672

			Total capitalization	$	193,847		$	285,404		$	321,776


(1)	As of the date hereof, our long term indebtedness is $201.1 million, consisting of $62.0 million under our revolving credit facility, $130.0 million under our term loan facility and $9.1 million under our U.S. Government Guaranteed Ship Financing Bonds which includes a current portion of $582,000.

(2)	On November 14, 2005, 850,672 of our 4,253,362 outstanding subordinated units owned by Martin Resource Management, the owner of our general partner, converted into common units on a one-for-one basis following our quarterly cash distribution on such date. Additional conversions of our outstanding subordinated units may occur in the future provided that certain distribution thresholds provided in our partnership agreement are met by us.

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PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS

Our common units are quoted on the Nasdaq National Market under the symbol “MMLP.” Our common units were admitted for quotation on November 1, 2002 at an initial public offering price of $19.00 per common unit. The following table shows the low and high closing sale prices per common unit, as reported by the Nasdaq National Market, and the cash distributions per unit for the periods indicated.


		Common Unit
		Price Range				Cash
						Distributions
		Low		High		Per Unit

2006:
	Quarter Ended March 31(1)	$	29.00	$	30.25		—
2005:
	Quarter Ended December 31	$	29.70	$	33.04	$	0.610	(2)
	Quarter Ended September 30	$	30.19	$	34.25	$	0.570
	Quarter Ended June 30	$	30.03	$	33.99	$	0.550
	Quarter Ended March 31	$	29.03	$	34.20	$	0.535
2004:
	Quarter Ended December 31	$	27.22	$	29.93	$	0.535
	Quarter Ended September 30	$	26.51	$	29.78	$	0.525
	Quarter Ended June 30	$	23.57	$	29.90	$	0.525
	Quarter Ended March 31	$	27.20	$	30.30	$	0.525


(1)	Through January 10, 2006.

(2)	Declared on January 5, 2006 and payable on February 14, 2006 to unitholders of record on February 1, 2006.

The last reported sale price of our common units on the Nasdaq National Market on January 10, 2006 was $29.12. As of December 29, 2005 there were approximately 15 holders of record and 6,569 beneficial owners of our common units.

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SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA

The following table shows selected historical and pro forma financial data for Martin Midstream Partners Predecessor and Martin Midstream Partners L.P. for the periods and as of the dates indicated. Martin Midstream Partners Predecessor is the term used to describe certain assets, liabilities and operations owned by Martin Resource Management that were transferred to us upon completion of our initial public offering in November 2002. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere herein.

The selected historical financial data as of and for the periods presented below is derived from the audited or unaudited combined or consolidated statements of either Martin Midstream Partners Predecessor or Martin Midstream Partners included in our filings with the SEC, which are incorporated by reference herein.

The selected pro forma financial data is derived from the unaudited pro forma financial statements included elsewhere in this prospectus supplement. For income statement items, the selected pro forma financial data assumes that the Prism Gas acquisition, the CF Martin Sulphur acquisition and the related borrowings under our credit facility occurred on January 1, 2004. For balance sheet items, the summary pro forma financial data assumes that the offering occurred on September 30, 2005. For a description of all of the assumptions used in preparing the selected pro forma financial data, you should read the notes to the pro forma financial statements included elsewhere in this prospectus supplement. The pro forma financial data should not be considered as indicative of the historical results we would have had or the future results that we will have after the offering.

The following table also shows our EBITDA which is described below under “Non-GAAP Financial Measure.”

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		Martin			Martin Midstream Partners
		Midstream
		Predecessor

					Period From															Pro Forma As Adjusted
		Period From			November 6,
		January 1,			2002			Years Ended						Nine Months Ended									Nine Months
		2002 Through			Through			December 31,						September 30,						Year Ended			Ended
		November 5,			December 31,															December 31,			September 30,
		2002			2002			2003			2004			2004			2005			2004			2005

														(Unaudited)
		(In thousands)
Income Statement Data:
Revenues		$	116,160		$	33,746		$	192,731		$	294,144		$	202,511		$	293,816		$	414,243		$	382,083
Cost of products sold			84,442			26,504			150,892			229,976			156,892			232,141			331,245			308,622
Operating expenses			17,389			3,189			21,590			34,475			24,995			32,778			46,297			39,953
Selling, general, and administrative expenses			4,662			656			4,986			6,198			4,672			5,420			10,482			9,041
Depreciation and amortization			3,741			747			4,765			8,766			6,276			8,672			12,923			11,251

	Total costs and expenses		110,234			31,096			182,233			279,415			192,835			279,011			400,947			368,867
Other Operating income			—			—			589			—			—			—			—			—

Operating income			5,926			2,650			11,087			14,729			9,676			14,805			13,296			13,216
Equity in earnings (losses) of unconsolidated entities			2,565			599			2,801			912			532			222			7,112			4,896
Interest expense			(3,283	)		(345	)		(2,001	)		(3,326	)		(2,338	)		(3,834	)		(7,204	)		(6,327	)
Other, net			42			5			94			11			52			127			237			108

Income before income taxes			5,250			2,909			11,981			12,326			7,922			11,320			13,441			11,893
Income taxes			1,959			—			—			—			—			—			—			—

Net income		$	3,291		$	2,909		$	11,981		$	12,326		$	7,922		$	11,320		$	13,441		$	11,893

Balance Sheet Data (at Period End):
Total assets					$	100,455		$	139,685		$	188,332		$	175,594		$	255,234					$	404,009
Due to affiliates						—			560			429			210			1,216						6,960
Long-term debt (including current portion)						35,000			67,000			73,000			69,000			121,004						139,104
Owner’s equity (partners’ capital)						47,106			45,892			75,534			75,671			72,843						182,672
Cash Flow Data:
Net cash flow provided by (used in):
	Operating activities	$	316		$	4,824		$	10,273		$	12,812		$	7,889		$	24,276
	Investing activities		(1,962	)		(2,116	)		(27,621	)		(34,322	)		(31,789	)		(46,445	)
	Financing activities		6,897			(6,287	)		17,884			22,424			23,857			22,101
Other Financial Data:
Maintenance capital expenditures(1)		$	394		$	157		$	2,773		$	5,182		$	5,396		$	3,179
Expansion capital expenditures(1)			1,909			2,850			29,159			30,234			30,019			33,142

	Total capital expenditures	$	2,303		$	3,007		$	31,932		$	35,416		$	35,415		$	36,321

EBITDA(2)(3)		$	12,274		$	4,001		$	18,747		$	24,418		$	16,536		$	23,826		$	33,568		$	29,471


(1)	Maintenance capital expenditures represent capital expenditures to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and extend their useful lives. Expansion capital expenditures represent capital expenditures to expand the existing operating capacity of our assets, whether through construction or acquisition. Repair and maintenance expenditures associated with existing assets that are minor in nature and do not extend the useful life of existing assets are treated as operating expenses as incurred.

(2)	See “Non-GAAP Financial Measure” below.

(3)	For the nine months ended September 30, 2005, pro forma as adjusted EBITDA includes an approximately $0.9 million charge in connection with the settlement of an outstanding Prism Gas lawsuit.

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Non-GAAP Financial Measure

We define EBITDA as net income plus interest expense, income taxes and depreciation and amortization expense. We use EBITDA as a supplemental financial measure to assess:


	•	the ability of our assets to generate cash sufficient for us to pay interest costs and to make cash distributions to our unitholders;

	•	the financial performance of our assets;

	•	our performance over time and in relation to other companies that own similar assets and that we believe calculate EBITDA in a manner similar to us; and

	•	in certain situations, the appropriateness of the purchase price of assets or companies we might consider acquiring.

The following table reconciles our historical EBITDA to our historical net income and on a pro forma basis as described elsewhere herein:


		Martin
		Midstream
		Predecessor		Martin Midstream Partners

		Period From		Period From										Pro Forma As Adjusted
		January 1,		November 6,
		2002		2002		Years Ended				Nine Months Ended						Nine Months
		Through		Through		December 31,				September 30,				Year Ended		Ended
		November 5,		December 31,										December 31,		September 30,
		2002		2002		2003		2004		2004		2005		2004		2005

												(Unaudited)
		(In thousands)
EBITDA Reconciliation:
	Net Income	$	3,291	$	2,909	$	11,981	$	12,326	$	7,922	$	11,320	$	13,441	$	11,893
Plus:
	Depreciation and amortization		3,741		747		4,765		8,766		6,276		8,672		12,923		11,251
	Interest Expense		3,283		345		2,001		3,326		2,338		3,834		7,204		6,327
	Income Taxes		1,959		—		—		—		—		—		—		—

EBITDA		$	12,274	$	4,001	$	18,747	$	24,418	$	16,536	$	23,826	$	33,568	$	29,471

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion of our financial condition and results of operations in conjunction with the selected historical and pro forma financial information included or incorporated by reference in this prospectus supplement and the accompanying prospectus.

Overview

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


	•	Terminalling and storage services for petroleum and by-products

	•	Natural gas gathering, processing and LPG distribution

	•	Marine transportation services for petroleum products and by-products

	•	Sulfur gathering, processing and distribution

	•	Fertilizer manufacturing and distribution

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

Critical Accounting Policies

Our discussion and analysis of our financial condition and results of operations should be read in conjunction with our audited consolidated and combined financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2004 filed with the SEC on March 16, 2005 as well as our unaudited consolidated and condensed financial statements included in our quarterly report on Form 10-Q for the quarter ended September 30, 2005 filed with the SEC on November 9, 2005. 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, other than as described below, 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 and Condensed Financial Statements contained in our quarterly report on Form 10-Q referenced above and the similar note in the consolidated and combined financial statements included in our annual report on Form 10-K referenced above in conjunction with this Management’s Discussion and Analysis of Financial Condition and Results of Operations. Some of the more significant estimates in these financial statements include the amount of the allowance for doubtful accounts receivable and the determination of the fair value of our reporting units under SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”).

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Product Exchanges

We enter into product exchange agreements with third parties whereby we agree to exchange LPGs with third parties. We record the balance of LPGs due to other companies under these agreements at quoted market product prices and the balance of LPGs due from other companies at the lower of cost or market. Cost is determined using the first-in, first-out method.

Revenue Recognition

For our terminalling segment, we recognize revenue monthly for storage contracts based on the contracted monthly tank fixed fee. For throughput contracts, we recognize revenue based on the volume moved through our terminals at the contracted rate. For our marine transportation segment, we recognize revenue for contracted trips upon completion of the trips. For time charters, we recognize revenue based on the daily rate. For our natural gas gathering, processing and LPG distribution segment, we recognize revenue for product delivered by truck upon the delivery of LPGs to our customers, which occurs when the customer physically receives the product. When product is sold in storage, or by pipeline, we recognize revenue when the customer receives the product from either the storage facility or pipeline. For our sulfur segment, we recognize revenue for product delivered by truck upon the delivery of sulfur to our customers, which occurs when the customer physically receives the product. For our fertilizer segment, we recognize revenue when the customer takes title to the product, either at our plant or the customer’s facility.

Equity Method Investment

We used the equity method of accounting for our interest in CF Martin Sulphur because we only owned an unconsolidated non-controlling 49.5% limited partner interest in this entity. We did not recognize a gain when we contributed our molten sulfur business to CF Martin Sulphur because we concluded we had an implied commitment to support the operations of this entity as a result of our role as a supplier of product to CF Martin Sulphur and our relationship to Martin Resource Management, which guarantees certain of the debt of this entity.

As a result of the non-recognition of this gain, the amount we initially recorded as an investment in CF Martin Sulphur on our balance sheet is less than the amount of our underlying equity in this entity as recorded on the books of CF Martin Sulphur. We are amortizing such excess amount over 20 years, the expected life of the net assets contributed to this entity, as additional equity in earnings of CF Martin Sulphur in our statements of operations.

On July 15, 2005, we acquired the remaining interests in CF Martin Sulphur not previously owned by us. Subsequent to the acquisition, CF Martin Sulphur is included in the consolidated financial presentation of our sulfur segment.

Following our acquisition of Prism Gas in November 2005, we own an unconsolidated 50% interest in each of Waskom Gas Processing Company, the owner of the Waskom Processing Plant, the Fishhook Gathering System and the Matagorda Gathering System. As a result, they are accounted for by the equity method and we do not include any portion of their net income in our operating income.

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.

We have performed the annual impairment tests as of September 30, 2003, September 30, 2004 and September 30, 2005, respectively. In performing such tests, we determined we had three “reporting units”

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which contained goodwill. These reporting units were three of our reporting segments: marine transportation, natural gas gathering, processing and LPG distribution and fertilizer.

We determined fair value in each reporting unit based on a multiple of current annual cash flows. We determined such multiple from our recent experience with actual acquisitions and dispositions and valuing potential acquisitions and dispositions.

Environmental Liabilities

We have historically not experienced circumstances requiring us to account for environmental remediation obligations. If such circumstances arise, we would estimate remediation obligations utilizing a remediation feasibility study and any other related environmental studies that we may elect to perform. We would record changes to our estimated environmental liability as circumstances change or events occur, such as the issuance of revised orders by governmental bodies or court or other judicial orders and our evaluation of the likelihood and amount of the related eventual liability.

Allowance for Doubtful Accounts

In evaluating the collectibility of our accounts receivable, we assess a number of factors, including a specific customer’s ability to meet its financial obligations to us, the length of time the receivable has been past due and historical collection experience. Based on these assessments, we record both specific and general reserves for bad debts to reduce the related receivable to the amount we ultimately expect to collect from customers.

Asset Retirement Obligation

In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), we recognize and measure our asset retirement obligations and the associated asset retirement cost upon acquisition of the related asset. Subsequent measurement and accounting provisions are in accordance with SFAS 143.

Reclassifications

As previously reported in our Quarterly Report on Form 10-Q for the three months ended September 30, 2005, which was filed with the SEC on November 9, 2005, we converted to a new accounting system in August 2005. In connection with the system conversion, we closely examined expense classifications under the new system. Upon review, it was determined that certain payroll, property insurance and property tax expenses that were previously categorized as selling, general and administrative expenses would be more appropriately classified as operating expenses or costs of products sold. As a result, those expenses were set up in the new system with the new classification. Accordingly, it is necessary for us to reclassify the related expense items for fiscal years 2002, 2003 and 2004. Since the reclassifications, as indicated in the tables set forth below, had no impact on the prior periods’ revenues, operating income, cash flows from operations or net income, the Partnership has determined that the reclassifications are not material to our audited financial statements for the prior periods. Nonetheless, we are effecting the reclassifications in order to provide comparative clarity and consistency among the 2002-2004 annual periods when compared to our financial reporting for our current 2005 fiscal year.

The following tables set forth the effects of the reclassifications on certain line items within our previously reported consolidated statements of income for the years ended December 31, 2004, 2003 and 2002 (dollars in thousands), which statements of income and certain relevant footnotes thereto as well as

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the relevant portions of Management’s Discussion and Analysis of Financial Condition and Results of Operations for those periods have been updated as hereinafter provided in this prospectus supplement.


	Terminalling
	and Storage		LPG		Marine		Fertilizer		SG&A		Total

Year Ended December 31, 2004
Cost of products sold (as previously reported)	$	6,775	$	197,859	$	—	$	25,207	$	—	$	229,841
Cost of products sold (as reclassified)		6,775		197,859		—		25,342		—		229,976
Operating expenses (as previously reported)		6,699		928		24,796		—		—		32,423
Operating expenses (as reclassified)		8,494		1,185		24,796		—		—		34,475
Selling, general and administrative (as previously reported)		2,194		1,457		175		1,793		2,766		8,385
Selling, general and administrative (as reclassified)		399		1,200		175		1,658		2,766		6,198


	Terminalling
	and Storage		LPG		Marine		Fertilizer		SG&A		Total

Year Ended December 31, 2003
Cost of products sold (as previously reported)	$	107	$	128,055	$	—	$	22,605	$	—	$	150,767
Cost of products sold (as reclassified)		107		128,055		—		22,730		—		150,892
Operating expenses (as previously reported)		1,413		1,052		18,135		—		—		20,600
Operating expenses (as reclassified)		2,141		1,314		18,135		—		—		21,590
Selling, general and administrative (as previously reported)		1,180		1,362		305		1,566		1,688		6,101
Selling, general and administrative (as reclassified)		452		1,100		305		1,441		1,688		4,986


	Terminalling										Consolidating
	and Storage		LPG		Marine		Fertilizer		SG&A		Reclassification			Total

Year Ended December 31, 2002
Cost of products sold (as previously reported)	$	—	$	87,189	$	—	$	23,324	$	—	$	(5	)	$	110,508
Cost of products sold (as reclassified)		—		87,189		—		23,762		—		(5	)		110,946
Operating expenses (as previously reported)		1,181		1,307		17,201		—		—		21			19,710
Operating expenses (as reclassified)		1,724		1,632		17,201		—		—		21			20,578
Selling, general and administrative (as previously reported)		1,266		1,365		524		2,474		1,011		(16	)		6,624
Selling, general and administrative (as reclassified)		723		1,040		524		2,036		1,011		(16	)		5,318

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, 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 an underground LPG storage facility in Arcadia, Louisiana;

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	•	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, an LPG truck loading and unloading and pipeline distribution terminal in Mont Belvieu, Texas.

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

Ownership

Following the completion of this offering, Martin Resource Management will own an approximate 37.8% limited partnership interest in us, a 2% general partnership interest in us and all of our incentive distribution rights.

Management

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

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 and indirect expenses it incurs or payments it makes on our behalf or in connection with the operation of our business. There is no monetary limitation on the amount we are required to reimburse Martin Resource Management for direct expenses. Under the omnibus agreement, the reimbursement amount with respect to indirect general and administrative and corporate overhead expenses was capped at $2.0 million for the twelve month period ending October 31, 2004. For each of the subsequent three years, this amount may be increased by no more than the percentage increase in the consumer price index and is also subject to adjustment for expansions of our operations. These indirect expenses cover all of the centralized corporate functions Martin Resource Management provides for us, such as accounting, treasury, clerical billing, information technology, administration of insurance, general office expenses and employee benefit plans and other general corporate overhead functions we share with Martin Resource Management retained businesses.

Martin Resource Management also licenses certain of its trademarks and trade names to us under this omnibus agreement.

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 LPG distribution operations. We lease an underground storage facility from Martin Resource Management in Arcadia, Louisiana with a storage capacity of 65 million gallons. 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, LPG storage services, sulfuric acid and lube oil product purchases and sulfur and fertilizer payroll reimbursements from Martin Resource

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Management accounted for approximately 5% and 6% of our total cost of products sold during the nine months ended September 30, 2005 and 2004, 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 LPG distribution services for its operations. Martin Resource Management is also a significant customer of fertilizer products and we provide terminalling 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 4% and 6% of our total revenues for the nine months ended September 30, 2005 and 2004, respectively. In connection with the closing of the Tesoro Marine asset acquisition, we entered into certain agreements with Martin Resource Management pursuant to which we provide terminalling and marine transportation services to Midstream Fuel and Midstream Fuel provides terminal services to us to handle lubricants, greases and drilling fluids.

Omnibus Agreement

We are a party to an omnibus agreement with Martin Resource Management. In this agreement:


	•	Martin Resource Management agreed not to compete with us in the terminalling, marine transportation, LPG distribution and fertilizer businesses, subject to the exceptions described more fully in “Certain Relationships and Related Transactions — Agreements — Omnibus Agreement” of our annual report on Form 10-K for the year ended December 31, 2004 filed with the SEC on March 16, 2005.

	•	Martin Resource Management agreed to indemnify us for a period of five years for environmental losses arising prior to our initial public offering, which we closed in November 2002, as well as preexisting litigation and tax liabilities.

	•	We agreed to reimburse Martin Resource Management for the provision of general and administrative services under our partnership agreement, provided that the reimbursement amount with respect to indirect general and administrative and corporate overhead expenses was capped at $2.0 million for the year ending October 31, 2004. For each of the subsequent three years, this amount may be increased by no more than the percentage increase in the consumer price index and is also subject to adjustment for expansions of our operations. In addition, our general partner has the right to agree to further increases in connection with expansions of our operations through the construction of new assets or businesses. This limitation does not apply to the cost of any third party legal, accounting or advisory services received, or the direct expenses of Martin Resource Management incurred, in connection with acquisition or business development opportunities evaluated on our behalf.

	•	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.

Motor Carrier Agreement

We are a party to a motor carrier agreement with Martin Transport, Inc., a wholly owned subsidiary of Martin Resource Management, through which Martin Resource Management operates its land transportation operations. This agreement was amended in October 2005 to expand the term and to make adjustments to the pricing based on current market conditions and rates. The agreement has a term that expires in November 2006, and will automatically renew for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicable term. Under this agreement, Martin Transport transports our LPG shipments as well as other liquid products. Our shipping rates were fixed for the first year of the agreement, subject to certain cost adjustments. These rates are subject to any adjustment to which we

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mutually agree or in accordance with a price index. Additionally, during the term of the agreement, shipping charges are also subject to fuel surcharges determined on a weekly basis in accordance with the U.S. Department of Energy’s national diesel price list.

Other Agreements

We are a party to several other agreements with Martin Resource Management. In October 2005, several of these agreements were amended to expand the term thereof and to make adjustments to the pricing terms. All of such adjustments were based upon current market conditions and rates and were approved by our conflicts committee. The result of such pricing adjustments, should increase the net income received by us under all of the agreements after taking into account all amounts paid by us to Martin Resource Management under such agreements. The agreements between us and Martin Resource Management are as follows:


	•	Specialty Petroleum Terminal Services Agreement — under which we provide terminalling and storage services to Martin Resource Management at a set rate. Effective each November 1, this agreement automatically renews for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicable term. The fees we charge under this agreement are adjusted annually based on a price index.

	•	Marine Transportation Agreement — under which we provide marine transportation services to Martin Resource Management on a spot-contract basis. Effective each November 1, this agreement automatically renews for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicable term. The fees we charge Martin Resource Management are based on applicable market rates. Additionally, Martin Resource Management had previously agreed through November 1, 2005, to use our four vessels that were not subject to term agreements in a manner such that we would receive at least $5.6 million annually for the use of these vessels by Martin Resource Management and third parties. This agreement, absent the annual guarantee described above, was extended for a subsequent one year period on November 1, 2005.

	•	Product Storage Agreement — under which Martin Resource Management provides us underground storage for LPGs. Effective each November 1, this agreement automatically renews for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicable term. Our per-unit cost under this agreement is adjusted annually based on a price index.

	•	Product Supply Agreements — under which Martin Resource Management provides us with marine fuel and sulfuric acid. Effective each November 1, these agreements automatically renew for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicable term. We purchase products at a set margin above Martin Resource Management’s cost for such products during the term of the agreements.

	•	Throughput Agreement — under which Martin Resource Management agrees to provide us with sole access to and use of a LPG truck loading and unloading and pipeline distribution terminal located at Mont Belvieu, Texas. Effective each November 1, this agreement automatically renews for consecutive one-year periods unless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicable term. Our throughput fee is adjusted annually based on a price index.

	•	Terminal Services Agreement — under which we provide terminalling services to Martin Resource Management. Effective each December 1, this agreement will automatically renew on a month-to-month basis until either party terminates the agreement by giving written notice to the other party

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		at least 60 days prior to the expiration of the then-applicable term. The per gallon throughput fee we charge under this agreement is adjusted annually based on a price index.

	•	Transportation Services Agreement — under which we provide marine transportation services to Martin Resource Management. This agreement has a three-year term, which began in December 2003, and will automatically renew for successive one-year terms unless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicable term. In addition, within 30-days of the expiration of the then-applicable term, both parties have the right to renegotiate the rate for the use of our vessels. If no agreement is reached as to a new rate by the end of the then-applicable term, the agreement will terminate. The per gallon fee we charge under this agreement is adjusted annually based upon mutual agreement of the parties or in accordance with a price index.

	•	Lubricants and Drilling Fluids Terminal Services Agreement — under which Martin Resource Management provides terminal services to us. Effective each November 1, this agreement automatically renews for successive one-year terms until either party terminates the agreement by giving written notice to the other party at least 60 days prior to the end of the then-applicable term. The per gallon handling fee and the percentage of our commissions we are charged under this agreement is adjusted annually based on a price index.

Finally, Martin Resource Management also granted us a perpetual, non-exclusive use, ingress-egress and utility facilities easement in connection with the transfer of our Stanolind terminal assets to us.

Our Relationship with CF Martin Sulphur

On July 15, 2005, we acquired all of the remaining limited partnership interests in CF Martin Sulphur from CF Industries, Inc. and certain affiliates of Martin Resource Management. Prior to this transaction, our unconsolidated non-controlling 49.5% limited partnership interest in CF Martin Sulphur, was accounted for using the equity method of accounting. In addition, on July 15, 2005, we acquired all of the outstanding membership interests in CF Martin Sulphur’s general partner. Thus, we now control the management of CF Martin Sulphur and will conduct its day-to-day operations. Subsequent to the acquisition, CF Martin Sulphur is a wholly owned partnership which is included in the consolidated financial presentation of our sulfur segment.

Prior to July 15, 2005, we were both an important supplier to and customer of CF Martin Sulphur. We chartered one of our offshore tug/barge tanker units to CF Martin Sulphur for a guaranteed daily rate, subject to certain adjustments. This charter had an unlimited term but may be cancelled by CF Martin Sulphur upon 90 days notice. CF Martin Sulphur paid to have this tug/barge tanker unit reconfigured to carry molten sulfur. In the event CF Martin Sulphur terminated this charter agreement, we would have been obligated to reimburse CF Martin Sulphur for a portion of such reconfiguration costs.

As a result of the July 15, 2005 acquisition of all the outstanding interests in CF Martin Sulphur this contingent obligation has been terminated.

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Results of Operations

The combined results of operations for the year ended December 31, 2002, have been derived from the combined financial statements of Martin Midstream Partners Predecessor for the period from January 1, 2002 through November 5, 2002 and the consolidated financial statements of Martin Midstream Partners, L.P. for the period from November 6, 2002 through December 31, 2002. The results of operations for the years ended December 31, 2003 and 2004 and the nine months ended September 30, 2004 and 2005 have been derived from the consolidated financial statements of Martin Midstream Partners L.P.


												Nine Months Ended
			Year Ended December 31									September 30

			2004			2003			2002			2005			2004

												(Unaudited)
			(In thousands)
Revenues:
	Terminalling		$	17,919		$	6,921		$	5,158		$	16,858		$	12,623
	Marine transportation			34,780			26,342			24,440			26,634			25,079
	Product sales:
		LPG distribution		203,427			133,038			92,408			199,487			136,349
		Sulfur		—			—			—			17,743			—
		Fertilizer		29,780			26,296			27,900			25,980			22,397
		Terminalling and storage		8,238			134			—			7,114			6,063

				241,445			159,468			120,308			250,324			164,809

		Total revenues		294,144			192,731			149,906			293,816			202,511

Costs and expenses:
	Cost of products sold:
		LPG distribution		197,859			128,055			87,189			192,187			132,467
		Sulfur		—			—			—			12,030			—
		Fertilizer		25,342			22,730			24,137			21,955			19,434
		Terminalling and storage		6,775			107			—			5,969			4,991

				229,976			150,892			110,946			232,141			156,892
Expenses:
	Operating expenses			34,475			21,590			20,578			32,778			24,995
	Selling, general and administrative			6,198			4,986			5,318			5,420			4,672
	Depreciation and amortization			8,766			4,765			4,488			8,672			6,276

		Total costs and expenses		279,415			182,233			141,330			279,011			192,835

Other operating income				—			589			—			—			—

		Operating income		14,729			11,087			8,576			14,805			9,676

Other income (expense):
	Equity in earnings of unconsolidated entities			912			2,801			3,164			222			532
	Interest expense			(3,326	)		(2,001	)		(3,628	)		(3,834	)		(2,338	)
	Other, net			11			94			47			127			52

		Total other income (expense)		(2,403	)		894			(417	)		(3,485	)		(1,754	)

Income before income taxes				12,326			11,981			8,159			11,320			7,922
Income taxes				—			—			1,959			—			—

Net income			$	12,326		$	11,981		$	6,200		$	11,320		$	7,922

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Prior to November 6, 2002, our consolidated and combined financial statements reflected our operations as being subject to income taxes. Subsequent to November 6, 2002, we are not subject to income taxes due to our partnership structure. Therefore, we believe a more meaningful comparison of the results of our operations is income before income taxes.

Our effective income tax rates for the period from January 1, 2002 through November 5, 2002, the nine months ended September 30, 2002, was 37%. Our effective income tax rates for the periods we were taxable differed from the federal tax rate of 34% primarily as a result of state income taxes and the non-deductibility of certain goodwill amortization for book purposes.

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 income by segment, and equity in earnings of unconsolidated entities, for the nine months ended September 30, 2005 and 2004 and the years ended December 31, 2004, 2003, and 2002.


											Nine Months Ended
		Year Ended December 31,									September 30,

		2004			2003			2002			2005			2004

											(Unaudited)
		(In thousands)
Terminalling and storage		$	6,749		$	3,818		$	2,328		$	6,274		$	4,534
Marine transportation			5,827			4,693			3,858			2,465			4,118
Natural gathering, processing and LPG distribution			3,080			2,456			2,237			4,675			1,961
Sulfur			—			—			—			1,991			—
Fertilizer			1,839			1,808			1,164			1,924			997
Indirect selling, general, and administrative expenses			(2,766	)		(1,688	)		(1,011	)		(2,524	)		(1,934	)
	Operating income	$	14,729		$	11,087		$	8,576		$	14,805		$	9,676
Equity in earnings of unconsolidated entities		$	912		$	2,801		$	3,164		$	222		$	532

Our results of operations are discussed on a comparative basis below. We discuss items we do not allocate on a segment basis, such as equity in earnings of unconsolidated entities, interest expense, income tax expenses, and indirect selling, general and administrative expenses, after the comparative discussion of our results within each segment.


	*Nine Months Ended September 30, 2005 Compared to the Nine Months Ended September 30, 2004*

Our total revenues were $293.8 million for the nine months ended September 30, 2005 compared to $202.5 million for the nine months ended September 30, 2004, an increase of $91.3 million, or 45%. Our cost of products sold was $232.1 million for the nine months ended September 30, 2005 compared to $156.9 million for the nine months ended September 30, 2004, an increase of $75.2 million or 48%. Our total operating expenses were $32.8 million for the nine months ended September 30, 2005 compared to $25.0 million for the nine months ended September 30, 2004, an increase of $7.8 million, or 31%.

Our total selling, general and administrative expenses were $5.4 million for the nine months ended September 30, 2005 compared to $4.7 million for the nine months ended September 30, 2004, an increase of $0.7 million, or 15%. Total depreciation and amortization was $8.7 million for the nine months ended September 30, 2005 compared to $6.3 million for the nine months ended September 30, 2004, an increase of $2.4 million or 38%. Our operating income was $14.8 million for the nine months ended September 30, 2005 compared to $9.7 million for the nine months ended September 30, 2004, an increase of $5.1 million, or 53%.

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The results of operations are described in greater detail on a segment basis below.

Terminalling and Storage Segment. The following table summarizes our results of operations in our terminalling and storage segment.


				Nine Months Ended
				September 30,

				2005		2004

				(In thousands)
				(Unaudited)
Revenues:
	Services			$	16,858	$	12,623
	Products				7,114		6,063

			Total revenues		23,972		18,686
Cost of products sold					5,969		4,991
Operating expenses					8,198		6,148

		Operating margin			9,805		7,547
Selling, general and administrative expenses					220		396
Depreciation and amortization					3,311		2,617

		Operating income		$	6,274	$	4,534

Revenues. Our terminalling and storage revenues increased $5.3 million, or 28%, for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004. This increase was due to additional revenue generated from the Neches terminal assets we acquired in June 2004. These assets contributed additional revenue of $2.1 million for the first nine months of 2005 compared to the first nine months of 2004. We also experienced increased terminal volume throughput and increased pricing, primarily at both of our full service and our fuel and lubricants terminals. These terminals accounted for an increase of $2.0 million in service revenues and $1.1 million in products revenue.

Cost of products sold. Our cost of products increased $1.0 million, or 20%, for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004. This increase was a result of increases in the price paid for lubricants for the first nine months of 2005 compared to the same period in 2004.

Operating expenses. Operating expenses increased $2.1 million, or 33%, for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004. Of this increase, $1.4 million was a result of the additional operating expenses for the Neches terminal asset acquisition. Also included in this increase is our recognition of a $0.6 million estimated loss during the third quarter of 2005, which approximates our hurricane deductibles under our applicable insurance policies. These losses were a result of Hurricanes Katrina and Rita. We experienced flood damage at six of our terminals and wind damage at three other terminal locations. In connection with such casualty losses, we recorded a $1.2 million non-cash impairment charge equal to the net book value of the damaged assets and a corresponding receivable for the expected recovery under our applicable insurance policies, thus resulting in no financial statement impact.

Selling, general and administrative expenses. Selling, general and administrative expenses decreased $0.2 million, or 44%, for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004. This was primarily a result of net bad debt recoveries experienced in the first nine months of 2005 compared to net bad debt expense incurred in the first nine months of 2004.

Depreciation and amortization. Depreciation and amortization increased $0.7 million, or 26%, for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004. This increase was primarily a result of the Neches terminal asset acquisition.

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In summary, terminalling and storage operating income increased $1.7 million, or 38%, for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004.

Marine Transportation Segment. The following table summarizes our results of operations in our marine transportation segment.


		Nine Months Ended
		September 30,

		2005		2004

		(In thousands)
		(Unaudited)
Revenues		$	26,634	$	25,079
Operating expenses			20,288		17,977

	Operating margin		6,346		7,102
Selling, general and administrative expenses			215		118
Depreciation and amortization			3,666		2,866

	Operating income	$	2,465	$	4,118

Revenues. Our marine transportation revenues increased $1.6 million, or 6%, for the nine months ended September 30, 2005, compared to the nine months ended September 30, 2004. Our inland marine assets, coupled with leased inland marine assets, generated an additional $3.2 million in revenue due to stronger customer demand, higher equipment utilization, and charging our inland customers the increase in our fuel costs. Partially offsetting this inland revenue increase was a $0.3 million decrease in offshore revenues as a result of decreased utilization. Because the majority of our inland equipment is on time charter, the impact of Hurricanes Katrina and Rita was minor.

Intersegment sales of $1.2 million from our marine transportation segment to our sulfur segment were eliminated, reducing reported marine transportation revenue by this amount. Our sulfur segment accounted for these costs in operating expense. This intersegment charge has been eliminated from our sulfur segment’s operating expenses. Prior to July 15, 2005, we owned an unconsolidated, non-controlling 49.5% limited partnership interest in CF Martin Sulphur, which was accounted for using the equity method of accounting. As of July 15, 2005, CF Martin is now one of our wholly owned subsidiaries. As a result, all intercompany transactions are eliminated in consolidation.

Operating expenses. Operating expenses increased $2.3 million, or 13%, for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004. The increase was a result of increased operating costs, including leased operating equipment and fuel expenses.

Selling, general and administrative costs. Selling, general and administrative expenses increased $0.1 million, or 82%, for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004.

Depreciation and amortization. Depreciation and amortization increased $0.8 million, or 28%, for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004. This increase was due primarily to maintenance capital expenditures made in the last 12 months.

In summary, our marine transportation operating income decreased $1.7 million, or 40%, for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004. Without the new intersegment revenue eliminations resulting from the establishment of our sulfur segment, operating income would have only decreased $0.5 million, or 12%, for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004.

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Natural Gas Gathering, Processing and LPG Distribution Segment. The following table summarizes our results of operations in our natural gas gathering, processing and LPG distribution segment.


		Nine Months Ended
		September 30,

		2005		2004

		(In thousands)
		(Unaudited)
Revenues		$	199,487	$	136,349
Cost of products sold			192,187		132,467
Operating expenses			1,555		870

	Operating margin		5,745		3,012
Selling, general and administrative expenses			905		967
Depreciation and amortization			165		84

	Operating income	$	4,675	$	1,961

LPG Volumes (gallons)			185,927		160,691

Revenues. Our LPG distribution revenues increased $63.1 million, or 46%, for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004. Our average sales price increased 26% for the first nine months of 2005 compared to the first nine months of 2004. This increase was due to a general increase in the prices of LPG’s. Sales volume increased 16% as a result of increased demand for both industrial customers and retail propane customers.

Cost of products sold. Our cost of products sold increased $59.7 million, or 45%, for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004. This increase was less than our increase in LPG revenues, as we were able to increase our per gallon margins. Much of this margin increase was the result of rapid LPG price increases that occurred in the third quarter of 2005. These rapid price increases were the result of Hurricanes Katrina and Rita.

Operating expenses. Operating expenses increased $0.7 million, or 79%, for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004. This increase was primarily a result of our East Texas pipeline acquisition which occurred in January 2005.

Selling, general and administrative expenses. Selling, general and administrative expenses decreased $0.1 million, or 6%, for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2005.

Depreciation and amortization. Depreciation and amortization increased $0.1 million, or 96%, for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004. This increase was primarily a result of our East Texas pipeline acquisition which occurred in January 2005.

In summary, our LPG distribution operating income increased $2.7 million, or 138%, for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004.

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Sulfur Segment. The following table summarizes our results of operations in our sulfur segment.


		Nine Months Ended
		September 30,

		2005		2004

		(In thousands)
		(Unaudited)
Revenues		$	17,743	$	—
Cost of products sold			12,030		—

	Operating margin		5,713		—
Operating expenses			2,737		—

Selling, general and administrative expenses			299		—

Depreciation and amortization			686		—

	Operating income	$	1,991	$	—

Sulfur Volumes (tons)			261.0		—

Our sulfur segment was established in April 2005, as a result of the acquisition of the Bay Sulfur assets and the beginning of construction of a sulfur priller. On July 15, 2005, we purchased the equity interests of CF Martin Sulphur not owned by us. Since that date, the results of CF Martin have been included in the results reported in the above table. Prior to July 15, 2005, we owned an unconsolidated non-controlling 49.5% limited partnership interest in CF Martin Sulphur, which was accounted for using the equity method of accounting. CF Martin Sulphur is now a wholly-owned subsidiary. As a result, all intercompany transactions are eliminated in consolidation.

Intersegment expense of $1.2 million, which is the charge from our marine transportation segment to our sulfur segment for the charter of one offshore tug/barge tanker unit, was eliminated from our sulfur segment’s operating expenses.

Fertilizer Segment. The following table summarizes our results of operations in our fertilizer segment.


		Nine Months Ended
		September 30,

		2005		2004

		(In thousands)
		(Unaudited)
Revenues		$	25,980	$	22,397
Cost of products sold and operating expenses			21,955		19,434

	Operating margin		4,025		2,963
Selling, general and administrative expenses			1,257		1,257
Depreciation and amortization			844		709

	Operating income	$	1,924	$	997

Fertilizer Volumes (tons)			112.7		118.9

Revenues. Our fertilizer revenues increased $3.6 million, or 16%, for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004. Our sales price per ton increased 22% as a result of selling our higher priced premium products in the third quarter of 2005. In 2004, these sales were made in the fourth quarter. Also, we were able to pass through increased raw material costs, contributing to our sales price per ton increase. These price increases were partially offset by a 5% decrease in volume sold. Unfavorable weather conditions in some of our marketing areas contributed to this volume decrease.

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Cost of products sold and operating expenses. Our cost of products sold and operating expenses increased $2.5 million, or 13%, for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004. This increase was due to a 19% increase in our cost per ton of products sold. This increased cost per ton was a result of selling our higher cost premium products and also a result of price increases of our raw materials. We experienced a 5% decrease in volume sold, which partially offset this increase in our cost per ton of fertilizer products sold.

Selling, general and administrative expenses. Selling, general and administrative expenses were approximately the same for both nine month periods.

Depreciation and amortization. Depreciation and amortization expenses increased $0.1 million, or 19%, for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004.

In summary, our fertilizer operating income increased $0.9 million, or 93%, for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004.

Statement of Operations Items as a Percentage of Revenues. Our cost of products sold, operating expenses, selling, general and administrative expenses, and depreciation and amortization as a percentage of revenues for the three months and nine months ended September 30, 2005 and 2004 are as follows:


	Three Months						Nine Months
	Ended						Ended
	September 30,						September 30,

	2005			2004			2005			2004

Revenues		100	%		100	%		100	%		100	%
Cost of products sold		78	%		77	%		79	%		77	%
Operating expenses		13	%		12	%		11	%		12	%
Selling, general and administrative expenses		1	%		2	%		2	%		2	%
Depreciation and amortization		3	%		3	%		3	%		3	%

Equity in Earnings of Unconsolidated Entities. For the nine months ended September 30, 2005 and 2004, equity in earnings of unconsolidated entities relates to our unconsolidated non-controlling 49.5% limited partner interest in CF Martin Sulphur until the acquisition of the interest therein not owned by us on July 15, 2005. Equity in earnings of unconsolidated entities for the period January 1, 2005 through July 14, 2005 decreased $0.2 million, or 58%, from the nine months ended September 30, 2004.

On July 15, 2005, we acquired all of the remaining interest in CF Martin Sulphur not owned by us from CF Industries, Inc. and certain subsidiaries of Martin Resource Management. Prior to this transaction, our unconsolidated non-controlling 49.5% limited partnership interest in CF Martin Sulphur was accounted for using the equity method of accounting. Subsequent to the acquisition, CF Martin Sulphur is a wholly-owned subsidiary and is included in our consolidated financial statements and in our sulfur segment.

Prior to July 15, 2005, equity in earnings of CF Martin Sulfur included amortization of the difference between our book investment in the partnership and our related underlying equity balance. Such amortization amounted to $0.3 million for the period January 1, 2005 through July 14, 2005 compared to $0.4 million for the nine months ended September 30, 2004.

Interest Expense. Our interest expense for all operations was $3.8 million for the nine months ended September 30, 2005 compared to $2.3 million for the nine months ended September 30, 2004, an increase of $1.5 million, or 64%. This increase was primarily due to an increase in average debt outstanding and an increase in interest rates in the first nine months of 2005 compared to the first nine months in 2004.

Indirect Selling, General and Administrative Expenses. Indirect selling, general and administrative expenses were $2.5 million for the nine months ended September 30, 2005 compared to $1.9 million for the nine months ended September 30, 2004, an increase of $0.6 million or 31%. The increase was primarily due to increased overhead allocation from Martin Resource Management, increased costs related

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to implementation of procedures under the Sarbanes-Oxley and costs related to potential acquisitions which failed to materialize.

Martin Resource Management allocates to us a portion of its indirect selling, general and administrative expenses for services such as accounting, treasury, clerical billing, information technology, administration of insurance, engineering, general office expenses and employee benefit plans and other general corporate overhead functions we share with Martin Resource Management retained businesses. This allocation is based on the percentage of time spent by Martin Resource Management personnel that provide such centralized services. Generally accepted accounting principles also permit other methods for allocating these expenses, such as basing the allocation on the percentage of revenues contributed by a segment. The allocation of these expenses between Martin Resource Management and us is subject to a number of judgments and estimates, regardless of the method used. We can provide no assurances that our method of allocation, in the past or in the future, is or will be the most accurate or appropriate method of allocating these expenses. Other methods could result in a higher allocation of selling, general and administrative expenses to us, which would reduce our net income. Under our omnibus agreement with Martin Resource Management, the reimbursement amount with respect to indirect general and administrative and corporate overhead expenses was capped at $2.0 million for the year ending October 31, 2004. For each of the subsequent three years, this amount may be increased by no more than the percentage increase in the consumer price index and is also subject to adjustment for expansions of our operations. Effective January 2004, the cap was increased from $1.0 million to $2.0 million to account for the additional operations acquired in acquisitions, including the Tesoro Marine acquisition. In addition, our general partner has the right to agree to increases in this cap in connection with expansions of our operations through the acquisition or construction of new assets or businesses. Martin Resource Management allocated indirect selling, general and administrative expenses of $0.9 million for the nine months ended September 30, 2005 compared to $0.8 million for the nine months ended September 30, 2004.


	*Year Ended December 31, 2004 Compared to the Year Ended December 31, 2003*

Our total revenues were $294.1 million for the year ended December 31, 2004 compared to $192.7 million for the year ended December 31, 2003, an increase of $101.4 million, or 53%. Our cost of products sold was $230.0 million for the year ended December 31, 2004 compared to $150.9 million for the year ended December 31, 2003, an increase of $79.1 million, or 52%. Our total operating expenses were $34.5 million for the year ended December 31, 2004 compared to $21.6 million for the year ended December 31, 2003, an increase of $12.9 million, or 60%.

Our total selling, general and administrative expenses were $6.2 million for the year ended December 31, 2004 compared to $5.0 million for the year ended December 31, 2003, an increase of $1.2 million, or 24%. Total depreciation and amortization was $8.8 million for the year ended December 31, 2004 compared to $4.8 million for the year ended December 31, 2003, an increase of $4.0 million, or 84%. Other operating income in 2003 solely consisted of a gain of $0.6 million related to an involuntary conversion of assets. Our operating income was $14.7 million for the year ended December 31, 2004 compared to $11.1 million for the year ended December 31, 2003, an increase of $3.6 million, or 33%.

The results of operations are described in greater detail on a segment basis below.

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Terminalling and Storage Segment. The following table summarizes our results of operations in our terminalling and storage segment.


			Years Ended
			December 31,

			2004		2003

			(In thousands)
Revenues:
	Services		$	17,919	$	6,921
	Products			8,238		134

		Total Revenues		26,157		7,055

Cost of products sold				6,775		107
Operating expenses				8,494		2,141

		Operating margin		10,888		4,807
Selling, general and administrative expenses				399		452
Depreciation and amortization				3,740		537

	Operating income		$	6,749	$	3,818

Revenues. Our terminalling and storage revenues increased $19.1 million, or 271%, for the year ended December 31, 2004 compared to the year ended December 31, 2003. This increase was primarily due to additional revenue generated by the Tesoro Marine assets we acquired in December 2003. These assets accounted for $8.3 million in terminalling and storage service revenues and $8.2 million in lubricant products sales in 2004. These assets contributed $0.3 million in revenue in 2003. During 2004, we also had increased revenues of $2.8 million from the Neches terminal acquisition.

Cost of products sold. Our cost of products sold was $6.8 million for the year ended December 31, 2004 compared to $0.1 million for the year ended December 31, 2003. This amount represents lubricant cost of products sold as a result of the Tesoro Marine acquisition in December 2003.

Operating expenses. Operating expenses increased $6.4 million, or 297%, for the year ended December 31, 2004 compared to the year ended December 31, 2003. This increase was primarily a result of additional operating expenses of $4.6 million from the Tesoro Marine asset acquisition, and $1.3 million from the Neches terminal acquisition.

Selling, general and administrative expenses. Selling, general and administrative expenses decreased $0.1 million, or 12%, for the year ended December 31, 2004 compared to the year ended December 31, 2003.

Depreciation and amortization. Depreciation and amortization increased $3.2 million, or 596%, for the year ended December 31, 2004 compared to the year ended December 31, 2003. This increase was a result of the Tesoro Marine asset acquisition and the Neches terminal acquisition.

In summary, terminalling and storage operating income increased $2.9 million or 77%, for the year ended December 31, 2004 compared to the year ended December 31, 2003.

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Marine Transportation Segment. The following table summarizes our results of operations in our marine transportation segment.


			Years Ended
			December 31,

			2004		2003

			(In thousands)
Revenues			$	34,780	$	26,342
Operating expenses				24,796		18,135

		Operating margin		9,984		8,207
Selling, general and administrative expenses				175		305
Depreciation and amortization				3,982		3,209

	Operating income		$	5,827	$	4,693

Revenues. Our marine transportation revenues increased $8.5 million, or 32%, for the year ended December 31, 2004 compared to the year ended December 31, 2003. A revenue increase of $6.2 million was generated as a result of marine transportation assets acquired from Tesoro Marine and other parties in the fourth quarter of 2003. Inland marine assets we operated in both years generated an additional revenue increase of $1.8 million. We also leased additional inland equipment which generated incremental revenue of $2.0 million. The total increase in inland revenues was a result of increased business volume and also a result of charging our inland customers the increase in our fuel costs. Offsetting these increases in inland revenue was a decrease of $1.6 million in offshore revenues. This was a result of our offshore asphalt tow undergoing repairs for over two months during this period as well as decreased demand for its services in the second and third quarter due to softness in the asphalt markets in which we operate. Also, the four hurricanes which impacted the Gulf of Mexico and Florida in the third quarter of 2004 negatively impacted our revenues by $0.4 million.

Operating expenses. Operating expenses increased $6.7 million, or 37%, for the year ended December 31, 2004 compared to the year ended December 31, 2003. An increase of $4.8 million was primarily a result of marine transportation assets acquired from Tesoro Marine and other parties in the fourth quarter of 2003. The remaining increase was a result of increased operating costs, including leased operating equipment and fuel expenses. A portion of these increased costs were a result of having to relocate marine transportation assets out of the path of the four hurricanes that impacted the Gulf of Mexico and Florida in the third quarter of 2004.

Selling, general and administrative expenses. Selling, general and administrative expenses decreased $0.1 million, or 43%, for the year ended December 31, 2004 compared to the year ended December 31, 2003.

Depreciation and amortization. Depreciation and amortization increased $0.8 million, or 24%, for the year ended December 31, 2004 compared to the year ended December 31, 2003. This increase was due to acquisitions made in the fourth quarter of 2003 and capital expenditures made in 2004.

In summary, our marine transportation operating income increased $1.1 million, or 24%, for the year ended December 31, 2004 compared to the year ended December 31, 2003.

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Natural Gas Gathering, Processing and LPG Distribution Segment. The following table summarizes our results of operations in our natural gas gathering, processing and LPG distribution segment.


			Years Ended
			December 31,

			2004		2003

			(In thousands)
Revenues			$	203,427	$	133,038
Cost of products sold				197,859		128,055
Operating expenses				1,185		1,314

		Operating margin		4,383		3,669
Selling, general and administrative expenses				1,200		1,100
Depreciation and amortization				103		113

	Operating income		$	3,080	$	2,456

LPG Volumes (gallons)				226,565		192,478

Revenues. Our LPG distribution revenues increased $70.4 million, or 53%, for the year ended December 31, 2004 compared to the year ended December 31, 2003. Our sales volume increased 18% as a result of increased demand from industrial customers and increased sales to retail propane customers, as we improved our market share in certain portions of our marketing area. Also, our average sales price per gallon was 30% higher in 2004 compared to 2003. This price increase was due to a general increase in the prices of LPGs.

Costs of product sold. Our cost of products increased $69.8 million, or 55%, for the year ended December 31, 2004 compared to the year ended December 31, 2003. This increase was due to a general increase in the prices of LPG’s. Our gross margin per gallon remained approximately the same for both periods.

Operating expenses. Operating expenses declined $0.1 million, or 10%, for the year ended December 31, 2004 compared to the year ended December 31, 2003.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $0.1 million, or 9%, for the year ended December 31, 2004 compared to the year ended December 31, 2003.

Depreciation and amortization. Depreciation and amortization was approximately the same for both years.

In summary, our LPG distribution income increased $0.6 million, or 25%, for the year ended December 31, 2004 compared to the year ended December 31, 2003.

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Fertilizer Segment. The following table summarizes our results of operations in our fertilizer segment.


			Years Ended
			December 31,

			2004		2003

			(In thousands)
Revenues			$	29,780	$	26,296
Cost of products sold and operating expenses				25,342		22,730

		Operating margin		4,438		3,566
Selling, general and administrative expenses				1,658		1,441
Depreciation and amortization				941		906

			$	1,839	$	1,219

Other operating income				—		589

	Operating income		$	1,839	$	1,808

Fertilizer Volumes (tons)				146.2		144.9

Revenues. Our fertilizer revenues increased $3.5 million, or 13%, for the year ended December 31, 2004 compared to the year ended December 31, 2003. We experienced a 12% increase in our average sales prices, as we were able to pass through increased raw material costs. Our sales volume also increased by 1%.

Costs of products sold and operating expense. Our cost of products sold and operating expense increased $2.6 million, or 11%, for the year ended December 31, 2004 compared to the year ended December 31, 2003. This increase was due to an 11% increase in our cost per ton of fertilizer products sold, as well as a 1% increase in sales volume. The increased cost per ton was a result of price increases in raw materials.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $0.2 million, or 15%, for the year ended December 31, 2004 compared to the year ended December 31, 2003.

Depreciation and amortization. Depreciation and amortization was approximately the same for both years.

Other operating income. Other operating income in 2003 solely consisted of a gain of $0.6 million related to an involuntary conversion of assets.

In summary, our fertilizer operating income was approximately the same for both years.

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December 31, 2003. The following table summarizes, on a comparative basis, these items of our statement of operations as a percentage of our revenues.


	Years Ended
	December 31,

	2004			2003

	(In thousands)
Revenues		100	%		100	%
Cost of products sold		78	%		78	%
Operating expenses		12	%		11	%
Selling, general and administrative expenses		2	%		3	%
Depreciation and amortization		3	%		2	%

Equity in Earnings of Unconsolidated Entities. For the years ended December 31, 2004 and 2003, equity in earnings of unconsolidated entities relates to our unconsolidated non-controlling 49.5% limited partner interest in CF Martin Sulphur.

Equity in earnings of unconsolidated entities for 2004 of $0.9 million decreased $1.9 million, or 67%, from the same period in 2003. As a result, we have recorded a negative investment in CF Martin Sulphur of $750,000 which we expect to recover through future earnings. This decrease was the result of a 16% decline in volume sold and a decline in the operating margin. The decrease in volume sold was a result of reduced demand by a certain customer in the second quarter of 2004 and a reduction of sulfur supply available for sale in the first quarter of 2004. The decline in operating margin was a result of decreased utilization of CF Martin Sulphur’s barge transportation system in the third quarter of 2004 due to the four hurricanes that impacted the Gulf of Mexico and Florida. Due to these factors, the cash distributions we received from CF Martin Sulphur decreased by $1.6 million in 2004 compared to 2003. For 2004 we received cash distributions of $2.0 million. For the same period in 2003, we received cash distributions of $3.6 million.

Equity in earnings of CF Martin Sulphur includes amortization of the difference between our book investment in the partnership and our related underlying equity balance. Such amortization amounted to $0.5 million for both years.

CF Martin Sulphur was not in compliance with the minimum EBITDA covenant for the second and third quarters of 2004 under its credit facility with Harris Trust and Savings Bank. The bank agreed to waive CF Martin Sulphur’s non-compliance with such covenant as of June 30, 2004 and September 30, 2004. On October 29, 2004, CF Martin Sulphur and the Bank replaced the minimum EBITDA covenant with a cash flow leverage covenant and amended the maturity date of such credit facility to March 31, 2007. CF Martin was in compliance with this new covenant at December 31, 2004 and we believe that CF Martin Sulphur will maintain compliance with such amended covenant.

Interest Expense. Our interest expense for all operations was $3.3 million for 2004 compared to $2.0 million for 2003, an increase of $1.3 million, or 66%. This increase was primarily due to an increase in average debt outstanding and an increase in interest rates in 2004 compared to 2003. Additionally, there was an increase in amortization of deferred debt costs of $0.4 million for 2004 compared to 2003.

Indirect Selling, General and Administrative Expenses. Indirect selling, general and administrative expenses were $2.8 million for 2004 compared to $1.7 million for 2003, an increase of $1.1 million or 64%. This increase was primarily due to increased overhead allocation of $0.3 million from MRMC and increased costs related to complying with the requirements of the Sarbanes-Oxley Act of 2002.

Martin Resource Management allocated to us a portion of its indirect selling, general and administrative expenses for services such as accounting, treasury, clerical billing, information technology, administration of insurance, engineering, general office expense and employee benefit plans and other general corporate overhead functions we share with the Martin Resource Management retained businesses. This allocation is based on the percentage of time spent by Martin Resource Management personnel that provide such centralized services. Generally accepted accounting principles also permit other methods for

S-58

allocation these expenses, such as basing the allocation on the percentage of revenues contributed by a segment. The allocation of these expenses between Martin Resource Management and us is subject to a number of judgments and estimates, regardless of the method used. We can provide no assurances that our method of allocation, in the past or in the future, is or will be the most accurate or appropriate method of allocation these expenses. Other methods could result in a higher allocating of selling, general and administrative expense to us, which would reduce our net income. Under the omnibus agreement, the reimbursement amount with respect to indirect general and administrative and corporate overhead expenses was capped at $2.0 million for the 12 month period ending October 31, 2004. For each of the subsequent three years, this amount may be increased by no more than the percentage increase in the consumer price index and is also subject to adjustment for expansions of our operations. Effective January 2004, the cap was increased from $1.0 million to $2.0 million to account for the additional operations acquired in acquisitions, including the Tesoro Marine acquisition. In addition, our general partner has the right to agree to increases in this cap in connection with expansions of our operations through the acquisitions or construction of new assets or businesses. Martin Resource Management allocated indirect selling, general and administrative expenses of $1.1 million for the year ended December 31, 2004 compared to $0.7 million for the year ended December 31, 2003.


	*Year Ended December 31, 2003 Compared to Year Ended December 31, 2002*

Our total revenues were $192.7 million in 2003 compared to $149.9 million in 2002, an increase of $42.8 million, or 29%. Our cost of products sold was $150.9 million in 2003 compared to $110.9 million in 2002, an increase of $40.0 million, or 36%. Our total operating expenses were $21.6 million in 2003 compared to $20.6 million in 2002, an increase of $1.0 million, or 5%.

Our total selling, general and administrative expenses were $5.0 million in 2003 compared to $5.3 million in 2002, a decrease of $0.3 million, or 6%. Depreciation and amortization was $4.8 million in 2003 compared to $4.5 million in 2002, an increase of $0.3 million, or 6%. Other operating income in 2003 solely consisted of a gain of $0.6 million related to an involuntary conversion of assets. Our operating income was $11.1 million in 2003 compared to $8.6 million in 2002, an increase of $2.5 million, or 29%.

These results of operations are discussed in greater detail on a segment basis below.

Terminalling and Storage Segment. The following table summarizes our results of operations in our terminalling segment.


			Years Ended
			December 31,

			2003		2002

			(In thousands)
Revenues:
	Services		$	6,921	$	5,158
	Products			134		—

		Total Revenues		7,055		5,158

Cost of products sold				107		—
Operating expenses				2,141		1,724

		Operating margin		4,807		3,434
Selling, general and administrative expenses				452		723
Depreciation and amortization				537		383

	Operating income		$	3,818	$	2,328

Revenues. Our terminalling and storage revenues increased $1.9 million, or 37%, in 2003 compared to 2002. This increase was due primarily to additional revenue generated by our two newly constructed asphalt tanks that were put into service in May 2002 and an increase in rates for certain terminalling

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contracts at our Tampa terminal. Additionally, the Tesoro Marine asset acquisition, which occurred in late December 2003, generated service revenues of $0.2 million and product sales, which consisted primarily of lubricants, of $0.1 million.

Cost of products sold. Our cost of products sold was $0.1 million for 2003, which approximated our product sales.

Operating expenses. Our operating expenses increased $0.4 million, or 24%, in 2003 compared to 2002. This increase was due primarily to increased gas utility expense.

Selling, general and administrative expenses. Selling, general and administrative expenses decreased $0.3 million, or 37%, in 2003 compared to 2002.

Depreciation and amortization. Depreciation and amortization increased $0.2 million, or 40%, in 2003 compared to 2002.

In summary, our terminalling and storage operating income increased $1.5 million, or 64%, in 2003 compared to 2002.

Marine Transportation Segment. The following table summarizes our results of operations in our marine transportation segment.


			Years Ended
			December 31,

			2003		2002

			(In thousands)
Revenues			$	26,342	$	24,440
Operating expenses				18,135		17,201

		Operating margin		8,207		7,239
Selling, general and administrative expenses				305		524
Depreciation and amortization				3,209		2,857

	Operating income		$	4,693	$	3,858

Revenues. Our marine transportation revenues increased $1.9 million, or 8%, in 2003 compared to 2002. Approximately $0.5 million of this increase was due to two offshore barge units that were fully utilized in 2003. These units were in the shipyard in the first quarter of 2002. One of the offshore barge units was in the shipyard during 2002 while being converted from fuel oil service to sulfur service. This unit is currently fully utilized under a term contract with CF Martin Sulphur. The other offshore barge unit was in the shipyard during the first quarter of 2002 for routine repairs and maintenance. We also experienced an increase in revenues of $1.1 million as a result of increased daily rates realized by our inland barge fleet as there was increased demand by industrial users of fuel oil as this product was an economic substitute for higher cost natural gas. Finally, our marine acquisitions, which occurred in the fourth quarter of 2003, generated $0.3 million of additional inland revenue.

Operating expenses. Operating expenses increased $0.9 million, or 5%, in 2003 compared to 2002. Reduced maintenance and lease expenses of $1.4 million were more than offset by increases in salaries, benefits, fuel, supplies and other operating expenses.

Selling, general and administrative expenses. Selling, general and administrative expenses decreased $0.2 million, or 42%, in 2003 compared to 2002.

Depreciation and amortization. Depreciation and amortization increased $0.4 million, or 12%, in 2003 compared to 2002. This increase was due primarily to depreciation of maintenance capital expenditures made during 2002.

In summary, our marine transportation operating income increased $0.8 million, or 22%, in 2003 compared to 2002.

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Natural Gas Gathering, Processing and LPG Distribution Segment. The following table summarizes our results of operations in our natural gas gathering, processing and LPG distribution segment.


			Years Ended
			December 31,

			2003		2002

			(In thousands)
Revenues			$	133,038	$	92,408
Cost of products sold				128,055		87,189
Operating expenses				1,314		1,632

		Operating margin		3,669		3,587
Selling, general and administrative expenses				1,100		1,040
Depreciation and amortization				113		310

	Operating income		$	2,456	$	2,237

LPG Volumes (gallons)				192,478		179,508

Revenues. Our LPG distribution revenues increased $40.6 million, or 44%, in 2003 compared to 2002. This increase was due to both volume and price increases. Our volume for the year ended December 31, 2003 was 7% greater than 2002. The average sales price per gallon was 34% greater for 2003 compared to 2002. The increase in both volume and price was a result of an industry-wide increase in demand for LPGs during the first quarter of 2003 compared to the first quarter of 2002 because of colder temperatures during the first quarter of 2003. This increased price generally maintained itself throughout 2003.

Cost of products sold. Our cost of products sold increased $40.9 million, or 47%, in 2003 compared to 2002, which approximated our increase in sales. Our LPG cost per gallon increased approximately 37% due to colder temperatures, which resulted in an industry-wide increase in demand for LPGs in the first quarter of 2003 compared to the first quarter of 2002.

Operating expenses. Operating expenses decreased $0.3 million, or 19%, in 2003 compared to 2002.

Selling, general and administrative expenses. Selling, general and administrative expenses were approximately the same for both years.

Depreciation and amortization. Depreciation and amortization was decreased $0.2 million, or 64%, in 2003 compared to 2002.

In summary, our LPG distribution operating income increased $0.2 million, or 10%, in 2003 compared to 2002.

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Fertilizer Segment. The following table summarizes our results of operations in our fertilizer segment.


			Years Ended
			December 31,

			2003		2002

			(In thousands)
Revenues			$	26,296	$	27,900
Cost of products sold and operating expenses				22,730		23,762

		Operating margin		3,566		4,138
Selling, general and administrative expenses				1,441		2,036
Depreciation and amortization				906		938

			$	1,219	$	1,164

Other operating income				589		—

	Operating income		$	1,808	$	1,164

Fertilizer Volumes (tons)				144.9		158.1

Revenues. Our fertilizer revenues decreased $1.6 million, or 6%, in 2003 compared to 2002. Our sales volume declined 8% for the year ended December 31, 2003. Volume decrease was the result of the loss of an industrial customer and adverse weather conditions in one of our marketing regions. Offsetting this decrease was a 3% increase in the average selling price per ton in 2003 compared to 2002.

Cost of products sold and operating expenses. Our cost of products sold and operating expenses decreased $1.0 million, or 4%, in 2003 compared to 2002. In 2003, we experienced increased costs of raw materials, some of which we were not able to pass on to our customers.

Selling, general and administrative expenses. Selling, general, and administrative expenses decreased $0.6 million, or 29%, in 2003 compared to 2002. This decrease was primarily due to a reduction in personnel and a reduction in advertising on lawn and garden products.

Depreciation and amortization. Depreciation and amortization was approximately the same for both years.

Other operating income. Other operating income in 2003 consisted solely of a gain of $0.6 million related to an involuntary conversion of assets.

In summary, our fertilizer operating income increased $0.6 million, or 55%, in 2003 compared to 2002.

Statement of Operations Items as a Percentage of Revenues. In the aggregate, our cost of products sold, operating expenses, selling, general and administrative expenses, and depreciation and amortization have remained relatively constant as a percentage of revenues for the years ended December 31, 2003 and December 31, 2002. The following table summarizes, on a comparative basis, these items of our statement of operations as a percentage of our revenues.


	Years Ended
	December 31,

	2003		2002

	(In thousands)
Revenues		100%		100%
Cost of products sold		78%		74%
Operating expenses		11%		14%
Selling, general and administrative expenses		3%		4%
Depreciation and amortization		2%		3%

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Equity in Earnings of Unconsolidated Entities. Prior to November 6, 2002, equity in earnings of unconsolidated entities primarily related to our 49.5% unconsolidated non-controlling limited partner interest in CF Martin Sulphur but also included a 50% interest in a sulfur fungicide joint venture. Subsequent to November 6, 2002, this line item includes the CF Martin Sulphur investment only, as the interest in the fungicide joint venture was retained by Martin Resource Management.

Equity in earnings of unconsolidated entities for 2003 of $2.8 million decreased by $0.4 million, or 11%, compared to 2002. This decrease was a result of reduced volume of products handled during 2003 compared to 2002. Prior to our initial public offering, we held a 50% interest in a sulfur fungicide joint venture which had a $0.2 million loss for 2002. This joint venture interest was retained by Martin Resource Management following our initial public offering. This increase was more than offset by a decrease in equity in earnings from CF Martin Sulphur of $0.6 million. For the year ended December 31, 2003, we received cash distributions from CF Martin Sulphur of $3.6 million. For the same period in 2002, we received cash distributions of $0.9 million. Equity in earnings of CF Martin Sulphur includes amortization of the difference between our book investment in the partnership and our related underlying equity balance. Such amortization amounted to $0.5 million for both years.

Interest Expense. Our interest expense for all operations was $2.0 million for 2003 compared to $3.6 million for 2002, a decrease of $1.6 million, or 45%. This decrease was primarily due to lower interest rates on our variable rate debt in 2003 compared to 2002.

Indirect Selling, General and Administrative Expenses. Indirect selling, general and administrative expense was $1.7 million for 2003 compared to $1.0 million for 2002, an increase of $0.7 million, or 67%. This increase was primarily due to higher legal fees, accounting fees and other costs associated being a public company.

Martin Resource Management allocates to us a portion of its indirect selling, general and administrative expenses for services such as accounting, engineering, information technology and risk management. This allocation is based on the percentage of time spent by Martin Resource Management personnel that provide such centralized services. Generally accepted accounting principles also permit other methods for allocation of these expenses, such as basing the allocation on the percentage of revenues contributed by a segment. The allocation of these expenses between Martin Resource Management and us is subject to a number of judgments and estimates, regardless of the method used. We can provide no assurances that our method of allocation, in the past or in the future, has been or will be the most accurate or appropriate method of allocation of these expenses. Other methods could result in a higher allocation of selling, general and administrative expenses to us, which would reduce our net income. Under the omnibus agreement, the reimbursement amount with respect to indirect general and administrative and corporate overhead expenses is capped at $2.0 million for the year period ending October 31, 2004. For each of the subsequent three years, this amount may be increased by no more than the percentage increase in the consumer price index and is also subject to adjustment for expansions of our operations. The cap was recently increased from $1.0 million to $2.0 million to account for the additional operations acquired in recent acquisitions, including the Tesoro Marine asset acquisition. In addition, our general partner has the right to agree to further increases in connection with expansions of our operations through the acquisition or construction of new assets or businesses.

Liquidity and Capital Resources


	*Cash Flows and Capital Expenditures*

For the nine months ended September 30, 2005, cash was unchanged as a result of $24.3 million provided by operating activities, $46.4 million used in investing activities and $22.1 million provided by financing activities. For the nine months ended September 30, 2004, cash was unchanged as a result of $7.9 million provided by operating activities, $31.8 million provided by investing activities and $23.9 million used in financing activities.

In 2004, cash increased $0.9 million as a result of $12.8 million provided by operating activities, $34.3 million used in investing activities and $22.4 million provided by financing activities. In 2003, cash

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increased $0.5 million as a result of $10.3 million provided by operating activities, $27.6 million used in investing activities and $17.9 million provided by financing activities. In 2002, cash increased $1.7 million as a result of $5.1 million provided by operating activities, $4.1 million used in investing activities and $0.6 million provided by financing activities.

For the periods presented, our investing activities consisted primarily of capital expenditures. Generally, our capital expenditure requirements have consisted, and we expect that our capital requirements will continue to consist, of:


	•	maintenance capital expenditures, which are capital expenditures made to replace assets to maintain our existing operations and to extend the useful lives of our assets; and

	•	expansion capital expenditures, which are capital expenditures made to grow our business, to expand and upgrade our existing marine transportation, terminalling, storage and manufacturing facilities, and to construct new plants, storage facilities, terminalling facilities and new marine transportation assets.

For the nine months ended September 30, 2005, our investing activities of $46.4 million consisted principally of capital expenditures and acquisitions. For the nine months ended September 30, 2004, our investing activities of $31.8 million consisted principally of $1.7 million of cash distributions from an unconsolidated partnership and $30.1 million of acquisitions, proceeds from sale of property, plant and equipment and capital expenditures.

In 2004, our investing activities consisted primarily of cash paid for acquisitions, payments for property, plant and equipment, proceeds from sale of property, plant and equipment and cash distributions received from an unconsolidated partnership.

In 2003, our investing activities consisted of cash paid for acquisitions, cash distributions received from an unconsolidated partnership and insurance proceeds from a casualty loss at one of our fertilizer facilities.

In 2002, our investing activities consisted primarily of payments for property plant and equipment and cash distributions received from an unconsolidated partnership.

For the nine months ended September 30, 2005 and 2004, our capital expenditures for property and equipment were $36.3 million and $32.6 million, respectively.

As to each period:


	•	For the nine months ended September 30, 2005 we spent $33.1 million for expansion and $3.2 million for maintenance. Our expansion capital expenditures were made in connection with the purchase of the East Texas Pipeline, the Bay Sulfur asset acquisition, the construction of a sulfur priller at our Neches, Texas facility, the purchase of additional marine equipment and the purchase of the CF Martin Sulphur partnership interests not owned by us. Our maintenance capital expenditures were primarily made for marine equipment, including expenditures as a result of increased steel and shipyard costs, and terminal and fertilizer facilities.

	•	For the nine months ended September 30, 2004 we spent $28.9 million for expansion and $3.7 million for maintenance. Our expansion capital expenditures were made in connection with the Neches and OOS terminal acquisitions. Our maintenance capital expenditures were primarily made for marine equipment, including expenditures as a result of increased steel and shipyard costs, and terminal and fertilizer facilities.

For 2004, 2003 and 2002 our capital expenditures for property and equipment were $35.4 million, $31.9 million and $5.3 million, respectively.

As to each period:


	•	In 2004, we spent $30.2 million for expansion and $5.2 million for maintenance. Our expansion capital expenditures were primarily made in connection with the Neches and Freeport terminal acquisitions. Our maintenance capital expenditures were primarily made in our marine

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		transportation business for routine dockings of our vessels pursuant to United States Coast Guard requirements and terminal and fertilizer facilities.

	•	In 2003, we spent $29.2 million for expansion and $2.8 million for maintenance. Our expansion capital expenditures were made in connection with the Tesoro Marine and Cross acquisitions, as well as the acquisition of an inland pushboat and two inland tank barges. Our maintenance capital expenditures were primarily made in our marine transportation business for required Coast Guard dry docking of our vessels. We received $0.7 million from insurance proceeds relating to a fire loss, offsetting a portion of our maintenance capital expenditures.

	•	In 2002, we spent $4.8 million for expansion and $0.6 million for maintenance. Our expansion capital expenditures were primarily made for the construction of two new asphalt tanks and the purchase of two inland barges that were previously, operated under an operating lease agreement. Our maintenance capital expenditures were primarily made in our marine transportation business for routine dockings of our vessels pursuant to United States Coast Guard requirements.

For the nine months ended September 30, 2005, financing activities consisted of cash distributions of $14.0 million paid to common and subordinated unitholders, payment of long term debt under our credit facility of $16.3 million, payment of CF Martin Sulphur debt of $2.4 million, borrowings of long-term debt under our credit facility of $53.2 million and payment of debt issuance costs of $0.4 million. For the nine months ended September 30, 2004, financing activities consisted of cash distributions paid to common and subordinated unitholders of $12.9 million, net proceeds from a follow on equity offering of $34.8 million, payment of long term debt under our credit facility of $39.4 million and borrowings of long-term debt under our credit facility of $41.4 million.

In 2004, our financing activities consisted of net proceeds from a follow-on public offering and related transactions of $34.8 million, cash distributions paid to common and subordinated unitholders of $17.5 million, payments of long-term debt under our predecessor credit facility of $43.2 million and borrowings of long-term debt under our predecessor credit facility of $49.2 million and payments of debt issuance costs of $0.9 million. The follow-on offering occurred in February 2004. We issued 1,322,500 common units, resulting in proceeds of $34.0 million, net of underwriters’ discounts, commissions and offering expenses. Our general partner contributed $0.8 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 debt under our predecessor credit facility.

In 2003, our financing activities consisted of borrowings under our predecessor credit facility, payments of debt issuance costs and cash distributions paid to unitholders. Borrowings of $30.0 million from our predecessor credit facility were used to acquire assets of Tesoro Petroleum, Cross Oil and marine assets from a third party. We paid $0.9 million in debt issuance costs related to the expansion of our predecessor credit facility from $60 million to $80 million. Cash distributions of $13.2 million were paid to our common and subordinated unitholders.

In 2002, our financing activities consisted primarily of our initial public offering and related transactions. Net proceeds from the offering of $50.6 million along with an initial draw from our predecessor credit facility of $37.2 million, net of issuance costs, were used to pay off our existing debt of $8.8 million and debt and related costs assumed from Martin Resource Management of $73.3 million. Additionally, we paid down $2.2 million of our new credit facility during the period subsequent to our initial public offering.


	*Capital Resources*

Historically, we have generally satisfied our working capital requirements and funded our capital expenditures with cash generated from operations and borrowings. We expect our primary sources of funds for short-term liquidity needs will be cash flows from operations and borrowings under our credit facility.

As of September 30, 2005, we had $121.0 million of outstanding indebtedness, consisting of outstanding borrowings of $88.4 million under our predecessor $120.0 million acquisition subfacility,

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$23.5 million under our predecessor $30.0 million working capital subfacility and $9.1 million of U.S. Government Guaranteed Ship Financing Bonds. Under the predecessor acquisition subfacility, we borrowed $3.5 million in connection with the acquisition of the East Texas Pipeline in January 2005, $5.0 million in connection with the acquisition of the operating assets of Bay Sulfur Company in April 2005, and $19.4 million in connection with the acquisition of the partnership interests in CF Martin Sulphur not owned by us in July 2005. In connection with the acquisition, we assumed $11.5 million of indebtedness owed by CF Martin Sulphur and promptly repaid $2.4 million of such indebtedness. The remaining indebtedness relates to certain financing of CF Martin Sulphur under its U.S. Government Guaranteed Ship Financing Bonds. Our credit facility requires us to redeem the U.S. Government Guaranteed Ship Financing Bonds not later than March 31, 2006. We intend to execute the redemption using a portion of the net proceeds from this offering.

In November 2005, we borrowed approximately $62.8 million under our credit facility to pay a portion of the purchase price for the Prism Gas acquisition. The remainder of the purchase price was funded by $5 million previously escrowed by us, $15 million of new equity capital provided by Martin Resource Management in exchange for newly issued common units, approximately $10 million of newly issued common units issued to certain of the sellers and approximately $0.5 million in capital provided by Martin Resource Management in order to continue the 2% general partnership interest in us. The common units were priced at $32.54 per common unit, based on the average closing price of our common units on the Nasdaq during the ten trading days immediately preceding and immediately following the date of the execution of the definitive purchase agreement. We intend to use a portion of the proceeds from this offering to repay a portion of the amounts drawn on our new credit facility.

In September 2004, we filed a shelf registration statement with the SEC covering the offer and sale from time to time, in our discretion and as our business circumstances and market conditions warrant, of up to $200 million of our common units, debt securities, and/or debt securities of our operating subsidiary. The nature and terms of any securities to be offered and sold under the registration statement, including the use of proceeds, will be described in related prospectus supplements to be filed with the SEC from time to time.

Upon completion of this offering and the application of the net proceeds therefrom, we believe that cash generated from operations and our borrowing capacity under our credit facility, will be sufficient to meet our working capital requirements, anticipated capital expenditures and scheduled debt payments for the 12-month period following the date of this prospectus supplement. However, our ability to satisfy our working capital requirements, to fund planned capital expenditures and to satisfy our debt service obligations will depend upon our future operating performance, which is subject to certain risks. Please read “Risks Related to Our Business” for a discussion of such risks.


	*Description of Our Credit Facility*

On November 10, 2005, we entered into a new $225.0 million multi-bank credit facility. The credit facility is comprised of a $130.0 million term loan facility and a $95.0 million revolving credit facility, which includes a $20.0 million letter of credit sub-limit. Our credit facility also includes procedures for additional financial institutions to become revolving lenders, or for any existing revolving lender to increase its revolving commitment, subject to a maximum of $100.0 million for all such increases in revolving commitments of new or existing revolving lenders. The revolving credit facility is used for ongoing working capital needs and general partnership purposes, and to finance permitted investments, acquisitions and capital expenditures. On November 10, 2005, we borrowed $130.0 million under the term loan facility and $52.2 million under the revolving credit facility to repay preexisting indebtedness under our predecessor credit facility and to fund a portion the purchase price paid in the Prism Gas acquisition. On December 13, 2005, we borrowed $6.0 million under the revolving credit facility to fund the purchase price paid in the A&A Fertilizer acquisition.

Our obligations under the credit facility are secured by substantially all of our assets, including, without limitation, inventory, accounts receivable, vessels, equipment, fixed assets and the interests in our

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operating subsidiaries. We may prepay all amounts outstanding under this facility at any time without penalty.

Indebtedness under the credit facility bears interest at either LIBOR plus an applicable margin or the base prime rate plus an applicable margin. The applicable margin for revolving loans that are LIBOR loans ranges from 1.75% to 3.25% and the applicable margin for revolving loans that are base prime rate loans ranges from 0.75% to 2.25%. The applicable margin for term loans that are LIBOR loans ranges from 2.25% to 3.25% and the applicable margin for term loans that are base prime rate loans ranges from 1.25% to 2.25%. The applicable margin for existing borrowings is 3.25%. On May 1, 2006, the applicable margins will increase by 0.50% if we have not received at least $50.0 million from the issuance of our equity after November 10, 2005. We incur a commitment fee on the unused portions of the credit facility.

In addition, the credit facility contains various covenants, which, among other things, limit our ability to: (i) incur indebtedness; (ii) grant certain liens; (iii) merge or consolidate unless we are the survivor; (iv) sell all or substantially all of our assets; (v) make certain acquisitions; (vi) make certain investments; (vii) make capital expenditures; (viii) make distributions other than from available cash; (ix) create obligations for some lease payments; (x) engage in transactions with affiliates; (xi) engage in other types of business; and (xii) our joint ventures to incur indebtedness or grant certain liens.

The credit facility also contains covenants, which, among other things, require us to maintain specified ratios of: (i) minimum net worth (as defined in the credit facility) of $75.0 million plus 50% of net proceeds from equity issuances after November 10, 2005; (ii) EBITDA (as defined in the credit facility) to interest expense of not less than 3.0 to 1.0 at the end of each fiscal quarter; (iii) total funded debt to EBITDA of not more than (x) 5.5 to 1.0 for the fiscal quarter ended September 30, 2005, (y) 5.25 to 1.00 for the fiscal quarters ending December 31, 2005 through September 30, 2006, and (z) 4.75 to 1.00 for each fiscal quarter thereafter; and (iv) total secured funded debt to EBITDA of not more than (x) 5.50 to 1.00 for the fiscal quarter ended September 30, 2005, (y) 5.25 to 1.00 for the fiscal quarters ending December 31, 2005 through September 20, 2006, and (z) 4.00 to 1.00 for each fiscal quarter thereafter.

On November 10 of each year, commencing with November 10, 2006, we must prepay the term loans under the credit facility with 75% of Excess Cash Flow (as defined in the credit facility), unless its ratio of total funded debt to EBITDA is less than 3.00 to 1.00. If we receive greater than $15.0 million from the incurrence of indebtedness other than under the credit facility, we must prepay indebtedness under the credit facility with all such proceeds in excess of $15.0 million. Any such prepayments are first applied to the term loans under the credit facility. We must prepay revolving loans under the credit facility with the net cash proceeds from any issuance of its equity. We must also prepay indebtedness under the credit facility with the proceeds of certain asset dispositions. Other than these mandatory prepayments, the credit facility requires interest only payments on a quarterly basis until maturity. All outstanding principal and unpaid interest must be paid by November 10, 2010. The credit facility contains customary events of default, including, without limitation, payment defaults, cross-defaults to other material indebtedness, bankruptcy-related defaults, change of control defaults and litigation-related defaults.

After giving effect to the Prism Gas acquisition and the A&A fertilizer acquisition, our outstanding indebtedness includes approximately $192.0 million under the credit facility and $9.1 million of U.S. Guaranteed Ship Financing Bonds due 2021, which were assumed in connection with our July 2005 acquisition of the remaining equity interests in CF Martin Sulphur not owned by us. After giving effect to this offering, our outstanding indebtedness will consist of approximately $130.0 million under the term loan facility and approximately $9.1 million of the U.S. Government Guaranteed Ship Financing Bonds due 2021, which will be repaid not later than March 31, 2006 using a portion of the net proceeds from this offering.

We paid cash interest in the amount of $1,185,000 and, $577,000 for the three months ended September 30, 2005 and 2004, respectively, and $2,987,000 and, $1,331,000 for the nine months ended September 30, 2005 and 2004 respectively.

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Total Contractual Cash Obligations. A summary of our total contractual cash obligations, as of September 30, 2005, is as follows:


			Payment due by period

			Total		Less than						Due
Type of Obligation			Obligation		One Year		1-3 Years		3-5 Years		Thereafter

			(In thousands)
Long-term debt(1)
	Revolving credit facility		$	23,500	$	—	$	23,500	$	—	$	—
	Term loan facility			88,400		—		88,400		—		—
		U.S. Government Guaranteed Ship Financing Bonds(2)		9,104		582		1,164		1,164		6,194
Non-competition agreement				450		50		100		100		200
Operating leases				7,460		1,880		1,926		318		3,336
Interest expense(3):
	Revolving credit facility			3,947		1,281		2,563		103		—
	Term loan facility			14,586		4,735		9,470		381		—

Total contractual cash obligations			$	147,447	$	8,528	$	127,123	$	2,066	$	9,730


(1)	As described elsewhere herein, we incurred approximately $72.4 million in additional borrowings under our credit facility in connection with the acquisition of Prism Gas in November 2005 and the A&A Fertilizer acquisition in December 2005.

(2)	Pursuant to the terms of our credit facility, we are required to repay this indebtedness (including the applicable prepayment premium) not later than March 31, 2006. We intend to do so using a portion of the net proceeds form this offering.

(3)	Interest commitments are estimated using our current interest rates for the respective credit agreements over their remaining terms.

Letter of Credit. At September 30, 2005, we had outstanding irrevocable letters of credit in the amount of $2.6 million which were issued under our credit facility.

No Off-Balance Sheet Arrangements. We do not have any off-balance sheet financing arrangements.


	*Other Obligations*

In connection with the acquisition of the remaining interests in CF Martin Sulphur not owned by us, we assumed $11.5 million of indebtedness owed by CF Martin Sulphur and promptly repaid $2.4 million of such indebtedness. Of the $11.5 million of indebtedness we assumed, $9.4 million relates to U.S. Government Guaranteed Ship Financing Bonds maturing in 2021. The outstanding balance as of September 30, 2005 was $9.1 million. These bonds are payable in equal semi-annual installments of $291,000 and are secured by certain marine vessels owned by CF Martin Sulphur. Pursuant to the terms of our credit facility, we are obligated to repay these bonds (including the applicable prepayment premium) by March 31, 2006, which we intend to do using a portion of the proceeds of this offering.

Seasonality

A substantial portion of our revenues are dependent on sales prices of products, particularly LPGs and fertilizers, which fluctuate in part based on winter and spring weather conditions. The demand for LPGs is strongest during the winter heating season. The demand for fertilizers is strongest during the early spring planting season. However, our terminalling and storage and marine transportation businesses and the molten sulfur business of CF Martin Sulphur are typically not impacted by seasonal fluctuations. We expect to derive a majority of our net income from our terminalling and storage, marine transportation and

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sulfur businesses. Therefore, we do not expect that our overall net income will be impacted by seasonality factors. However, extraordinary weather events, such as hurricanes, have in the past, and could in the future, impact our terminalling and storage and marine transportation businesses. For example, Hurricanes Katrina and Rita in the third quarter of 2005 adversely impacted our operating expenses and the four hurricanes that impacted the Gulf of Mexico and Florida in the third quarter of 2004 adversely impacted our terminalling and storage and marine transportation business’s revenues.

Impact of Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the nine months ended September 30, 2005 and 2004. However, inflation remains a factor in the United States economy and could increase our cost to acquire or replace property, plant and equipment as well as our labor and supply costs. We cannot assure you that we will be able to pass along increased costs to our customers.

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

Environmental Matters

Our operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. We incurred no significant environmental costs, liabilities or expenditures to mitigate or eliminate environmental contamination during 2002, 2003, 2004 or the first three quarters of 2005. Under the omnibus agreement with Martin Resource Management, Martin Resource Management will indemnify us for five years after the November 6, 2002 closing of our initial public offering for:


	•	certain potential environmental liabilities associated with the assets it contributed to us relating to events or conditions that occurred or existed before the closing of our initial public offering, and

	•	any payments we are required to make, as a successor in interest to affiliates of Martin Resource Management, under environmental indemnity provisions contained in the contribution agreement associated with the contribution of assets by Martin Resource Management to CF Martin Sulphur in November 2000.

Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. We are exposed to market risks associated with commodity prices, counterparty credit and interest rates. Historically, we have not engaged in commodity contract trading or hedging activities. However, in connection with our acquisition of Prism Gas, we intend to establish a hedging policy and to monitor and manage the commodity market risk associated with the commodity risk exposure of the Prism acquisition. In addition, we will focus on utilizing counterparties for these transactions whose financial condition is appropriate for the credit risk involved in each specific transaction.

Commodity Price Risk. As a result of our Prism Gas acquisition, we are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of our gathering, processing and sales activities. Prism Gas gathering and processing revenues are earned under various contractual arrangements with gas producers. Gathering revenues are generated through a combination of fixed-fee and index-related arrangements. Processing revenues are generated primarily through contracts which provide for processing on percent-of-liquids (POL) and percent-of-proceeds (POP) basis. Prism Gas has entered into hedging transactions through 2006 to protect a portion of its commodity exposure from these POL and POP contracts. As of December 31, 2005, Prism Gas has hedged approximately 63% of its commodity risk by volume for 2006. These hedging arrangements are in the form of swaps for crude

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oil, natural gas and ethane. We anticipate entering into additional commodity derivatives in 2006 and beyond to manage our risks associated with these market fluctuations, and will consider using various commodity derivatives, including forward contracts, swaps, collars, futures and options, although there is no assurance that we will be able to do so or that the terms thereof will be similar to our existing hedging arrangements. In addition, we will consider derivative arrangements that include the specific NGL products as well as natural gas and crude oil.

Hedging Arrangements in Place

Year

Commodity Hedged

Volume

Type of Derivative

Basis Reference

2006

Natural Gas

10,000 MMBTU/Month (Jan-Mar)

Natural Gas Swap ($10.69)

Center Point East

2006

Natural Gas

10,000 MMBTU/Month (Jan-Mar)

Natural Gas Swap ($11.50)

Center Point East

2006

Ethane

6,000 BBL/Month

Ethane Swap ($29.09)

Mt. Belvieu

2006

Condensate & Natural Gasoline

2,000 BBL/Month

Crude Oil Swap ($66.80)

NYMEX

2006

Condensate & Natural Gasoline

2,000 BBL/Month

Crude Oil Swap ($66.25)

NYMEX

2006

Condensate & Natural Gasoline

1,000 BBL/Month

Crude Oil Swap ($65.10)

NYMEX

2006

Natural Gas

10,000 MMBTU/Month (April-Dec)

Natural Gas Swap ($9.03)

Houston Ship Channel

2006

Natural Gas

10,000 MMBTU/Month (April-Dec)

Natural Gas Swap ($9.54)

Houston Ship Channel

Our LPG storage and distribution business is a “margin-based” business in which our gross profits depend on the excess of our sales prices over our supply costs. As a result, our profitability is sensitive to changes in the market price of LPGs. LPGs are a commodity and the price we pay for them can fluctuate significantly in response to supply and other market conditions over which we have no control. When there are sudden and sharp decreases in the market price of LPGs, we may not be able to maintain our margins. Consequently, sudden and sharp decreases in the wholesale cost of LPGs could reduce our gross profits. We attempt to minimize our exposure to market risk by maintaining a balanced inventory position by matching our physical inventories and purchase obligations with sales commitments.

Other than the current and anticipated hedging arrangements noted above, we have not historically acquired and held inventory or derivative financial instruments for the purpose of speculating on price changes that might expose us to indeterminable losses.

We entered into the current hedging arrangements with an investment grade subsidiary of a major oil company and an investment grade commercial bank. 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.

Our principal customers with respect to Prism Gas’ natural gas gathering and processing are large, natural gas marketing services and industrial end-users. In addition, substantially all of our natural gas and NGL sales are made at market-based prices. This concentration of credit risk may affect our overall credit risk in that these customers may be similarly affect by changes in economic, regulatory or other factors. Our standard gas and NGL sales contracts contain adequate assurance provisions which allow us to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment in a form satisfactory to us.

Interest Rate Risk. We are exposed to changes in interest rates as a result of our credit facility, which had weighted-average interest rate of 7.61% as of December 31, 2005. We had a total of $192.0 million of indebtedness outstanding under our credit facility as of the date hereof. Based on the amount of debt owed by us on December 31, 2005, the impact of a 1% increase in interest rates on this amount of debt would result in an increase in interest expense and a corresponding decrease in net income of approximately $2.0 million annually.

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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 five primary business lines include:


	•	Terminalling and storage services for petroleum products and by-products

	•	Natural gas gathering, processing and LPG distribution

	•	Marine transportation services for petroleum products and by-products

	•	Sulfur gathering, processing and distribution

	•	Fertilizer manufacturing and marketing

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


	*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 1990’s, 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.

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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 diesel fuel, lubricants, chemicals and supplies. The demand for these types of terminals, services and products is driven primarily by offshore exploration, development and production in the Gulf of Mexico. Offshore activity is greatly influenced by current and projected prices of oil and natural gas.

Marine Terminals. We own or operate 16 marine terminals along the Gulf Coast from Tampa, Florida to Corpus Christi, Texas. Our terminal assets are located at strategic distribution points for the products we handle and are in close proximity to our customers. Further, the location and composition of our terminals are structured to complement our other businesses and reflect our strategy to provide a broad range of integrated services in the handling and transportation of petroleum products and by-products. We developed our terminalling and storage assets by acquiring existing terminalling and storage facilities and then customizing and upgrading these facilities as needed to integrate the facilities into our petroleum product and by-product transportation network and to more effectively service customers. We expect to continue to acquire facilities, streamline their operations and customize and upgrade them as part of our growth strategy. We also continually evaluate opportunities to add services and increase access to our terminals to attract more customers and create additional revenues.

We are one of the largest operators of marine service terminals in the Gulf Coast region. These terminals are used to distribute and market lubricants and the full service terminals also provide shore bases for companies that are operating in the offshore exploration and production industry. Customers are primarily oil and gas exploration and production companies and oilfield service companies such as drilling mud 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. We also generate revenues through the distribution and marketing of lubricants. Lubricants are used in the operation of offshore drilling rigs, offshore production and transmission platforms, and various ships and equipment engaged in marine transportation. In addition, Martin Resource Management, through contractual arrangements, pays us for terminalling and storage of fuel oil at these terminal facilities.

We own or operate 16 marine terminals that we divide generally into three classes of terminals: (i) full service terminals, (ii) fuel and lubricant terminals and (iii) specialty petroleum terminals.

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

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

Terminal

Location

Acres

Tanks

Aggregate Capacity

Pelican Island

Galveston, Texas

51.3

57,200 Bbls.

Harbor Island(1)

Harbor Island, Texas

25.5

37,400 Bbls.

Freeport

Freeport, Texas

17.8

8,300 Bbls.

Port O’Connor(2)

Port O’Connor, Texas

22.8

7,000 Bbls.

Sabine Pass(3)

Sabine Pass, Texas

23.1

18,100 Bbls.

Cameron “East”(4)

Cameron, Louisiana

34.3

33,000 Bbls.

Cameron “West”(5)

Cameron, Louisiana

16.9

19,000 Bbls.


(1)	A portion of this terminal is located on land owned by a third party and leased under a lease that expires in January 2010 and can be extended through January 2015.

(2)	This terminal is located on land owned by a third party and leased under a lease that expires in March 2009 and can be extended through March 2014.

(3)	A portion of this terminal is located on land owned by a third party and leased under a lease that expires in September 2016 and can be renewed through September 2036.

(4)	This terminal is located on land owned by third parties and leased under leases that expire between March 2007 and June 2017.

(5)	This terminal is located on land owned by a third party and leased under a lease that expires in February 2008 and can be extended through February 2013.

Fuel and Lubricant Terminals. We own or operate five lubricant and fuel oil terminals, which we acquired in the Tesoro Marine asset acquisition. These terminals are located in the Gulf Coast region and provide storage and handling service for lubricants and fuel oil. We also distribute and market lubricants at these terminals.

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


Terminal	Location	Tanks		Aggregate Capacity

Amelia	Amelia, Louisiana		17		14,900 Bbls.
Berwick(1)	Berwick, Louisiana		4		24,900 Bbls.
Intra-Coastal City(2)	Intra-Coastal City, Louisiana		17		34,300 Bbls.
Fourchon(3)	Fourchon, Louisiana		7		30,100 Bbls.
Venice(4)	Venice, Louisiana		1		7,200 Bbls.


(1)	This terminal is located on land owned by third parties and leased under a lease that expires in September 2007 and can be extended through September 2017.

(2)	A portion of this terminal is located on land owned by a third party at which we throughput fuel oil pursuant to an agreement that expires in December 2006 and can be extended through December 2009.

(3)	This terminal is located on land owned by a third party at which we throughput lubricants and fuel oil pursuant to an agreement that expires in March 2007.

(4)	This terminal is currently out of service as a result of Hurricane Katrina.

Specialty Petroleum Terminals. We own or operate four terminal facilities providing storage and handling services for some or all of the following: asphalt, sulfur, sulfuric acid, fuel oil, crude oil and other petroleum products and by-products. Our specialty terminals have an aggregate storage capacity of approximately 1.5 million barrels. Each of these terminals has storage capacity for petroleum products and by-products and has assets to handle products transported by vessel, barge and truck. Our Tampa terminal is located on approximately 10 acres of land owned by the Tampa Port Authority and leased to us under a 10-year lease that expires on December 15, 2006. Our Stanolind terminal is located on approximately

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11 acres of land owned by Martin Resource Management and us and 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.

At our Tampa, Neches and Stanolind terminals, our customers are primarily large oil refining and natural gas processing companies. We charge a fixed monthly fee for the use of our facilities, based on the capacity of the applicable tank. We conduct a substantial portion of our terminalling and storage operations under long-term contracts, which enhances the stability and predictability of our operations and cash flow. We attempt to balance our short term and long term terminalling contracts in order to allow us to maintain a consistent level of cash flow while maintaining flexibility to earn higher storage revenues when demand for storage space increases. At our Ouachita County terminal, Cross operates the terminal under a long-term terminalling agreement whereby we receive a throughput fee. We also continually evaluate opportunities to add services and increase access to our terminals to attract more customers and create additional revenues.

The following is a summary description of our specialty marine terminals:

Aggregate

Terminal

Location

Tanks(3)

Capacity

Products

Description

Tampa(1)

Tampa, Florida

719,000 Bbls.

Asphalt, fuel oil and sulfuric acid

Marine terminal, loading/unloading for vessels, barges and trucks

Stanolind(2)

Beaumont, Texas

160,000 Bbls.

Asphalt and fuel oil

Marine terminal, loading/unloading for vessels, barges and trucks

Neches

Beaumont, Texas

500,400 Bbls.

Ammonia, asphalt, fuel oil, sulfuric acid and fertilizer

Marine terminal, loading/unloading for vessels, barges, railcars and trucks

Ouachita County

Ouachita County, Arkansas

77,500 Bbls.

Crude oil

Marine terminal, loading/unloading for vessels, barges and trucks


(1)	This terminal is located on land owned by the Tampa Port Authority and leased to us under a lease that expires in December 2006.

(2)	A portion of this terminal is located on land owned by Martin Resource Management and on land we own. We use marine terminal, loading and unloading, and other common use facilities owned by Martin Resource Management under a perpetual use, ingress-egress and utility facilities easement.

(3)	In addition to the tanks listed in the table we own one tank at our Tampa terminal and three tanks at the Stanolind terminal in connection with our sulfur business. Martin Resource Management owns two tanks at the Stanolind terminal.

Inland Terminals. We own or operate two inland terminals. At Mont Belvieu, Texas, we own a rail unloading terminal where we unload and measure petroleum by-products and transport these products via a half-mile pipeline to Enterprise Products Texas Operating L.P.’s LPG fractionator facility. Our fees for the use of this facility are based on the number of gallons unloaded at the terminal. In Channelview, Texas, we operate an inland terminal used for lubricant storage, packaging and distribution. This terminal is used as our central hub for lubricant distribution where we receive, package, and ship our lubricants to our terminals or directly to customers.

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The following is a summary description our inland terminals:


Terminal	Location	Aggregate Capacity	Products	Description

Channelview(1)	Houston, Texas	10,000 sq. ft. warehouse	Lubricants	Truck loading/unloading
Mont Belvieu	Mont Belvieu, Texas	20 rail car spaces	Propane-propylene mix	Rail car unloading


(1)	This terminal is located on land owned by a third party and leased to us under a lease that expires in May 2009 and can be extended to May 2014.

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 or 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 will 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 Gathering, Processing and LPG Distribution Segment*

LPG Industry Overview. LPG is a by-product of oil refining and natural gas processing. LPG consists of hydrocarbons that are vapors at normal temperatures and pressures but change to liquid at moderate pressures. The main constituent of LPG is propane, and LPG is often generally referred to as propane. Other LPG products include butanes and natural gasoline.

Propane is used as a heating fuel, an engine fuel, an industrial fuel and as a petrochemical feedstock in the production of ethylene and propylene. Butane is used as a petrochemical feedstock in the production of ethylene and butadiene (a key ingredient in synthetic rubber), as a blend stock for motor gasoline and to derive isobutane through isomerization. Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is used primarily as motor gasoline blend stock or petrochemical feedstock.

LPG Facilities. We purchase LPGs primarily from major domestic oil refiners and natural gas processors. We transport LPGs using Martin Resource Management’s land transportation fleet or by

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contracting with common carriers, owner-operators and railroad tank cars. We typically enter into annual contracts with independent retail 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 LPGs, including during times of peak demand, through:


	•	storage of propane 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 LPG facilities:


LPG Facility(1)	Location	Capacity	Description

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

Storage	Arcadia, Louisiana(2)	65 million gallons	Underground storage
	Hattiesburg, Mississippi(3)	4.2 million gallons	Underground storage
	Mt. Belvieu, Texas(3)	2.8 million gallons	Underground storage


(1)	In addition, under a throughput agreement whose initial term ends in October 2005, we are entitled to the sole access to and use of a truck loading and unloading and pipeline distribution terminal owned by Martin Resource Management and located at Mont Belvieu, Texas. This terminal facility has a storage capacity of 330,000 gallons.

(2)	We lease our underground storage at Arcadia, Louisiana from Martin Resource Management under a three-year product storage agreement, which is renewable on a yearly basis thereafter subject to a redetermination of the lease rate for each subsequent year.

(3)	We lease our underground storage at Hattiesburg, Mississippi and Mont Belvieu, Texas from third parties under one-year lease agreements, which we have renewed annually for more than 20 years.

Our above ground storage facilities have one or more 12,000 or 30,000 gallon storage tanks. We lease underground storage capacity of 120 million gallons in Arcadia, Louisiana from Martin Resource Management. We also lease 2.5 million gallons of underground storage in Mont Belvieu, Texas and 4.2 million gallons at Hattiesburg, Mississippi from third parties under one-year lease agreements. As a result of our and Martin Resource Management’s distribution system and storage capacity, we have the ability to buy and store large volumes of LPG that allow us to achieve product cost savings and avoid shortages during periods of tight supply.

Our LPG customers consist of retail propane distributors, industrial processors and refiners. For the year ended December 31, 2004, we sold approximately 43% of our LPG volume to independent retail propane distributors located in Texas and the southeastern United States and approximately 57% of our LPG volume to refiners and industrial processors.

LPG Competition. We compete with large integrated LPG producers and marketers, as well as small local independent marketers. LPGs compete primarily with natural gas, electricity and fuel oil as an energy source, principally on the basis of price, availability and portability.

LPG Seasonality. The level of LPG 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

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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 LPGs than the weather.

Although the LPG industry is subject to seasonality factors, such factors generally do not affect our natural gas gathering, processing and LPG distribution business because we do not consume LPGs. We generally maintain consistent margins in our natural gas gathering, processing and LPG distribution business because we attempt to pass increases and decreases in the cost of LPGs directly to our customers. We generally try to coordinate our sales and purchases of LPGs based on the same daily price index of LPGs in order to decrease the impact of LPG price volatility on our profitability.

Prism Gas Acquisition. On November 10, 2005 we acquired Prism Gas. See “Summary — Recent Developments — Prism Gas Acquisition.” Following this acquisition, Prism Gas is operated and reported as part of our natural gas gathering, processing and LPG distribution business segment, which has been expanded to include natural gas gathering and processing as well as the LPG distribution business described herein.

Prism Gas has ownership interests in over 330 miles of natural gas gathering 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 150 MMcfd capacity natural gas processing plant located in East Texas. The underlying assets are in two operating areas:


	East Texas


	•	The East Texas area assets consist of the Waskom Processing Plant, the McLeod Gathering System and other related gathering systems (collectively known as the East Texas Gathering System).


	-	Waskom Processing Plant — The Waskom Processing Plant, located in Harrison County in East Texas, currently has 150 MMcfd of processing capacity with full fractionation facilities. For the nine months ended September 30, 2005, inlet throughput and NGL fractionation averaged approximately 157 MMcfd and 7,300 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.

	-	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 nine months ended September 30, 2005, the McLeod Gathering System gathered approximately 7 MMcfd of natural gas. Prism Gas owns a consolidated 100% interest in this system.

	-	East Texas Gathering Systems — The East Texas Gathering Systems, located in Panola and Harrison Counties, Texas, are gathering systems built to deliver gas produced in these areas to market outlets. Prism Gas owns a consolidated 100% interest in this system.

The natural gas supply for the Waskom Processing Plant, the McLeod Gathering System and the East Texas Gathering Systems is derived primarily from natural gas wells located in the Cotton Valley formation of east Texas and northwest Louisiana. The Cotton Valley formation is one of the largest tight gas plays in the U.S. and extends over fourteen counties in East Texas and into northwest Louisiana. This formation has experienced significant levels of drilling activity in recent years with nearly 3,000 wells drilled since 1997. Improved technology, drilling applications and commodity prices have enhanced the economics of drilling in the Cotton Valley formation. This increase in drilling activity has provided us with access to newly developed natural gas supplies.

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Our primary suppliers of natural gas to the Waskom Processing Plant include BP and Devon, which collectively represented approximately 54% of the 129 MMcfd of natural gas supplied in 2004 and approximately 49% of the 157 MMcfd of natural gas supplied for the nine months ended September 30, 2005. A substantial portion (approximately 40%) 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 also receive a significant amount of trucked-in NGLs that are fractionated, treated and stabilized at the Waskom Processing Plant. The tightening of pipeline dew point specifications and access to local markets with high NGL demand has resulted in increased trucked-in NGL volumes at the Waskom Processing Plant. We recently completed a 2,000 bpd expansion to our 7,500 bpd fractionator and a 600 bpd expansion to our 600 bpd stabilizer to provide additional capacity for this increase in trucked-in NGL volumes. We also receive natural gas at the Waskom Processing Plant from our McLeod Gathering System.

There are currently three competing processing plants that operate within a 40-mile radius of our Waskom facility. We believe that the Waskom Processing Plant’s location, its fractionator and access to NGL outlets make it a very effective competitor. Our plant is located in Harrison County, Texas and is well positioned to capitalize on the growing east Texas and northwest Louisiana production base. Drilling activity in the Cotton Valley trend is moving north from the Panola-Harrison County line further into Harrison County. Our plant is the preferred gas plant for much of this new production due to its proximity to the increased drilling activity. In addition, the Waskom Processing Plant is the only plant in this area that has full fractionation capability with access to a strong local market for NGLs. Purchasers of NGLs fractionated at Waskom include Eastman Chemical Company, Aeropres Corporation and ANGUS Chemical Company. Prior to the Prism Gas acquisition, we were one of the largest purchasers of NGLs at the Waskom Processing Plant.

The Waskom Processing Plant’s processing contracts are predominately percent-of-liquids (POL) contracts, in which we retain a portion of the NGLs recovered as a processing fee. The plant also operates under percent-of-proceeds (POP) contracts in which we retain a portion of both the residue gas and the NGLs as payment for services. There is currently only one minor contract for processing on a keep-whole basis. We are not contractually required to process these keep-whole volumes and, therefore, only process natural gas related to this contract under profitable conditions. Prism Gas has not processed any keep-whole natural gas since May 2005, and we do not expect to process any in 2006.

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, of which we own a 50% operated interest with the remaining 50% owned by CenterPoint Energy Gas Processing, Inc. The processing contracts in the McLeod Gathering System are predominately percent-of-proceeds (POP) contracts. Natural gas gathered in the region surrounding the McLeod Gathering System has two primary outlets, including the Waskom Processing Plant. We believe that we have a competitive advantage as the McLeod Gathering System has lower fuel charges and line losses than the competing system. As drilling activity and demand for outlets for high nitrogen gas increases, we believe we are well positioned to further increase gathering volumes through the McLeod Gathering System.

Cotton Valley wells are now being drilled in the southern area served by the McLeod Gathering System. The new Cotton Valley wells that have recently been tied into the system are percent-of-liquids (POL) contracts with a small gathering fee. These contracts are typically lower margin, higher volume contracts. In this area, competition is geographic based with the McLeod Gathering System capturing wells that are located near the system and the competitor capturing wells that are near its system.

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The East Texas Gathering System was constructed in 2004 to tie producers into Gulf South Pipeline Gathering Company’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. We anticipate volumes to grow on these systems from continued drilling from the existing producers as well as additional contracts from new production which will likely be connected to this system on a fixed-fee basis.


	Gulf Coast


	•	The Gulf Coast area assets consist of the Fishhook Gathering System and the Matagorda Gathering System located offshore and onshore of the Texas Gulf Coast.


	-	Fishhook Gathering System — The Fishhook Gathering System, located in Jefferson County, Texas and offshore federal waters, gathers and transports gas in both offshore and onshore areas. For the nine months ended September 30, 2005, the Fishhook Pipeline gathered and transported approximately 37 MMcfd of natural gas. Prism Gas owns an unconsolidated 50% non-operating interest in Panther Interstate Pipeline Energy, LLC, 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 Gathering System — The Matagorda Gathering System, located in Matagorda County, Texas and offshore Texas state waters, gathers gas in both the offshore and onshore areas. For the nine months ended September 30, 2005, the Matagorda Gathering System gathered approximately 16 MMcfd of natural gas. Prism Gas owns an unconsolidated 50% non-operating interest in the Matagorda 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 Matagorda Gathering System and the Fishhook Gathering System gather and transport natural gas from Texas and federal waters of the Gulf of Mexico to onshore pipelines. The offshore natural gas supply for the Matagorda Gathering System is produced primarily from the Brazos Area blocks, which are near shore in the Texas state waters. Additionally, the Matagorda Gathering System includes onshore gathering in Matagorda, Wharton and Brazoria Counties. The Fishhook Pipeline gathers and transports natural gas principally from the eastern portion of the High Island Area which is further offshore.

The Matagorda Gathering System gathers gas from producers including Energy Partners, Noble Energy and American Coastal. Contracts for the offshore portion of the Matagorda Gathering System are a combination of fixed transportation fees plus a fixed margin. The contracts for the onshore portion of the Matagorda Gathering System are under either a fixed margin or a fixed transportation fee. Most of the onshore natural gas on this system is sold to Kinder Morgan under a term contract. Since 2001, drilling activity and production in this area has remained fairly steady. We expect drilling activity for traditional shelf targets will remain stable with upside potential for increased volumes from deep well natural gas prospects. 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 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.

The Fishhook Gathering System is located in federal waters offshore from Beaumont, Texas and gathers gas from producers including Forest Oil, Unocal and Seneca Resources. 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. As producers drill deeper targets near the Fishhook Gathering System, we expect increased volumes to be gathered and transported through this system. Contracts on this system are 100% fee-for-service contracts with both the maximum gathering fee and the maximum transmission fee stated in Panther Interstate Pipeline Energy, LLC’s FERC Gas Tariff, on file with the FERC. There are currently two competing pipelines in the area which

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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.


	*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, 12,000 miles of which 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 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 pushboat and one to three tank barges, depending upon the horsepower of the pushboat, the river or canal capacity and conditions, and customer requirements. Our offshore tows consist of one tugboat, with much greater horsepower than an inland pushboat, 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		15	20,000 bbl and under	Asphalt, crude oil, fuel oil, gasoline and sulfur(1)
Inland tank barges		21	20,000 - 30,000 bbl	Asphalt, crude oil, fuel oil and gasoline(1)
Inland pushboats		17	800 - 1,800 horsepower	N/A
Offshore tank barges		2	40,000 bbl and 95,000 bbl	Asphalt and fuel oil
Offshore tugboats		2	3,200 - 7,200 horsepower	N/A


(1)	One of our 15 inland tank barges with capacity of up to 20,000 bbl, and seven of our 21 inland tank barges with capacity of 20,000 to 30,000 bbl, are specialized and equipped to transport asphalt.

Our largest marine transportation customers include major and independent oil and gas refining companies, petroleum marketing companies and Martin Resource Management. We conduct our marine transportation services under spot contracts and under term contracts that typically range from one to 12 months in length.

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In order to maintain a balance of pricing flexibility and stable cash flow, we strive to maintain an appropriate mix of spot versus term contracts, based on current market conditions. We are currently a party to a charter agreement with Martin Resource Management for the use of four of our marine vessels on a spot-contract basis subject to the availability of such vessels at the time of Martin Resource Management’s request. The fees we charge Martin Resource Management are based on the then applicable market rates we charge third parties on a spot-contract basis. For the year ended December 31, 2004, we generated revenues of $8.6 million for the use of these four vessels.

Finally, in connection with the acquisition of marine services assets from Tesoro Marine Services, L.L.C. (“Tesoro Marine”), in December 2003 we entered into a new transportation services agreement with Martin Resource Management under which we provide marine transportation services. The per gallon fee we charge under this agreement is fixed during the first year of the agreement and is adjusted annually based on a price index. This fee was determined based on comparable market rates for arms-length negotiated fees. The agreement has a three-year term, which began in December 2003, and will automatically renew for successive one-year terms unless either party terminates the agreement by giving written notice to the other party at least 30 days prior to the expiration of the then-applicable term. In addition, within 30-days of the expiration of the then applicable term, both parties have the right to renegotiate the rate for the use of our vessels. If no agreement is reached as to a new rate by the end of the then-applicable term, the agreement will terminate.

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

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provide operational flexibility, safety, environmental and financial responsibility, adequate insurance and quality of service consistent with the customer’s own operations and policies. We operate a diversified asset base that, together with the services provided by Martin Resource Management, enables us to offer our customers an integrated distribution network consisting of transportation, terminalling, distribution and midstream logistical services for petroleum products and by-products.

In addition to competitors that provide marine transportation services, we also compete with providers of other modes of transportation, such as rail tank cars, tractor-trailer tank trucks and, to a limited extent, pipelines. We believe we offer a competitive advantage over rail tank cars and tractor-trailer tank trucks because marine transportation is a more efficient, and generally less expensive, mode of transporting petroleum products and by-products. For example, a typical two inland barge unit carries a volume of product equal to approximately 80 rail cars or 250 tanker trucks. Pipelines generally provide a less expensive form of transportation than marine transportation. However, pipelines are not able to transport most of the products we transport and are generally a less flexible form of transportation because they are limited to the fixed point-to-point distribution of commodities in high volumes over extended periods of time.

Seasonality. The demand for our marine transportation business is subject to some seasonality factors. Our asphalt shipments are generally higher during April through November when weather allows for efficient road construction. However, demand for marine transportation of sulfur, fuel oil and gasoline is directly related to production of these products in the oil refining and natural gas processing business, which is fairly stable.


	*Sulfur Segment*

Industry Overview. Sulfur is a natural element and is required to produce a variety of industrial products. In the United States, approximately 11 million tons of sulfur is consumed annually, with the Tampa, Florida area being the largest single market. Currently, all sulfur produced in the United States is “recovered sulfur,” or sulfur that is a by-product from oil refineries and natural gas processing plants. Sulfur production in the United States is principally located along the Gulf Coast, along major inland waterways and in some areas of the western United States.

Sulfur is an important plant nutrient and is used in the manufacture of phosphate fertilizers. Approximately 53% of worldwide sulfur consumption is currently used for phosphate fertilizers, with the balance used for industrial purposes. The primary application of sulfur in fertilizers occurs in the form of sulfuric acid. Burning sulfur creates sulfur dioxide, which is subsequently oxidized and dissolved in water to create sulfuric acid. The sulfuric acid is then combined with phosphate rock to make phosphoric acid, the base material for most high-grade phosphate fertilizers.

In addition to agricultural applications, sulfur (usually in the form of sulfuric acid) is essential for manufacturing pharmaceuticals, paper, chemicals, paint, steel, petroleum and other products. Sulfuric acid is the most commonly produced chemical in the world.

Our Operations and Products. Our new sulfur segment was established in April 2005, as a result of the acquisition of the Bay Sulfur assets and the beginning of construction of a sulfur priller at our Neches facility in Beaumont, Texas. The Sulfur prilling assets we acquired from Bay Sulfur 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. We are also constructing a sulfur priller and ship loading system at our Neches facility in Beaumont, Texas. When completed, this facility will have the capacity to process approximately 2,000 metric tons of molten sulfur per day. Our sulfur prilling facilities provide refiners with an alternative market for the sale of their residual sulfur.

On July 15, 2005, we acquired the remaining partnership interests in CF Martin Sulphur not previously owned by us from CF Industries, Inc. and certain affiliates of Martin Resource Management for

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$18.9 million. Prior to the acquisition, CF Martin Sulphur was managed and operated by its general partner which was equally owned and controlled by Martin Resource Management and CF Industries. We now control the management of CF Martin Sulphur and will conduct its day to day operations. CF Martin Sulphur is now a wholly owned partnership which is included in our consolidated financial statements and included in the financial presentation of our sulfur segment.

As the owner of CF Martin Sulphur, 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 2004, CF Martin Sulphur handled over 1.9 million long tons of sulfur. In the U.S. recovered sulfur is mainly kept in liquid form from production to usage at a temperature of approximately 275 degrees Fahrenheit. Because of the temperature requirement, the sulfur industry uses specialized equipment to store and transport molten sulfur. We have the necessary transportation and storage assets and expertise to handle the unique requirements for transportation and storage of molten sulfur for domestic customers.

The term of our commercial contracts typically range from one to five years in length. The prices in such contracts are usually tied to a published market indicator and fluctuate, typically quarterly, 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 that range from three to five years in duration.

Our Sulfur Facilities. We lease approximately 186 railcars equipped to transport molten sulfur. We also have 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 pushboat		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 also own the following tanks as part of our molten sulfur business:

Terminal

Location

Tanks

Total Aggregate Capacity

Products Stored

Tampa

Tampa, Florida

16,000 long tons

Molten sulfur

Stanolind

Beaumont, Texas

46,500 long tons

Molten sulfur

Competition. Eight 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 or lease two of the five vessels currently used to transport molten sulfur between Tampa, Florida and United States ports on the Gulf of Mexico. 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.


	*Fertilizer Segment*

Industry Overview. Fertilizers are manufactured chemicals containing nutrients known to improve the fertility of soils. Nitrogen, phosphorus, potassium and sulfur are the four most important nutrients for crop growth. These nutrients are found naturally in soils. However, soils used for agriculture become depleted of these nutrients and frequently require fertilizers rich in these essential nutrients to restore fertility. The Fertilizer Institute has estimated that the earth’s soil contains less than 20% of organic plant nutrients needed to meet worldwide food production needs. As a result, we believe mineral fertilizer production will continue to be an important industrial market.

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The fertilizer market is primarily driven by agricultural demand. Worldwide consumption of mineral fertilizers grew from 117 million tons in 1980 to 138 million tons in 1990, and remained relatively flat from 1990 to 2000. Despite the relative stagnation in the past ten years, we expect the worldwide fertilizer market to grow over the next two decades. The United Nations has estimated that the world population will reach 7.7 billion by 2020, an increase of 35% from 5.7 billion in 1995. The United Nations also has estimated that the world population in 2020 will require an estimated 40% more grain than the world population in 1999 and that most of this increase in production will need to be produced on existing cultivated land through increased yield per acre. Consequently, we expect agricultural demand for fertilizer products to increase to support the greater agricultural output requirements for the increase in population.

Industrial sulfur products are used in a wide variety of industries. For example, these products are used in power plants, paper mills, auto and tire manufacturing plants, food processing plants, road construction, cosmetics and pharmaceuticals. The largest consumers of industrial sulfur products are power plants, paper mills and rubber products manufacturers.

Our Operations and Products. We entered the 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 at the companies, and to integrate each of the businesses into our business. These acquisitions have subsequently increased the profitability of our fertilizer business.

Fertilizer and related sulfur products are a natural extension of our business because of our access to sulfur and our distribution capabilities. This business allows us to leverage the sulfur segment of our business. Our annual fertilizer and industrial sulfur products sales have grown from approximately 62,000 tons in 1997 to approximately 146,000 tons in 2004 as a result of acquisitions and internal growth.

We manufacture and market the following 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 ammonium sulfate, 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.

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	•	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 Fertilizer Plants. The following is a summary description of our fertilizer plants:


Facility	Location	Capacity	Description

Two fertilizer plants	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
Industrial sulfur blending plant	Texarkana, Texas	18,000 tons/year	Emulsified sulfur production
Fertilizer Plant	Beaumont, Texas	70,000 tons/year	Liquid sulfur fertilizer production

We previously owned a fertilizer plant in Maricopa, Arizona which we sold in February, 2005. In May 2003, we experienced a casualty loss caused by a lightening strike at one of our Odessa, Texas sulfur and fertilizer facilities. We used the insurance proceeds to upgrade our equipment at this facility.

In the United States, fertilizer is generally sold to farmers through local dealers. These dealers are typically owned and supplied by much larger wholesale distributors. We sell primarily to these wholesale distributors, as well as to a small number of independent dealers throughout the United States. Our industrial sulfur products are marketed primarily in the eastern United States, where many paper manufacturers and power plants are located.

Our fertilizer products are sold in accordance with our price lists that vary from state to state. We update our price lists periodically to make seasonal pricing adjustments. If necessary, we adjust our price lists more frequently to maintain competitive pricing. These products are sold at negotiated prices, generally set on an annual basis. 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.

Competition. We compete with several other large fertilizer and sulfur products manufacturers. However, we believe our close proximity to our customers is a competitive advantage for us. Because our manufacturing plants are located close to our customer base, we are able to save on freight costs and respond quickly to customer requests, and we also believe we have greater insight about local market conditions. Additionally, we believe the development of our sulfur business affords us a secure and reliable source of sulfur materials.

Seasonality. Sales of our agricultural fertilizer are partly seasonal as a result of increased demand during the growing season. Sales of our industrial sulfur-based products, however, are generally consistent throughout the year. In 2004, approximately 10% of our product sales volumes were to industrial users.

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, or 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, or the Pooling Agreement, through which approximately 95% of the world’s commercial shipping tonnage is reinsured through a group reinsurance policy. With regard to collision coverage, the first $1.0 million of coverage is insured by our

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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 pollution claims, our insurance covers up to $1.0 billion of liability per accident or occurrence. 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

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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 Mont Belvieu terminal we use is located in an EPA-designated ozone non-attainment area, referred to as the Houston-Galveston non-attainment area, which is now subject to a new, EPA-adopted 8-hour standard for complying with the national standard for ozone. Categorized as being in “moderate” non-attainment for ozone, the Houston-Galveston non-attainment area has until 2010 to achieve compliance with this new standard, which almost certainly will require the adoption of more restrictive regulations in this non-attainment area for the issuance of air permits for new or modified facilities. In addition, existing sources of air emissions in the Houston-Galveston area are already subject to stringent emission reduction requirements. Failure to comply with applicable air statutes or regulations may lead to the assessment of

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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.


	*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 stormwater runoff and that applicable facilities develop and implement plans for the management of stormwater runoff (referred to as stormwater pollution prevention plans or “SWPPPs”) as well as for the prevention and control of oil spills (referred to as spill prevention, control and countermeasure or “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 are currently reviewing our SPCC plans and, where necessary, are amending such plans to comply with applicable regulations adopted by EPA in 2002. Current EPA deadlines require us to complete amendment of these SPCC plans by February 17, 2006 and, as applicable, implement these amendments by August 18, 2006; however, the EPA has recently proposed new rules that could extend these amendment and implementation deadlines to October 31, 2007. We believe that compliance with the conditions of such permits and plans will not have a material effect on our operations.

On August 7, 2000, a spill of molten sulfur occurred at our Stanolind terminal near Beaumont, Texas, which at the time was owned and operated by Martin Gas Sales LLC, a wholly-owned subsidiary of Martin Resource Management. Martin Gas Sales LLC has since changed its name to Martin Product Sales, LLC. The Texas Department of Health and Texas Natural Resource Conservation Commission (the predecessor agency to the present-day Texas Commission on Environmental Quality) investigated the spill and its clean-up. These agencies found that there was no impact on public health, and that there was no reason to remove the solidified sulfur from the river bottom. However, the United States attorney in Beaumont, Texas, initiated an investigation under the criminal provisions of the Clean Water Act. To avoid protracted litigation and possible criminal claims against employees, Martin Product Sales agreed to plead guilty to a single felony violation of the federal Clean Water Act and was sentenced to pay a $50,000 fine. As part of its plea agreement with the United States, Martin Product Sales also agreed to implement a remedial program at our Stanolind terminal and our sulfur loading facility in Tampa, Florida. Martin Product Sales instituted the remedial program as of March 1, 2002, and we believe that it has been substantially implemented, although it must remain in effect for five years. Martin Product Sales does not have any contracts with the United States government that might be affected by a debarment or listing proceeding, and the United States Attorney’s Office has agreed to inform any agency initiating a debarment or listing proceeding of the implementation of the remedial program. A previous criminal conviction, however, may result in increased fines and other sanctions if Martin Product Sales is subsequently convicted or pleads guilty to a similar offense in the future. Martin Resource Management will indemnify us under the omnibus agreement for any losses we suffer within five years from November 6, 2002, the date of our initial public offering, that relate to or result from, this event.


	*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

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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, pushboats, 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-flag vessels be manned by United States citizens. Foreign-flag seamen generally receive lower wages and benefits than those received by United States citizen seamen. This requirement significantly increases operating costs of United States-flag vessel operations compared to foreign-flag 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-flag vessel owners. The United States Coast Guard and American Bureau of Shipping maintain the most stringent regime of vessel inspection in the world, which tends to result in higher regulatory compliance costs for United States-flag 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

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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 pushboats, 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 pushboats 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 pushboats, tugboats or tank barges.


	*Regulations Affecting Natural Gas Transmission, Processing and Gathering*

We own a 50% non-operating interest in Panther Interstate Pipeline Energy, LLC. Panther Interstate Pipeline Energy, LLC’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 (the “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 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.

On August 8, 2005, President Bush signed into law the Domenici-Barton Energy Policy Act of 2005 (the “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, the 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 you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to oil and natural gas transportation capacity. In addition, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of regular litigation, so, in such a circumstance, the classification and regulation of some of our gathering facilities and intrastate transportation pipelines may be subject to change based on future determinations by FERC and the courts.

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Other state and local regulations also affect our 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.


	•	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 337 individuals who provide direct support to our operations. None of these employees are represented by labor unions. To date, Martin Resource Management has not experienced any work stoppages. Martin Resource Management hired 31 former Prism Gas employees in connection with the Prism Gas acquisition. Of these 31 employees, 6 are in managerial positions and 25 are in administrative and operational positions. These employees support the Prism Gas operations. Martin Resource Management hired 12 former A&A Fertilizer employees in connection with the A&A Fertilizer acquisition all of whom are in operational positions. These employees support the A&A Fertilizer operations.

Litigation

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.

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MANAGEMENT

Management of Martin Midstream Partners L.P.

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

Three directors of our general partner serve on a conflicts committee to review specific matters that the directors believe may involve conflicts of interest. The conflicts committee determines if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates and must meet the independence standards to serve on an audit committee of a board of directors established by Nasdaq and applicable securities laws. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders. In addition, the members of the conflicts committee also serve on an audit committee that reviews our external financial reporting, recommends engagement of our independent auditors and reviews procedures for internal auditing and the adequacy of our internal accounting controls. The members of the conflicts committee also serve on the compensation committee, which oversees compensation decisions for the officers of our general partner as well as the compensation plans described below. The current members of our conflicts committee, audit committee, nominating committee and compensation committee are our outside directors, John P. Gaylord, C. Scott Massey and Howard Hackney, all of whom meet the independence standards established by Nasdaq.

We are managed and operated by the directors and officers of our general partner. All of our operational personnel are employees of Martin Resource Management. All of the officers of our general partner will spend a substantial amount of time managing the business and affairs of Martin Resource Management and its other affiliates. These officers may face a conflict regarding the allocation of their time between our business and the other business interests of Martin Resource Management. Our general partner intends to cause its officers to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs.

Directors and Executive Officers of Martin Midstream GP LLC

The following table shows information for the directors and executive officers of our general partner. Executive officers and directors are elected for one-year terms.


Name	Age		Position with the General Partner

Ruben S. Martin		54	President, Chief Executive Officer and Director
Robert D. Bondurant		47	Executive Vice President and Chief Financial Officer
Donald R. Neumeyer		58	Executive Vice President and Chief Operating Officer
Wesley M. Skelton		58	Executive Vice President, Chief Administrative Officer and Controller
Scott D. Martin		40	Director(1)
John P. Gaylord		44	Director
C. Scott Massey		53	Director
Howard Hackney		65	Director


(1)	Scott D. Martin also serves as General Manager, Marine Operations of our general partner.

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Ruben S. Martin serves as President, Chief Executive Officer and a member of the Board of Directors of our general partner. Mr. Martin has served in such capacities since June 2002. Mr. Martin has served as President of Martin Resource Management since 1981 and has served in various capacities within the company since 1974. Mr. Martin has also served as President of CF Martin Sulphur, LLC, since its inception in 2000. Mr. Martin and Scott D. Martin, see below, are brothers. Mr. Martin holds a bachelor of science degree in industrial management from the University of Arkansas.

Robert D. Bondurant serves as Executive Vice President and Chief Financial Officer of our general partner. Mr. Bondurant has served in such capacities since June 2002. Mr. Bondurant joined Martin Resource Management in 1983 as Controller and subsequently was appointed Chief Financial Officer and a member of its Board of Directors in 1990. Mr. Bondurant served in the audit department at Peat Marwick, Mitchell and Co from 1980 to 1983. Mr. Bondurant is also the Chief Financial Officer and Secretary of CF Martin Sulphur, LLC. Mr. Bondurant holds a bachelor of business administration degree in accounting from Texas A&M University and is a Certified Public Accountant, licensed in the state of Texas.

Donald R. Neumeyer serves as Executive Vice President and Chief Operating Officer of our general partner. Mr. Neumeyer has served in such capacities since June 2002. Mr. Neumeyer joined Martin Resource Management in March of 1982 as an operations manager. He has served as Vice President of Operations and Chief Operating Officer since 1983 and as a Director since 1990. From 1978 to 1982 Mr. Neumeyer was employed by Crystal Oil Company of Shreveport, Louisiana as Vice President of Marketing, Refining and Gas Processing. From 1970 to 1978 Mr. Neumeyer was employed by Mobil Oil Corporation in various capacities within its pipeline, crude oil, and gas liquid operations. Mr. Neumeyer holds a bachelor of science in mechanical engineering from Southern Methodist University in Dallas and is a registered professional engineer in the state of Texas.

Wesley M. Skelton serves as Executive Vice President, Controller and Chief Administrative Officer of our general partner. Mr. Skelton has served in such capacities since June 2002. Mr. Skelton joined Martin Resource Management in 1981 and has served as Chief Administrative Officer since 1981 and a Director since 1990. Prior to joining Martin Resource Management, Mr. Skelton served as Treasurer of First Federal Savings & Loan, Marshall, Texas from January 1977 through January 1981 and was employed by Peat Marwick, Mitchell & Co. from August 1973 through January 1977. Mr. Skelton holds a bachelor of business administration degree from the University of Texas, and is a Certified Public Accountant licensed in the state of Texas.

Scott D. Martin serves as a member of the Board of Directors and as General Manager, Marine Operations of our general partner. Mr. Martin has served in such capacities since June 2002. Mr. Martin has served as a Director of Martin Resource Management since 1990. He has held a variety of positions in marketing, transportation, terminalling, finance, operations and business development with Martin Resource Management since 1980. Mr. Martin and Ruben S. Martin, see above, are brothers. Mr. Martin holds a bachelor of science degree in business administration from University of Arkansas, where he is a member of the Walton Business School advisory board.

John P. Gaylord serves as a member of the Board of Directors of our general partner. Mr. Gaylord has served as a Director since June 2002. Mr. Gaylord has served as the President of Jacintoport Terminal Company since 1992. He originally joined Jacintoport Terminal Company when it was founded in 1989 as Vice President of Finance. Jacintoport Terminal Company is the general partner of Chartco Terminal L.P. which has terminalling and storage operations in Houston, Texas. Mr. Gaylord holds a bachelor of arts degree from Texas Christian University and a masters of business administration degree from Southern Methodist University.

C. Scott Massey serves as a member of the Board of Directors of our general partner. Mr. Massey has served as a Director since June 2002. Mr. Massey has been self employed as a Certified Public Accountant since 1998. From 1977 to 1998, Mr. Massey worked for KPMG Peat Marwick, LLP in

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various positions, including, most recently, as a Partner in the firm’s Tax Practice — Energy, Real Estate, Timber from 1986 to 1998. Mr. Massey received a bachelor of business administration degree from the University of Texas at Austin and a juris doctor degree from the University of Houston. Mr. Massey is a Certified Public Accountant, licensed in the states of Louisiana and Texas.

Howard Hackney serves as a member of the Board of Directors of our general partner. Mr. Hackney has served as a Director since May 2005. Mr. Hackney currently serves as a director of Texas Bank and Trust of Longview, Texas and Federal Home Loan Bank of Dallas, Texas. His past experience includes service as the President of Texas Bank and Trust of Longview, Texas, President of Bank One of Longview, Texas, President and a director of Merchant and Planters National Bank of Sherman, Texas and Executive Vice President and a director of Capital National Bank of Houston, Texas. Mr. Hackney received a BBA and MBA from Southern Methodist University.

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MATERIAL TAX CONSIDERATIONS

This section addresses all of the material tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, except as otherwise indicated, is the opinion of Baker Botts L.L.P., counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of United States federal income tax law that are addressed in this section. This section is based upon current provisions of the Internal Revenue Code, existing regulations, proposed regulations to the extent noted and current administrative rulings and court decisions, all of which are subject to change. Changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Martin Midstream Partners L.P. and our operating partnership.

No attempt has been made in this section to comment on all federal income tax matters affecting us or the unitholders. Moreover, this section focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), real estate investment trusts (REITs) or mutual funds. Accordingly, we urge each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.

All statements of law and legal conclusions, but not statements of facts, contained in this section, except as otherwise indicated, are the opinions of Baker Botts L.L.P. Such opinions are based on the accuracy and completeness of facts described in this prospectus supplement and in the accompanying prospectus and representations made by us to Baker Botts L.L.P. Baker Botts L.L.P. has not undertaken any obligation to update its opinions discussed in this section after the date of this prospectus supplement.

No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. An opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions expressed in this section may not be sustained by a court if challenged by the IRS. Any such challenge by the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any dispute with the IRS will be borne directly or indirectly by the unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

For the reasons described below, Baker Botts L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues:


	(1) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “Material Tax Considerations — Tax Consequences of Unit Ownership — Treatment of Short Sales”);

	(2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “Material Tax Considerations — Disposition of Common Units — Allocations Between Transferors and Transferees”);

	(3) whether our method for depreciating Section 743 adjustments is sustainable (please read “Material Tax Considerations — Tax Consequences of Unit Ownership — Section 754 Election”); and

	(4) whether assignees of common units who fail to execute and deliver transfer applications will be treated as partners for federal income tax purposes (please read “Material Tax Considerations — Limited Partner Status”).

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Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable unless the amount of cash distributed is in excess of the partner’s adjusted basis in his partnership interest.

Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the marketing (including sales of propane to retail customers or end users), transportation, storage and processing of crude oil, natural gas and products thereof, and certain other “natural resources” and products, including sulfur, sulfur products and fertilizer. 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 assets held for the production of income that otherwise constitutes qualifying income. We estimate that, as of the date of this prospectus supplement, at least 90% of our gross income for the current calendar year is qualifying income. In reliance upon facts provided by Martin Resource Management, us and our general partner concerning the sources and amounts of gross income attributable to our businesses through the month-end prior to the date of this prospectus, together with the representation that the composition of such gross income remained materially unchanged through the date of this prospectus supplement, and based on applicable legal authority, Baker Botts L.L.P. is of the opinion that at least 90% of our gross income for the current calendar year as of the date of this prospectus supplement constitutes qualifying income.

No ruling has been or will be sought from the IRS and the IRS has made no determination of our status as a partnership for federal income tax purposes, the status of the operating partnership for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Baker Botts L.L.P., based upon the Internal Revenue Code, Treasury Regulations, published revenue rulings and court decisions and the representations and assumptions described below, that as of the date of this prospectus supplement Martin Midstream Partners L.P. will be classified as a partnership and our operating partnership will be disregarded as an entity separate from Martin Midstream Partners L.P. for federal income tax purposes.

In rendering its opinion, Baker Botts L.L.P. has relied on certain assumptions, and on factual representations made by us and our general partner. Such assumptions and representations are:


	•	Neither we nor our operating partnership has elected or will elect to be treated as a corporation; and

	•	For each taxable year, at least 90% of our gross income has been and will be income from sources that Baker Botts L.L.P. has opined, or will opine, is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.

We intend to monitor our income on a continuing basis and to manage our operations in subsequent taxable years with the objective to assure, although we cannot completely assure, that the ratio of our qualifying income to our total gross income will remain at 90% or above for each such taxable year.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

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If we were taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to the unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The remainder of this section is based on Baker Botts L.L.P.’s opinion that Martin Midstream Partners L.P. will be classified as a partnership and our operating partnership will be disregarded as an entity separate from Martin Midstream Partners L.P. for federal income tax purposes.

Limited Partner Status

Unitholders who have become limited partners of Martin Midstream Partners L.P. will be treated as partners of Martin Midstream Partners L.P. for federal income tax purposes. Also:


	•	assignees who have executed and delivered transfer applications, and are awaiting admission as limited partners; and

	•	unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units,

will be treated as partners of Martin Midstream Partners L.P. for federal income tax purposes. Because there is no direct authority dealing with the status of assignees of common units who are entitled to execute and deliver transfer applications and become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, counsel is unable to opine that such persons are partners for federal income tax purposes. If not partners, such persons will not be eligible for the federal income tax treatment described in this discussion. Furthermore, a purchaser or other transferee of common units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record holders of common units unless the common units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those common units.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “Material Tax Considerations — Tax Consequences of Unit Ownership — Treatment of Short Sales.”

Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their status as partners in Martin Midstream Partners L.P. for federal income tax purposes.

Tax Consequences of Unit Ownership


	*Flow-through of Taxable Income*

We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether cash distributions are received by him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution from us. Each unitholder will be required to include in income his allocable

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share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year.


	*Treatment of Distributions*

Our distributions to a unitholder generally will not be taxable to the unitholder for federal income tax purposes to the extent of his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “Material Tax Considerations — Disposition of Common Units.” To the extent our distributions cause a unitholder’s “at risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “Material Tax Considerations — Tax Consequences of Unit Ownership — Limitations on Deductibility of Losses.”

Any reduction in a unitholder’s share of our liabilities for which no partner, including our general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution of cash to that unitholder. A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture and/or substantially appreciated “inventory items,” both as defined in the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having been distributed his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis for the share of Section 751 Assets deemed relinquished in the exchange.


	*Ratio of Taxable Income to Distributions*

We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through December 31, 2007, will be allocated an amount of federal taxable income for that period that will be approximately 20% or less of the cash distributed with respect to that period. We anticipate that after the taxable year ending December 31, 2007, the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower, and any differences could be material and could materially affect the value of the common units.

For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be greater, and perhaps substantially greater, than 20% with respect to the period described above if:


	•	gross income from operations exceeds the amount required to make the minimum quarterly distribution on all units, yet we only distribute the minimum quarterly distribution on all units, or

	•	we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or

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		amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.


	*Basis of Common Units*

A unitholder’s initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A limited partner will have no share of our debt that is recourse to our general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “Material Tax Considerations — Disposition of Common Units — Recognition of Gain or Loss.”


	*Limitations on Deductibility of Losses*

The deduction by a unitholder of his share of our losses will be limited to the tax basis in his common units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by five or fewer individuals or some tax-exempt organizations, to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause his at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable to the extent that his tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of his common units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by any amount of money he borrows to acquire or hold his common units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the common units for repayment. A unitholder’s at risk amount will increase or decrease as the tax basis of the unitholder’s common units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

The passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or investments in other publicly traded partnerships, or salary or active business income. Similarly, a unitholder’s share of our net income may be offset by our passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.

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	*Limitations on Interest Deductions*

The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:


	•	interest on indebtedness properly allocable to property held for investment;

	•	our interest expense attributed to portfolio income; and

	•	the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit.

Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that net passive income from a publicly traded partnership constitutes investment income for purposes of the limitations on the deductibility of investment interest. In addition, the unitholder’s share of our portfolio income will be treated as investment income.


	*Entity-Level Collection*

If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.


	*Allocation of Income, Gain, Loss and Deduction*

In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss for the entire year, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to our general partner.

Specified items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of property contributed or deemed contributed to us, referred to in this discussion as “Contributed Property.” The effect of these allocations to a unitholder purchasing common units in this offering essentially will be the same as if the tax basis of our assets were equal to their fair market value at the time of this offering. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner to eliminate the negative balance as quickly as possible.

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Baker Botts L.L.P. is of the opinion that, with the exception of the issues described in “Material Tax Considerations — Tax Consequences of Unit Ownership — Section 754 Election” and “Material Tax Considerations — Disposition of Common Units — Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.


	*Treatment of Short Sales*

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 a partner for those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:


	•	any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

	•	any cash distributions received by the unitholder as to those units would be fully taxable; and

	•	all of these distributions would appear to be ordinary income.

Baker Botts L.L.P. 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 should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read “Material Tax Considerations — Disposition of Common Units — Recognition of Gain or Loss.”


	*Alternative Minimum Tax*

Each unitholder will be required to take into account his share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. We do not expect to generate significant tax preference items or adjustments. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in common units on their liability for the alternative minimum tax.


	*Tax Rates*

In general, the highest effective United States federal income tax rate for individuals for 2005 is 35% and the maximum United States federal income tax rate for net capital gains of an individual for 2005 is 15% if the asset disposed of was held for more than 12 months at the time of disposition.


	*Section 754 Election*

We made the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election generally permits us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other partners. For purposes of this discussion, a partner’s inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.

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or the 150% declining balance method. In addition, the holder of a common unit (other than a common unit that is sold in this offering) may be entitled by reason of a Section 743(b) adjustment to amortization deductions in respect of property to which the traditional method of eliminating differences in “book” and tax basis applies. It would not be possible to maintain uniformity of units if this requirement were literally followed; therefore under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these Treasury Regulations. Please read “Material Tax Considerations — Tax Treatment of Operations” and “Material Tax Considerations — Uniformity of Units.”

Although Baker Botts L.L.P. is unable to opine as to the validity of this approach because there is no clear authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized book-tax disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of the property, or treat that portion as non-amortizable to the extent attributable to property the common basis of which is not amortizable. This method is consistent with the regulations under Section 743 of the Internal Revenue Code but is arguably inconsistent with Treasury Regulation Section 1.167(c)-l(a)(6). Although Treasury Regulation Section 1.167(c)-1(a)(6) is not expected to directly apply to a material portion of our assets, if we determine that our position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. In addition, if purchasers of common units (other than those that are sold in this offering) are entitled to different treatment in respect of property as to which we are using the traditional method of eliminating differences in “book” and tax basis, we may also take a position that results in lower annual deductions to some or all of our unitholders than might otherwise be available. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “Material Tax Considerations — Disposition of Common Units — Recognition of Gain or Loss.” Please read “Material Tax Considerations — Tax Treatment of Operations” and “Material Tax Considerations — Uniformity of Units.”

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have a higher tax basis in his share of our assets for purposes of computing, among other items, his depreciation and depletion deductions and his share of any gain or loss on a sale of our assets. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election.

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resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations


	*Accounting Method and Taxable Year*

We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read “Material Tax Considerations — Disposition of Common Units — Allocations Between Transferors and Transferees.”


	*Tax Basis, Depreciation and Amortization*

The tax basis of our assets is used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to this offering will be borne by our general partner, its affiliates and our other unitholders as of that time. Please read “Material Tax Considerations — Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets are placed in service. We are not entitled to any amortization deductions with respect to any goodwill conveyed to us on formation. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure, or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a partner who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all, of those deductions as ordinary income upon a sale of his interest in us. Please read “Material Tax Considerations — Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction” and “Material Tax Considerations — Disposition of Common Units — Recognition of Gain or Loss.”

The costs incurred in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.


	*Valuation and Tax Basis of Our Properties*

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates of basis are subject to challenge and

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will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units


	*Recognition of Gain or Loss*

Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held more than 12 months will generally be taxed at a maximum rate of 15%. However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the regulations.

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partnership interest (one in which gain would be recognized if it were sold, assigned or terminated at its fair market value) if the taxpayer or related persons enter(s) into:


	•	a short sale;

	•	an offsetting notional principal contract; or

	•	a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.


	*Allocations Between Transferors and Transferees*

In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus supplement as the Allocation Date. However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

It is uncertain, due to the absence of interpretative authority, whether this method conforms to the requirements of applicable Treasury Regulations. Accordingly, Baker Botts L.L.P. is unable to opine on the validity of this method of allocating income and deductions between unitholders. If this method is disallowed or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between unitholders to conform to a method permitted under future Treasury Regulations.

A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.


	*Notification Requirements*

A unitholder who sells any of his units, other than through a broker, generally is required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A person who purchases units from a unitholder is required to notify us in writing of that purchase within 30 days after purchase. We are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker.


	*Constructive Termination*

We will be considered to have been terminated for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. A constructive termination results in the closing of our taxable year for all unitholders. 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 result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. We would be required to make new tax elections after a termination, including

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a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “Material Tax Considerations — Tax Consequences of Unit Ownership — Section 754 Election.”

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, we will withhold at the highest applicable tax rate from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8 or applicable substitute form in order to obtain credit for these withholding taxes.

In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which are effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

Under a ruling of the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent that this gain is effectively connected with a United States trade or business of the foreign unitholder. Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned 5% or less in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.

Administrative Matters


	*Information Returns and Audit Procedures*

We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and

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deduction for our preceding taxable year. In preparing this information, which will not be reviewed by Baker Botts L.L.P., we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, regulations or administrative interpretations of the IRS. Neither we nor Baker Botts L.L.P. can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. Our partnership agreement names Martin Midstream GP LLC as our Tax Matters Partner.

The Tax Matters Partner has made and will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.


	*Nominee Reporting*

Persons who hold an interest in us as a nominee for another person are required to furnish to us:


	(a) the name, address and taxpayer identification number of the beneficial owner and the nominee;

	(b) whether the beneficial owner is:


	(1) a person that is not a United States person;

	(2) a foreign government, an international organization or any wholly-owned agency or instrumentality of either of the foregoing; or

	(3) a tax-exempt entity;


	(c) the amount and description of units held, acquired or transferred for the beneficial owner; and

	(d) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

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own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.


	*Accuracy-related Penalties*

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

A substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:


	(1) for which there is, or was, “substantial authority;” or

	(2) as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

More stringent rules apply to “tax shelters,” a term that in this context does not appear to include us. If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns to avoid liability for this penalty.

A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 200% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 400% or more than the correct valuation, the penalty imposed increases to 40%.


	*Reportable Transactions*

If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produced certain kinds of losses in excess of $2 million. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read “— Information Returns and Audit Procedures.” Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following provisions:


	•	accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “— Accuracy-related Penalties,”

	•	for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability and

	•	in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any “reportable transactions.”

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State, Local, Foreign and Other Tax Considerations

In addition to federal income taxes, you will be subject to other taxes, including state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder is urged to consider their potential impact on his investment in us. We will own property or do business in Alabama, Arkansas, California, Georgia, Florida, Illinois, Louisiana, Mississippi, Texas and Utah. We may also own property or do business in other state or foreign jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements.

In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “Material Tax Considerations — Tax Consequences of Unit Ownership — Entity-Level Collections.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as United States federal tax returns, that may be required of him. Baker Botts L.L.P. has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

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INVESTMENT IN MARTIN MIDSTREAM PARTNERS L.P. BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of Employee Retirement Income Security Act of 1974, as amended (referred to as “ERISA”), and restrictions imposed by Section 4975 of the Internal Revenue Code. For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:


	(a) whether the investment is prudent under Section 404(a)(1)(B) of ERISA;

	(b) whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(l)(C) of ERISA; and

	(c) whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return.

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and/or Section 4975 of the Internal Revenue Code prohibits employee benefit plans, and IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code with respect to the plan.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner also would be a fiduciary of the plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things,


	(a) the equity interests acquired by employee benefit plans are publicly offered securities; i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws,

	(b) the entity is an “operating company,” i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority owned subsidiary or subsidiaries, or

	(c) there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest, disregarding some interests held by our general partner, its affiliates, and some other persons, is held by the employee benefit plans referred to above, IRAs and other employee benefit plans not subject to ERISA, including governmental plans.

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) above.

Plan fiduciaries contemplating a purchase of common units are urged to consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

S-110

UNDERWRITING

Citigroup Global Markets Inc. is acting as representative of the underwriters named below. Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus supplement, each underwriter named below has agreed to purchase, and we have agreed to sell to that underwriter, the number of common units set forth opposite the underwriters name.


		Number of
Underwriter		common units

Citigroup Global Markets Inc.			1,125,000
Raymond James & Associates, Inc.			525,000
RBC Capital Markets Corporation			525,000
A.G. Edwards & Sons, Inc.			525,000
KeyBanc Capital Markets, a division of McDonald Investments Inc.			300,000

	Total		3,000,000

The underwriting agreement provides that the obligations of the underwriters to purchase the common units included in this offering are subject to approval of legal matters by counsel and to other conditions. The underwriters are obligated to purchase all the common units (other than those covered by the over-allotment option described below) if they purchase any of the common units.

The underwriters propose to offer some of the common units directly to the public at the public offering price set forth on the cover page of this prospectus supplement and some of the common units to dealers at the public offering price less a concession not to exceed $0.7862 per common unit. The underwriters may allow, and dealers may reallow a concession not to exceed $0.10 per common unit on sales to other dealers. If all the common units are not sold at the initial offering price, the representative may change the public offering price and the other selling terms.

We have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus supplement, to purchase up to 450,000 additional common units at the public offering price less the underwriting discount. The underwriters may exercise the option solely for the purpose of covering over-allotments, if any, in connection with this offering. To the extent the option is exercised, each underwriter must purchase a number of additional common units approximately proportionate to that underwriter’s initial purchase commitment.

We, Martin Resource Management, our operating subsidiaries, our general partner and the directors and executive officers of our general partner have agreed that, for a period of 90 days from the date of this prospectus supplement, we and they will not, without the prior written consent of Citigroup Global Markets Inc., dispose of or hedge any of our common units or any securities convertible into or exchangeable for our common units. Citigroup Global Markets Inc. in its sole discretion may release any of the securities subject to these lock-up agreements at any time without notice.

The common units are quoted on the Nasdaq National Market under the symbol “MMLP.”

The following table shows the underwriting discounts and the commissions that we are to pay to the underwriters in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units.


	No Exercise		Full Exercise

Per common unit	$	1.3104	$	1.3104
Total	$	3,931,200	$	4,520,880

In connection with the offering, Citigroup Global Markets Inc. on behalf of the underwriters, may purchase and sell our common units in the open market. These transactions may include short sales, syndicate covering transactions and stabilizing transactions. Short sales involve syndicate sales of common units in excess of the number of common units to be purchased by the underwriters in the offering, which

S-111

creates a syndicate short position. “Covered” short sales are sales of common units made in an amount up to the number of common units represented by the underwriters’ over-allotment option. In determining the source of common units to close out the covered syndicate short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through the over-allotment option. Transactions to close out the covered syndicate short involve either purchases of the common units in the open market after the distribution has been completed or the exercise of the over-allotment option. The underwriters may also make “naked” short sales of common units in excess of the over-allotment option. The underwriters must close out any naked short position by purchasing common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering. Stabilizing transactions consist of bids for or purchases of common units in the open market while the offering is in progress.

The underwriters also may impose a penalty bid. Penalty bids permit the underwriters to reclaim a selling concession from a syndicate member when Citigroup Global Markets Inc. repurchases common units originally sold by that syndicate member in order to cover syndicate short positions or make stabilizing purchases.

Any of these activities may have the effect of preventing or retarding a decline in the market price of the common units. They may also cause the price of the common units to be higher than the price that would otherwise exist in the open market in the absence of these transactions. The underwriters may conduct these transactions on the Nasdaq National Market or in the over-the-counter market, or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time.

In addition, in connection with this offering, some of the underwriters (and selling group members) may engage in passive market making transactions in the common units on the Nasdaq National Market, prior to the pricing and completion of this offering. Passive market making consists of displaying bids on the Nasdaq National Market no higher than the bid prices of independent market makers and making purchases no higher than those independent bids and effected in response to order flow. Net purchases by a passive market maker on each day are limited to a specified percentage of the passive market maker’s average daily trading volume in the common units during a specified period and must be discontinued when that limit is reached. Passive market making may cause the price of the common units to be higher than the price that otherwise would exist in the open market in the absence of those transactions. If the underwriters commence passive market making transactions, they may discontinue them at any time.

We estimate that the total expenses of this offering will (excluding underwriting discounts and commissions) be $500,000.

Some of the underwriters and their affiliates have engaged in, and may in the future engage in, investment banking and other commercial dealings in the ordinary course of business with us and our affiliates. In connection with the Prism Gas acquisition, we and our affiliates paid RBC Capital Markets Corporation, which is one of the underwriters of this offering, an investment banking fee. In addition, an affiliate of RBC Capital Markets Corporation is administrative agent, lead arranger, book runner and a lender under our credit facility, for which it received compensation, including compensation received in connection with the recent amendment to our credit agreement and expansion of our credit facility. That affiliate, and an affiliate of KeyBanc Capital Markets, a division of McDonald Investments Inc., who is also a lender under such facility, will receive a portion of the net proceeds from this offering through our repayment of part of the outstanding indebtedness under that facility.

Because the NASD views the common units offered hereby as interests in a direct participation program, this offering is being made in compliance with Rule 2810 of the NASD Conduct Rules.

A prospectus in electronic format may be made available on the websites maintained by one or more of the underwriters. The representatives may agree to allocate a number of common units to underwriters

S-112

for sale to their online brokerage account holders. The representatives will allocate common units to underwriters that may make Internet distributions on the same basis as other allocations. In addition, common units may be sold by the underwriters to securities dealers who resell common units to online brokerage account holders.

We, Martin Resource Management, our general partner, our operating subsidiaries and the general partner of our operating partnership have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act and liabilities arising from breaches of representations and warranties contained in the underwriting agreement, or to contribute to payments that may be required to be made in respect of these liabilities.

VALIDITY OF THE COMMON UNITS

The validity of the common units will be passed upon for us by Baker Botts L.L.P., Dallas, Texas. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Vinson & Elkins L.L.P., Houston, Texas.

EXPERTS

The following financial statements and management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2004 have been relied upon in preparing this prospectus supplement in reliance upon the reports of KPMG LLP, independent registered public accounting firm, and upon the authority of said firm as experts in accounting and auditing: (i) the consolidated and combined financial statements, respectively, of Martin Midstream Partners L.P. and subsidiaries and Martin Midstream Partners Predecessor as of December 31, 2004, 2003 and 2002, and for the period from November 6, 2002 through December 31, 2002 and for the period from January 1, 2002 through November 5, 2002, (ii) the financial statements of CF Martin Sulphur, L.P. as of December 31, 2004, 2003 and 2002, and for years ended December 31, 2004, 2003 and 2002, and (iii) the balance sheet of Martin Midstream GP LLC as of December 31, 2004.

The following financial statements have been relied upon in preparing this prospectus supplement in reliance upon the reports of Deloitte & Touche LLP, independent registered accounting firm, and upon the authority of said firm as experts in accounting and auditing: (i) the consolidated financial statements of Prism Gas as of and for the years ended December 31, 2004, 2003 and 2002, and (ii) the financial statements of Waskom Gas Processing Company as of and for the years ended December 31, 2004, 2003 and 2002.

The audit reports covering the December 31, 2002 financial statements of Martin Midstream Partners L.P., Martin Midstream Partners Predecessor and CF Martin Sulphur, L.P. refer to a change in the method of accounting for goodwill and other intangible assets.

WHERE YOU CAN FIND MORE INFORMATION

We file annual, quarterly and special reports, proxy statements, information statements and other information with the SEC. You may read and copy this information, for a copying fee, at the SEC’s public reference room at 100 F Street, NE, Washington, DC 20549-2521, and at the SEC’s Regional Offices located at Citicorp Center, 500 West Madison Street, Suite 1400, Chicago, Illinois 60661 and Seven World Trade Center, Suite 1300, New York, New York 10048. We encourage you to call the SEC at 1-800-SEC-0330 for more information about its public reference rooms. Our SEC filings are also available to the public from commercial document retrieval services and at the web site maintained by the SEC at http://www.sec.gov. Information about us is also available to the public from our website at http://www.martinmidstream.com.

S-113

This prospectus supplement is part of a registration statement we have filed with the SEC relating to the securities we may offer. As permitted by SEC rules, this prospectus supplement does not contain all of the information we have included in the registration statement and the accompanying exhibits and schedules we file with the SEC. You should read the registration statement and the exhibits and schedules for more information about us and our securities. The registration statement, exhibits and schedules are available at the SEC’s public reference room or through its web site.

You may also obtain a copy of our filings with the SEC, at no cost, by writing or telephoning us at the following address:

Martin Midstream Partners L.P.

4200 Stone Road

Kilgore, Texas 75662

Attention: Robert D. Bondurant

Telephone: (903) 983-6200

S-114

INCORPORATION OF DOCUMENTS BY REFERENCE

The SEC allows us to “incorporate by reference” into this prospectus the information we have filed with the SEC. This means that we can disclose important information to you without actually including the specific information in this prospectus by referring you to other documents filed separately with the SEC. These other documents contain important information about us, our financial condition and results of operations. The information incorporated by reference is an important part of this prospectus. Information that we file later with the SEC will automatically update and may replace information in this prospectus and information previously filed with the SEC.

We incorporate by reference in this prospectus the documents listed below:


	•	our annual report on Form 10-K for the year ended December 31, 2004 filed with the SEC on March 16, 2005, our amended annual report on Form 10-K/A filed with the SEC on April 29, 2005;

	•	our quarterly report on Form 10-Q for the quarter ended March 30, 2005 filed with the SEC on May 4, 2005, our quarterly report on Form 10-Q for the quarter ended June 30, 2005 filed with the SEC on August 2, 2005 and our quarterly report on Form 10-Q for the quarter ended September 30, 2005 filed on November 9, 2005;

	•	our current reports on Form 8-K filed January 6, 2005, April 22, 2005, May 4, 2005, May 27, July 18, 2005, September 6, 2005, November 14, 2005 and January 11, 2006; and our amendment to current report on Form 8-K/A filed on January 4, 2005 (excluding any portions thereof that are deemed to be furnished and not filed);

	•	the description of our common units in our registration statement on Form 8-A (File No. 1-02801862) filed pursuant to the Securities Exchange Act of 1934 on October 29, 2002; and

	•	all documents filed by us under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934 between the date of this prospectus and the termination of the registration statement (excluding any portions thereof that are deemed to be furnished and not filed).

You may obtain any of the documents incorporated by reference in this prospectus from the SEC through the SEC’s web site at the address provided above.

You should rely only on the information incorporated by reference or provided in this prospectus supplement. If information in incorporated documents conflicts with information in this prospectus supplement you should rely on the most recent information. If information in an incorporated document conflicts with information in another incorporated document, you should rely on the most recent incorporated document. You should not assume that the information in this prospectus supplement or any document incorporated by reference is accurate as of any date other than the date of those documents. We have not authorized anyone else to provide you with any information.

S-115

INDEX TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS


		Page

Martin Midstream Partners L.P. Unaudited Pro Forma Financial Statements:
	Introduction		F-2
	Unaudited Pro Forma Consolidated Balance Sheet as of September 30, 2005		F-3
	Unaudited Pro Forma Consolidated Statement of Operations for the nine months ended September 30, 2005		F-4
	Unaudited Pro Forma Consolidated Statement of Operations for the year ended December 31, 2004		F-5
	Notes to Unaudited Pro Forma Financial Statements		F-6

F-1

MARTIN MIDSTREAM PARTNERS L.P.

UNAUDITED PRO FORMA FINANCIAL STATEMENTS

INTRODUCTION

The following unaudited pro forma financial statements have been derived from the historical consolidated financial statements of Martin Midstream Partners L.P. (“MMLP”) and CF Martin Sulphur L.P. and the historical consolidated financial statements of Prism Gas Systems I, L.P. (“Prism Gas”), all as incorporated by reference herein. The pro forma financial statements should be read in conjunction with the accompanying notes to pro forma financial statements and with the historical financial statements and related notes set forth elsewhere or incorporated by reference herein.

For income statement items, the pro forma financial statements assume that the Prism Gas acquisition, the CF Martin Sulphur L.P. (“CF Martin Sulphur”) acquisition and the related borrowings under our credit facility occurred on January 1, 2004. For balance sheet items, the pro forma financial statements assume that the Prism Gas acquisition and this offering occurred on September 30, 2005. The CF Martin Sulphur acquisition occurred on July 15, 2005 and is reflected in the consolidated balance sheet of MMLP as of September 30, 2005. The pro forma financial statements give pro forma effect to the following transactions:


	•	the acquisition of Prism Gas for $97.4 million (including the assumption of approximately $4.2 million in working capital obligations, $0.3 million of assumed long-term liabilities and $0.5 million in acquisition expenses);

	•	the financing of the Prism Gas acquisition through a combination of $62.8 million under MMLP’s new credit facility, $5.0 million in a previously funded escrow account, $15.0 million of new equity capital provided by Martin Resource Management Corporation, $9.6 million of seller financing provided by certain Prism Gas sellers through the issuance of new MMLP common units, and $0.5 million in capital provided by Martin Resource Management Corporation to continue its general partnership interest in us;

	•	$3.1 million of debt underwriting fees incurred in connection with borrowings under MMLP’s credit facility;

	•	the completion of this offering net of $4.4 million in underwriting fees and offering expenses;

	•	the repayment of $48.3 million under MMLP’s revolving credit facility immediately after the closing of this offering; and

	•	the acquisition of the remaining interests in CF Martin Sulphur not previously owned by MMLP for $18.9 million.

The pro forma adjustments are based upon currently available information and certain estimates and assumptions, and therefore the actual adjustments will differ from the pro forma adjustments. However, management believes that the assumptions used provide a reasonable basis for presenting the significant effects of the acquisition and offering and related transactions as contemplated and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the pro forma financial statements. The pro forma financial statements may not be indicative of the results that actually would have occurred if we had completed the acquisition and the offering on the dates indicated. In addition, the pro forma financial statements are not necessarily indicative of the results of MMLP’s future operations.

F-2

MARTIN MIDSTREAM PARTNERS L.P.

UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET

September 30, 2005


			Martin						Pro Forma			Pro Forma
			Midstream			Prism			Adjustments —			Adjustments —			Pro Forma
			Partners L.P.			Gas			Acquisition			Offering			as Adjusted

			(Dollars in thousands)
ASSETS
Cash			$	3,116		$	5,925		$	92,918	(a)	$	87,360	(d)	$	43,352
										(92,918	)(b)		(4,431	)(e)
										(2,563	)(b)
										502	(c)		1,783	(f)
													(48,340	)(g)
Accounts and other receivable				50,796			13,523			(1,352	)(b)		—			62,967
Product exchange receivables				3,615			—			—			—			3,615
Inventories				34,554			374			(123	)(b)		—			34,805
Due from affiliates				1,098			341			—			—			1,439
Other current assets				532			233			(17	)(b)		—			748

	Total current assets			93,711			20,396			(3,553	)		36,372			146,926

Property, plant & equipment, at cost				200,410			9,475			7,500	(b)		—			217,385
	Accumulated depreciation			(55,958	)		(3,367	)		3,367	(b)		—			(55,958	)

		Property, plant and equipment, net		144,452			6,108			10,867			—			161,427

Goodwill				7,455			—			19,539	(b)		—			26,994
Covenant not to compete				—			—			600	(b)		—			600
Investment in unconsolidated entities				—			17,037			42,963	(b)		—			60,000
Other assets, net				9,616			406			(5,000	)(a)		—			8,062
										3,137	(a)
										(97	)(b)

	Total assets		$	255,234		$	43,947		$	68,456		$	36,372		$	404,009

LIABILITIES AND PARTNERS’ CAPITAL
Current installment of notes payable			$	582		$	—		$	—		$	—		$	582
Trade and other accounts payable				46,168			7,205			(262	)(b)		—			53,111
Product exchange payables				9,824			—			—			—			9,824
Due to affiliates				1,216			5,744			—			—			6,960
Taxes payable				—			6,388			—			—			6,388
Accrued settlement				—			1,100			—			—			1,100
Other accrued liabilities				3,291			572			(179	)(b)		—			3,684

	Total current liabilities			61,081			21,009			(441	)		—			81,649
Long term debt				120,422			—			66,440	(a)		(48,340	)(g)		138,522
Deferred income taxes				—			71			—			—			71
Other long-term obligations				888			207			—			—			1,095

	Total liabilities			182,391			21,287			65,999			(48,340	)		221,337

Commitments and contingencies
Partners’ capital
	Common Units			78,366			22,660			9,615	(a)		87,360	(d)		185,910
										15,000	(a)		(4,431	)(e)
										(22,660	)(b)
	Subordinated units			(6,095	)		—			—			—			(6,095	)
	General partner			572			—			502	(c)		1,783	(f)		2,857

		Total partners’ capital		72,843			22,660			2,457			84,712			182,672

			$	255,234		$	43,947		$	68,456		$	36,372		$	404,009

See accompanying notes to the unaudited pro forma financial statements.

F-3

MARTIN MIDSTREAM PARTNERS L.P.

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

Nine Months Ended September 30, 2005


				Martin									Pro Forma						Pro Forma
				Midstream			CF Martin						Adjustments —			Pro Forma			Adjustments —			Pro Forma
				Partners L.P.			Sulphur			Prism Gas			Acquisitions			as Adjusted			Offering			as Adjusted

				(Dollars in thousands, except per unit amounts)
Revenues:
	Terminalling and storage			$	16,858		$	—		$	—		$	—		$	16,858		$	—		$	16,858
	Marine transportation				26,634			—			—			(3,311	)(k)		23,323			—			23,323
	Product Sales:
		LPG distribution			199,487			—			69,373			(11,239	)(k)		257,621			—			257,621
		Sulfur			17,743			33,900			—			(267	)(k)		51,376			—			51,376
		Fertilizer			25,980			—			—			(187	)(k)		25,793			—			25,793
		Terminalling and storage			7,114			—			—			(2	)(k)		7,112			—			7,112

					250,324			33,900			69,373			(11,695	)		341,902			—			341,902

	Total revenues				293,816			33,900			69,373			(15,006	)		382,083			—			382,083

Costs and expenses:
	Cost of products sold:
		LPG distribution			192,187			—			66,207			(11,239	)(k)		247,155			—			247,155
		Sulfur			12,030			21,958			—			(187	)(k)		33,801			—			33,801
		Fertilizer			21,955			—			—			(258	)(k)		21,697			—			21,697
		Terminalling and storage			5,969			—			—			—			5,969			—			5,969

					232,141			21,958			66,207			(11,684	)		308,622			—			308,622
Expenses:
	Operating expenses				32,778			9,331			1,166			(3,322	)(k)		39,953			—			39,953
	Selling, general and administrative				5,420			771			2,850						9,041			—			9,041
	Depreciation and amortization				8,672			1,510			644			200	(o)		11,251			—			11,251
														225	(p)
	Impairment				—			—			—			—			—			—			—

		Total costs and expenses			279,011			33,570			70,867			(14,581	)		368,867			—			368,867

			Operating income (loss)		14,805			330			(1,494	)		(425	)		13,216			—			13,216

Other income (expenses):
	Equity in earnings of unconsolidated entities				222			—			4,896			(222	)(i)		4,896			—			4,896
	Interest expense				(3,834	)		(450	)		5			(3,299	)(l)		(8,727	)		2,400	(q)		(6,327	)
														(678	)(m)
														(471	)(h)
	Other, net				127			—			(19	)		—			108			—			108

		Total other income (expense)			(3,485	)		(450	)		4,882			(4,670	)		(3,723	)		2,400			(1,323	)

	Income taxes				—			—			7,115			(7,115	)(j)		—			—			—

Net income (loss)				$	11,320		$	(120	)	$	(3,727	)	$	2,020		$	9,493		$	2,400		$	11,893

General partners’ interest in net income				$	226																	$	238	(n)
Limited partners’ interest in net income				$	11,094																	$	11,655	(n)
Net income per limited partner unit				$	1.31																	$	1.06	(n)
Weighted average limited partner units					8,475,862																		10,981,071	(n)

See accompanying notes to the unaudited pro forma financial statements.

F-4

MARTIN MIDSTREAM PARTNERS L.P.

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

Year Ended December 31, 2004


			Martin									Pro Forma						Pro Forma
			Midstream			CF Martin						Adjustments —			Pro Forma			Adjustments —			Pro Forma
			Partners L.P.			Sulphur			Prism Gas			Acquisitions			as Adjusted			Offering			as Adjusted

			(Dollars in thousands, except per unit amounts)
Revenues:
	Terminalling and storage		$	17,919		$	—		$	—		$	—		$	17,919		$	—		$	17,919
	Marine transportation			34,780			—			—			(5,789	)(k)		28,991						28,991
	Product Sales:
		LPG distribution		203,427			—			71,384			(9,135	)(k)		265,676			—			265,676
		Sulfur					64,719						(720	)(k)		63,999			—			63,999
		Fertilizer		29,780			—			—			(316	)(k)		29,464			—			29,464
		Terminalling and storage		8,238			—			—			(44	)(k)		8,194			—			8,194

				241,445			64,719			71,384			(10,215	)		367,333			—			367,333

	Total revenues			294,144			64,719			71,384			(16,004	)		414,243			—			414,243

Costs and expenses:
	Cost of products sold:
		LPG distribution		197,859			—			68,132			(9,135	)(k)		256,856			—			256,856
		Sulfur					43,275						(316	)(k)		42,959			—			42,959
		Fertilizer		25,342						—			(687	)(k)		24,655			—			24,655
		Terminalling and storage		6,775			—			—			—			6,775			—			6,775

				229,976			43,275			68,132			(10,138	)		331,245			—			331,245
Expenses:
	Operating expenses			34,475			15,830			1,858			(5,866	)(k)		46,297			—			46,297
	Selling, general and administrative			6,198			1,460			2,824						10,482			—			10,482
	Depreciation and amortization			8,766			2,589			983			285	(o)		12,923			—			12,923
													300	(p)

		Total costs and expenses		279,415			63,154			73,797			(15,419	)		400,947			—			400,947

		Operating income (loss)		14,729			1,565			(2,413	)		(585	)		13,296			—			13,296

Other income (expenses):
	Equity in earnings of unconsolidated entities			912						7,112			(912	)(i)		7,112			—			7,112
	Interest expense			(3,326	)		(782	)		(20	)		(4,398	)(l)		(10,404	)		3,200	(q)		(7,204	)
													(1,251	)(m)
													(627	)(h)
	Other, net			11			—			226			—			237			—			237

		Total other income (expense)		(2,403	)		(782	)		7,318			(7,188	)		(3,055	)		3,200			(145	)

Income (loss) before income taxes				12,326			783			4,905			(7,773	)		10,241			3,200			13,441
Income taxes				—			—			1,500			(1,500	)(j)		—			—			—

Net income (loss)			$	12,326		$	783		$	3,405		$	(6,273	)	$	10,241		$	3,200		$	13,441

General partners’ interest in net income			$	247																	$	269	(n)
Limited partners’ interest in net income			$	12,079																	$	13,172	(n)
Net income per limited partner unit			$	1.45																	$	1.20	(n)
Weighted average limited partner units				8,349,551																		10,981,071	(n)

See accompanying notes to the unaudited pro forma financial statements.

F-5

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS

(a) Reflects $66.4 million in borrowings under Martin Midstream Partners L.P. (“MMLP”) credit facility (including $3.1 million of debt underwriting fees incurred in connection with such borrowings and $0.5 million in acquisition expenses), $5.0 million in a previously funded escrow account, $15.0 million of MMLP common units issued to Martin Resource Management Corporation, and $9.6 million of new MMLP common units issued to certain of the Prism Gas sellers.

(b) Reflects the payment of $92.9 million for the acquisition of Prism Gas. The carrying value of Prism Gas’s net assets at September 30, 2005 was $22.7 million. After considering the $4.2 million working capital adjustment, the adjustment to fair market value at acquisition was $70.2 million. The preliminary purchase price allocation for the Prism Gas acquisition was based on a third party valuation and is as follows:


		Purchase price
		allocation

Current assets		$	16,341
Property and equipment			16,975
Investments in partnerships			60,000
Other assets			309
Covenant not to compete			600
Goodwill			19,539
Current liabilities			(20,568	)
Long-term liabilities			(278	)

	Total	$	92,918

(c) Reflects MMLP’s general partner’s contribution resulting from the common units issued in connection with the Prism Gas acquisition.

(d) Reflects the gross proceeds to MMLP of $87.4 million from the issuance and sale of 3,000,000 common units at an assumed offering price of $29.12 per common unit.

(e) Reflects the payment of $4.4 million for the underwriting discount and other offering costs. These costs will be allocated to the common units.

(f) Reflects the contribution of $1.8 million from MMLP’s general partner in order to maintain its 2% interest.

(g) Represents the payment of $48.3 million under our revolving credit facility. The remaining debt represents term debt of $130.0 million and $8.5 million of U.S. Government Guaranteed Ship Financing Bonds.

(h) Reflects the amortization of the bank fees of $3.1 million over a 5 year period, which is the life of the bank facility.

(i) Reflects the elimination of the equity interest related to CF Martin Sulphur.

(j) Reflects the elimination of federal and state income taxes.

(k) Reflects the elimination of intercompany activity between MMLP and each of CF Martin Sulphur and Prism.

(l) Reflects increase of interest expense resulting from the borrowings under MMLP’s credit facility of $66.4 million which includes $3.1 million of debt underwriting fees incurred in connection with such borrowings and $0.5 million in acquisition expenses. The interest rate used to determine the pro forma adjustments for the borrowings under the bank credit facility was 6.62% which represents MMLP’s current

F-6

MARTIN MIDSTREAM PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS — (Continued)

rate on the credit facility. The interest rate was based on 3-month LIBOR +225 basis points and can vary. An increase of ¹/8 percent in the interest rate would increase interest expense and decrease income before income taxes by $0.1 million per year.

(m) Reflects increase of interest expense resulting from the borrowings of $18.9 million related to the acquisition of CF Martin Sulphur. The interest rate used to determine the pro forma adjustments for the borrowings under the credit facility was 6.62% which represents MMLP’s current rate on the credit facility. The interest rate was based on 3-month LIBOR +225 basis points and can vary. An increase of ¹/8 percent in the interest rate would increase interest expense and decrease income before income taxes by $0.024 million per year.

(n) MMLP’s general partner’s allocation of the net income is based on its combined 2.0% interest in MMLP. Its general partners’ 2.0% allocation of net income has been deducted before calculating net income per limited partners’ unit. The computation of pro forma net income per limited partner unit assumes that 7,578,381 common units and 3,402,690 subordinated units, or a total of 10,981,071 units, were outstanding at all time periods presented.

(o) Reflects the change in depreciation expense of the acquired assets from Prism Gas. Pro forma depreciation expense was based on estimated useful lives of 19 years for the gas plant and gathering system assets. The estimated useful life was determined using the weighted average useful life of the McLeod, East Texas, and Hallsville assets. Due to the new carrying value of the Prism Gas assets upon acquisition, historical depreciation expense has been adjusted.

(p) Reflects the amortization of the covenant not to compete of $0.6 million over a 2-year period.

(q) Reflects reduction of interest expense resulting from repayments of $48.3 million of borrowings under MMLP’s credit facility. The interest rate used to determine pro forma adjustments for the borrowings under the credit facility was 6.62% which represents MMLP’s current rate on the credit facility. The interest rate was based on 3-month LIBOR +225 basis points and can vary.

F-7

PROSPECTUS

$200,000,000

Martin Midstream Partners L.P.

COMMON UNITS

DEBT SECURITIES

Martin Operating Partnership L.P.

DEBT SECURITIES

The following securities may be offered under this prospectus:


	•	Common units representing limited partner interests in Martin Midstream Partners L.P.;

	•	Debt securities of Martin Midstream Partners L.P.; and

	•	Debt securities of Martin Operating Partnership L.P.

The aggregate initial offering price of the securities that we offer by this prospectus will not exceed $200,000,000. We will offer the securities in amounts, at prices and on terms to be determined by market conditions at the time of our offerings. This prospectus describes only the general terms of these securities and the general manner in which we will offer these securities. The specific terms of any securities we offer will be included in a supplement to this prospectus. The prospectus supplement will describe the specific manner in which we will offer the securities and also may add, update or change information contained in this prospectus. The common units are traded on the Nasdaq National Market under the symbol “MMLP.”

You should read this prospectus and the prospectus supplement carefully before you invest in any of our securities. This prospectus may not be used to consummate sales of our securities unless it is accompanied by a prospectus supplement.

Investing in our securities involves risk. You should carefully consider the risk factors described under “Risk Factors” beginning on page 2 of this prospectus before you make any investment in our securities.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined whether this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The date of this prospectus is July 19, 2004

TABLE OF CONTENTS


ABOUT THIS PROSPECTUS			i
MARTIN MIDSTREAM PARTNERS L.P.			1
THE GUARANTORS			1
RISK FACTORS			2
FORWARD-LOOKING STATEMENTS			17
USE OF PROCEEDS			18
RATIO OF EARNINGS TO FIXED CHARGES			18
DESCRIPTION OF THE DEBT SECURITIES			18
DESCRIPTION OF THE COMMON UNITS			27
CASH DISTRIBUTION POLICY			30
THE PARTNERSHIP AGREEMENT			38
MATERIAL TAX CONSIDERATIONS			50
INVESTMENT IN US BY EMPLOYEE BENEFIT PLANS			63
PLAN OF DISTRIBUTION			64
LEGAL MATTERS			65
EXPERTS			65
WHERE YOU CAN FIND MORE INFORMATION			66
INCORPORATION BY REFERENCE			66
GLOSSARY OF TERMS			A-1

You should rely only on the information contained in this prospectus, any prospectus supplement and the documents we have incorporated by reference. We have not authorized anyone else to give you different information. We are not offering these securities in any state where the offer is not permitted. You should not assume that the information in this prospectus or any prospectus supplement is accurate as of any date other than the date on the front of those documents. We will disclose any material changes in our affairs in an amendment to this prospectus, a prospectus supplement or a future filing with the Securities and Exchange Commission incorporated by reference in this prospectus.

ABOUT THIS PROSPECTUS

This prospectus is part of a registration statement on Form S-3 that we have filed with the Securities and Exchange Commission using a “shelf” registration process. Under this shelf registration process, we may sell, in one or more offerings, up to $200,000,000 in total aggregate initial offering price of securities described in this prospectus. This prospectus provides you with a general description of Martin Midstream Partners L.P., Martin Operating Partnership L.P. and the securities offered under this prospectus.

Each time we sell securities under this prospectus, we will provide a prospectus supplement that will contain specific information about the terms of that offering and the securities being offered. The prospectus supplement also may add to, update or change information in this prospectus. If there is any inconsistency between the information in this prospectus and any prospectus supplement, you should rely on the information in the prospectus supplement. You should read carefully this prospectus, any prospectus supplement and the additional information described below under the heading “Where You Can Find More Information.”

As used in this prospectus, “Martin Midstream Partners,” “we,” “us,” and “our” and similar terms mean Martin Midstream Partners L.P., and, unless the context requires otherwise, our operating partnership, Martin Operating Partnership L.P. References to “Martin Midstream Partners Predecessor,” “we,” “ours,” “us,” or like terms when used in a historical context for periods prior to November 2002 refer to the assets and operations of Martin Resource Management Corporation’s businesses that were contributed to us in connection with the closing of our initial public offering in November 2002. References in this prospectus to

“Martin Operating Partnership” refer to our operating partnership, Martin Operating Partnership L.P. References in this prospectus to “Martin Resource Management” refer to Martin Resource Management Corporation and its direct and indirect consolidated and unconsolidated subsidiaries.

MARTIN MIDSTREAM PARTNERS L.P.

We are a publicly traded Delaware limited partnership formed in conjunction with our initial public offering in November 2002. We provide terminalling, marine transportation, distribution and midstream logistical services for producers and suppliers of hydrocarbon products and by-products, lubricants and other liquids. We also manufacture and market sulfur-based fertilizers and related products. Hydrocarbon products and by-products are produced primarily by major and independent oil and gas companies who often turn to independent third parties, such as us, for the transportation and disposition of these products. We operate primarily in the Gulf Coast region of the United States. This region is a major hub for petroleum refining, natural gas processing and support services to the offshore exploration and production industry. We provide our marine transportation and midstream logistical services and distribute hydrocarbon products and by-products primarily to customers who are located in this region or in close proximity to ports located along the Gulf of Mexico Intracoastal Waterway and the Mississippi River inland waterway system. The fertilizer and related products we manufacture are sold throughout the United States. Martin Midstream GP LLC serves as our general partner and our operations are conducted through our operating partnership, Martin Operating Partnership. In addition, we own an unconsolidated non-controlling 49.5% limited partnership interest in CF Martin Sulfur, L.P., from which we receive a material portion of our net income and cash available for distribution. That partnership collects and aggregates, transports, stores and markets molten sulfur supplied by oil refiners and natural gas processors. Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

We maintain our principal executive offices at 4200 Stone Road, Kilgore, Texas 75662, and our telephone number is (903) 983-6200.

THE GUARANTORS

Martin Midstream Partners will unconditionally guarantee any series of debt securities of Martin Operating Partnership offered by this prospectus, as set forth in a related prospectus supplement. If a series of debt securities of Martin Midstream Partners is guaranteed, Martin Operating Partnership will unconditionally guarantee such series of debt securities of Martin Midstream Partners offered by this prospectus, as set forth in a related prospectus supplement. As used in this prospectus, the term “Guarantor” means, Martin Midstream Partners in its role as guarantor of the debt securities of Martin Operating Partnership or Martin Operating Partnership in its role as guarantor of the debt securities of Martin Midstream Partners.

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. You should carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in us. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay distributions on our common units or make principal or interest payments on our debt securities, the trading price of our common units or our debt securities could decline and you could lose all or part of your investment.

Risks Relating to Our Business


	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 or make principal or interest payments on our debt securities.

We may not have sufficient available cash each quarter in the future to pay the minimum quarterly distribution on all our units or make principal and interest payments on our debt securities. 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 or use to make principal or interest payments on our debt securities 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 hydrocarbon 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 revolving credit facility; and

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

You should also be aware that the amount of cash we have available for distribution or to make principal or interest payments on our debt securities 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 or make principal and interest payments on our debt securities during periods when we record losses and may not make cash distributions or may not make principal and interest payments on our debt securities during periods when we record net income.


	*Adverse weather conditions could reduce our results of operations and ability to make distributions to our unitholders or make principal and interest payments on our debt securities.*

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 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, pushboats, 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 segment can be affected if offshore drilling operations are disrupted by weather in the Gulf of Mexico.


	We receive a material portion of our net income and cash available for distribution or to make principal and interest payments on our debt securities from our unconsolidated non-controlling 49.5% limited partner interest in CF Martin Sulphur, L.P.

We receive a material portion of our net income and cash available for distribution or to make principal and interest payments on our debt securities from our unconsolidated non-controlling 49.5% limited partner interest in CF Martin Sulphur, L.P. CF Industries, Inc. owns the remaining 49.5% limited partner interest. We have virtually no rights or control over the operations or management of cash generated by this entity. CF Martin Sulphur, L.P. is managed by its general partner, which is owned equally by CF Industries, Inc. and Martin Resource Management. Deadlocks between CF Industries, Inc. and Martin Resource Management over issues relating to the operation of CF Martin Sulphur, L.P. could have an adverse impact on its results of operations and, consequently, the amount and timing of cash generated by its operations that is available for distribution to its partners, including us as a limited partner.

Additionally, the partnership agreement for CF Martin Sulphur, L.P. requires that entity to make cash distributions to its limited partners subject to the discretion of its general partner, other than in limited circumstances. As a result, we are substantially dependent upon the discretion of that general partner with respect to the amount and timing of cash distributions from that entity. If the general partner of CF Martin Sulphur, L.P. does not distribute the cash generated by its operations to its limited partners, as a result of a deadlock between CF Industries, Inc. and Martin Resource Management or for any other reason, including operating difficulties or if CF Martin Sulphur, L.P. is unable to meet its debt service obligations, our cash flow and quarterly distributions or ability to make principal and interest payments on our debt securities would be reduced significantly.


	*We may have to sell our interest, or buy the other partnership interests in CF Martin Sulphur, L.P. at a time when it may not be in our best interest to do so.*

The CF Martin Sulphur, L.P. partnership agreement contains a buy-sell mechanism that could be implemented by a partner under certain circumstances. As a result of this buy-sell mechanism, we could be forced to either sell our limited partner interest or buy the limited and general partner interests of CF Industries, Inc. in CF Martin Sulphur, L.P. at a time when it may not be in our best interest to do so. In addition, we may not have sufficient cash or available borrowing capacity under our revolving credit facility to allow us to elect to purchase the limited and general partner interest of CF Industries, Inc., in which case we may be forced to sell our limited partner interest as a result of this buy-sell mechanism when we would otherwise prefer to keep this interest. Further, if CF Industries, Inc. implements this buy-sell mechanism and we decide to use cash from operations or obtain financing to purchase CF Industries, Inc.’s interest in that partnership, we may not be able to make distributions to our unitholders or make principal and interest payments on our debt securities. Conversely, if we are required to sell our interest in this partnership, we would lose our share of distributable income from its operations, and our ability to make subsequent distributions to our unitholders or to make principal and interest payments on our debt securities could be adversely affected.


	If CF Martin Sulphur, L.P. issues additional partnership interests, our ownership interest in this partnership could be diluted. Consequently, our share of CF Martin Sulphur, L.P.’s distributable cash could be reduced, which could adversely affect our ability to make distributions to our unitholders or to make principal and interest payments on our debt securities.

CF Martin Sulphur, L.P. has the ability under its partnership agreement to issue additional general and limited partner interests. If CF Martin Sulphur, L.P. issues additional interests, our ownership percentage in CF Martin Sulphur, L.P., and our share of CF Martin Sulphur, L.P.’s distributable cash, may decrease. This decrease in our ownership interest could reduce the amount of cash distributions we receive from CF Martin Sulphur, L.P. and could adversely affect our ability to make distributions to our unitholders or to make principal and interest payments on our debt securities.


	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 or to make principal and interest payments on our debt securities could be adversely affected.

Our operations are subject to the operating hazards and risks incidental to terminalling, marine transportation and the distribution of hydrocarbon 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 LPGs and other hydrocarbon 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.


	The price volatility of hydrocarbon products and by-products can reduce our results of operations and ability to make distributions to our unitholders or to make principal and interest payments on our debt securities.

We and our affiliates purchase hydrocarbon products and by-products such as molten sulfur, sulfur derivatives, fuel oil, 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 of certain products for third parties. The price and market value of hydrocarbon products and by-products can be volatile. Our 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. Future price volatility could have an adverse impact on our results of operations, cash flow and ability to make distributions to our unitholders or to make principal and interest payments on our debt securities.


	*Restrictions in our credit agreement may prevent us from making distributions to our unitholders or to make principal and interest payments on our debt securities.*

As of June 23, 2004, we have approximately $62.0 million of secured indebtedness outstanding, composed of $37.0 million of debt under our revolving credit facility and $25.0 million of term debt. Our payment of principal and interest on our secured debt reduces the cash available for distribution to our unitholders or to make principal and interest payments on our debt securities. In addition, we are prohibited by our revolving credit facility from making cash distributions or to make principal and interest payments on our debt securities during an event of default or if the payment of a distribution or a payment on our debt securities would cause an event of default under any of our secured debt agreements. Our leverage and various limitations in our revolving credit facility may reduce our ability to incur additional debt, engage in some 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 or to make principal and interest payments on our debt securities. 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 or to make principal and interest payments on our debt securities. 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.


	*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 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 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 or to make principal and interest payments on our debt securities.


	*Demand for our terminalling 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 has historically 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 services.


	*Our LPG and fertilizer businesses are seasonal and could cause our revenues to vary.*

The demand for LPG is highest in the winter. Therefore, revenue from our LPG distribution business is higher in the winter than in other seasons. Our fertilizer business experiences 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 business lines may cause our results of operations to vary on a quarter to quarter basis and thus could cause our cash available for quarterly distributions or payments on our debt securities 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 or to make principal and interest payments on our debt securities.


	Our business is subject to federal, state and local laws and regulations relating to environmental, safety and other regulatory matters. The violation of or the cost of compliance with these laws and regulations could adversely affect our results of operations and ability to make distributions to our unitholders or to make principal and interest payments on our debt securities.

Our business is subject to a wide range of environmental, safety and other regulatory laws and regulations. For example, our operations are subject to permit requirements and increasingly stringent regulations under numerous environmental laws, such as the Clean Air Act, the Clean Water Act, the Resource Conservation and Recovery Act, and similar state and local laws. Our costs could increase due to more strict pollution control requirements or liabilities resulting from compliance with future required operating or other regulatory

permits. New environmental regulations might adversely impact our results of operations and ability to pay distributions to our unitholders or to make principal and interest payments on our debt securities. Federal and state agencies also could impose additional safety requirements, any of which could adversely affect our results of operations and ability to make distributions to our unitholders or to make principal and interest payments on our debt securities.

The loss or insufficient attention of key personnel could negatively impact our results of operations and ability to make distributions to our unitholders or to make principal and interest payments on our debt securities. 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 loss of significant commercial relationships with Martin Resource Management could adversely impact our results of operations and ability to make distributions to our unitholders or to make principal and interest payments on our debt securities.

Martin Resource Management provides us with various services and products pursuant to various commercial contracts. The loss of any of these services 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 or to make principal and interest payments on our debt securities. Additionally, we provide marine transportation and terminalling 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 or to make principal and interest payments on our debt securities.


	Our business would be adversely affected if operations at our terminalling, transportation 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 or to make principal and interest payments on our debt securities. 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;

	•	environmental remediations;

	•	labor difficulties; and

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


	*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 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 flag vessels when compared with foreign flag 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 flag 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 or to make principal and interest payments on our debt securities.


	*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 pushboats, 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 pushboats 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 pushboats, 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 or to make principal and interest payments on our debt securities.


	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 or to make principal and interest payments on our debt securities.

Risks Relating to an Investment in Us


	Cost reimbursements due to Martin Resource Management may be substantial and will reduce our cash available for distribution to our unitholders or to make principal and interest payments on our debt securities.


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

Martin Resource Management owns approximately 50.2% of our outstanding limited partner interests and 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.

	•	We own a unconsolidated non-controlling 49.5% limited partnership interest in CF Martin Sulphur, L.P., which operates a business involving the acquisition, handling and sale of molten sulfur. As a limited partner, we have virtually no rights or control over the operation and management of this entity. The day-to-day operation and control of this partnership is managed by its general partner, CF Martin Sulphur, L.L.C., which is owned equally by CF Industries, Inc. and Martin Resource Management. Because we have very limited control over the operations and management of CF Martin Sulphur, L.P., we are subject to the risks that this business may be operated in a manner that would not be in our interest. For example, the amount of cash distributed to us from CF Martin Sulphur, L.P. could decrease if it uses a significant amount of cash from operations or additional debt to make significant capital expenditures or acquisitions.


	•	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 common 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, you 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.

	•	In some instances, our general partner may cause us to borrow funds to permit us to pay cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.

	•	Our general partner has broad discretion to establish financial reserves for the proper conduct of our business. These reserves also will affect the amount of cash available for distribution. Our general partner may establish reserves for distribution on the subordinated units, but only if those reserves will not prevent us from distributing the full minimum quarterly distribution, plus any arrearages, on the common units for the following four quarters.


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

and its affiliates, including Martin Resource Management, control approximately 50.2% of all the limited partner units, our general partner cannot be removed without the consent of it and its affiliates.


	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 or to make principal and interest payments on our debt securities.


	*Our 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.*


	•	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.

Agreement — Limited Liability” for a discussion of the implications of the limitations on liability to a unitholder.


	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.


	•	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.


	*We may issue additional common units without unitholder approval, which would dilute each unitholder’s ownership interest.*


	•	the issuance of common units 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.

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; and

	•	the market price of the common units may decline.


	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.

If, at any time, Martin Resource Management no longer controls our general partner, the lender 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 or to make principal and interest payments on our debt securities.


	*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 the potential tax liability of unitholders, please read “— Tax Risks — Tax gain or loss on the disposition of our common units could be different than expected” and “The Partnership Agreement — Limited Call Right.”


	*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. 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 or to make principal and interest payments on our debt securities.


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

Tax Risks

You should read “Material Tax Considerations” for a full discussion of the expected material federal income tax considerations of owning and disposing of common units.


	The IRS could treat us as a corporation for tax purposes, which would substantially reduce the cash available for distribution to unitholders or to make principal and interest payments on our debt securities.

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

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


	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.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from our counsel’s conclusions expressed in this prospectus. 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. Our counsel has not rendered an opinion on certain matters affecting us. 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 unitholders sell 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 their tax basis in that common unit, will, in effect, become taxable income to them 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 unitholders. Should the IRS

successfully contest some positions we take, 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 unitholders sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale.


	*Changes in federal income tax law could affect the value of our common units.*

On May 28, 2003, the Jobs and Growth Tax Relief Reconciliation Act of 2003 was signed into law, which generally reduces the maximum tax rate applicable to corporate dividends to 15%. This reduction could materially affect the value of our common units in relation to alternative investments in corporate stock, as investments in corporate stock may be relatively more attractive to individual investors thereby exerting downward pressure on the market price of our common units.


	*Tax-exempt entities, regulated investment companies 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), regulated investment companies (known as mutual funds) and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business income and will be taxable to them. Very little of our income will be qualifying income to a regulated investment company. 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 are registered as a tax shelter. This may increase the risk of an IRS audit of us or a unitholder.*

We are registered with the IRS as a “tax shelter.” Our tax shelter registration number is 02318000009. The federal income tax laws require that some types of entities, including some partnerships, register as “tax shelters” in response to the perception that they claim tax benefits that may be unwarranted. As a result, we may be audited by the IRS and tax adjustments could be made. Any unitholder owning less than a 1% profits interest in us has very limited rights to participate in the income tax audit process. Further, any adjustments in our tax returns will lead to adjustments in our unitholders’ tax returns and may lead to audits of unitholders’ tax returns and adjustments of items unrelated to us. Unitholders will bear the cost of any expense incurred in connection with an examination of their tax return.


	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 will adopt depreciation positions that may not conform to all aspects of the Treasury regulations. Please read “Material Tax Considerations — Tax Consequences of Unit Ownership — Section 754 Election.” 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 unitholder tax returns. Please read “Material Tax Considerations — Uniformity of Units” for a further discussion of the effect of, and reasons for, the depreciation and amortization positions we will adopt.


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

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, Arizona, Arkansas, Georgia, Florida, Illinois, Louisiana, Mississippi, Texas and Utah. We may do business or own property in other states or foreign countries in the future. It is the responsibility of the unitholder 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.

Risks Relating to the Debt Securities


	Martin Midstream Partners is a holding company and we conduct our operations through our subsidiary, Martin Operating Partnership, and depend on cash flow from Martin Operating Partnership to service any of our debt obligations.

Martin Midstream Partners conducts all of its operations through its subsidiary, Martin Operating Partnership, and owns no significant assets other than the limited partnership interests in Martin Operating Partnership and ownership of membership interests in Martin Operating GP LLC, the general partner of Martin Operating Partnership. Therefore, our ability, and the ability of Martin Operating Partnership, to make required payments on any debt securities issued will depend on the performance of Martin Operating Partnership and its ability to make required payments and/or to distribute funds to us. The ability of this subsidiary to make required payments and/or make such distributions may be restricted by, among other things, its debt agreements and applicable state partnership laws and other laws and regulations. Under our debt agreements, Martin Operating Partnership is prohibited from making a distribution to us that would result in a default in such debt agreements. Furthermore, applicable state partnership laws restrict Martin Operating Partnership from making distributions to us that would result in its insolvency. If we or Martin Operating Partnership are unable to obtain the funds necessary to pay the principal amount at maturity of our debt securities, we may be required to adopt one or more alternatives, such as a refinancing of the debt securities. We cannot assure you that we would be able to so refinance our debt securities.


	*Your right to receive payments on our debt securities is unsecured and will be effectively subordinated to our existing and future secured indebtedness.*

Any debt securities, including any guarantees, issued by Martin Midstream Partners or Martin Operating Partnership will be effectively subordinated to the claims of our secured creditors. In the event of the insolvency, bankruptcy, liquidation, reorganization, dissolution or winding up of the business of Martin Midstream Partners or Martin Operating Partnership, secured creditors would generally have the right to be paid in full before any distribution is made to the holders of our debt securities. As of June 23, 2004, Martin Midstream Partners had outstanding approximately $62.0 million of secured indebtedness.


	A guarantee by Martin Midstream Partners or Martin Operating Partnership could be deemed to be a fraudulent conveyance under certain circumstances, and a court may try to subordinate or void such guarantee.

Under federal bankruptcy laws and comparable provisions of state fraudulent transfer laws, a guarantee by Martin Midstream Partners or Martin Operating Partnership could be voided, or claims in respect of a guarantee could be subordinated to all other debts of that guarantor if, among other things, the guarantor, at the time it incurred the indebtedness evidenced by its guarantee, received less than reasonably equivalent fair value or fair consideration for the incurrence of such guarantee, and


	•	was insolvent or rendered insolvent by reason of such incurrence;

	•	was engaged in a business or transaction for which the guarantor’s remaining assets constituted unreasonably small capital; or

	•	intended to incur, or believed that it would incur, debts beyond its ability to pay such debts as they mature.

In addition, any payment by that guarantor pursuant to its guarantee could be voided and required to be returned to the guarantor, or to a fund for the benefit of the creditors of the guarantor. The measures of insolvency for purposes of these fraudulent transfer laws will vary depending upon the law applied in any proceeding to determine whether a fraudulent transfer has occurred. Generally, however, a guarantor would be considered insolvent if:


	•	the sum of its assets, including contingent liabilities, were greater than the fair saleable value of all of its assets;

	•	the present fair saleable value of its assets were less than the amount that would be required to pay its procurable liability, including contingent liabilities, on its existing debts, as they become absolute or mature; or

	•	it could not pay its debts as they become due.


	Martin Midstream Partners and Martin Operating Partnership are required to distribute all of their available cash to their partners and are not required to accumulate cash for the purpose of meeting their future obligations to holders of our debt securities, which may limit the cash available to service those debt securities.

The partnership agreements of Martin Midstream Partners and Martin Operating Partnership require us to distribute all of our available cash each fiscal quarter to our partners. Available cash is generally defined to mean all cash on hand at the end of the quarter, plus certain working capital borrowings after the end of the quarter, less reserves established by the general partner in its sole discretion to provide for the proper conduct of our business (including reserves for future capital expenditures), to comply with applicable law or agreements, including debt agreements, or to provide funds for future distributions to partners. Depending on the timing and amount of the cash distributions to our partners and because we are not required to accumulate cash for the purpose of meeting obligations to holders of any debt securities, such distributions could significantly reduce the cash available to us in subsequent periods to make payments on any debt securities.

FORWARD-LOOKING STATEMENTS

Statements included in this prospectus, the accompanying prospectus supplement and the documents we incorporate by reference 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.

USE OF PROCEEDS

Unless we specify otherwise in any prospectus supplement, we will use the net proceeds (after the payment of offering expenses and underwriting discounts and commissions) from the sale of securities offered hereby for general partnership purposes, which may include, among other things:


	•	paying or refinancing all or a portion of our indebtedness outstanding at the time, including indebtedness incurred in connection with acquisitions; and

	•	funding working capital, capital expenditures or acquisitions.

The actual application of proceeds from the sale of any particular offering of securities using this prospectus will be described in the applicable prospectus supplement relating to such offering. The precise amount and timing of the application of these proceeds will depend upon our funding requirements and the availability and cost of other funds.

RATIO OF EARNINGS TO FIXED CHARGES

The table below sets forth the ratio of earnings to fixed charges of Martin Midstream Partners and Martin Midstream Partners Predecessor on a consolidated basis for the periods indicated. The ratio of earnings to fixed charges is presented below for the years ending December 31, 1999, 2000, 2001, 2002 and 2003 and the three months ended March 31, 2004.

Martin Midstream Partners Predecessor

Martin Midstream Partners L.P.

Period from

January 1,

Period from

2002

November 6,

Three Months

Year Ended December 31

through

2002 through

Year Ended

Ended

November 5,

December 31,

March 31,

1999

2000

2001

2002

2003

2004

Ratio of Earnings to Fixed Charges

0.73

1.19

2.13

1.78

10.28

7.37

6.26x

For these ratios, “earnings” is the amount resulting from adding the following items:


	•	pre-tax income from continuing operations, before minority interest and equity in earnings of unconsolidated partnership;

	•	distributed income of equity investments; and

	•	fixed charges.

The term “fixed charges” means the sum of the following:


	•	interest expense;

	•	amortized debt issuance costs; and

	•	estimated interest element of rentals.

DESCRIPTION OF THE DEBT SECURITIES

Martin Midstream Partners may issue senior debt securities under an indenture between Martin Midstream Partners, as issuer, Martin Operating Partnership, as the Guarantor, if applicable, and a trustee that we will name in the related prospectus supplement. We refer to this indenture as the “Martin Midstream Partners senior indenture.” Martin Midstream Partners may also issue subordinated debt securities under an indenture to be entered into among Martin Midstream Partners, Martin Operating Partnership, as the Guarantor, if applicable, and a trustee that we will name in the related prospectus supplement. We refer to this indenture as the “Martin Midstream Partners subordinated indenture.”

Martin Operating Partnership may issue senior debt securities under an indenture among Martin Operating Partnership, as issuer, Martin Midstream Partners, as the Guarantor, and a trustee that we will

name in the related prospectus supplement. We refer to this indenture as the “Martin Operating Partnership senior indenture.” Martin Operating Partnership may also issue subordinated debt securities under an indenture to be entered into among Martin Operating Partnership, Martin Midstream Partners, as the Guarantor, and a trustee that we will name in the related prospectus supplement. We refer to this indenture as the “Martin Operating Partnership subordinated indenture.”

We refer to the Martin Midstream Partners senior indenture, the Martin Operating Partnership senior indenture, the Martin Midstream Partners subordinated indenture and the Martin Operating Partnership subordinated indenture collectively as the “indentures.” The debt securities will be governed by the provisions of the related indenture and those made part of the indenture by reference to the Trust Indenture Act of 1939.

We have summarized material provisions of the indentures, the debt securities and the guarantees below. This summary is not complete. We have filed the form of senior indentures and the form of subordinated indentures with the SEC as exhibits to the registration statement of which this prospectus forms a part, and you should read the indentures for provisions that may be important to you.

Unless the context otherwise requires, references in this “Description of the Debt Securities” to “we,” “us” and “our” mean Martin Midstream Partners and Martin Operating Partnership and references herein to an “indenture” refer to the particular indenture under which we issue a series of debt securities.

Provisions Applicable to Each Indenture

General. Any series of debt securities:


	•	will be general obligations of the issuer;

	•	will be general obligations of the Guarantor if they are guaranteed by the Guarantor; and

	•	may be subordinated to the Senior Indebtedness of Martin Midstream Partners and Martin Operating Partnership.

The indentures do not limit the amount of debt securities that may be issued under any indenture, and do not limit the amount of other indebtedness or securities that we may issue. We may issue debt securities under the indentures from time to time in one or more series, each in an amount authorized prior to issuance.

No indenture contains any covenants or other provisions designed to protect holders of the debt securities in the event we participate in a highly leveraged transaction or upon a change of control. The indentures also do not contain provisions that give holders the right to require us to repurchase their securities in the event of a decline in our credit ratings for any reason, including as a result of a takeover, recapitalization or similar restructuring or otherwise.

Terms. We will prepare a prospectus supplement and either a supplemental indenture, or authorizing resolutions of the board of directors of our general partner, accompanied by an officers’ certificate, relating to any series of debt securities that we offer, which will include specific terms relating to some or all of the following:


	•	whether the debt securities will be senior or subordinated debt securities;

	•	the form and title of the debt securities of that series;

	•	whether the debt securities will be secured or not;

	•	the total principal amount of the debt securities of that series;

	•	whether the debt securities will be issued in individual certificates to each holder or in the form of temporary or permanent global securities held by a depositary on behalf of holders;

	•	the date or dates on which the principal of and any premium on the debt securities of that series will be payable;


	•	any interest rate which the debt securities of that series will bear, the date from which interest will accrue, interest payment dates and record dates for interest payments;

	•	any right to extend or defer the interest payment periods and the duration of the extension;

	•	whether and under what circumstances any additional amounts with respect to the debt securities will be payable;

	•	whether the debt securities are entitled to the benefit of any guarantee by any Guarantor;

	•	the place or places where payments on the debt securities of that series will be payable;

	•	any provisions for optional redemption or early repayment;

	•	any provisions that would require the redemption, purchase or repayment of debt securities;

	•	the denominations in which the debt securities will be issued;

	•	whether payments on the debt securities will be payable in foreign currency or currency units or another form and whether payments will be payable by reference to any index or formula;

	•	the portion of the principal amount of debt securities that will be payable if the maturity is accelerated, if other than the entire principal amount;

	•	any additional means of defeasance of the debt securities, any additional conditions or limitations to defeasance of the debt securities or any changes to those conditions or limitations;

	•	any changes or additions to the events of default or covenants described in this prospectus;

	•	any restrictions or other provisions relating to the transfer or exchange of debt securities;

	•	any terms for the conversion or exchange of the debt securities for our other securities or securities of any other entity;

	•	any changes to the subordination provisions for the subordinated debt securities; and

	•	any other terms of the debt securities of that series.

This description of debt securities will be deemed modified, amended or supplemented by any description of any series of debt securities set forth in a prospectus supplement related to that series.

We may sell the debt securities at a discount, which may be substantial, below their stated principal amount. These debt securities may bear no interest or interest at a rate that at the time of issuance is below market rates. If we sell these debt securities, we will describe in the prospectus supplement any material United States federal income tax consequences and other special considerations.

If we sell any of the debt securities for any foreign currency or currency unit or if payments on the debt securities are payable in any foreign currency or currency unit, we will describe in the prospectus supplement the restrictions, elections, tax consequences, specific terms and other information relating to those debt securities and the foreign currency or currency unit.

Guarantee of Martin Midstream Partners. Martin Midstream Partners will fully, irrevocably and unconditionally guarantee on an unsecured basis all series of debt securities of Martin Operating Partnership, and may execute a notation of guarantee as further evidence of its guarantee. The applicable prospectus supplement will describe the terms of any such guarantee by Martin Midstream Partners.

Martin Midstream Partners’ guarantee of the senior debt securities will be Martin Midstream Partners’ unsecured and unsubordinated general obligation, and will rank on a parity with all of Martin Midstream Partners’ other unsecured and unsubordinated indebtedness. Martin Midstream Partners’ guarantee of the subordinated debt securities will be Martin Midstream Partners’ unsecured general obligation and will be subordinated to all of Martin Midstream Partners’ other unsecured and unsubordinated indebtedness.

Guarantee of Martin Operating Partnership. Martin Operating Partnership may fully, irrevocably and unconditionally guarantee on an unsecured basis all series of debt securities of Martin Midstream Partners and may execute a notation of guarantee as further evidence of such guarantee. The applicable prospectus supplement will describe the terms of any such guarantee by Martin Operating Partnership.

If a series of senior debt securities of Martin Midstream Partners is guaranteed, Martin Operating Partnership’s guarantee of the senior debt securities will be Martin Operating Partnership’s unsecured and unsubordinated general obligation, and will rank on a parity with all of Martin Operating Partnership’s other unsecured and unsubordinated indebtedness. If a series of subordinated debt securities of Martin Midstream Partners is guaranteed, Martin Operating Partnership’s guarantee of the subordinated debt securities will be Martin Operating Partnership’s unsecured general obligation and will be subordinated to all of Martin Operating Partnership’s other unsecured and unsubordinated indebtedness.

The obligations of each Guarantor under its guarantee of the debt securities will be limited to the maximum amount that will not result in the obligations of the Guarantor under the guarantee constituting a fraudulent conveyance or fraudulent transfer under federal or state law, after giving effect to:


	•	all other contingent and fixed liabilities of the Guarantor; and

	•	any collections from or payments made by or on behalf of any other Guarantor in respect of the obligations of the Guarantor under its guarantee.

The guarantee of any Guarantor may be released under certain circumstances. If we exercise our legal or covenant defeasance option with respect to debt securities of a particular series as described below in “— Defeasance,” then any Guarantor will be released with respect to that series. Further, if no default has occurred and is continuing under the indentures, and to the extent not otherwise prohibited by the indentures, a Guarantor will be unconditionally released and discharged from the guarantee:


	•	automatically upon any sale, exchange or transfer, whether by way of merger or otherwise, to any person that is not our affiliate, of all of our direct or indirect limited partnership or other equity interests in the Guarantor;

	•	automatically upon the merger of the Guarantor into us or the liquidation and dissolution of the Guarantor; or

	•	following delivery of a written notice by us to the trustee, upon the release of all guarantees by the Guarantor of any debt of ours for borrowed money for a purchase money obligation or for a guarantee of either, except for any series of debt securities.

Consolidation, Merger and Sale of Assets. Each of Martin Midstream Partners and Martin Operating Partnership has agreed, however, that it will not consolidate with or merge into any entity (other than Martin Midstream Partners, Martin Operating Partnership or their subsidiaries, as applicable) or lease, transfer or dispose of all or substantially all of its assets to any entity (other than Martin Midstream Partners, Martin Operating Partnership or their subsidiaries, as applicable) unless:


	•	it is the continuing entity; or

	•	if it is not the continuing entity, the resulting entity or transferee is organized and existing under the laws of any United States jurisdiction and assumes the performance of its covenants and obligations under the indentures; and

	•	in either case, immediately after giving effect to the transaction, no default or event of default would occur and be continuing or would result from the transaction.

Upon any such consolidation, merger or asset lease, transfer or disposition involving Martin Midstream Partners or Martin Operating Partnership, the resulting entity or transferee will be substituted for Martin Midstream Partners or Martin Operating Partnership, as applicable, under the applicable indenture and debt securities. In the case of an asset transfer or disposition other than a lease, Martin Midstream Partners or Martin Operating Partnership, as applicable, will be released from the applicable indenture.

Events of Default. Unless we inform you otherwise in the applicable prospectus supplement, the following are events of default with respect to a series of debt securities:


	•	failure to pay interest on that series of debt securities when due that continue for 30 days;

	•	default in the payment of principal of or premium, if any, on any debt securities of that series when due at its stated maturity, upon redemption, upon required repurchase or otherwise;

	•	default in the payment of any sinking fund payment on any debt securities of that series when due;

	•	failure by the issuer or, if the series of debt securities is guaranteed by the Guarantor, by such Guarantor, to comply for 60 days with the other agreements contained in the indentures, any supplement to the indentures or any board resolution authorizing the issuance of that series after written notice by the trustee or by the holders of at least 25% in principal amount of the outstanding debt securities issued under that indenture that are affected by that failure;

	•	certain events of bankruptcy, insolvency or reorganization of the issuer or, if the series of debt securities is guaranteed by the Guarantor, of the Guarantor;

	•	if the series is guaranteed by the Guarantor,


	•	any of the guarantees ceases to be in full force and effect, except as otherwise provided in the indentures;

	•	any of the guarantees is declared null and void in a judicial proceeding; or

	•	the Guarantor denies or disaffirms its obligations under the indentures or its guarantee; and


	•	any other event of default provided for in that series of debt securities.

A default under one series of debt securities will not necessarily be a default under another series. The trustee may withhold notice to the holders of the debt securities of any default or event of default (except in any payment on the debt securities) if the trustee considers it in the interest of the holders of the debt securities to do so.

If an event of default for any series of debt securities occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the outstanding debt securities of the series affected by the default (or, in some cases, 25% in principal amount of all debt securities issued under the applicable indenture that are affected, voting as one class) may declare the principal of and all accrued and unpaid interest on those debt securities to be due and payable. If an event of default relating to certain events of bankruptcy, insolvency or reorganization occurs, the principal of and interest on all the debt securities issued under the applicable indenture will become immediately due and payable without any action on the part of the trustee or any holder. The holders of a majority in principal amount of the outstanding debt securities of the series affected by the default (or, in some cases, of all debt securities issued under the applicable indenture that are affected, voting as one class) may in some cases rescind this accelerated payment requirement.

A holder of a debt security of any series issued under each indenture may pursue any remedy under that indenture only if:


	•	the holder gives the trustee written notice of a continuing event of default for that series;

	•	the holders of at least 25% in principal amount of the outstanding debt securities of that series make a written request to the trustee to pursue the remedy;

	•	the holders offer to the trustee indemnity satisfactory to the trustee;

	•	the trustee fails to act for a period of 60 days after receipt of the request and offer of indemnity; and

	•	during that 60-day period, the holders of a majority in principal amount of the debt securities of that series do not give the trustee a direction inconsistent with the request.

This provision does not, however, affect the right of a holder of a debt security to sue for enforcement of any overdue payment.

In most cases, holders of a majority in principal amount of the outstanding debt securities of a series (or of all debt securities issued under the applicable indenture that are affected, voting as one class) may direct the time, method and place of:


	•	conducting any proceeding for any remedy available to the trustee; and

	•	exercising any trust or power conferred upon the trustee relating to or arising as a result of an event of default.

The issuer is required to file each year with the trustee a written statement as to its compliance with the covenants contained in the applicable indenture.

Modification and Waiver. Each indenture may be amended or supplemented if the holders of a majority in principal amount of the outstanding debt securities of all series issued under that indenture that are affected by the amendment or supplement (acting as one class) consent to it. Without the consent of the holder of each debt security affected, however, no modification may:


	•	reduce the amount of debt securities whose holders must consent to an amendment, a supplement or a waiver;

	•	reduce the rate of or change the time for payment of interest on the debt security;

	•	reduce the principal of the debt security or change its stated maturity;

	•	reduce any premium payable on the redemption of the debt security or change the time at which the debt security may or must be redeemed;

	•	change any obligation to pay additional amounts on the debt security;

	•	make payments on the debt security payable in currency other than as originally stated in the debt security;

	•	impair the holder’s right to institute suit for the enforcement of any payment on or with respect to the debt security;

	•	make any change in the percentage of principal amount of debt securities necessary to waive compliance with certain provisions of the indenture or to make any change in the provision related to modification;

	•	modify the provisions relating to the subordination of any subordinated debt security in a manner adverse to the holder of that security;

	•	waive a continuing default or event of default regarding any payment on the debt securities; or

	•	release the Guarantor, or modify the guarantee of the Guarantor in any manner adverse to the holders.

Each indenture may be amended or supplemented or any provision of that indenture may be waived without the consent of any holders of debt securities issued under that indenture:


	•	to cure any ambiguity, omission, defect or inconsistency;

	•	to provide for the assumption of the issuer’s obligations under the indentures by a successor upon any merger, consolidation or asset transfer permitted under the indenture;

	•	to provide for uncertificated debt securities in addition to or in place of certificated debt securities or to provide for bearer debt securities;

	•	to provide any security for, any guarantees of or any additional obligors on any series of debt securities or, with respect to the senior indentures, the related guarantees;


	•	to comply with any requirement to effect or maintain the qualification of that indenture under the Trust Indenture Act of 1939;

	•	to add covenants that would benefit the holders of any debt securities or to surrender any rights the issuer has under the indentures;

	•	to add events of default with respect to any debt securities; and

	•	to make any change that does not adversely affect any outstanding debt securities of any series issued under that indenture in any material respect.

The holders of a majority in principal amount of the outstanding debt securities of any series (or, in some cases, of all debt securities issued under the applicable indenture that are affected, voting as one class) may waive any existing or past default or event of default with respect to those debt securities. Those holders may not, however, waive any default or event of default in any payment on any debt security or compliance with a provision that cannot be amended or supplemented without the consent of each holder affected.

Defeasance. When we use the term defeasance, we mean discharge from some or all of our obligations under the indentures. If any combination of funds or government securities are deposited with the trustee under an indenture sufficient to make payments on the debt securities of a series issued under that indenture on the dates those payments are due and payable, then, at our option, either of the following will occur:


	•	we will be discharged from our or their obligations with respect to the debt securities of that series and, if applicable, the related guarantees (“legal defeasance”); or

	•	we will no longer have any obligation to comply with the restrictive covenants, the merger covenant and other specified covenants under the applicable indenture, and the related events of default will no longer apply (“covenant defeasance”).

If a series of debt securities is defeased, the holders of the debt securities of the series affected will not be entitled to the benefits of the applicable indenture, except for obligations to register the transfer or exchange of debt securities, replace stolen, lost or mutilated debt securities or maintain paying agencies and hold moneys for payment in trust. In the case of covenant defeasance, our obligation to pay principal, premium and interest on the debt securities and, if applicable, guarantees of the payments will also survive.

Unless we inform you otherwise in the prospectus supplement, we will be required to deliver to the trustee an opinion of counsel that the deposit and related defeasance would not cause the holders of the debt securities to recognize income, gain or loss for U.S. federal income tax purposes. If we elect legal defeasance, that opinion of counsel must be based upon a ruling from the U.S. Internal Revenue Service or a change in law to that effect.

No Personal Liability of General Partner. Martin Midstream GP LLC, the general partner of Martin Midstream Partners, and its directors, managers, officers, employees and members, in such capacity, will not be liable for the obligations of Martin Midstream Partners or Martin Operating Partnership under the debt securities, the indentures or the guarantees or for any claim based on, in respect of, or by reason of, such obligations or their creation. By accepting a debt security, each holder of that debt security will have agreed to this provision and waived and released any such liability on the part of Martin Midstream GP LLC and its directors, managers, officers, employees and members. This waiver and release are part of the consideration for our issuance of the debt securities. It is the view of the SEC that a waiver of liabilities under the federal securities laws is against public policy and unenforceable.

Governing Law. New York law will govern the indentures and the debt securities.

Trustee. We may appoint a separate trustee for any series of debt securities. We use the term “trustee” to refer to the trustee appointed with respect to any such series of debt securities. We may maintain banking and other commercial relationships with the trustee and its affiliates in the ordinary course of business, and the trustee may own debt securities.

Form, Exchange, Registration and Transfer. The debt securities will be issued in registered form, without interest coupons. There will be no service charge for any registration of transfer or exchange of the debt securities. However, payment of any transfer tax or similar governmental charge payable for that registration may be required.

Debt securities of any series will be exchangeable for other debt securities of the same series, the same total principal amount and the same terms but in different authorized denominations in accordance with the applicable indenture. Holders may present debt securities for registration of transfer at the office of the security registrar or any transfer agent we designate. The security registrar or transfer agent will effect the transfer or exchange if its requirements and the requirements of the applicable indenture are met.

The trustee will be appointed as security registrar for the debt securities. If a prospectus supplement refers to any transfer agent we initially designate, we may at any time rescind that designation or approve a change in the location through which any transfer agent acts. We are required to maintain an office or agency for transfers and exchanges in each place of payment. We may at any time designate additional transfer agents for any series of debt securities.

In the case of any redemption, we will not be required to register the transfer or exchange of:


	•	any debt security during a period beginning 15 business days prior to the mailing of the relevant notice of redemption and ending on the close of business on the day of mailing of such notice; or

	•	any debt security that has been called for redemption in whole or in part, except the unredeemed portion of any debt security being redeemed in part.

Payment and Paying Agents. Unless we inform you otherwise in a prospectus supplement, payments on the debt securities will be made in U.S. dollars at the office of the trustee or any paying agent. At our option, however, payments may be made by wire transfer for global debt securities or by check mailed to the address of the person entitled to the payment as it appears in the security register. Unless we inform you otherwise in a prospectus supplement, interest payments may be made to the person in whose name the debt security is registered at the close of business on the record date for the interest payment.

Unless we inform you otherwise in a prospectus supplement, the trustee under the applicable indenture will be designated as the paying agent for payments on debt securities issued under that indenture. We may at any time designate additional paying agents or rescind the designation of any paying agent or approve a change in the office through which any paying agent acts.

If the principal of or any premium or interest on debt securities of a series is payable on a day that is not a business day, the payment will be made on the following business day. For these purposes, unless we inform you otherwise in a prospectus supplement, a “business day” is any day that is not a Saturday, a Sunday or a day on which banking institutions in New York, New York or a place of payment on the debt securities of that series is authorized or obligated by law, regulation or executive order to remain closed.

Subject to the requirements of any applicable abandoned property laws, the trustee and paying agent will pay to us upon written request any money held by them for payments on the debt securities that remains unclaimed for two years after the date upon which that payment has become due. After payment to us, holders entitled to the money must look to us for payment. In that case, all liability of the trustee or paying agent with respect to that money will cease.

Book-Entry Debt Securities. The debt securities of a series may be issued in the form of one or more global debt securities that would be deposited with a depositary or its nominee identified in the prospectus supplement. Global debt securities may be issued in either temporary or permanent form. We will describe in the prospectus supplement the terms of any depositary arrangement and the rights and limitations of owners of beneficial interests in any global debt security.

Provisions Applicable Solely to the Martin Midstream Partners and Martin Operating Partnership Subordinated Indentures

Subordination. Debt securities of a series may be subordinated to the issuer’s “Senior Indebtedness,” which is defined generally to include any obligation created or assumed by the issuer (or, if the series is guaranteed, the Guarantor) for the repayment of borrowed money, any purchase money obligation created or assumed by the issuer, and any guarantee therefor, whether outstanding or hereafter issued, unless, by the terms of the instrument creating or evidencing such obligation, it is provided that such obligation is subordinate or not superior in right of payment to the debt securities (or, if the series is guaranteed, the guarantee of the Guarantor), or to other obligations which are pari passu with or subordinated to the debt securities (or, if the series is guaranteed, the guarantee of the Guarantor). Subordinated debt securities will be subordinated in right of payment, to the extent and in the manner set forth in the subordinated indentures and the prospectus supplement relating to such series, to the prior payment of all of the issuer’s indebtedness and that of the Guarantor that is designated as “Senior Indebtedness” with respect to the series.

The holders of Senior Indebtedness of the issuer or, if applicable, the Guarantor, will receive payment in full of the Senior Indebtedness before holders of subordinated debt securities will receive any payment of principal, premium or interest with respect to the subordinated debt securities upon any payment or distribution of our assets or, if applicable to any series of outstanding debt securities, the Guarantors’ assets, to creditors:


	•	upon a liquidation or dissolution of the issuer or, if applicable to any series of outstanding debt securities, the Guarantor; or

	•	in a bankruptcy, receivership or similar proceeding relating to the issuer or, if applicable to any series of outstanding debt securities, to the Guarantor.

Until the Senior Indebtedness is paid in full, any distribution to which holders of subordinated debt securities would otherwise be entitled will be made to the holders of Senior Indebtedness, except that the holders of subordinated debt securities may receive units representing limited partner interests and any debt securities that are subordinated to Senior Indebtedness to at least the same extent as the subordinated debt securities.

If the issuer does not pay any principal, premium or interest with respect to Senior Indebtedness within any applicable grace period (including at maturity), or any other default on Senior Indebtedness occurs and the maturity of the Senior Indebtedness is accelerated in accordance with its terms, the issuer may not:


	•	make any payments of principal, premium, if any, or interest with respect to subordinated debt securities;

	•	make any deposit for the purpose of defeasance of the subordinated debt securities; or

	•	repurchase, redeem or otherwise retire any subordinated debt securities, except that in the case of subordinated debt securities that provide for a mandatory sinking fund, the issuer may deliver subordinated debt securities to the trustee in satisfaction of our sinking fund obligation,

unless, in either case,


	•	the default has been cured or waived and any declaration of acceleration has been rescinded;

	•	the Senior Indebtedness has been paid in full in cash; or

	•	the issuer and the trustee receive written notice approving the payment from the representatives of each issue of “Designated Senior Indebtedness.”

Generally, “Designated Senior Indebtedness” will include:


	•	any specified issue of Senior Indebtedness of at least $100.0 million; and

	•	any other Senior Indebtedness that we may designate in respect of any series of subordinated debt securities.

During the continuance of any default, other than a default described in the immediately preceding paragraph, that may cause the maturity of any Designated Senior Indebtedness to be accelerated immediately without further notice, other than any notice required to effect such acceleration, or the expiration of any applicable grace periods, the issuer may not pay the subordinated debt securities for a period called the “Payment Blockage Period.” A Payment Blockage Period will commence on the receipt by the issuer and the trustee of written notice of the default, called a “Blockage Notice,” from the representative of any Designated Senior Indebtedness specifying an election to effect a Payment Blockage Period and will end 179 days thereafter.

The Payment Blockage Period may be terminated before its expiration:


	•	by written notice from the person or persons who gave the Blockage Notice;

	•	by repayment in full in cash of the Designated Senior Indebtedness with respect to which the Blockage Notice was given; or

	•	if the default giving rise to the Payment Blockage Period is no longer continuing.

Unless the holders of the Designated Senior Indebtedness have accelerated the maturity of the Designated Senior Indebtedness, we may resume payments on the subordinated debt securities after the expiration of the Payment Blockage Period.

Generally, not more than one Blockage Notice may be given in any period of 360 consecutive days. The total number of days during which any one or more Payment Blockage Periods are in effect, however, may not exceed an aggregate of 179 days during any period of 360 consecutive days.

After all Senior Indebtedness is paid in full and until the subordinated debt securities are paid in full, holders of the subordinated debt securities shall be subrogated to the rights of holders of Senior Indebtedness to receive distributions applicable to Senior Indebtedness.

As a result of the subordination provisions described above, in the event of insolvency, the holders of Senior Indebtedness, as well as certain of our general creditors, may recover more, ratably, than the holders of the subordinated debt securities.

DESCRIPTION OF THE COMMON UNITS

Our common units represent limited partner interests that entitle the holders to participate in our partnership distributions and to exercise the rights and privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and our general partner in and to partnership distributions, see “Cash Distribution Policy.” For a general discussion of the expected federal income tax consequences of owning and disposing of common units, see “Material Tax Considerations.” References in this “Description of the Common Units” to “we,” “us” and “our” mean Martin Midstream Partners L.P.

Number of Units

We currently have 4,222,500 common units outstanding, 4,188,405 of which are held by the public, and 34,095 are held by officers and directors of our general partner. In addition, we currently have 4,253,362 subordinated units outstanding, all of which are held by Martin Resource Management and its affiliates. For a description of our subordinated units, please read “— Subordinated Units.” The common units, together with our subordinated units, represent an aggregate 98.0% limited partner interest. Our general partner owns an aggregate 2.0% general partner interest in us.

Listing

Our outstanding common units are traded on the Nasdaq National Market under the symbol “MMLP.” Any additional common units that we issue also will be traded on the Nasdaq National Market.

Transfer Agent and Registrar

Duties. Mellon Investor Services LLC serves as transfer agent and registrar for our common units. We will pay all fees charged by the transfer agent for transfers of common units, except the following must be paid by unitholders:


	•	surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

	•	special charges for services requested by a holder of a common unit; and

	•	other similar fees or charges.

We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal. The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

Each purchaser of common units offered by this prospectus must execute a transfer application. Any subsequent transfers of a common unit will not be recorded by the transfer agent or recognized by us unless the transferee executes and delivers a transfer application. By executing and delivering a transfer application, the transferee of common units:


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

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

	•	agrees to be bound by the terms and conditions of, and executes, our partnership agreement;

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

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

	•	makes the consents and waivers contained in our partnership agreement.

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

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

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


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

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

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


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

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

Our partnership agreement requires that a transferor of common units must provide the transferee with all information that may be necessary to transfer the common units. The transferor is not required to insure the execution of the transfer application by the transferee and has no liability or responsibility if the transferee neglects or chooses not to execute and forward the transfer application to the transfer agent. Please read “The Partnership Agreement — Status as Limited Partner or Assignee.”

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

Voting

Each holder of common units is entitled to the voting rights specified under “The Partnership Agreement — Voting Rights” below.

Subordinated Units

Our subordinated units are a separate class of limited partner interests in Martin Midstream Partners, and the rights of holders to participate in distributions to partners differ from, and are subordinate to, the rights of the holders of common units. For any given quarter, any available cash will first be distributed to our general partner and to the holders of our common units, until the holders of our common units have received the minimum quarterly distribution plus any arrearages, and then will be distributed to the holders of subordinated units. Please read “Cash Distribution Policy.”

The subordinated units may also convert into common units under certain circumstances. Please read “Cash Distribution Policy — Subordination Period.”


	*Limited Voting Rights*

Holders of subordinated units sometimes vote as a single class together with the common units and sometimes vote as a class separate from the holders of common units and, as in the case of holders of common units, will have very limited voting rights. During the subordination period, common units and subordinated units each vote separately as a class on the following matters:


	•	a sale or exchange of all or substantially all of our assets;

	•	the election of a successor general partner in connection with the removal of the general partner;

	•	dissolution or reconstitution of our partnership;

	•	a merger of our partnership;

	•	issuance of limited partner interests in some circumstances; and

	•	some amendments to our partnership agreement including any amendment that would cause us to be treated as an association taxable as a corporation.

The subordinated units are not entitled to a separate class vote on approval of the withdrawal of our general partner or the transfer by our general partner of its general partner interest or incentive distribution rights under some circumstances. Removal of our general partner requires:


	•	a 66²/3% vote of all outstanding units voting as a single class, and

	•	the election of a successor general partner by the holders of a majority of the outstanding common units and subordinated units, voting as separate classes.

Under our partnership agreement, our general partner generally will be permitted to effect amendments to our partnership agreement that do not materially adversely affect unitholders without the approval of any unitholders.


	*Distributions upon Liquidation*

If we liquidate during the subordination period, in some circumstances, holders of outstanding common units will be entitled to receive more per unit in liquidating distributions than holders of outstanding subordinated units. The per unit difference will be dependent upon the amount of gain or loss that we recognize in liquidating our assets. Following conversion of the subordinated units into common units, all units will be treated the same upon liquidation.

CASH DISTRIBUTION POLICY

Distributions of Available Cash

General. Within 45 days after the end of each quarter, Martin Midstream Partners will distribute all of our available cash to unitholders of record on the applicable record date. During the subordination period, which we define below and in the glossary located in Appendix A, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.50 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units.

Available Cash. We define available cash in the glossary located in Appendix A, and it generally means, for each fiscal quarter, all cash on hand at the end of the quarter:


	•	less the amount of cash our general partner determines in its reasonable discretion is necessary or appropriate to:

	•	provide for the proper conduct of our business;

	•	comply with applicable law, any of our debt instruments, or other agreements; or

	•	provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;

	•	plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our revolving credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners.

Intent to Distribute the Minimum Quarterly Distribution. We intend to distribute to the holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.50 per unit, or $2.00 per year, to the extent we have sufficient cash from our operations after the establishment of cash reserves and payment of expenses, including payments to our general partner. There is no guarantee, however, that we will pay the minimum quarterly distribution on the common units in any quarter, and we will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default is existing, under our revolving credit facility.

Restrictions on Our Ability to Distribute Available Cash Contained in Our Credit Agreement. Our ability to distribute available cash is contractually restricted by the terms of our credit agreement. Our credit agreement contains covenants requiring us to maintain certain financial ratios. We are prohibited from making any distributions to unitholders if the distribution would cause an event of default, or an event of default is existing, under our credit agreement or, if after giving effect to any distribution, we would then have less than $5 million of borrowing availability thereunder.

Operating Surplus and Capital Surplus

General. All cash distributed to unitholders will be characterized as either “operating surplus” or “capital surplus.” We distribute available cash from operating surplus differently than available cash from capital surplus.

Operating Surplus. We define operating surplus in the glossary located in Appendix A. For any period it generally means:


	•	our cash balance at the closing of our initial public offering; plus

	•	$8.5 million (as described below); plus

	•	all of our cash receipts since our initial public offering, excluding cash from borrowings that are not working capital borrowings, sales of equity and debt securities and sales or other dispositions of assets outside the ordinary course of business; plus

	•	working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; less

	•	all of our operating expenditures since our initial public offering, including the repayment of working capital borrowings, but not the repayment of other borrowings, and including maintenance capital expenditures; less

	•	the amount of cash reserves our general partner deems necessary or advisable to provide funds for future operating expenditures.

Capital Surplus. We also define capital surplus in the glossary located in Appendix A. It will generally be generated only by:


	•	borrowings other than working capital borrowings;

	•	sales of debt and equity securities; and

	•	sales or other disposition of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirements or replacements of assets.

Characterization of Cash Distributions. We will treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began operations equals the operating surplus as of the most recent date of determination of available cash. We will treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As reflected above, operating surplus includes $8.5 million in addition to our cash balance at the closing of our initial public offering, cash receipts from our operations and cash from working capital borrowings. This amount does not reflect actual cash on hand at the closing of our initial public offering that was available for distribution to our unitholders. Rather, it is a provision that will enable us, if we choose, to distribute as operating surplus up to $8.5 million of cash we receive in the future from non-operating sources, such as asset sales, issuances of securities and long-term borrowings, that would otherwise be distributed as capital surplus. While we do not currently anticipate that we will make any distributions from capital surplus in the near term, we may determine that the sale or disposition of an asset or business owned or acquired by us may be beneficial to our unitholders. If we distribute to you the equity we own in a subsidiary or the proceeds from the sale of one of our businesses, such a distribution would be characterized as a distribution from capital surplus.

Subordination Period

General. During the subordination period, which we define below and in the glossary located in Appendix A, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.50 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.

Subordination Period. We define the subordination period in the glossary located in Appendix A. The subordination period will extend until the first day of any quarter beginning after September 30, 2009 in which each of the following tests are met:


	•	distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

	•	the “adjusted operating surplus” (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and

	•	there are no arrearages in payment of the minimum quarterly distribution on the common units.

Early Conversion of Subordinated Units. Before the end of the subordination period, a portion of the subordinated units may convert into common units on a one-for-one basis immediately after the distribution of available cash to the partners in respect of any quarter ending on or after:


	•	September 30, 2005 with respect to 20% of the subordinated units;

	•	September 30, 2006 with respect to 20% of the subordinated units;

	•	September 30, 2007 with respect to 20% of the subordinated units; and

	•	September 30, 2008 with respect to 20% of the subordinated units.

The early conversions will occur if at the end of the applicable quarter each of the following occurs:


	•	distributions of available cash from operating surplus on the common units and the subordinated units equal or exceed the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

	•	the adjusted operating surplus generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and

	•	there are no arrearages in payment of the minimum quarterly distribution on the common units.

However, the early conversion of the second, third or fourth 20% of the subordinated units may not occur until at least one year following the early conversion of the first, second or third 20% of the subordinated units, as the case may be.

In addition to the early conversion of subordinated units described above, 20% of the subordinated units may convert into common units on a one-for-one basis prior to the end of the subordination period if at the end of a quarter ending on or after September 30, 2005 each of the following occurs:


	•	distributions of available cash from operating surplus on each common unit and subordinated unit equaled or exceeded $2.50 for each of the two consecutive, non-overlapping four-quarter periods immediately preceding that date;

	•	the adjusted operating surplus generated during each of the two consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of a distribution of $2.50 on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and

	•	there are no arrearages in payment of the minimum quarterly distribution on the common units.

This additional early conversion is a one time occurrence.

Finally, 20% of the subordinated units may convert into common units on a one-for-one basis prior to the end of the subordination period if at the end of a quarter ending on or after September 30, 2005 each of the following occurs:


	•	distributions of available cash from operating surplus on each common unit and subordinated unit equaled or exceeded $3.00 for each of the two consecutive, non-overlapping four-quarter periods immediately preceding that date;

	•	the adjusted operating surplus generated during each of the two consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of a distribution of $3.00 on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and

	•	there are no arrearages in payment of the minimum quarterly distribution on the common units.

This additional early conversion is a one time occurrence.

Generally, the earliest possible date by which all subordinated units may be converted into common units is September 30, 2007.

Adjusted Operating Surplus. We define adjusted operating surplus in the glossary located in Appendix A and for any period it generally means:


	•	operating surplus generated with respect to that period; less

	•	any net increase in working capital borrowings with respect to that period; less

	•	any net reduction in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

	•	any net decrease in working capital borrowings with respect to that period; plus

	•	any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods.

Effect of Expiration of the Subordination Period. Upon expiration of the subordination period, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general

partner other than for cause and units held by our general partner and its affiliates are not voted in favor of such removal:


	•	the subordination period will end and each subordinated unit will immediately convert into one common unit;

	•	any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

	•	the general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at the time.

Distributions of Available Cash from Operating Surplus during the Subordination Period

We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:


	•	First, 98% to the common unitholders, pro rata, and 2% to our general partner until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter;

	•	Second, 98% to the common unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

	•	Third, 98% to the subordinated unitholders, pro rata, and 2% to our general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

	•	Thereafter, in the manner described in “— Incentive Distribution Rights” below.

Distributions of Available Cash from Operating Surplus after the Subordination Period

We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:


	•	First, 98% to all unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

	•	Thereafter, in the manner described in “— Incentive Distribution Rights” below.

Incentive Distribution Rights

Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.

If for any quarter:


	•	we have distributed available cash from operating surplus on each common unit and subordinated unit in an amount equal to the minimum quarterly distribution; and

	•	we have distributed available cash from operating surplus on each outstanding common unit in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:


	•	First, 98% to all unitholders, pro rata, and 2% to our general partner, until each unitholder receives a total of $0.55 per unit for that quarter (the “first target distribution”);

	•	Second, 85% to all unitholders, pro rata, and 15% to our general partner, until each unitholder receives a total of $0.625 per unit for that quarter (the “second target distribution”);

	•	Third, 75% to all unitholders, pro rata, and 25% to our general partner, until each unitholder receives a total of $0.75 per unit for that quarter (the “third target distribution”);

	•	Thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.

In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterly distribution.

Percentage Allocations of Available Cash from Operating Surplus

The following table illustrates the percentage allocations of the additional available cash from operating surplus between the unitholders and our general partner up to various target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Target Amount,” until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests shown for our general partner include its 2% general partner interest and assumes the general partner has not transferred the incentive distribution rights.


		Marginal Percentage Interest
		in Distributions
	Total Quarterly Distribution
	Target Amount	Unitholder		General Partner

Minimum Quarterly Distribution	$0.50		98%		2	%
First Target Distribution	up to $0.55		98%		2	%
Second Target Distribution	above $0.55 up to $0.625		85%		15	%
Third Target Distribution	above $0.625 up to $0.75		75%		25	%
Thereafter	above $0.75		50%		50	%

Distributions from Capital Surplus

How Distributions from Capital Surplus Will Be Made. We will make distributions of available cash from capital surplus, if any, in the following manner:


	•	First, 98% to all unitholders, pro rata, and 2% to our general partner, until we distribute for each common unit that was issued in this offering an amount of available cash from capital surplus equal to the initial public offering price;

	•	Second, 98% to the common unitholders, pro rata, and 2% to our general partner, until we distribute for each common unit an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

	•	Thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

Effect of a Distribution from Capital Surplus. Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from the initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the

“unrecovered initial unit price.” Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. Any distribution of capital surplus before the unrecovered initial unit price is reduced to zero, however, cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we distribute capital surplus on a unit in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero. We will then make all future distributions from operating surplus, with 50% being paid to the holders of units, 48% to the holders of the incentive distribution rights and 2% to our general partner.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:


	•	the minimum quarterly distribution;

	•	target distribution levels;

	•	unrecovered initial unit price;

	•	the number of common units issuable during the subordination period without a unitholder vote; and

	•	the number of common units into which a subordinated unit is convertible.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level. We will not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if legislation is enacted or if existing law is modified or interpreted in a manner that causes us to become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, we will reduce the minimum quarterly distribution and the target distribution levels by multiplying the same by one minus the sum of the highest marginal federal corporate income tax rate that could apply and any increase in the effective overall state and local income tax rates. For example, if we became subject to a maximum marginal federal and effective state and local income tax rate of 38%, then the minimum quarterly distribution and the target distributions levels would each be reduced to 62% of their previous levels.

Distributions of Cash upon Liquidation

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

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any

further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner.

Manner of Adjustments for Gain. The manner of the adjustment for gain is set forth in our partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner:


	•	First, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

	•	Second, 98% to the common unitholders, pro rata, and 2% to our general partner until the capital account for each common unit is equal to the sum of:


	(1) the unrecovered initial unit price; plus

	(2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; plus

	(3) any unpaid arrearages in payment of the minimum quarterly distribution;


	•	Third, 98% to the subordinated unitholders, pro rata, and 2% to our general partner until the capital account for each subordinated unit is equal to the sum of:


	(1) the unrecovered initial unit price; and

	(2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;


	•	Fourth, 98% to all unitholders, pro rata, and 2% to our general partner, until we allocate under this paragraph an amount per unit equal to:


	(1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less

	(2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98% to the unitholders, pro rata, and 2% to our general partner, for each quarter of our existence;


	•	Fifth, 85% to all unitholders, pro rata, and 15% to our general partner, pro rata, until we allocate under this paragraph an amount per unit equal to:


	(1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less

	(2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 85% to the units, pro rata, and 15% to our general partner, pro rata, for each quarter of our existence;


	•	Sixth, 75% to all unitholders, pro rata, and 25% to our general partner, until we allocate under this paragraph an amount per unit equal to:


	(1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less

	(2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 75% to the unitholders, pro rata, and 25% to our general partner for each quarter of our existence;


	•	Thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

Manner of Adjustments for Losses. Upon our liquidation, we will generally allocate any loss to our general partner and the unitholders in the following manner:


	•	First, 98% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2% to our general partner until the capital accounts of the subordinated unitholders have been reduced to zero;

	•	Second, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2% to our general partner until the capital accounts of the common unitholders have been reduced to zero; and

	•	Thereafter, 100% to our general partner.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first priority above will no longer be applicable.

Adjustments to Capital Accounts. We will make adjustments to capital accounts upon the issuance of additional units. In doing so, we will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and our general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, we will allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner that results, to the extent possible, in the general partner’s capital account balances equaling the amount that they would have been if no earlier positive adjustments to the capital accounts had been made.

THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. A copy of the partnership agreement of Martin Midstream Partners is filed as an exhibit to this registration statement of which this prospectus is a part.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:


	•	With regard to distributions of available cash, please read “Cash Distribution Policy.”

	•	With regard to the transfer of common units, please read “Description of the Common Units — Transfer of Common Units.”

	•	With regard to allocations of taxable income and taxable loss, please read “Material Tax Considerations.”

Organization and Duration

We were organized in June 2002 and have a perpetual existence.

Purpose

Our purposes under our partnership agreement are limited to owning the equity of the general partner of our operating partnership, serving as the limited partner of our operating partnership and engaging in any business activities that may be engaged in by our operating partnership or that are approved by our general partner. The partnership agreement of our operating partnership provides that our operating partnership may, directly or indirectly, engage in:


	•	its operations as conducted immediately after our initial public offering;

	•	any other activity approved by our general partner but only to the extent that our general partner reasonably determines that, as of the date of the acquisition or commencement of the activity, the activity generates “qualifying income” as this term is defined in Section 7704 of the Internal Revenue Code; or


	•	any activity that enhances the operations of an activity that is described in either of the two preceding clauses.

Although our general partner has the ability to cause us and our operating partnership to engage in activities other than those described in this prospectus, our general partner has no current plans to do so. Our general partner is authorized in general to perform all acts as it may deem, in its sole discretion, necessary to carry out our purposes and to conduct our business.

Power of Attorney

Each limited partner, and each person who acquires a unit from a unitholder and executes and delivers a transfer application, grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants our general partner the authority to amend, and to make consents and waivers under, our partnership agreement.

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described under “— Limited Liability.”

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”) and that he otherwise acts in conformity with the provisions of our partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners 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 for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us who reasonably believe that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds that liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act is liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, unless otherwise agreed, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except the assignee is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from our partnership agreement.

Our operating partnership currently conducts business in 10 states. Maintenance of our limited liability as a limited partner of our operating partnership may require compliance with legal requirements in the jurisdictions in which our operating partnership conducts business, including qualifying our subsidiaries to do business there. Limitations on the liability of limited partners for the obligations of a limited partnership have not been clearly established in many jurisdictions. If, by virtue of our limited partner interest in our operating partnership or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right to remove or replace the general partner of our operating partnership, to approve some amendments to our partnership agreement of our operating partnership, or to take other action under our partnership agreement of our operating partnership constituted “participation in the control” of its business for purposes of the statutes of any relevant jurisdiction, then we could be held personally liable for the obligations of our operating partnership under the law of that jurisdiction to the same extent as its general partner under the circumstances.

Voting Rights

The following matters require the unitholder vote specified below. Matters requiring the approval of a “unit majority” require:


	•	during the subordination period, the approval of a majority of the outstanding common units, excluding those common units held by our general partner and its affiliates, and a majority of the outstanding subordinated units, voting as separate classes; and

	•	after the subordination period, the approval of a majority of the outstanding common units.


Matter		Vote Requirement

Issuance of additional common units or units of equal rank with the common units during the subordination period		Unit majority, with certain exceptions described under “— Issuance of Additional Securities.”
Issuance of units senior to the common units during the subordination period		Unit majority.
Issuance of units junior to the common units during the subordination period		No approval rights.
Issuance of additional units after the subordination period		No approval rights.
Amendment of the partnership agreement		Certain amendments may be made by the general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “— Amendment of the Partnership Agreement.”
Merger of our partnership or the sale of all or substantially all of our assets		Unit majority. Please read “— Merger, Sale or Other Disposition of Assets.”
Dissolution of our partnership		Unit majority. Please read “— Termination and Dissolution.”
Reconstitution of our partnership upon dissolution		Unit majority.
Withdrawal of the general partner		The approval of a majority of the outstanding common units, excluding common units held by the general partner and its affiliates, is required for the withdrawal of the general partner prior to September 30, 2012 in a manner which would cause a dissolution of our partnership. Please read “— Withdrawal or Removal of the General Partner.”


Matter		Vote Requirement

Removal of the general partner		Not less than 66% of the outstanding units, including units held by our general partner and its affiliates. Please read “— Withdrawal or Removal of the General Partner.”
Transfer of the general partner interest		Our general partner may transfer its general partner interest without a vote of our unitholders in connection with the general partner’s merger or consolidation with or into, or sale of all or substantially all of its assets to, a third person. Our general partner may also transfer all of its general partner interest to an affiliate without a vote of our unitholders. The approval of a majority of the outstanding common units, excluding common units held by the general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to September 30, 2012. Please read “— Transfer of General Partner Interests and Incentive Distribution Rights.”
Transfer of incentive distribution rights		Except for transfers to an affiliate or another person as part of the general partner’s merger or consolidation with or into, or sale of all or substantially all of its assets to, such affiliate or person, the approval of a majority of the outstanding common units is required in most circumstances for a transfer of the incentive distribution rights to a third party prior to September 30, 2012. Please read “— Transfer of General Partner Interests and Incentive Distribution Rights.”
Transfer of ownership interests in the general partner		No approval required at any time. Please read “— Transfer of Ownership Interests in the General Partner.”

Issuance of Additional Securities

Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities and rights to buy partnership securities for the consideration and on the terms and conditions established by our general partner in its sole discretion without the approval of the unitholders. During the subordination period, however, except as discussed in the following paragraph, we may not issue equity securities ranking senior to the common units or an aggregate of more than 1,500,000 additional common units or units on a parity with the common units without the approval of the holders of a majority of the outstanding common units and subordinated units, voting as separate classes.

During and after the subordination period, we may issue an unlimited number of common units as follows:


	•	upon conversion of the subordinated units;

	•	under employee benefit plans;

	•	upon conversion of the general partner interest and incentive distribution rights as a result of a withdrawal of our general partner;

	•	in the event of a combination or subdivision of common units;


	•	in connection with an acquisition or a capital improvement that increases cash flow from operations per unit on a pro forma basis; or

	•	if the proceeds of the issuance are used exclusively to repay up to $15 million of certain of our indebtedness.

It is possible that we will fund acquisitions through the issuance of additional common units or other equity securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities that, in the sole discretion of our general partner, have special voting rights to which the common units are not entitled.

Upon issuance of additional partnership securities, our general partner will be required to make additional capital contributions to the extent necessary to maintain its 2% general partner interest in us. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other equity securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain its percentage interest, including its interest represented by common units and subordinated units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership securities.

Amendment of the Partnership Agreement

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

Prohibited Amendments. No amendment may be made that would:


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

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

	•	change the duration of our partnership;

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

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

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

No Unitholder Approval. Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner or assignee to reflect:


	•	a change in our name, the location of our principal place of business, our registered agent or our registered office;

	•	the admission, substitution, withdrawal, or removal of partners in accordance with our partnership agreement;

	•	the reduction in the vote needed to remove the general partner from not less than 66²/3% of all outstanding units to a lesser percentage of all outstanding units;

	•	an increase in the percentage of a class of units that a person or group may own without losing their voting rights from 20% to a higher percentage;

	•	a change that, in the sole discretion of our general partner, is necessary or advisable for us to qualify or to continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we, our operating partnership nor its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

	•	an amendment changing our fiscal or taxable year and any changes that are necessary as a result of a change in our fiscal or taxable year;

	•	an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents, or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or plan asset regulations adopted under the Employee Retirement Income Security Act of 1974, whether or not substantially similar to plan asset regulations currently applied or proposed;

	•	subject to the limitations on the issuance of additional partnership securities described above, an amendment that in the discretion of our general partner is necessary or advisable for the authorization of additional partnership securities or rights to acquire partnership securities;

	•	any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

	•	an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

	•	any amendment that, in the sole discretion of our general partner, is necessary or advisable for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;

	•	a change in our fiscal year or taxable year and related changes;

	•	a merger of the partnership or any of its subsidiaries into, or a conveyance of assets to, a newly-created limited liability entity the sole purpose of which is to effect a change in the legal form of the partnership into another limited liability entity; and

	•	any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner or assignee if those amendments, in the sole discretion of our general partner:


	•	do not adversely affect the limited partners (or any particular class of limited partners) in any material respect;

	•	are necessary or advisable to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;


	•	are necessary or advisable to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange or trading system on which the limited partner interests are or will be listed for trading, compliance with any of which our general partner deems to be in our best interest and the best interest of the limited partners;

	•	are necessary or advisable for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

	•	are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval. Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for federal income tax purposes if one of the amendments described above under “— No Unitholder Approval” should occur. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the units unless we obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners or cause us, our operating partnership or our subsidiaries to be taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously taxed as such).

Any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action must be approved by the affirmative vote of limited partners constituting not less than the voting requirement sought to be reduced.

Action Relating to Our Operating Partnership

Without the approval of the holders of units representing a unit majority, our general partner is prohibited from consenting on our behalf or on behalf of the general partner of our operating partnership to any amendment to the partnership agreement of our operating partnership or taking any action on our behalf permitted to be taken by a partner of our operating partnership in each case that would adversely affect our limited partners (or any particular class of limited partners) in any material respect.

Merger, Sale or Other Disposition of Assets

Our partnership agreement generally prohibits our general partner, without the prior approval of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval.

If conditions specified in our partnership agreement are satisfied, our general partner may merge us or any of our subsidiaries into, or convey some or all of our assets to, a newly formed entity if the sole purpose of that merger or conveyance is to change our legal form into another limited liability entity. The unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a merger or consolidation, a sale of substantially all of our assets or any other transaction or event.

Termination and Dissolution

We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:


	•	the election of our general partner to dissolve us, if approved by a unit majority;

	•	the sale, exchange or other disposition of all or substantially all of our assets and properties and our subsidiaries;

	•	the entry of a judicial order dissolving us; or

	•	the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor.

Upon a dissolution under the last clause, the holders of a majority of the outstanding common units and subordinated units, voting as separate classes, may also elect, within specific time limitations, to reconstitute us and continue our business on the same terms and conditions described in our partnership agreement by forming a new limited partnership on terms identical to those in our partnership agreement and having as general partner an entity approved by the holders of a majority of the outstanding common units and subordinated units, voting as separate classes, subject to our receipt of an opinion of counsel to the effect that:


	•	the action would not result in the loss of limited liability of any limited partner; and

	•	neither our partnership, the reconstituted limited partnership nor our operating partnership would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are reconstituted and continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that the liquidator deems necessary or desirable in its judgment, liquidate our assets and apply the proceeds of the liquidation as provided in “Cash Distribution Policy — Distributions of Cash upon Liquidation.” The liquidator may defer liquidation of our assets for a reasonable period or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to the partners.

Withdrawal or Removal of the General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to September 30, 2012 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after September 30, 2012, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the foregoing, our general partner may withdraw without unitholder approval upon 90 days’ notice to the limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “— Transfer of General Partner Interests and Incentive Distribution Rights.”

Upon the withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a majority of the outstanding common units and subordinated units, voting as separate classes, may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless

within 180 days after that withdrawal, the holders of a majority of the outstanding common units and subordinated units, voting as separate classes, agree in writing to continue our business and to appoint a successor general partner.

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66²/3% of the outstanding units, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units and subordinated units, voting as separate classes. The ownership of more than 33¹/3% of the outstanding units by our general partner and its affiliates would give it the practical ability to prevent its removal. As of March 31, 2004, affiliates of our general partner owned approximately 59.5% of our outstanding units.

Our partnership agreement also provides that if our general partner is removed under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:


	•	the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

	•	any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

	•	our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at the time.

In the event of removal of a general partner under circumstances where cause exists or withdrawal of a general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for the fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. If the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest and its incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Interests and Incentive Distribution Rights

Except for transfer by our general partner of all, but not less than all, of its general partner interest in us or its incentive distribution rights to:


	•	an affiliate of our general partner (other than an individual); or

	•	another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity,

Our general partner may not transfer all or any part of its general partner interest in us or its incentive distribution rights to another person prior to September 30, 2012 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. In the case of a transfer by our general partner of its general partner interest in us, as a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement, furnish an opinion of counsel regarding limited liability and tax matters, and agree to be bound by the provisions of our partnership agreement and the partnership agreement of our operating partnership.

The general partner and its affiliates may at any time transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Ownership Interests in General Partner

At any time, the members of our general partner may sell or transfer all or part of their membership interests in our general partner to an affiliate without the approval of the unitholders.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Martin Midstream GP LLC as our general partner or otherwise change management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. The general partner has the discretion to increase, but not subsequently decrease, the ownership percentage at which voting rights are forfeited. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the prior approval of the directors of our general partner.


	•	the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

	•	any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

	•	our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.

Limited Call Right

If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding partnership securities of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the remaining partnership securities of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least ten

but not more than 60 days notice. Our general partner may exercise this right in its sole discretion. The purchase price in the event of this purchase will be the greater of:


	•	the highest cash price paid by either of our general partner or any of its affiliates for any partnership securities of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those partnership securities; and

	•	the current market price as of the date three days before the date the notice is mailed.

As a result of our general partner’s right to purchase outstanding partnership securities, a holder of partnership securities may have his partnership securities purchased at an undesirable time or price. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material Tax Considerations — Disposition of Common Units.”

Meetings and Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, unitholders or assignees who are record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. Common units that are owned by an assignee who is a record holder, but who has not yet been admitted as a limited partner, will be voted by our general partner at the written direction of the record holder. Absent direction of this kind, the common units will not be voted, except that, in the case of common units held by our general partner on behalf of non-citizen assignees, our general partner will distribute the votes on those common units in the same ratios as the votes of limited partners on other units are cast.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or, subject to the provision described in the next paragraph, by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “— Issuance of Additional Securities.” However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units as a single class.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner or Assignee

Except as described above under “— Limited Liability,” the common units will be fully paid and unitholders will not be required to make additional contributions.

An assignee of a common unit, after executing and delivering a transfer application, but pending its admission as a substituted limited partner, is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and distributions from us, including liquidating distributions. Our general partner will vote and exercise other powers attributable to common units owned by an assignee that has not become a substitute limited partner at the written direction of the assignee. Please read “— Meetings and Voting.” Transferees that do not execute and deliver a transfer application will not be treated as assignees or as record holders of common units, and will not receive cash distributions, federal income tax allocations or reports furnished to holders of common units. Please read “Description of the Common Units — Transfer of Common Units.”

Non-citizen Assignees; Redemption

If we are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create either (i) a substantial risk of cancellation or forfeiture of any property in which we have an interest because of the nationality, citizenship or other related status of any limited partner or assignee, or (ii) a substantial risk that we or one or more of our subsidiaries or other entities in which we have at least a 25% equity interest will not be permitted to conduct business as a United States maritime company under the Jones Act and other United States federal statutes based on the status of any limited partner or assignee as a non-United States citizen, we may redeem the units held by any of these limited partners or assignees at the units’ current market price. In order to avoid any cancellation or forfeiture, our general partner may require each limited partner or assignee to furnish information about his nationality, citizenship or related status. If a limited partner or assignee fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or if our general partner determines after receipt of the information that the limited partner or assignee is not an eligible citizen, the limited partner or assignee may be treated as a non-citizen assignee. In addition to other limitations on the rights of an assignee that is not a substituted limited partner, a non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation.

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:


	•	our general partner;

	•	any departing general partner;

	•	any person who is or was an affiliate of a general partner or any departing general partner;

	•	any person who is or was a member, partner, officer, director, employee, agent or trustee of our general partner, any departing general partner, or any affiliate of a general partner or any departing general partner; or

	•	any person who is or was serving at the request of a general partner or any departing general partner or any affiliate of a general partner or any departing general partner, as an officer, director, manager, employee, member, partner, agent or trustee of another person.

Any indemnification under these provisions will only be out of our assets. Our general partner will not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable demand and at his own expense, have furnished to him:


	•	a current list of the name and last known address of each partner;

	•	a copy of our tax returns;

	•	information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each became a partner;

	•	copies of the partnership agreement, the certificate of limited partnership of the partnership, related amendments and powers of attorney under which they have been executed;

	•	information regarding the status of our business and financial condition; and

	•	any other information regarding our affairs as is just and reasonable.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or which we are required by law or by agreements with third parties to keep confidential.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other partnership securities proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of Martin Midstream GP LLC as our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions.

MATERIAL TAX CONSIDERATIONS

regulations to the extent noted and current administrative rulings and court decisions, all of which are subject to change. Changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Martin Midstream Partners and Martin Operating Partnership.

No attempt has been made in this section to comment on all federal income tax matters affecting us or the unitholders. Moreover, this section focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (“IRAs”), real estate investment trusts (“REITs”) or mutual funds. Accordingly, we urge each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.

All statements of law and legal conclusions, but not statements of facts, contained in this section, except as otherwise indicated, are the opinions of Baker Botts L.L.P. Such opinions are based on the accuracy and completeness of facts described in this prospectus and representations made by us to Baker Botts L.L.P. Baker Botts L.L.P. has not undertaken any obligation to update its opinions discussed in this section after the date of this prospectus.

For the reasons described below, Baker Botts L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues:


	(1) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales”);

	(2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “— Disposition of Common Units — Allocations Between Transferors and Transferees”);

	(3) whether our method for depreciating Section 743 adjustments is sustainable (please read “— Tax Consequences of Unit Ownership — Section 754 Election”); and

	(4) whether assignees of common units who fail to execute and deliver transfer applications will be treated as partners for federal income tax purposes (please read “— Limited Partner Status”).

Partnership Status

sales of propane to retail customers or end users), and certain other “natural resources” and products, including sulfur, sulfur products and fertilizer. Other types of qualifying income include interest other than from a financial business, dividends, real property rents, gains from the sale of real property and gains from the sale or other disposition of assets held for the production of income that otherwise constitutes qualifying income. We estimate that, as of the date of this prospectus, less than 7% of our gross income is not qualifying income. In reliance upon facts provided by Martin Resource Management, us and our general partner concerning the sources and amounts of gross income attributable to our businesses for the current calendar year through the month-end prior to the date of this prospectus, together with the representation that the composition of such gross income remained materially unchanged through the date of this prospectus, and based on applicable legal authority, Baker Botts L.L.P. is of the opinion that at least 90% of our gross income as of the date of this prospectus constitutes qualifying income.

No ruling has been or will be sought from the IRS and the IRS has made no determination of our status as a partnership for federal income tax purposes, the status of the operating partnership for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Baker Botts L.L.P., based upon the Internal Revenue Code, Treasury Regulations, published revenue rulings and court decisions and the representations and assumptions described below, that as of the date of this prospectus Martin Midstream Partners L.P. will be classified as a partnership and our operating partnership will be disregarded as an entity separate from Martin Midstream Partners L.P. for federal income tax purposes.

In rendering its opinion, Baker Botts L.L.P. has relied on certain assumptions, and on factual representations made by us and our general partner. Such assumptions and representations are:


	•	Neither we nor our operating partnership has elected or will elect to be treated as a corporation; and

	•	For each taxable year, more than 90% of our gross income has been and will be income from sources that Baker Botts L.L.P. has opined, or will opine, is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.

If we were taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to the unitholders, and our net income would be taxed at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The remainder of this section is based on Baker Botts L.L.P.’s opinion that Martin Midstream Partners will be classified as a partnership and our operating partnership will be disregarded as an entity separate from Martin Midstream Partners for federal income tax purposes.

Limited Partner Status

Unitholders who have become limited partners of Martin Midstream Partners will be treated as partners of Martin Midstream Partners for federal income tax purposes. Also:


	•	assignees who have executed and delivered transfer applications, and are awaiting admission as limited partners; and

	•	unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units,

will be treated as partners of Martin Midstream Partners for federal income tax purposes. Because there is no direct authority dealing with the status of assignees of common units who are entitled to execute and deliver transfer applications and become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, counsel is unable to opine that such persons are partners for federal income tax purposes. If not partners, such persons will not be eligible for the federal income tax treatment described in this discussion. Furthermore, a purchaser or other transferee of common units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record holders of common units unless the common units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those common units.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales.”

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income. We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether cash distributions are received by him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution from us. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year.

Treatment of Distributions. Our distributions to a unitholder generally will not be taxable to the unitholder for federal income tax purposes to the extent of his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “— Disposition of Common Units.” To the extent our distributions cause a unitholder’s “at risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “— Limitations on Deductibility of Losses.”

he will be treated as having been distributed his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis for the share of Section 751 Assets deemed relinquished in the exchange.

Basis of Common Units. A unitholder’s initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A limited partner will have no share of our debt that is recourse to our general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

Limitations on Deductibility of Losses. The deduction by a unitholder of his share of our losses will be limited to the tax basis in his common units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by five or fewer individuals or some tax-exempt organizations, to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause his at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable to the extent that his tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.

Limitations on Interest Deductions. The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:


	•	interest on indebtedness properly allocable to property held for investment;

	•	our interest expense attributed to portfolio income; and


	•	the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit.

Entity-Level Collections. If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction. In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss for the entire year, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to our general partner.

Baker Botts L.L.P. is of the opinion that, with the exception of the issues described in “— Section 754 Election” and “— Disposition of Common Units — Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

Treatment of Short Sales. 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 a partner for those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:


	•	any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;


	•	any cash distributions received by the unitholder as to those units would be fully taxable; and

	•	all of these distributions would appear to be ordinary income.

Baker Botts L.L.P. 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 should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read “— Disposition of Common Units — Recognition of Gain or Loss.”

Alternative Minimum Tax. Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 ($87,500 in the case of married individuals filing separately) of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Tax Rates. In general, the highest effective United States federal income tax rate for individuals for 2003 is 35% and the maximum United States federal income tax rate for net capital gains of an individual for 2003 is 15% if the asset disposed of was held for more than 12 months at the time of disposition.

Section 754 Election. We made the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election generally permits us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other partners. For purposes of this discussion, a partner’s inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.

Treasury regulations under Section 743 of the Internal Revenue Code require, if the remedial allocation method is adopted, a portion of the Section 743(b) adjustment attributable to recovery property to be depreciated over the remaining cost recovery period for the Section 704(c) built-in gain. Under Treasury Regulation Section 1.167(c)-l(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code rather than cost recovery deductions under Section 168 is generally required to be depreciated using either the straight-line method or the 150% declining balance method. In addition, the holder of a common unit (other than a common unit that is sold in this offering) may be entitled by reason of a Section 743(b) adjustment to amortization deductions in respect of property to which the traditional method of eliminating differences in “book” and tax basis applies. It would not be possible to maintain uniformity of units if this requirement were literally followed; therefore under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these Treasury Regulations. Please read “— Tax Treatment of Operations” and “— Uniformity of Units.”

a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. In addition, if purchasers of common units (other than those that are sold in this offering) are entitled to different treatment in respect of property as to which we are using the traditional method of eliminating differences in “book” and tax basis, we may also take a position that results in lower annual deductions to some or all of our unitholders than might otherwise be available. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “— Disposition of Common Units — Recognition of Gain or Loss.” Please read “— Tax Treatment of Operations” and “— Uniformity of Units.”

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year. We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read “— Disposition of Common Units — Allocations Between Transferors and Transferees.”

Tax Basis, Depreciation and Amortization. The tax basis of our assets is used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to this offering will be borne by our general partner, its affiliates and our other unitholders as of that time. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction.”

If we dispose of depreciable property by sale, foreclosure, or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a partner who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all, of those deductions as ordinary income upon a sale of his interest in us. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction” and “— Disposition of Common Units — Recognition of Gain or Loss.”

Valuation and Tax Basis of Our Properties. The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss. Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest (one in which gain would be recognized if it were sold, assigned or terminated at its fair market value) if the taxpayer or related persons enter(s) into:


	•	a short sale;

	•	an offsetting notional principal contract; or

	•	a futures or forward contract with respect to the partnership interest or substantially identical property.

Allocations Between Transferors and Transferees. In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the Allocation Date. However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Notification Requirements. A person who purchases units from a unitholder is required to notify us in writing of that purchase within 30 days after purchase. We are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker.

Constructive Termination. We will be considered to have been terminated for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. A constructive termination results in the closing of our taxable year for all unitholders. 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 result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.”

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations, other foreign persons and regulated investment companies raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.

A regulated investment company or “mutual fund” is required to derive 90% or more of its gross income from interest, dividends and gains from the sale of stocks or securities or foreign currency or specified related sources. It is not anticipated that any significant amount of our gross income will include that type of income.

foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned 5% or less in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.

Administrative Matters

Information Returns and Audit Procedures. We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by Baker Botts L.L.P., we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, regulations or administrative interpretations of the IRS. Neither we nor Baker Botts L.L.P. can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The Tax Matters Partner has made and will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% interest in profits in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

Nominee Reporting. Persons who hold an interest in us as a nominee for another person are required to furnish to us:


	(a) the name, address and taxpayer identification number of the beneficial owner and the nominee;

	(b) whether the beneficial owner is:


	(1) a person that is not a United States person;

	(2) a foreign government, an international organization or any wholly-owned agency or instrumentality of either of the foregoing; or

	(3) a tax-exempt entity;


	(c) the amount and description of units held, acquired or transferred for the beneficial owner; and


	(d) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Registration as a Tax Shelter. The Internal Revenue Code requires that “tax shelters” be registered with the Secretary of the Treasury. It is arguable that we are not subject to the registration requirement on the basis that we may not constitute a tax shelter. However, we have registered as a tax shelter with the Secretary of Treasury in the absence of assurance that we are not be subject to tax shelter registration and in light of the substantial penalties that might be imposed if registration is required and not undertaken. Our tax shelter registration number is 02318000009.

Issuance of this tax shelter registration number does not indicate that investment in us or the claimed tax benefits have been reviewed, examined or approved by the IRS.

A unitholder who sells or otherwise transfers a unit in a later transaction must furnish the registration number to the transferee. The penalty for failure of the transferor of a unit to furnish the registration number to the transferee is $100 for each failure. The unitholders must disclose our tax shelter registration number on Form 8271 to be attached to the tax return on which any deduction, loss or other benefit we generate is claimed or on which any of our income is included. A unitholder who fails to disclose the tax shelter registration number on his return, without reasonable cause for that failure, will be subject to a $250 penalty for each failure. Any penalties discussed are not deductible for federal income tax purposes.

Recently issued Treasury Regulations require taxpayers to report certain information on Internal Revenue Service Form 8886 if they participate in a “reportable transaction.” You may be required to file this form with the Internal Revenue Service if we participate in a “reportable transaction.” A transaction may be a reportable transaction based upon any of several factors. You are urged to consult with your own tax advisor concerning the application of any of these factors to your investment in our common units. Congress is considering legislative proposals that, if enacted, would impose significant penalties for failure to comply with these disclosure requirements. The Treasury Regulations also impose obligations on “material advisors” that organize, manage or sell interests in registered “tax shelters.” As described in this prospectus, we have registered as a tax shelter, and, thus one of our material advisors will be required to maintain a list with specific information, including your name and tax identification number, and to furnish this information to the Internal Revenue Service upon request. You are urged to consult with your own tax advisor concerning any possible disclosure obligation with respect to your investment and should be aware that we and our material advisors intend to comply with the list and disclosure requirements.

Accuracy-Related Penalties. An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.


	(1) for which there is, or was, “substantial authority;” or

	(2) as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

State, Local, Foreign and Other Tax Considerations

In addition to federal income taxes, you will be subject to other taxes, including state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder is urged to consider their potential impact on his investment in us. We will initially own property or do business in Alabama, Arizona, Arkansas, Georgia, Florida, Illinois, Louisiana, Mississippi, Texas and Utah. We may also own property or do business in other states or foreign jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirements, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements.

In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “— Tax Consequences of Unit Ownership — Entity-Level Collections.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

Tax Consequences of Ownership of Debt Securities

A description of the material federal income tax consequences of the acquisition, ownership and disposition of debt securities will be set forth on the prospectus supplement relating to the offering of debt securities.

INVESTMENT IN US BY EMPLOYEE BENEFIT PLANS

An equity investment in us by an employee benefit plan is subject to additional considerations because the investments of such plans are subject to the fiduciary responsibility and prohibited transaction provisions of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), and restrictions imposed by Section 4975 of the Internal Revenue Code. For these purposes, the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans established or

maintained by an employer or employee organization and IRAs. Among other things, consideration should be given to:


	(a) whether the investment is prudent under Section 404(a)(1)(B) of ERISA;

	(b) whether in making the investment, the employee benefit plan will satisfy the diversification requirements of Section 404(a)(l)(C) of ERISA; and

	(c) whether the investment will result in recognition of unrelated business taxable income by the employee benefit plan and, if so, the potential after-tax investment return.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans from engaging in specified transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code with respect to the employee benefit plan.

The Department of Labor has issued a regulation (the “Plan Assets Regulation”) that provides guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under some circumstances. Under the Plan Assets Regulation, an entity’s assets would not be considered to be “plan assets” if, among other things:


	(a) the equity interests acquired by employee benefit plans are publicly offered securities; i.e., the equity interests are held by 100 or more investors independent of the issuer and each other, freely transferable and registered under certain provisions of the federal securities laws;

	(b) the entity is an “operating company,” i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority owned subsidiary or subsidiaries; or

	(c) equity investment in the entity by benefit plan investors is not significant, which means that less than 25% of the value of each class of equity interest, disregarding interests held by the issuer, its affiliates, and some other persons, is held by employee benefit plans and certain other plans not subject to ERISA, including governmental plans.

Our assets should not be considered “plan assets” under the Plan Assets Regulation because it is expected that the common units will constitute publicly-offered securities, within the meaning of (a) immediately above.

Plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

PLAN OF DISTRIBUTION

We may sell the securities being offered hereby directly to purchasers, through agents, through underwriters or through dealers.

We, or agents designated by us, may directly solicit, from time to time, offers to purchase the securities. Any such agent may be deemed to be an underwriter as that term is defined in the Securities Act of 1933 (the “Securities Act”). We will name the agents involved in the offer or sale of the securities and describe any commissions payable by us to these agents in the prospectus supplement. Unless otherwise indicated in the prospectus supplement, these agents will be acting on a best efforts basis for the period of their appointment. The agents may be entitled under agreements which may be entered into with us to indemnification by us

against specific civil liabilities, including liabilities under the Securities Act of 1933. The agents may also be our customers or may engage in transactions with or perform services for us in the ordinary course of business.

If we utilize any underwriters in the sale of the securities in respect of which this prospectus is delivered, we will enter into an underwriting agreement with those underwriters at the time of sale to them. We will set forth the names of these underwriters and the terms of the transaction in the prospectus supplement, which will be used by the underwriters to make resales of the securities in respect of which this prospectus is delivered to the public. We may indemnify the underwriters under the relevant underwriting agreement to indemnification by us against specific liabilities, including liabilities under the Securities Act. The underwriters may also be our customers or may engage in transactions with or perform services for us in the ordinary course of business.

If we utilize a dealer in the sale of the securities in respect of which this prospectus is delivered, we will sell those securities to the dealer, as principal. The dealer may then resell those securities to the public at varying prices to be determined by the dealer at the time of resale. We may indemnify the dealers against specific liabilities, including liabilities under the Securities Act. The dealers may also be our customers or may engage in transactions with, or perform services for us in the ordinary course of business.

Common units and debt securities may also be sold directly by us. In this case, no underwriters or agents would be involved. We may use electronic media, including the Internet, to sell offered securities directly.

To the extent required, this prospectus may be amended or supplemented from time to time to describe a specific plan of distribution or such specific plan of distribution may be set forth in the related prospectus supplement. The place and time of delivery for the securities in respect of which this prospectus is delivered are set forth in the accompanying prospectus supplement.

LEGAL MATTERS

The validity of the securities offered in this prospectus will be passed upon for us by Baker Botts L.L.P. If certain legal matters in connection with an offering of the securities made by this prospectus and a related prospectus supplement are passed on by counsel for the underwriters of such offering, that counsel will be named in the applicable prospectus supplement related to that offering.

EXPERTS

The following financial statements have been incorporated in this prospectus by reference in reliance upon the reports of KPMG LLP, independent registered public accounting firm, and upon the authority of said firm as experts in accounting and auditing: (i) the consolidated and combined financial statements, respectively, of Martin Midstream Partners and subsidiaries and Martin Midstream Partners Predecessor as of December 31, 2003 and 2002, and for the year ended December 31, 2003, for the period from November 6, 2002 through December 31, 2002, for the period from January 1, 2002 through November 5, 2002 and for the year ended December 31, 2001, (ii) the financial statements of CF Martin Sulphur, L.P. as of December 31, 2003 and 2002, and for the years ended December 31, 2003, 2002 and 2001, (iii) the balance sheet of Martin Midstream GP LLC as of December 31, 2003, and (iv) the statement of revenues and direct operating expenses of Certain Assets of Tesoro Marine Services, L.L.C. for the year ended December 31, 2002.

The audit reports covering the December 31, 2002 financial statements of Martin Midstream Partners and Martin Midstream Partners Predecessor and CF Martin Sulphur, L.P. refer to a change in the method of accounting for goodwill and other intangible assets.

The audit report covering the statement of revenue and direct expenses of Certain Assets of Tesoro Marine Services, L.L.C. for the year ended December 31, 2002 includes an explanatory paragraph emphasizing that the statement was prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission and is not intended to be a complete presentation of the revenues and direct operating expenses of the assets, as defined in the purchase agreement between Tesoro Marine Services, L.L.C. and Martin Midstream Partners and Martin Operating Partnership dated October 27, 2003.

WHERE YOU CAN FIND MORE INFORMATION

We have filed a registration statement with the SEC under the Securities Act of 1933 that registers the securities offered by this prospectus. The registration statement, including the attached exhibits, contains additional relevant information about us. The rules and regulations of the SEC allow us to omit some information included in the registration statement from this prospectus.

In addition, we file annual, quarterly and other reports and other information with the SEC. You may read and copy any document we file at the SEC’s public reference room at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-732-0330 for further information on the operation of the SEC’s public reference room. Our SEC filings are available on the SEC’s web site at www.sec.gov. We also make available free of charge on our website, at www.martinmidstream.com, all materials that we file electronically with the SEC, including our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, Section 16 reports and amendments to these reports as soon as reasonably practicable after such materials are electronically filed with, or furnished to, the SEC. Information contained on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

INCORPORATION BY REFERENCE

We incorporate by reference in this prospectus the documents listed below:


	•	our annual report on Form 10-K for the year ended December 31, 2003 filed with the SEC on March 23, 2004;

	•	our quarterly report on Form 10-Q for the quarter ended March 31, 2004 filed with the SEC on May 13, 2004;

	•	our current report on Form 8-K/ A filed January 23, 2004, our current reports on Form 8-K filed on February 18, 2004 (excluding any portions thereof that are deemed to be furnished and not filed), June 2, 2004 (excluding any portions thereof that are deemed to be furnished and not filed) and June 30, 2004 (excluding any portions thereof that are deemed to be furnished and not filed) and our current report on Form 8-K/ A filed on June 30, 2004;

	•	the description of our common units in our registration statement on Form 8-A (File No. 1-02801862) filed pursuant to the Securities Exchange Act of 1934 on October 29, 2002; and

	•	all documents filed by us under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934 between the date of this prospectus and the termination of the registration statement (excluding any portions thereof that are deemed to be furnished and not filed).

You may obtain any of the documents incorporated by reference in this prospectus from the SEC through the SEC’s web site at the address provided above. You also may request a copy of any document incorporated by reference in this prospectus (including exhibits to those documents specifically incorporated by reference in this document), at no cost, by visiting our internet website at www.martinmidstream.com, or by writing or calling us at the following address:

Martin Midstream Partners L.P.

4200 Stone Road

Kilgore, Texas 75662

Attention: Robert D. Bondurant

Telephone: (903) 983-6200

APPENDIX A

GLOSSARY OF TERMS

adjusted operating surplus: For any period, operating surplus generated during that period is adjusted to:


	(a) decrease operating surplus by:


	(1) any net increase in working capital borrowings during that period; and

	(2) any net reduction in cash reserves for operating expenditures during that period not relating to an operating expenditure made during that period; and


	(b) increase operating surplus by:


	(1) any net decrease in working capital borrowings during that period; and

	(2) any net increase in cash reserves for operating expenditures during that period required by any debt instrument for the repayment of principal, interest or premium.

Adjusted operating surplus does not include that portion of operating surplus included in clause (a) (1) or the definition of operating surplus.

available cash: For any quarter ending prior to liquidation:


	(a) the sum of:


	(1) all cash and cash equivalents of Martin Midstream Partners L.P. and its subsidiaries, or in the case of Martin Operating Partnership L.P., all cash and cash equivalents of Martin Operating Partnership L.P., on hand at the end of that quarter; and

	(2) all additional cash and cash equivalents of Martin Midstream Partners L.P. and its subsidiaries, or in the case of Martin Operating Partnership L.P., all cash and cash equivalents of Martin Operating Partnership L.P., on hand on the date of determination of available cash for that quarter resulting from working capital borrowings made after the end of that quarter;


	(b) less the amount of cash reserves that is necessary or appropriate in the reasonable discretion of our general partner to:


	(1) provide for the proper conduct of the business of Martin Midstream Partners L.P. and its subsidiaries, or in the case of Martin Operating Partnership L.P., the proper conduct of the business of Martin Operating Partnership L.P., (including reserves for future capital expenditures and for future credit needs of Martin Midstream Partners L.P. and its subsidiaries, or in the case of Martin Operating Partnership L.P., future capital expenditures and future credit needs of Martin Operating Partnership L.P.) after that quarter;

	(2) comply with applicable law or any debt instrument or other agreement or obligation to which Martin Midstream Partners L.P. or any of its subsidiaries is a party or its assets are subject; and

	(3) provide funds for minimum quarterly distributions and cumulative common unit arrearages for any one or more of the next four quarters;

provided, however, that our general partner may not establish cash reserves for distributions to the subordinated units unless our general partner has determined that in its judgment the establishment of

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reserves will not prevent Martin Midstream Partners L.P. from distributing the minimum quarterly distribution on all common units and any cumulative common unit arrearages thereon for the next four quarters; and

provided, further, that disbursements made by Martin Midstream Partners L.P. or any of its subsidiaries or cash reserves established, increased or reduced after the end of that quarter but on or before the date of determination of available cash for that quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining available cash, within that quarter if our general partner so determines.

capital account: The capital account maintained for a partner under our partnership agreement. The capital account of a partner for a common unit, a subordinated unit, an incentive distribution right or any other partnership interest will be the amount which that capital account would be if that common unit, subordinated unit, incentive distribution right or other partnership interest were the only interest in us held by a partner.

capital surplus: All available cash distributed by Martin Midstream Partners L.P. from any source will be treated as distributed from operating surplus until the sum of all available cash distributed since the closing of Martin Midstream Partners L.P.’s initial public offering equals the operating surplus as of the end of the quarter before that distribution. Any excess available cash will be deemed to be capital surplus.

closing price: The last sale price on a day, regular way, or in case no sale takes place on that day, the average of the closing bid and asked prices on that day, regular way. In either case, as reported in the principal consolidated transaction reporting system for securities listed or admitted to trading on the principal national securities exchange on which the units of that class are listed or admitted to trading. If the units of that class are not listed or admitted to trading on any national securities exchange, the last quoted price on that day. If no quoted price exists, the average of the high bid and low asked prices on that day in the over-the-counter market, as reported by the Nasdaq National Market or any other system then in use. If on any day the units of that class are not quoted by any organization of that type, the average of the closing bid and asked prices on that day as furnished by a professional market maker making a market in the units of the class selected by Martin Midstream GP LLC. If on that day no market maker is making a market in the units of that class, the fair value of the units on that day as determined reasonably and in good faith by Martin Midstream GP LLC.

common unit arrearage: The amount by which the minimum quarterly distribution for a quarter during the subordination period exceeds the distribution of available cash from operating surplus actually made for that quarter on a common unit, cumulative for that quarter and all prior quarters during the subordination period.

current market price: For any class of units listed or admitted to trading on any national securities exchange as of any date, the average of the daily closing prices for the 20 consecutive trading days immediately prior to that date.

incentive distribution right: A non-voting limited partner partnership interest issued to Martin Midstream GP LLC in connection with the transfer of interests in Martin Operating Partnership L.P. to Martin Midstream Partners L.P. under Martin Midstream Partners L.P.’s partnership agreement. The partnership interest will confer upon its holder only the rights and obligations specifically provided in Martin Midstream Partners L.P.’s partnership agreement for incentive distribution rights.

incentive distributions: The distributions of available cash from operating surplus initially made to Martin Midstream GP LLC that are in excess of Martin Midstream GP LLC’s aggregate 2% general partner interest.

interim capital transactions: The following transactions if they occur prior to liquidation:


	(a) borrowings, refinancings or refundings of indebtedness and sales of debt securities (other than for working capital borrowings and other than for items purchased on open account in the ordinary course of business) by Martin Midstream Partners L.P. or any of its subsidiaries;

	(b) sales of equity interests by Martin Midstream Partners L.P. or any of its subsidiaries;

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	(c) sales or other voluntary or involuntary dispositions of any assets of Martin Midstream Partners L.P. or any of its subsidiaries (other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business, and sales or other dispositions of assets as a part of normal retirements or replacements).

operating expenditures: All expenditures of Martin Midstream Partners L.P. and its subsidiaries, including, but not limited to, taxes, reimbursements of Martin Midstream GP LLC, repayment of working capital borrowings, debt service payments and capital expenditures, subject to the following:


	(a) Payments (including prepayments) of principal of and premium on indebtedness, other than working capital borrowings will not constitute operating expenditures.

	(b) Operating expenditures will not include:


	(1) capital expenditures made for acquisitions or for capital improvements;

	(2) payment of transaction expenses relating to interim capital transactions; or

	(3) distributions to partners.

operating surplus: For any period prior to liquidation, on a cumulative basis and without duplication:


	(a) the sum of


	(1) $8.5 million plus all the cash of Martin Midstream Partners L.P. and its subsidiaries on hand as of the closing date of its initial public offering;

	(2) all cash receipts of Martin Midstream Partners L.P. and its subsidiaries for the period beginning on the closing date of its initial public offering and ending with the last day of that period, other than cash receipts from interim capital transactions; and

	(3) all cash receipts of Martin Midstream Partners L.P. and its subsidiaries after the end of that period but on or before the date of determination of operating surplus for the period resulting from working capital borrowings; less


	(b) the sum of:


	(1) operating expenditures for the period beginning on the closing date of Martin Midstream Partners L.P.’s initial public offering and ending with the last day of that period; and

	(2) the amount of cash reserves that is necessary or advisable in the reasonable discretion of Martin Midstream GP LLC to provide funds for future operating expenditures; provided however, that disbursements made or cash reserves established, increased or reduced after the end of that period but on or before the date of determination of available cash for that period shall be deemed to have been made, established, increased or reduced for purposes of determining operating surplus, within that period if Martin Midstream GP LLC so determines.

subordination period: The subordination period will generally extend from the closing of Martin Midstream Partners L.P.’s initial public offering until the first to occur of:


	(a) the first day of any quarter beginning after September 30, 2009 for which:


	(1) distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the sum of the minimum quarterly distribution on all of the outstanding common units and subordinated units for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

	(2) the adjusted operating surplus generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of

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	the minimum quarterly distribution on all of the common units and subordinated units that were outstanding during those periods on a fully-diluted basis, and the related distribution on the general partner interest in Martin Midstream Partners L.P. and our operating partnership; and

	(3) there are no outstanding cumulative common units arrearages.


	(b) the date on which Martin Midstream GP LLC is removed as general partner of Martin Midstream Partners L.P. upon the requisite vote by the limited partners under circumstances where cause does not exist and units held by Martin Midstream GP LLC and its affiliates are not voted in favor of the removal.

unit majority: When a matter must be approved by a unit majority, as the term is used in this prospectus, such matter must be approved as follows:


	(a) during the subordination period, the approval of a majority of the outstanding common units, excluding those common units held by Martin Midstream GP LLC and its affiliates, and a majority of the outstanding subordinated units, voting as separate classes; and

	(b) after the subordination period, the approval of a majority of the outstanding common units.

working capital borrowings: Borrowings exclusively for working capital purposes made under a revolving credit facility or other arrangement requiring all borrowings thereunder to be reduced to a relatively small amount each year for an economically meaningful period of time.

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3,000,000 Common Units

Representing Limited Partner Interests

PROSPECTUS SUPPLEMENT

January 10, 2006

Citigroup

Sole Book-Running Manager

Raymond James

RBC Capital Markets

A.G. Edwards

KeyBanc Capital Markets